Investigation of accessible pore structure evolution under

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Investigation of accessible pore structure evolution under pressurization and adsorption for coal and shale using small-angle neutron scattering Shimin Liu, Rui Zhang, Zuleima T. Karpyn, Hongkyu Yoon, and Thomas Dewers Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b03672 • Publication Date (Web): 07 Jan 2019 Downloaded from http://pubs.acs.org on January 17, 2019

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Energy & Fuels

Investigation of accessible pore structure evolution under pressurization and adsorption for coal and shale using small-angle neutron scattering Shimin Liua, *, Rui Zhanga, **, Zuleima Karpyna, Hongkyu Yoonb, Thomas Dewersb aDepartment

of Energy and Mineral Engineering, G3 Center and Energy Institute, The Pennsylvania State University, University Park, PA 16802, USA bGeoscience Research and Applications, Sandia National Laboratories, Albuquerque, New Mexico 87185, USA Corresponding Authors: *Tel. No.: +1 8148634491; Fax No.: +1 8148653248; Email: [email protected] **Emails: [email protected] Abstract

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Pore structure is an important parameter to quantify the reservoir rock adsorption capability

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and diffusivity, both of which are fundamental reservoir properties to evaluate the gas production

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and carbon sequestration potential for coalbed methane (CBM) and shale gas reservoirs. In this

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study, we applied small-angle neutron scattering (SANS) to characterize the total and accessible

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pore structures for two coal and two shale samples. We carried out in situ SANS measurements to

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probe the accessible pore structure differences under argon, deuterated methane (CD4) and CO2

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penetrations. The results show that the total porosity ranges between 0.25 and 5.8 % for the four

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samples. Less than 50 % of the total pores are accessible to CD4 for the two coals, while more than

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75 % of the pores were found to be accessible for the two shales. This result suggests that organic

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matter pores tend to be disconnected compared to mineral matter pores. Argon pressurization can

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induce pore contraction because of the mechanical compression of the solid skeleton in both the

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coal and shale samples. Hydrostatic compression has a higher effect on the nanopores of coal and

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shale with a higher accessible porosity. Both methane and CO2 injection can reduce the accessible

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nanopore volume due to a combination of mechanical compression, sorption-induced matrix

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swelling and adsorbed molecule occupation. CO2 has a higher effect on sorption-induced matrix

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swelling compared to methane for both the coal and shale samples. Gas densification and pore

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filling could occur at higher pressures and smaller pore sizes. In addition, the compression and

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adsorption could create nanopores in the San Juan coal and Marcellus shale drilled cores but could

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have an opposite effect in the other samples, namely, the processes could damage the nanopores

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in the Hazleton coal and Marcellus shale outcrop. Thus, the pore structure stability may be sample

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dependent.

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1. Introduction

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Coalbed methane (CBM) and shale gas are two important unconventional natural gas

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resources worldwide.1 Coal and gas shale are both self-sourced reservoir rocks where the gas is

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stored in both free phase and adsorbed phase. The pore structure of the coal and gas shale matrix

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is known to be heterogeneous and anisotropic. The pore structure change will depend on not only

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the pressure variation but also the gas-rock interaction effect through the sorption process during

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gas production in both CBM and shale gas reservoirs. Therefore, it is crucial to investigate the

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evolution of pore structure alteration under in situ gas depletion and injection.

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Previous studies in the literature primarily focused on the gas-induced matrix deformation

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of coal and shale. It was found that the CO2-induced swelling and strain distribution in coal are

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heterogeneous, depending on the lithotypes and microstructures.2,

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microlithotypes exhibited CO2-induced swelling, while the clay and inertite regions showed

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compression in coal.4 The volatile matter will affect the pore structure evolution during the

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carbonization process.5 Methane adsorption and expansion mainly occurred in the pore structure

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filled with clay minerals.6 The investigation of competitive CO2-CH4 adsorption in coal showed

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that the sorption-induced swelling appeared in the low CO2 mole fraction region, which is

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insensitive to temperature and pressure conditions.7 The internal swelling due to supercritical CO2

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Vitrite, liptite and clarite


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was much greater than that for gaseous CO2, and this difference increased with increasing pore

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pressure in coal.8 Compared with the different sorptive gases and different types of coal, the

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sorption-induced swelling was greater with CO2 compared to CH4.9 Moreover, CH4 caused

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swelling more slowly than CO2 at the same pressure.10 Lower rank coals exhibit a higher swelling

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effect than higher rank coals,9 where the presence of moisture significantly reduced the gas-

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induced swelling compared to dry coal samples. The deformation was larger in the direction

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perpendicular to the bedding plane compared to the direction parallel to the bedding plane for both

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water and gas adsorption under hydrostatic conditions.11, 12 It was also found that the mechanical

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deformation could be fully reversible in coal.13 From the simulation perspective, 14, 15 the smallest

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micropores (0.5 nm) tended to be compressed at low pressure (1-10 MPa) initially, followed by

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expansion with increasing pressure. However, only a few studies have focused on the deformation

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of gas shale or pure clay minerals. It was found that both water and CO2 can occupy the

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montmorillonite interlayers, causing strength reduction.16 With increasing CO2 pressure, the

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swelling of shale initially increased and then decreased.17 Moreover, the maximum swelling

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gradually decreased with increasing temperature for the shale sample. Compared with the coal

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sample, the gas adsorption-induced volumetric swelling strain for shale was approximately one

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magnitude lower than that for coal.18 For practical purposes, the sorption-induced anisotropic

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swelling of shale matrix has a significant impact on the caprock sealing efficiency for carbon

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sequestration.19

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It is notable that most of the deformation studies are based on bulk coal and shale samples,

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where the detection scale is in the macroscopic range. However, few studies have considered the

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deformation at nanopore scales in the rock matrix, especially in meso-/micropores. Since ad-


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/desorption and diffusion mainly occur in the meso-/micropore size range in the coal and gas shale

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matrix, it is critical to investigate the evolution of the pore structure as a function of the pressure

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for both inert and sorptive gases. In this study, four samples, including San Juan coal, Hazleton

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coal, Marcellus drilled core and outcrop shales, were used, where the results of the pore size-

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dependent pore accessibility determination of the two coals and the evolution of the fractal

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dimension under pressurization and adsorption of the four tested samples are shown in our

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previous studies.20, 21 The total and accessible pore structures were characterized based on small-

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angle neutron scattering (SANS) experiments. The in situ SANS measurements were conducted to

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evaluate the evolution of the pore size distribution (PSD) and porosity of the accessible pores with

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penetration of argon, deuterated methane (CD4) and CO2. The outcomes of this study will have

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important implications for gas storage estimates, transport modeling and gas production

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optimizations in CBM and shale gas reservoirs.

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2. Experimental methods

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2.1 Sample preparation and characterization

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The subbituminous coal (San Juan coal) and anthracite (Hazleton coal) were collected from

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the northern San Juan Basin in New Mexico and the town of Hazleton in Pennsylvania,

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respectively. Two shale samples were collected from the Marcellus shale formation in

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Pennsylvania. One was a drilled core sample, and the other was an outcrop sample. Both the coals

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and shales were pulverized to a particle size of ~0.5 mm for the SANS measurements and were

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comprehensively characterized to obtain the necessary input parameters for the modeling and pore

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structure evolution interpretation. The chemical composition of each rock sample was obtained by

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X-ray diffraction (XRD), as shown in Table S1 in the supplementary section. The chemical

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composition was used to estimate the effective scattering length density (SLD) and electron density


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for the scattering data fitting for each sample (Table S1). We found that the two coal samples had

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a lower percentage of mineral content and a higher percentage of total organic carbon (TOC)

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content compared to the two shale samples. The San Juan coal contained minerals such as quartz

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and kaolinite, whereas only tobelite was encountered in the Hazleton coal. The TOC content was

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63.95 % for the San Juan coal and 88.10 % for the Hazleton coal. As for the two Marcellus shale

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samples, the drilled core sample had the most diverse mineral content, whereas only quartz and

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muscovite were found in the outcrop sample. The drilled core sample had the lowest TOC content

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(2.06 %), and there was 8.48 % organic matter in the Marcellus outcrop shale. The outcrop shale

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sample had the highest quartz content (75.41 %), which could be due to the strong effect of

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weathering.

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2.2 SANS experiments

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The SANS measurements were conducted using the general-purpose small-angle neutron

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scattering (GP-SANS) instrument in High Flux Isotope Reactor (HFIR) at Oak Ridge National

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Laboratory (ORNL).22 The pulverized powder sample with a particle size of ~0.5 mm was

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uniformly loaded in the aluminum sample cell with an average thickness of ~1.65 mm for the

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testing of the samples. The median particle size could optimize the average scattering for all

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orientations of the pores and avoid scattering from the interparticle voids for the coal and shale

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samples. The effect of multiple scattering could be maximally reduced in samples with small

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thicknesses.23 The neutron wavelength was set to 6 Å, and the neutron wavelength spread 𝛥𝜆/𝜆

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was 0.13. The detector distances were chosen at 18.5 and 0.3 m to cover an overall range of

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scattering vectors between 3×10-3 and 0.5 Å-1, which corresponded to the pore size range between

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0.5 and 82 nm.24 All the 2D scattering profiles were radially averaged during data reduction using

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Igor macros.25 The representative profiles are shown in Figure S1 in the supplementary section.


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All the scattering intensities were normalized to absolute intensities by using the secondary

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standard.26

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Three gases, including inert and sorptive gases (argon, CD4 and CO2), were used for the in

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situ SANS measurements. The scattering at vacuum was determined for each sample as a reference.

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First, CD4 was injected in incremental pressure steps at a pressure of 20, 40 or 68 bar. Then, the

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sample cell was evacuated, and argon was injected through incremental pressure steps at a pressure

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of 68, 340 or 476 bar for each sample. Finally, CO2 was injected, and evacuation was also

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conducted before the injection procedure. The incremental injecting pressure steps for CO2 were

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the same as for CD4 at an injection pressure of 20, 40 or 68 bar. Notably, a contrast-matched

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condition was achieved during CD4 injection at 340 bar for the San Juan coal and at 476 bar for

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the Hazleton coal, Marcellus shale drilled core and outcrop samples.

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3. Results and discussion

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3.1 Experimental scattering data

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Figure 1 shows the scattering intensities 𝐼(𝑄) of the San Juan coal exhibiting the

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experimental 𝐼(𝑄) values under vacuum and contrast-matched conditions, as well as the in situ

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experimental 𝐼(𝑄) values under argon, CD4 and CO2 injection conditions. The 𝐼(𝑄) decreased with

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increasing scattering of vector 𝑄 in the entire 𝑄 range for all the scattering profiles of the San Juan

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coal. In the contrast-matched condition, the scattering counts at the detector reached the lowest

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value. However, for the 1D scattering profile, the 𝐼(𝑄) under contrast-matched conditions was

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smaller than that under vacuum conditions only in the low 𝑄 region. When 𝑄 was above 0.06 Å-1,

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the 𝐼(𝑄) at vacuum decreased. One reason could be the densification of CD4 in the small pores23,

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where the scattering contrast is relatively high. Another possibility is that the 𝑄-independent

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scattering background increased when CD4 injection occurred at high pressure.


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Figure 1. Representative scattering intensities (San Juan coal) (a) in vacuum and contrast-matched conditions; (b) argon injection; (c) CD4 injection and (d) CO2 injection.

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range for all the aforementioned conditions (Figures 1b, c and d). This decrease in the scattering

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intensity for argon injection (Figure 1b) could be primarily attributed to the shrinkage of pores due

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to the solid skeleton contraction, where the pressure-induced mechanical compression on the solid

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skeleton resulted in an increase in the solid density due to the grain contraction.27 In addition to

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the mechanical compression effect due to argon injection, there were sorption-induced effects on

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the microstructure of the rocks with regards to methane and CO2 adsorptions. As shown in Figures

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1c and d, the 𝐼(𝑄) decreased more severely compared to argon in the low 𝑄 range. This is due to

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the increased bulk density of methane or CO2 resulted in a reduction in the scattering contrast

For the in situ data, the 𝐼(𝑄) decreased with increasing injection pressure in the low 𝑄


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between the pores and matrix. And also, there was a sorption-induced gas-solid interface

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densification at which the sorption layer had a higher density compared to the bulk gas.23 In

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addition, the methane and CO2 sorption-induced pore deformation may have affected the scattering

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intensity due to the shrinkage/swelling effects.12 Interestingly, a large decrease in the scattering

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intensity for CO2 at 68 bar was observed (Figure 1d). One possible reason is that CO2 entered the

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liquid phase at 68 bar at room temperature, where the scattering contrast between the pores and

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rock matrix experienced a severe drop compared to gaseous CO2. All the results for the other three

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samples (the Hazleton coal, Marcellus shale drilled core and outcrop shales) were similar to the

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abovementioned findings of the San Juan coal; the experimental scattering intensities are shown

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in Figures S2-S4 in the supplementary section.

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3.2 Pore structure of the total and accessible pores

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Figure 2 shows the pore size distribution (PSD) of the total and accessible pores for the

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tested four samples. The PSD of the total pores was estimated using the scattering intensity under

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vacuum. The PSD of the accessible pores was determined by the scattering intensity difference

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between the vacuum and contrast-matched conditions. A model regression method was used to

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estimate the experimental scattering intensity to extract the PSD information.28 Based on this

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method, a polydisperse spherical pore (PDSP) model was used to fit the experimental scattering

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data of the four tested rock samples. The scattering intensity 𝐼(𝑄) can be expressed as:29

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𝐼(𝑄) = (𝜌s∗ ― 𝜌f∗ ) ∫𝑄max𝑉2(𝑟)𝑓(𝑟)𝑃(𝑄,𝑟)𝑑𝑟 +𝐵𝑘𝑔

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where (𝜌s∗ ― 𝜌f∗ ) is the scattering contrast between the pores and surrounding rock matrix where

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𝜌s∗ and 𝜌f∗ are the SLD of the solid matrix and pores, respectively; 𝑄min and 𝑄max are the lower

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and upper limits of 𝑄, respectively; 𝑉(𝑟) is the spherical pore volume with a radius 𝑟; 𝑓(𝑟) is the

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pore size distribution; 𝑃(𝑄, 𝑟) is the spherical form factor; and 𝐵𝑘𝑔 is the scattering background.

2 𝑄

min

(1)

2


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We defined the lower and upper limits of the pore diameter to be 0.5 and 200 nm, respectively,

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during the model fitting. In general, the pore size distribution 𝑓(𝑟) was multimodal for the tested

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samples, as shown in Figure 2. Notably, the pore range for the 𝑓(𝑟) of the accessible pores was

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smaller than that of the total pores over the entire detected pore range. This result is because the

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subtraction of the scattering intensity measured under vacuum from the scattering intensity

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measured under contrast-matched conditions led to a shorter pore range (𝑄 range) with a greater

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pore size (smaller 𝑄), which is mainly due to the incoherent scattering of hydrogen and/or the

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condensation effect of high pressure methane at a high level of 𝑄.23 In general, the 𝑓(𝑟) of the total

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pores was higher than that of the accessible pores for all the tested samples (Figure 2), indicating

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a certain percentage of inaccessible pores inside the rock samples.21, 23, 30-33 The difference of 𝑓(𝑟)

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between the total and accessible pores for the two shale samples (Figures 2c and d) was relatively

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smaller than that for the two coal samples (Figures 2a and b), indicating that a significant number

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of inaccessible pores were present in the tested coals, while only a small portion was present in the

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tested shales.


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Figure 2. Pore size distribution of total and accessible pores for (a) San Juan coal; (b) Hazleton coal; (c) Marcellus drilled core shale and (d) Marcellus outcrop shale.

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method, which can be expressed as:34

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𝑄INV = ∫𝑄max𝑄2𝐼(𝑄)𝑑𝑄 = 2𝜋2(𝜌s∗ ― 𝜌f∗ ) ∅(1 ― ∅)

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where 𝑄INV is the Porod invariant and ∅ is the porosity. The pore size range for the estimation of

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the total and accessible porosities is shown in Table S2. As shown in Figure 3a, the Hazleton coal

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had the lowest total porosity of less than 0.5 %. The San Juan coal had a relatively higher value of

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~4.5 %. Between the two Marcellus shale samples, the Marcellus shale drilled core sample had a

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smaller porosity of ~2 %, while the Marcellus shale outcrop sample had a porosity that was higher

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than 5.5 %. Furthermore, the fraction of accessible porosity was quantitatively estimated by the

Quantitatively, the total and accessible porosities can be estimated by the Porod invariant

𝑄

2

min

(2)


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total and accessible porosities, as shown in Figure 3b. Both coals had much lower fractions of

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accessible porosities (lower than 50 %) compared to the shale samples (higher than 75 %). This

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result suggests that the nanopores in the organic matter tended to be disconnected compared to the

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mineral matter since the coal had a much higher organic carbon content compared to the shale.

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3.3 Evolution of the accessible pore structure by gas injection

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3.3.1 Coal samples under gas injection

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3.3.1.1 Argon injection

Figure 3. (a) Total porosity and (b) fraction of accessible porosity for the tested samples.

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Figure 4 shows the PSD and porosity evolution of the accessible pores under Ar injection

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for the tested coal samples. The SLD contrast for the estimation of the PSD and porosity at each

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pressure for each sample is shown in Table S3. The pore size range for the porosity estimation at

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each pressure for each sample is shown in Table S4. The 𝑓(𝑟) slightly decreased with increasing

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Ar pressure in pore sizes larger than ~10 nm for the San Juan coal, as shown in Figure 4a. The

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𝑓(𝑟) peak at ~9 nm slightly shifted to a smaller pore size with increasing pressure, although there

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were variations in the 𝑓(𝑟) peak at ~5 nm (the inserted figure in Figure 4a). The decreasing trend 11 ACS Paragon Plus Environment

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of the 𝑓(𝑟) was consistent with that of the porosity results, where the accessible porosity generally

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decreased with increasing pressure, as shown in Figure 4c. This result suggests that the accessible

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pore volume decreased during the hydrostatic gas pressurization in the detected pore range for the

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San Juan coal. The results are different compared to those of a previous study in which there was

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no obvious change in the pore structure during helium injection at 155 bar for bituminous coals.35

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The latter suggests that the in situ high pressure (greater than ~150 bar) hydrostatic gas injection

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could lead to nanopore compression, but low pressure injection (less than ~150 bar) would have a

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negligible effect on the pore structure for bituminous coals.

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Figure 4. Evolution of accessible pore size distribution under argon injection for (a) San Juan coal and (b) Hazleton coal; Evolution of accessible porosity under argon injection for (c) San Juan coal and (d) Hazleton coal.


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However, there were huge variations in the 𝑓(𝑟) for the Hazleton coal, and there was no

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obvious trend in the 𝑓(𝑟) as a function of pressure (Figure 4b). Consistently, there was no obvious

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change in the accessible porosity for the Hazleton coal (Figure 4d). This result means that there

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could be a negligible effect of hydrostatic pressurization on semi-anthracite coal, which is different

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from the subbituminous coal mentioned above. This phenomenon may be caused by the

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significantly smaller accessible porosity (less than 0.08 %) for this high rank coal. Thus, the value

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of the accessible porosity could be an important factor for the degree of nanopore compression by

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hydrostatic gas pressurization. Notably, the detectable pore size greater than ~20 nm was due to

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the relatively high scattering background for this typical high rank sample (Figure S2). We could

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not estimate the 𝑓(𝑟) and accessible porosity of the Hazleton coal at 68 bar of argon injection due

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to the large error in the obtained scattering intensity.

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3.3.1.2 Methane injection

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Figure 5 shows the PSD and porosity evolution of the accessible pores under methane

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injection for the two coal samples. The SLD contrast for the estimation of the PSD and porosity at

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each pressure for each sample is shown in Table S5. The pore size range for the porosity estimation

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at each pressure for each sample is shown in Table S6. There were small changes in the 𝑓(𝑟) as a

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function of the methane pressure at pore sizes greater than ~20 nm, while the 𝑓(𝑟) peak at a pore

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size of ~15 nm decreased and the 𝑓(𝑟) peaks at pore sizes of ~10 and ~6 nm shifted to smaller

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sizes with increasing pressure when the pressure was below 40 bar for the San Juan coal, as shown

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in Figure 5a. This result indicates that, at a relatively low pressure (< 40 bar), the nanopores with

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a size < ~20 nm were mainly affected by the methane injection. However, when the pressure was

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68 bar, a huge variation in the 𝑓(𝑟) occurred, and the detectable pore size range shrunk. The

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vanished nanopores with pore sizes smaller than ~4 nm and pore sizes ranging between ~6 and


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~20 nm could be due to methane densification in these nanopores.21, 23 The nanopores could be

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filled with highly densified methane, where the SLD inside the nanopores approached that of the

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coal matrix. Thus, these nanopores became “invisible” to the neutron beam. However, another

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reason could be the increase in the incoherent scattering intensity with increasing methane pressure,

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where the information of the nanopores with a smaller size was smeared. Consistent with 𝑓(𝑟), the

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accessible porosity generally decreased with increasing methane pressure, as shown in Figure 5c,

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which is consistent with the macroscopic matrix swelling of bituminous coals under constant

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effective stresses.8 The accessible porosity significantly decreased at 68 bar, which could be caused

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by methane densification in the nanopores with pore sizes smaller than 20 nm as described above.

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Compared with the compressive effect of argon, the methane adsorption additionally showed not

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only sorption-induced matrix swelling but also filling of the accessible pores at pore sizes < 20 nm

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for the subbituminous coal sample.


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Figure 5. Evolution of accessible pore size distribution under CD4 injection for (a) San Juan coal and (b) Hazleton coal; Evolution of accessible porosity under CD4 injection for (c) San Juan coal and (d) Hazleton coal.

278

under all pressure conditions were observed as shown in Figure 5b; we could not find a trend for

279

𝑓(𝑟) as a function of the methane pressure. However, the accessible porosity slightly increased

280

with increasing pressure, as shown in Figure 5d, which is unexpected and different from the results

281

of the San Juan coal. Higher rank coal usually has a lower degree of sorption-induced matrix

282

swelling compared to lower rank coal.9 The created accessible pores when the pressure increased

283

for the Hazleton coal could be caused by the accessible pore volume slightly increasing with

284

increasing pressure for this tight coal with a significantly low porosity (< 0.5 %). The result may

For the Hazleton coal, relatively large variations in the 𝑓(𝑟) as a function of the pore size


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285

indirectly suggest that the fraction of accessible pores may be pressure dependent during gas

286

adsorption and desorption.36

287

3.3.1.3 CO2 injection

288

Figure 6 shows the PSD and porosity evolution of the accessible pores under CO2 injection

289

for the tested coal samples. The SLD contrast for the estimation of the PSD and porosity at each

290

pressure for each sample is shown in Table S7. The pore size range for the porosity estimation at

291

each pressure for each sample is shown in Table S8. Notably, we could not obtain the 𝑓(𝑟) at 68

292

bar for the San Juan coal due to the negative subtracted scattering intensity. There were variations

293

in the 𝑓(𝑟) as a function of the pore size with increasing pressure at pore sizes greater than ~7 nm

294

for the San Juan coal, as shown in Figure 6a. However, the 𝑓(𝑟) peak at a pore size of ~6 nm

295

decreased with increasing CO2 pressure and vanished at 40 bar (the inserted figure in Figure 6a).

296

CO2 densification could occur at 40 bar when the pore size was smaller than ~7 nm for the San

297

Juan coal. Additionally, rather than CO2 densification, the increase in the incoherent scattering

298

could be another reason as was discussed in the previous section. Compared with methane injection,

299

the densification of CO2 occurred at lower pressures. This phenomenon is consistent with the

300

porosity results in that, as shown in Figure 6c, the accessible porosity decreased with increasing

301

CO2 pressure, where the decrease rate was higher than that of methane in the same pressure range.

302

The CO2 injection resulted in a higher degree of sorption-induced matrix swelling compared to

303

methane.9 Also, the CO2 swelling rate was higher than that of methane at the same pressure for the

304

bituminous coals.10 In addition, the pore filling with CO2 could occur at a relatively lower pressure

305

(40 bar) compared to methane for the San Juan coal.


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Figure 6. Evolution of accessible pore size distribution under CO2 injection for (a) San Juan coal and (b) Hazleton coal; Evolution of accessible porosity under CO2 injection for (a) San Juan coal and (b) Hazleton coal.

311

the pressure was below 40 bar, as shown in Figure 6b. We observed a slight increase in the 𝑓(𝑟)

312

with increasing CO2 pressure. However, there was a significant increase in the 𝑓(𝑟) at 68 bar when

313

CO2 was injected. This result is consistent with the porosity results, where the accessible porosity

314

slightly increased with increasing pressure and significantly increased at 68 bar, as shown in Figure

315

6d. The pore accessibility could also increase with increasing pressure during CO2 injection. The

316

result at 68 bar (the liquid phase) was unexpected since the accessible porosity was nearly eight

317

times greater than the values at lower CO2 pressure (the gaseous phase). From Figure S1, we found

318

that the scattering intensity at 68 bar decreased in the low 𝑄 region but increased when 𝑄 was

For the Hazleton coal, there were variations in the 𝑓(𝑟) as a function of the pore size when


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319

greater than 0.02 Å-1 compared to the injection results at a lower CO2 pressure. One possible reason

320

could be that the estimated SLD inside the accessible pores may not be the SLD of the bulk CO2

321

at 68 bar for the Hazleton coal due to the very small accessible porosity. The SLD contrast between

322

the rock matrix and accessible pores may be underestimated, and thus, the PSD and porosity could

323

be overestimated. However, another possible reason could be that the accessible porosity in the

324

pore size range between 5.4 and 82 nm did significantly increase at 68 bar, at which pressure the

325

CO2 became liquid at room temperature. The liquid CO2 could partially fill the larger accessible

326

pores that were beyond the SANS detectable range, and a significant number of the smaller

327

accessible pores (perhaps the “bubble-like” pores inside the liquid CO2), which became “visible”

328

in the detectable pore range, increased for this particular high rank coal sample. Further analysis

329

needs to confirm the hypothesis.

330

3.3.1.4 Stability

331

Figure 7 shows the PSD and porosity of the total pores before and after the gas injection

332

for the tested coal samples. There were only small variations in the 𝑓(𝑟) of the total pores

333

(including both the accessible and inaccessible pores) when the pore size was > ~20 nm initially,

334

after the methane and argon injection, and before the CO2 injection, as shown in Figures 7a and b.

335

These results indicate that the nanopores with a size greater than ~20 nm were stable after

336

pressurization and adsorption for the two coal samples. However, greater variations in the 𝑓(𝑟)

337

existed for pore sizes < ~20 nm, which was different between the coal samples. For the San Juan

338

coal, the 𝑓(𝑟) peak at ~1 nm increased after methane and argon injection and before CO2 injection

339

(Figure 7a). This result is consistent with the porosity results, where total porosity also increased

340

(Figure 7c). For the Hazleton coal, the 𝑓(𝑟) slightly decreased at a pore size of ~8 nm, and the

341

𝑓(𝑟) peak at ~1 nm shifted to a smaller pore size (Figure 7b). Consistently, the total porosity


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decreased after methane and argon injection and before CO2 injection, as shown in Figure 7d. The

343

shrinkage of the nanopore structure for the Hazleton coal was consistent with a previous study on

344

anthracite6, where the deformation was related to the clay minerals. However, the macroscopic

345

coal deformation was reversible after helium and methane injection for coal samples from the

346

Illinois Basin12, which is different from the microscopic results in this study. Irreversible changes

347

in the pore structure did occur during the cyclic adsorption and desorption.37, 38 The results of the

348

two tested coals suggest that methane and argon penetration could permanently create nanopores

349

with a size of ~1 nm for the San Juan coal but could damage the nanopores with a size smaller

350

than 10 nm for the Hazleton coal.

351 352 353 354

Figure 7. The stability of total pore size distribution during gas injection for (a) San Juan coal and (b) Hazleton coal; The stability of total porosity before and after gas injection for (c) San Juan coal and (d) Hazleton coal.


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355

3.3.2 Shale samples under gas injection

356

3.3.2.1 Argon injection

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357

Figure 8 shows the PSD and porosity evolution of the accessible pores under Ar injection

358

for the tested Marcellus shale samples. The 𝑓(𝑟) slightly decreased with increasing Ar pressure

359

for pores with a size greater than ~10 nm for the Marcellus shale drilled core sample, as shown in

360

Figure 8a, although there were small variations in the 𝑓(𝑟) as a function of pressure. The 𝑓(𝑟) for

361

pore sizes between ~10 and ~20 nm slightly decreased, and the 𝑓(𝑟) peaks at pore sizes of ~3 and

362

~6 nm shifted to smaller pore sizes (inserted figure in Figure 8a). Similar to the 𝑓(𝑟), the accessible

363

porosity, in general, slightly decreased with increasing pressure (Figure 8c). Thus, the results

364

indicate that the nanopores in the Marcellus shale drilled core were compressed by hydrostatic

365

argon injection. Compared to the coal samples, the compressive effect for the Marcellus shale

366

drilled core with an accessible porosity that was even twice as large was smaller compared to the

367

San Juan coal.


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Figure 8. Evolution of accessible pore size distribution under argon injection for (a) Marcellus drilled core shale and (b) Marcellus outcrop shale; Evolution of accessible porosity under argon injection for (c) Marcellus drilled core shale and (d) Marcellus outcrop shale.

374

increasing argon pressure at pore sizes greater than ~10 nm for the Marcellus shale outcrop sample,

375

as shown in Figure 8b. There were also small variations in the 𝑓(𝑟) as a function of the gas pressure.

376

The 𝑓(𝑟) peak at a pore size of ~7 nm decreased and slightly shifted to a smaller pore size. The

377

accessible porosity also showed a decrease with increasing argon pressure (Figure 8d), which was

378

consistent with the 𝑓(𝑟) results. Additionally, the decrease rate for the outcrop sample was higher

379

than that of the drilled core sample. Since the outcrop sample had a higher accessible porosity, the

380

results indicated that the shale samples with a higher accessible porosity experienced a greater

381

compressive effect by hydrostatic pressurization. This phenomenon is similar to the results of the

Similar to the 𝑓(𝑟) of the shale core sample, the 𝑓(𝑟) also slightly decreased with


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382

two coal samples described in the previous section. In addition, weathering may reduce the shale

383

strength, and therefore, the outcrop sample with a significantly high quartz content (> 75 %)

384

experienced a greater degree of compression compared to the drilled core sample that was obtained

385

from deep in the underground.

386

3.3.2.2 Methane injection

387

Figure 9 shows the PSD and porosity evolution of the accessible pores under methane

388

injection for the two shale samples. The 𝑓(𝑟) slightly decreased with increasing methane pressure

389

for pore sizes greater than ~6 nm for the shale core sample (Figure 9a). The 𝑓(𝑟) peak at a pore

390

size of ~5 nm moved up first and then shifted left with increasing pressure, and another peak at a

391

pore size of ~3 nm moved down first and then shifted left with increasing pressure (insert figure

392

in Figure 9a). However, the accessible porosity first decreased at 20 bar and then remained constant

393

with increasing pressure up to a pressure of 68 bar, as shown in Figure 9c. This result suggests that

394

there may have been very little sorption-induced matrix swelling up to 40 bar and a negligible

395

swelling effect at pressures > 40 bar for the Marcellus drilled core sample. The sorption-induced

396

swelling for the shale was approximately one magnitude lower than that for the coal.18 This

397

phenomenon could be due to the low TOC content (~2 %) of the shale drilled core sample

398

compared to the San Juan coal (~64 %), even though the accessible porosity of the drilled core

399

sample was two times greater than that of the San Juan coal.


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Figure 9. Evolution of accessible pore size distribution under CD4 injection for (a) Marcellus drilled core shale and (b) Marcellus outcrop shale; Evolution of accessible porosity under CD4 injection for (c) Marcellus drilled core shale and (d) Marcellus outcrop shale.

406

increasing methane pressure when the pore size was greater than ~6 nm, as shown in Figure 9b.

407

The 𝑓(𝑟) peak at a pore size of ~4 nm shifted to a smaller pore size with increasing pressure.

408

Specifically, we found that a significant decrease in the 𝑓(𝑟) occurred in the pore size range

409

between 6 and 9 nm, where the 𝑓(𝑟) may have even vanished when the pressure was above 40 bar.

410

This result suggests that methane densification could occur in the nanopores within the pore size

411

range between 6 and 9 nm for the shale outcrop sample. The accessible porosity generally

412

decreased with increasing pressure, as shown in Figure 9d, which is different from the results of

413

the drilled core sample. We also found that the decrease rate of the accessible porosity as a function

However, for the Marcellus shale outcrop samples, the 𝑓(𝑟) obviously decreased with


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414

of the gas pressure was higher for methane injection compared to argon injection at relatively

415

lower pressures for the outcrop sample. The latter indicates that there was not only hydrostatic

416

compression but also a combination of adsorption-induced matrix swelling and pore filling (in the

417

pore size range between 6 and 9 nm) during methane injection for the Marcellus shale outcrop

418

sample. These results are similar to those of the San Juan coal sample.

419

3.3.2.3 CO2 injection

420

Figure 10 shows the PSD and porosity evolution of the accessible pores under CO2

421

injection for the tested shale samples. As depicted in Figure 10a, the 𝑓(𝑟) obviously decreased

422

with increasing CO2 pressure for pore sizes greater than ~10 nm for the Marcellus shale drilled

423

core sample. However, large variations were observed for the 𝑓(𝑟) peaks at pore sizes of ~3 and

424

~5 nm with increasing pressure (inserted figure in Figure 10a). The accessible porosity decreased

425

with increasing CO2 pressure initially below 40 bar and slightly increased at a pressure of 68 bar,

426

as shown in Figure 10c. The result is different from the supercritical CO2 swelling of shale, where

427

the degree of swelling first increased and then decreased with increasing pressure.17 The decrease

428

rate was higher during CO2 injection compared to methane injection, indicating a higher degree of

429

CO2 sorption-induced matrix swelling compared to methane for the Marcellus shale drilled core

430

sample. Notably, CO2 became liquid at 68 bar at room temperature. Condensation of liquid CO2

431

could occur at pore sizes between ~3 and ~4 nm, as shown in the inserted figure in Figure 10a,

432

because the 𝑓(𝑟) peak shifted to pore sizes smaller than ~3 nm and the number of nanopores

433

decreased.


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434 435 436 437 438 439

Figure 10. Evolution of accessible pore size distribution under CO2 injection for (a) Marcellus drilled core shale and (b) Marcellus outcrop shale; Evolution of accessible porosity under CO2 injection for (c) Marcellus drilled core shale and (d) Marcellus outcrop shale.

440

pore sizes greater than ~10 nm, though there were variations in the 𝑓(𝑟) as a function of the

441

pressure at pore sizes < ~10 nm for the Marcellus shale outcrop sample (Figure 10b). As was

442

expected, the 𝑓(𝑟) showed a significant decrease when CO2 became liquid. Consistently, the

443

accessible porosity continuously decreased with increasing CO2 pressure, as shown in Figure 10d.

444

At 68 bar, the accessible porosity significantly decreased and became less than half of the

445

accessible porosity value at vacuum. The results indicate that the effect of CO2 sorption-induced

446

matrix swelling was more pronounced compared to methane for the outcrop sample. At 68 bar, the

The value of 𝑓(𝑟) only slightly decreased with increasing CO2 pressure below 40 bar for


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447

detectable pore size was greater than ~15 nm. Thus, the condensation of and pore filling with liquid

448

CO2 could occur when the pore size was smaller than ~15 nm for this typical shale outcrop.

449

Additionally, nearly half of the accessible pore volume in the pore size range between 3.8 and 82

450

nm could be filled with a combination of liquid and adsorbed CO2 for the shale outcrop sample.

451

In general, for the two shale samples, CO2 had a profound sorption-induced swelling effect

452

compared to methane adsorption, which is similar to the coal results.9

453

3.3.2.4 Stability

454

Figure 11 shows the PSD and porosity of the total pores before and after gas injection for

455

the tested shale samples. There were variations in the 𝑓(𝑟) of the total pores initially, after methane

456

and argon injection, and before CO2 injection for the Marcellus shale drilled core sample, as shown

457

in Figure 11a. Specifically, there may have been a slight increase in the 𝑓(𝑟) when the pore size

458

was greater than ~30 nm for the shale drilled core sample (Figure 11a). There were fluctuations in

459

the 𝑓(𝑟) in the pore size range between ~5 and ~30 nm. Additionally, the 𝑓(𝑟) peak at a pore size

460

of ~1 nm slightly shifted to a smaller size (inserted figure in Figure 11a). As shown in Figure 11c,

461

the total porosity slightly increased after methane and argon injection and before CO2 injection.

462

We observed that the increased porosity could occur for a pore size greater than ~10 nm (Figure

463

11a). Relatively larger variations in the 𝑓(𝑟) were observed when the pore size was smaller than

464

~20 nm as was found for the Marcellus shale outcrop sample (Figure 11b). The total porosity also

465

exhibited larger variations, which decreased after methane and argon injection and before CO2

466

injection, as shown in Figure 11d. The decreased total porosity may be associated with the

467

decreased 𝑓(𝑟) for certain pore sizes: between ~5 and 10 nm, at ~1.5 nm, and at ~0.5 nm.


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Figure 11. The stability of total pore size distribution during gas injection for (a) Marcellus drilled core shale and (b) Marcellus outcrop shale; The stability of total porosity before and after gas injection for (c) Marcellus drilled core shale and (d) Marcellus outcrop shale.

474

SANS measurements were conducted to quantify the PSD and porosity of the total and

475

accessible pores for San Juan coal, Hazleton coal, Marcellus shale drilled core and outcrop samples.

476

The in situ SANS measurements were conducted to investigate the evolution of the PSD and

477

porosity of the accessible pores under various pressurization and adsorption environments. Based

478

on the characterization of the accessible pore structure evolution, several conclusions can be drawn

479

below:

480

(1) The total porosity ranges between 0.25 and 5.8 % at the detected pore size range (< ~82 nm)

481

for the tested coal and shale samples. Less than 50 % of the total porosity is accessible to

4. Conclusions


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482

methane for the two coals compared to greater than 75 % of the fraction of accessible porosity

483

for the two shales, indicating that the organic matter pores tend to be disconnected in this

484

nanopore range.

485

(2) For the two coal samples with different ranks, the hydrostatic compression has a higher effect

486

on coal with a higher accessible porosity and with a lower rank. For the San Juan

487

subbituminous coal, the nanopores with pore sizes < ~20 nm are affected by a combination of

488

compression and sorption-induced matrix swelling during the methane injection. Methane

489

densification and pore filling could occur above 68 bar. CO2 has a more profound effect on

490

matrix swelling, gas densification and pore filling for pore sizes smaller than ~7 nm, which

491

could occur above 40 bar. For the Hazleton semi-anthracite coal, there is no obvious effect of

492

matrix swelling, but the fraction of accessible pores could slightly increase with increasing

493

pressure during methane and CO2 injection. Methane and argon penetration could permanently

494

create nanopores at pore sizes of ~1 nm for the San Juan coal but could damage the nanopores

495

with a pore size smaller than 10 nm for the Hazleton coal.

496

(3) For the two Marcellus shale samples, the drilled core sample has a lower effect of compression

497

compared to the outcrop sample with a higher accessible porosity. The effect of methane

498

sorption-induced matrix swelling is small below 20 bar and negligible above 20 bar for the

499

Marcellus shale drilled core. However, there is notable matrix swelling for the Marcellus shale

500

outcrop sample, where densification and pore filling could occur in the nanopores with a size

501

ranging between 6 and 9 nm. Similar to the coal samples, CO2 also has a greater effect on

502

sorption-induced matrix swelling for the two shale samples. Densification of and pore filling

503

with CO2 occurs in pores with a size < ~15 nm at 68 bar for the outcrop sample. In addition, it


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504

is found that the total porosity increases for Marcellus shale drilled core but decreases for the

505

Marcellus shale outcrop after methane and argon injection.

506

Acknowledgments

507

We want to thank Jitendra Bahadur, Lilin He and the late Yuri Melnichenko for SANS

508

measurement and data reduction. This research used resources at the High Flux Isotope Reactor, a

509

DOE Office of Science User Facility operated by the Oak Ridge National Laboratory. This

510

material is, in part, based upon work supported by the U.S. Department of Energy, Office of

511

Science, Office of Basic Energy Sciences, under contract DE-SC0006883. This paper describes

512

objective technical results and analysis. Any subjective views or opinions that might be expressed

513

in the paper do not necessarily represent the views of the U.S. Department of Energy or the United

514

States Government. Sandia National Laboratories is a multimission laboratory managed and

515

operated by National Technology and Engineering Solutions of Sandia, LLC., a wholly owned

516

subsidiary of Honeywell International, Inc., for the U.S. Department of Energy’s National Nuclear

517

Security Administration under contract DE-NA-0003525. The authors declare no competing

518

financial interests.

519

References

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(1) Outlook, A. E., Energy information administration. Department of Energy 2016. (2) Karacan, C. O., Swelling-induced volumetric strains internal to a stressed coal associated with CO2 sorption. International Journal of Coal Geology 2007, 72, (3-4), 209-220. (3) Mao, L.; Hao, N.; An, L.; Chiang, F.-p.; Liu, H., 3D mapping of carbon dioxide-induced strain in coal using digital volumetric speckle photography technique and X-ray computer tomography. International Journal of Coal Geology 2015, 147, 115-125. (4) Karacan, C. O., Heterogeneous sorption and swelling in a confined and stressed coal during CO2 injection. Energy & Fuels 2003, 17, (6), 1595-1608. (5) Toishi, A.; Yamazaki, Y.; Uchida, A.; Saito, Y.; Aoki, H.; Nomura, S.; Arima, T.; Kubota, Y.; Hayashizaki, H., Quantitative Evaluation for Relationship between Development of Pore Structure and Swelling of Coal in Carbonization of Single Coal Particle. Isij International 2013, 53, (10), 1739-1748. (6) Feng, Z.; Zhou, D.; Zhao, Y.; Cai, T., Study on microstructural changes of coal after methane adsorption. Journal of Natural Gas Science and Engineering 2016, 30, 28-37. 29 ACS Paragon Plus Environment

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Investigation of accessible pore structure evolution under

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