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Environmental and Carbon Dioxide Issues
Molecular Simulation of Carbon Dioxide and Methane Adsorption in Shale Organic Nanopores Kecheng Zeng, Pei-Xue Jiang, Zengmin Lun, and Ruina Xu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02851 • Publication Date (Web): 20 Nov 2018 Downloaded from http://pubs.acs.org on November 23, 2018
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Energy & Fuels
Molecular Simulation of Carbon Dioxide and Methane Adsorption in Shale Organic Nanopores Kecheng Zenga,b, Peixue Jiangb, Zengmin Luna, Ruina Xub,* a
State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, 31 Xueyuan Road, Beijing 100083, China b
Key Laboratory for CO2 Utilization and Reduction Technology of Beijing,
Department of Energy and Power Engineering, Tsinghua University, Beijing 100084, China
Abstract: Using carbon dioxide as a displacing fluid to enhance shale gas recovery is a promising technique given its potential for significant contributions to both unconventional resource development and CO2 geological sequestration. The adsorption capacity of CO2 in nanoscale shale organic pores is the key issue to evaluate the feasibility of CO2-enhanced shale gas recovery (CO2-ESG) technology. However, due to the complex organic component of the solid surface, the fluid-solid interaction between the confined fluid and the solid surface and the intermolecular interaction between the confined fluids, the adsorption behavior of CO2 in the shale is not clear. In this work, shale organic nanopores with different geometries (slit pore and cylindrical pore) and different sizes (1, 2, 4 nm) are constructed using molecular dynamics and Monte Carlo methods. Isothermal adsorption of CO2 and methane as single components and competitive adsorption of a CO2-methane binary mixture are simulated in a nanoscale methane/CO2/organic matter system. The density profile and 1
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distribution contour indicate that CO2 adsorption in shale organic mesopores does not occur via monolayer adsorption. Considering the inadaptability of the Langmuir model to analyze the CO2 adsorption curve, a modified BET (Brunauer–Emmett– Teller) model is applied to describe and fit the data for the CO2 and methane adsorption amount, with the parameters in the modified BET model used to characterize the adsorption capacity and affinity of the fluid. The maximum adsorption amount, characteristic pressure and selectivity parameter of CO2, methane and a binary mixture indicate that the adsorption capacity and affinity of CO2 is stronger than methane under reservoir pressure, which provides useful support for enhancing shale gas recovery by injecting CO2.
1. Introduction Shale gas has become a promising energy resource that can satisfy the urgent call for cleaner fuels resulting from the depletion of conventional gas resources [1]. Although it is a kind of unconventional fossil energy resource, shale gas accounts for a great proportion of total natural gas reserves and production, such as in the U.S., for example, where the production of shale gas has reached 420 billion cubic meters in 2016 and makes up a significant share of up to 56% of total natural gas production. As a result of the fast development of the shale gas industry, the energy structure of the U.S. has changed from importing LNG to exporting it [2]. Hydraulic fracturing is used broadly in shale gas exploitation to increase the gas recovery ratio, but this technology has caused some environmental threats and is also limited by the lack of water resources around some shale reservoir zones. Compared with the methane fluid stored in shale kerogen organic pores, carbon dioxide (CO2) shows stronger adsorption capacity and affinity to shale because of the more intensive intermolecular 2
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Energy & Fuels
interaction with the pore surfaces; thus, the use of CO2 as a displacing fluid to replace water in fracturing is attractive since such a potential technique could not only increase the shale gas recovery ratio but also contribute to geological storage of CO2 [3, 4]. Based on advanced experimental methods, such as scanning transmission X-ray microscopy (STXM) and transmission electron microscope (TEM) scanning, previous studies have found that the chemical components of shale matrix pores are mostly composed of organic matter, such as kerogen, asphaltene, aromatic hydrocarbons and saturated hydrocarbons [3, 5]. Most of the shale matrix pores, excluding fracture and inorganic pores, are less than 10 nm in diameter [6]. These organic nanopores have very large specific areas and contribute to a great amount of adsorbed methane in a shale reservoir [7]. Therefore, the adsorption pattern, capacity and affinity of CO2 and methane in shale organic nanopores are key impact factors for the recovery performance of CO2-ESG. In such confined nanopores, the physical property and phase behavior of fluids are controlled mainly by the interaction between the fluid and complicated solid surface. With the effect of the nanopores’ structures and chemical components in the shale, the physical property and behavior of CO2 and methane, such as capillary condensation, adsorption/desorption hysteresis [8,9], competitive adsorption [10], slip flow and surface diffusion [11-13], are all different compared to the bulk state. Physical adsorption is the most direct characteristic of the interaction between fluid and pore surface and reveals how carbon dioxide can displace methane in shale nanopores and enhance the recovery ratio [14-16].
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Fig. 1. FIB/SEM microscopic images of a shale sample extracted from the Lower Silurian Longmaxi Formation irregular organic pores [3] In a real shale, the distribution of organic nanopores is in the microporous (pore size
