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Supercritical Methane Diffusion in Shale Nanopores: Effects of Pressure, Mineral Types, and Moisture Content Sen Wang, Qihong Feng, Ming Zha, Farzam Javadpour, and Qinhong Hu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02892 • Publication Date (Web): 04 Dec 2017 Downloaded from http://pubs.acs.org on December 4, 2017
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Energy & Fuels
Supercritical Methane Diffusion in Shale Nanopores: Effects of Pressure, Mineral Types, and Moisture Content Sen Wang,*,† Qihong Feng,*,† Ming Zha,† Farzam Javadpour,*,‡ and Qinhong Hu§ †
China University of Petroleum (East China), Qingdao 266580, China
‡
Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at
Austin, Austin, Texas 78712, United States §
Key Laboratory of Tectonics and Petroleum Resources, Ministry of Education, China
University of Geosciences, Wuhan 430074, China KEYWORDS: shale, diffusion, molecular dynamics, nanopore, organic matter, clay
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ABSTRACT Using molecular dynamics, we simulated the diffusion behavior of supercritical methane in shale nanopores composed of different matrix mineral types (organic matter, clay, and calcite). We studied the effects of pore size, pore pressure, and moisture content on the diffusion process. Our results show that confined methane molecules diffuse more rapidly with increases in pore size and temperature but diffuse slowly with an increase in pressure. Anisotropic diffusion behavior is also observed in directions parallel and perpendicular to the basal surfaces of nanoslits. We also found that mineral types composing the pore walls have a prominent effect on gas diffusion. The perfectly ordered structure and ultrasmooth surface of organic matter facilitate the transport of methane in dry pores even though its adsorption capability is much stronger than that of inorganic minerals. Moisture inhibits methane diffusion but this adverse effect is more evident in organic pores, because water migrates in the form of cluster, which acts as a piston and severely impedes methane diffusion. However, only an adsorbed water membrane is present at the surfaces of inorganic materials, leading to a weaker impact on methane diffusion. Remarkably, the ratios of the self-diffusion coefficients of confined fluid and bulk phase at different temperatures collapse onto a master curve dependent solely on the slit aperture. Therefore, we propose a mathematical model to facilitate upscaling studies from atomistic computations to macroscale measurements. The findings of this study provides a better understanding of hydrocarbon transport through shale formation, which is fundamentally important for reliably predicting production performance and optimizing hydraulic fracturing design.
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Energy & Fuels
1. INTRODUCTION Owing to increasing energy demand and the need to protect the environment, we are being forced to seek alternative energy resources.1 Until the global industry can produce electricity through thermodynamically efficient and economically viable technologies, the development of hydrocarbons confined in shale may serve as a bridging strategy to alleviate the energy crisis and reduce greenhouse gas emissions.2–5 Because of widespread nanopores and disordered pore structures, fluid flow through organic-rich shale is ~6 orders of magnitude slower than that in conventional formations.6 Recent advances in hydraulic fracturing technology, however, have led to a large increase in the production of shale resources.7–9 The total yield of shale gas has been as much as 15,213 Bcf in the United States, accounting for >50% of its natural gas production in 2015, whereas this share was only 1.6% of production in 2000.10–12 China has also made remarkable breakthroughs in the exploitation of shale gas and achieved annual production capacity of 175 Bcf in 2016, compared with almost zero commercial output in 2013.13 Although shale is playing an increasingly important role in the global energy industry, our knowledge of the fundamentals of fluid transport through multiscale and heterogeneous porous media is incomplete, because both static and dynamic properties of fluid confined in a nanopore differ tremendously from those at the macroscopic scale.14,15 Such behavior raises concerns and challenges on the applicability of Darcy’s law.6,16 Therefore, attempts have been made to compensate for the drawbacks of conventional hydrodynamics theory by incorporating other transport mechanisms, e.g., interfacial slip, adsorption/desorption effect, and gas diffusion. The contribution of each physical process is primarily dominated by the pore-size distribution and chemical composition of shale and also varies with the pressure and temperature. Recent studies have confirmed the prominent effect of gas diffusion upon mass transfer through nanoscale pores
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within the shale matrix.17–19 Etminan et al.17 suggested that the dissolved gas in amorphous kerogen contributes ~22% of the total gas in place, and the physics controlling its migration is molecular diffusion. On the basis of a theoretical model considering gas adsorption, Wu et al.18 reported that surface diffusion may account for as much as 93% of the total gas flow rate in a pore smaller than 2 nm. Thus there is a strong need to develop the fundamental understanding of methane diffusion through nanoporous shales,19 which are characterized by heterogeneous composition and structures at all scales.20 Some laboratory studies have been performed to understand gas diffusion behavior through shale matrix.17,21–26 Yuan et al.21 found that a bidisperse model can reasonably describe the transient pressure measured for CH4 diffusion through a shale sample from Sichuan Basin of China, and concluded that Fickian and Knudsen diffusion control the transport through macropores and micropores, respectively. Using a modified polyvinyl chloride (PVC) sample holder, Peng et al.22 improved a diffusion chamber method established for unconsolidated media to measure the diffusivity of consolidated rocks, but not for shale cores with extremely low matrix permeability on the order of nanodarcies. On the basis of batch pressure decay experiments, Etminan et al.17 developed an evaluation technique to estimate the contribution of different gas storage processes. They observed that an expansion of compressed gas in the pore network appears first, followed by gas desorption from the inner pore surface, and later by gas diffusion from kerogen. Cui et al.23 took into account the effect of gas adsorption and proposed new models to measure the permeability or diffusivity of cores and crushed samples under in situ conditions. Their method, which utilizes late-time pressure data from decay tests, is demonstrated to be more reliable and precise than the commonly used early-time technique.
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Energy & Fuels
Most recently, using the material balance principle, Yang et al.24 determined the surface diffusion coefficient of adsorbed CH4 in shale cores. An alternative technique, molecular dynamics (MD), has been widely employed to provide nanoscale resolution for interactions at interfacial surfaces and predict the thermophysical properties of systems under confinement.27,28 Assuming forces among interacting particles are estimated from empirical potential functions (the so-called force field), this method calculates the trajectory of each particle in a multibody system by numerically solving Newton’s law of motion, from which the key properties and molecular structures of such a complex system can be determined through statistically analyzing the ensemble constituted by different evolution states.28,29 The application of MD is of broad interest in the disciplines of shale gas and coalbed methane,5,30,31 carbon capture and sequestration,32 and enhanced recovery of gas hydrate and hydrocarbon resources.33,34 Beyond the static features such as adsorption, conformation, and interfacial tension, MD is also capable of obtaining dynamic properties, e.g., diffusion coefficient, transport behavior, and shear viscosity. Using this technique, Striolo35 found that, because of the long-lasting hydrogen bonds, water exhibits a fast ballistic diffusion through single-walled carbon nanotubes (SWNTs) having a diameter 1.08 nm in the first 500 ps, after which Fickian diffusion prevails, rather than the single-file type expected for a narrow pore. Mao and Sinnott36 studied the diffusion of CH4, C2H6, and C2H4 inside carbon nanotubes and suggested that fluid diffusivity is influenced by pore size and molecular density. Hu et al.28 compared the adsorption and diffusion of CH4 and CO2 in coal and concluded that the adsorbed CH4 can be effectively replaced by CO2, whose adsorption heat is greater. An MD simulation of multicomponent hydrocarbon mixtures permeating through a molecular model developed for oilprone type Ⅱ kerogen showed that the amorphous nanoporous material acts as a selective
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membrane and the transport mechanism is purely diffusive.37 Wang et al.27 disclosed that the diffusivity of shale oil increases greatly when migrating from micropores (
