Mineralogy and Gas Content of Upper Paleozoic Shanxi and Benxi Shale Formations in the Ordos Basin Fengyang Xiong, † Zhenxue Jiang, ‡,§ Hexin Huang, ∥ Ming Wen, ‡,§ and Joachim Moortgat* ,† † School of Earth Sciences, The Ohio State University, Columbus, Ohio 43210, United States ‡ State Key Laboratory of Petroleum Resources and Prospecting and § Unconventional Natural Gas Institute, China University of Petroleum, Beijing 102249, China ∥ State Key Laboratory of Continental Dynamics of Ministry of Geology, Northwest University, Xi’an 710069, China * S Supporting Information ABSTRACT: To directly measure the gas content in the Benxi and Shanxi subformations of the Ordos Basin in NW China, a series of canister desorption tests were carried out on 33 over-mature Lower Permian to Upper Carboniferous fresh shale cores (>3000 m) at both the reservoir temperature (75−80 °C) and an elevated temperature of 95 °C. Organic chemistry and X-ray diffraction analyses of 33 replicate samples were used to establish relationships between the gas content and rock composition. Geochemical measurements show that the total organic carbon (TOC) contents range from 0.49 to 13.7 wt %. The organic matter is mainly type III arising from lagoon and delta depositional settings. The dominant minerals are clay (25−97 wt %, average 59 wt %) and quartz (1−62 wt %, average 33 wt %). A new ternary diagram is proposed based on the origin and brittleness of the minerals. Multiple linear regressions of emitted gas volumes with respect to the full mineralogy and TOC show a strong positive correlation with TOC and a weak one with clay composition. This is consistent with independent high- pressure methane adsorption experiments in the literature. Elevating the temperature resulted in an incremental gas production of 12% for the Lower Permian Shanxi facies versus 62% from the Upper Carboniferous Benxi shale (with a weighted average of 43%). This may be indicative of more significant gas adsorption (related to the pore size distribution and specific surface areas) in the Benxi lagoon environment, which has more functional components (TOC and clay) and micropore volume than the Shanxi delta deposits, which are more quartz-rich. 1. INTRODUCTION Increased carbon dioxide (CO 2 ) concentrations in the atmosphere have resulted in a strong interest in low CO 2 - emission energy resources. 1 The development of shale gas as an unconventional resource alternative to oil and coal has led to an energy revolution in the United States. 2−9 According to the Energy Information Administration (2017), shale gas, together with gas in tight oil plays, will contribute approximately two-thirds of the total energy production in the United States by 2040. 10 An accurate assessment of shale gas capacity is therefore necessary prior to exploration and exploitation and plays a crucial role in the shale gas production process. 11−13 Researchers currently determine the gas content in place based on indirect and direct methods. 14,15 In the indirect method, the total gas in place is obtained from the sum of free gas, sorbed gas, and dissolved gas as classified by Curtis et al. (2002). 16 Free gas is calculated from an equation of state when porosity, reservoir temperature, and pressure are known. Sorbed gas is measured by high-pressure methane (and other hydrocarbons) isotherms under reservoir conditions. Under reservoir conditions, a certain amount of gas may also have dissolved in water, oil, and the organic matter (OM), such as kerogen and pyrobitumen. In direct approaches, shale cores are retrieved from the reservoir and then sealed in an airtight container. A certain amount of gas is already emitted during this recovery progress (i.e., from the uplift to the time before sealing), which is referred to as “lost gas”. After sealing, desorption and diffusion will continue inside the container. The measured gas at this stage of a “canister desorption test” (CDT) is often referred to as “desorbed” gas. 15,17 However, the gas volume from CDT consists of desorbed gas, free gas, and potentially dissolved gas. 17,18 In the following, we therefore use “emitted gas” instead of “desorbed gas” to refer to any of those components. When no more gas is emitted from the cores, “residual gas” is measured in the lab by crushing the cores. Lost gas is estimated by backward extrapolation of the early emitted gas evolution over time. Summing lost gas, emitted gas, and residual gas renders the total gas content in place. In the industry, this direct approach is commonly used owing to its simplicity and low cost. In these direct methods, the relationship between the measured desorbed gas content and (early) time is critical to estimate the lost gas. This approach, referred to as the United States Bureau of Mines (USBM) method, was first widely used in 1973 to measure gas contents in coal bed methane at shallow depth, based on the idea that the desorbed gas volume is linearly correlated with the square of lost time (the time from drilling the cores to the first desorption measure- ments). 19,20 However, this method was proven problematic when applied to shale gas because the composition, structure, Received: November 26, 2018 Revised: December 30, 2018 Published: January 11, 2019 Article pubs.acs.org/EF Cite This: Energy Fuels 2019, 33, 1061-1068 © 2019 American Chemical Society 1061 DOI: 10.1021/acs.energyfuels.8b04059 Energy Fuels 2019, 33, 1061−1068 Downloaded via OHIO STATE UNIV on March 21, 2019 at 18:10:03 (UTC). See https://pubs.acs.org/sharingguidelines for options on how to legitimately share published articles.