Anisotropic pore structure of shale and gas injection-induced nanopore alteration: A small-angle neutron scattering study

International Journal of Coal Geology 219 (2020) 103384

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Anisotropic pore structure of shale and gas injection-induced nanopore alteration: A small-angle neutron scattering study Shimin Liua,b, Rui Zhangb, a b

T

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State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Beijing 100083, China Department of Energy and Mineral Engineering, G3 Center and Energy Institute, Pennsylvania State University, University Park, Pennsylvania 16802, United States

A R T I C LE I N FO

A B S T R A C T

Keywords: Anisotropic pore structure Alteration and deformation Marcellus Shale Methane and CO2 injection in situ small-angle neutron scattering (SANS)

Gas transport in the shale matrix is controlled by pore structure, which can ultimately influence natural gas production potential and carbon sequestration in shale gas reservoirs. In this study, in situ small-angle neutron scattering (SANS) measurements under methane and CO2 injections were employed to investigate two Marcellus Shale thin section samples cut parallel and perpendicular to the bedding. Marcellus Shale nanopores show intrinsic anisotropy over the detected length scale of 5–2000 Å. Microscopic gas transport could be inhibited due to the decrease of accessible porosity with increasing gas pressure. The degree of inhibition may be higher for CO2 than for methane, and for the direction normal to the bedding than in the bedding direction. In addition, under the condition of liquid CO2, higher porosity reduction for the direction normal to the bedding may insight into nanoscale anisotropic wettability in the shale matrix.

1. Introduction In 2005, natural gas became an alternative to coal and crude oil as an energy resource due to its lower carbon emissions and the shale gas revolution in the United States (EIA, 2019). Around this time, unconventional natural gas became increasingly important due to the rapid increase in gas production from shale formations (CuetoFelgueroso and Juanes, 2013). Shale gas can be commercially produced thanks to mature well completion technologies, including horizontal drilling combined with hydraulic fracturing stimulation (Howarth et al., 2011). As a source rock, shale has a complex pore structure with low porosity and ultralow permeability (Kerr, 2010; Wang et al., 2018). Those pores in the shale matrix can be classified as macropore (> 50 nm), mesopore (2–50 nm), and micropore (< 2 nm), based on the International Union of Pure and Applied Chemistry (IUPAC) classification (Rouquerol et al., 1994). Gas is primarily stored as a free phase through compression in shale macropores and fractures and as both free phase and adsorbed phase in shale meso−/micropores due to gas adsorption (Rexer et al., 2014; Wang et al., 2016a). Gas storage and transport behaviors in nanopores in the shale matrix determine the natural gas production potential of shale gas reservoirs during flat production tail in which free gas is almost depleted (Gensterblum et al., 2015). After the depletion of free gas in fractures, matrix-stored gas becomes the source of gas that can be produced, and the matrix

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nanoscale pore structure controls gas transport behavior. Thus, a fundamental understanding of nanoscale pore structure in the shale matrix is essential for prediction of long-term gas production. The structure of the shale matrix is known to be heterogeneous and anisotropic (Chalmers et al., 2012; Gu et al., 2015; Kwon et al., 2004; Loucks et al., 2009). The anisotropic nanopore structure influences not only gas adsorption capacity, but also gas diffusion capability during natural gas production and/or carbon sequestration in shale gas reservoirs. The literature shows that anisotropic fluid transport has usually been found in shales. The permeability of both gas and liquid along the shale bedding direction is usually higher than that of the direction perpendicular to the bedding (Kwon et al., 2004; Ma et al., 2016; Pan et al., 2015; Wang et al., 2016b; Zhang and Scherer, 2012). And, permeability within the bedding plane has also been found to be anisotropic (Ma et al., 2016; Tan et al., 2017). Moreover, the sorption-induced strain has been found to be anisotropic in shale. Sorptioninduced strain from gas and liquid saturation is lower for the shale bedding direction than that of the direction perpendicular to the bedding (Chen et al., 2015; Liu et al., 2016; Lu et al., 2016; Wang et al., 2015; Yuan et al., 2014), which is opposite to permeability results. Based on our knowledge, limited studies have been devoted to characterizing the anisotropic fluid transport in shale pores within the nanometer scale. Fortunately, various techniques can be used to characterize shale pore structure, including invasive and noninvasive

Corresponding author. E-mail address: [email protected] (R. Zhang).

https://doi.org/10.1016/j.coal.2020.103384 Received 4 July 2019; Received in revised form 4 January 2020; Accepted 6 January 2020 Available online 07 January 2020 0166-5162/ © 2020 Elsevier B.V. All rights reserved.

International Journal of Coal Geology 219 (2020) 103384

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characterized using X-ray diffraction (XRD) and LECO carbon analyzer, respectively. Table 1 also shows the effective scattering length density (SLD) of the shale, which was estimated from the coherent SLD of each component and its weight percentage. The effective SLD of the tested Marcellus Shale will be used for pore property quantification in section 3.2 and SLD contrast estimation in section 3.3. The incoherent SLD will mainly contribute to the background of scattering intensity. We can find in Table 1 that muscovite, clinochlore, and TOC have much higher incoherent SLDs than other chemical components.

methods (Anovitz and Cole, 2015; Anovitz and Cole, 2019). Particularly, ultra−/small-angle neutron scattering (USANS/SANS), using elastic and coherent neutron scattering at ultra−/small scattering angles, can be used to noninvasively quantify total pores (Anovitz and Cole, 2015; Bahadur et al., 2014; Clarkson et al., 2012; King et al., 2015; Lee et al., 2014; Radlinski et al., 2004; Sun et al., 2017) or invasively quantify pore accessibility (Bahadur et al., 2018; Clarkson et al., 2013; Gu et al., 2016; He et al., 2012; Mastalerz et al., 2012; Melnichenko et al., 2012; Ruppert et al., 2013; Sakurovs et al., 2012), as well as gas adsorption effect (Eberle et al., 2016; Liu et al., 2019; Melnichenko et al., 2009; Radlinski et al., 2009a; Radlinski et al., 2009b; Stefanopoulos et al., 2017; Zhang et al., 2017). Recently, USANS/SANS has been used to investigate the anisotropic nature of shale nanopore structures (Gu et al., 2015; Gu and Mildner, 2018; Leu et al., 2016) and its effect by shale rock weathering (Jin et al., 2011), maturity (Anovitz et al., 2015), and solvent extraction (DiStefano et al., 2019) conditions. Therefore, the SANS technique is a great choice to extract anisotropic nanopore information in the shale matrix under fluid injection conditions. In this study, we focused on the characterization of anisotropic nanopore structure modification under methane and CO2 injections for Marcellus Shale samples through in situ SANS measurements. We found that both total pores and accessible pores of the Marcellus Shale exhibit anisotropic feature of structure and possibly anisotropic wettability. By increasing the pressure of methane and CO2, the shale porosity of the accessible pores decreases, which could potentially suppress gas transport capability at a high gas pressure. A higher porosity of the accessible pores along the bedding direction could give a higher degree of gas diffusion than that of the direction perpendicular to the bedding. The findings of this study will have a profound influence on long-term natural gas production and CO2 sequestration in shale gas reservoirs.

2.2. SANS experimental work In situ SANS measurements under gas injections were conducted using the General-Purpose SANS Diffractometer (GP-SANS) in the High Flux Isotope Reactor (HFIR) at the Oak Ridge National Laboratory (ORNL) (Wignall et al., 2012). Each prepared thin section specimen was placed in an aluminum sample cell. The aluminum sample cell was put into a “dome”-type high-pressure vessel for gas injection as schematically shown in Fig. 1 (Bahadur et al., 2015a). The neutron wavelength was chosen as 4.72 Å to minimize the effect of multiple scattering. Two sample-to-detector distances were chosen as 12 and 0.26 m to cover a scattering vector Q range between 3.5 × 10−3 and 1 Å−1. Each obtained 2D scattering profile was radially averaged to a 1D scattering curve and merged for each condition using the Igor macros package (Kline, 2006). Two sorptive gases, including CD4 and CO2, were used for the in situ SANS measurements of Marcellus Shale samples. The gas injection procedure is similar to the in situ SANS measurement in one of our previous studies using powder samples (Liu et al., 2019). For each thin section shale, the scattering intensity I(Q) was initially measured under vacuum condition. Then, CD4 was injected through an incremental pressure step procedure at 20, 47, 80, and 200 bar. After the CD4 evacuation, CO2 was sequentially injected at 21, 41, 69, and 90 bar. The I(Q) in vacuum was remeasured after CO2 evacuation at the closure of the measurement. The reference 2D scattering profiles under vacuum condition for each sample-to-detector distance of two thin sections cut parallel and perpendicular to the bedding are shown in Fig. 2. The 2D scattering profiles from sample-to-detector of 12 m are clearly shown to be isotropic and anisotropic for thin sections cut parallel and perpendicular to the bedding, respectively. These 2D scattering images from shale samples been cut in different orientations are consistent with previous studies using SANS (Anovitz et al., 2015; DiStefano et al., 2019; Gu et al., 2015; Gu and Mildner, 2018; Hall et al., 1983, 1986; Hjelm et al., 2018; Jin et al., 2011) or SAXS (Leu et al., 2016). As the incident neutron beam was put perpendicular to the thin section samples during the measurement, the 2D scattering profile for the sample cut parallel to the bedding presents the projection of scattering in the x-y plane containing the short axis of the ellipsoid and the 2D scattering profile for the sample cut perpendicular to the bedding presents the projection of scattering in the x-z or y-z plane containing both the short and long axes of the ellipsoid, as schematically shown in Fig. 3. As the directions of reciprocal space (scattering information) and real space (pore information) are orthogonal with each other, the 3D ellipsoidal scattering profile indicates that nanopores tend to be oriented or distributed along the bedding plane from a statistical perspective. In this study, we were able to obtain the pore information along the direction normal to the bedding from the circular averaged 1D scattering intensity of the thin section sample cut parallel to the bedding. Note that, anisotropic 2D scattering intensity from the thin section cut perpendicular to the bedding contains pore information of both the vertical and horizontal directions to the bedding (Gu and Mildner, 2018; Hall et al., 1986). Sector-average in 2D elliptical scattering intensity should be processed along the long and short axes of the ellipse to obtain two separate 1D scattering profiles accounting for the anisotropy. However, the beam center was put near the detector edge to reduce the number of the sample-to-detector distance using and measuring time (Fig. 2). And

2. Experimental methods 2.1. Sample preparation and characterization Marcellus Shale fresh core was collected from a drilled well of the Marcellus pay zone in northeast Pennsylvania. And, the core was drilled in the gas window without reported liquids. After it was drilled, the core was wrapped with plastic wraps by the driller for weathering prevention. The fresh core was first cut into two pieces parallel to beddings and then thin sections were prepared from one half and the powder was prepared from the other half. Thin section shale specimens were prepared for SANS measurement. Specimens cut both perpendicular and parallel to the bedding were prepared, with an average thickness of ~0.67 mm, where a small sample thickness will minimize the effect of multiple scattering. Table 1 shows the mineral compositions and total organic carbon (TOC) content of the shale, which were Table 1 Chemical compositions and the estimated SLD of the measured Marcellus Shale.a Chemical composition

Weight percentage (wt %)

Quartz 27.81 Muscovite 31.24 Albite 17.53 Clinochlore 12.24 Dolomite 5.19 Pyrite 3.04 Calcite 0.88 TOC 2.06 10 Effective SLD (×10 cm−2)

Coherent SLD (×1010 cm−2)

Incoherent SLD (×1010 cm−2)

4.14 3.84 3.97 3.31 5.40 3.81 4.69 2.57 3.94

0.08 6.08 0.78 11.23 0.30 0.79 0.23 16.33

a SLD of each component was estimated by its chemical formula and density through a website-based SLD calculator (https://sld-calculator.appspot.com/).

2

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Fig. 1. The “dome”-type high-pressure cell (Bahadur et al., 2015a). (1) cell body, (2) “dome”-like sapphire spacer, (3) sealing nut, (4) aluminum sample holder, (5) pressure adapters, (6) titanium sealing insert, (7) brass plate, (8) wire retainer, and (9) spring energized c-ring seal.

Fig. 2. Reference 2D scattering profiles of two thin sections of Marcellus Shale under vacuum condition: At sample-to-detector distance of 0.26 m for thin sections cut (a) parallel and (b) perpendicular to the bedding; At sample-to-detector distance of 12 m for thin sections cut (c) parallel and (d) perpendicular to the bedding. 3

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region, which is usually flat and Q independent, or by the slope of I(Q) Q4 versus Q4 (King et al., 2015), although the information of the microporosity could be difficult to differentiate from the background intensity (Bahadur et al., 2015b). In this study, the flat background was estimated by the fitting of the experimental data at the Q ranging between 0.5 and 0.7 Å−1 for each sample. I(Q) of the thin section cut perpendicular to the bedding is apparently higher than that of the thin section cut parallel to the bedding, indicating an apparent anisotropic pore structure of the tested Marcellus Shale. The anisotropic feature of shale from different directions is similar to the results of previous studies (Anovitz et al., 2015; DiStefano et al., 2019; Gu et al., 2015; Gu and Mildner, 2018; Hall et al., 1983, 1986; Hjelm et al., 2018; Jin et al., 2011; Leu et al., 2016). Consistently, the I(Q) ratio between the thin sections cut parallel and perpendicular to the bedding is less than unity over the entire Q range, as illustrated in the blue dotted line in Fig. 4. It suggests that the total pore volume at the direction perpendicular to the bedding is smaller than that for the bedding direction, where nanopores tend to be oriented or distributed along the bedding plane. Particularly, the I(Q) ratio is approximately constant at the relatively low Q region (Q < ~0.013 Å−1). When Q is higher than 0.01 Å−1, the I(Q) ratio first decreases and then increases with increasing Q, regardless of the possible error generation during the background subtraction of I(Q) at the high Q region. The result indicates that the degree of anisotropy seems to reach the highest at the Q around 0.06 Å−1, corresponding to the pore diameter around 105 Å using the correlation of d = 2π/Q for the measured Marcellus Shale. In order to characterize the structural alteration of the accessible pores for gas injections, the experimental scattering data under vacuum condition and at relatively lower gas pressures were subtracted by scattering intensity at the highest tested pressure (200 bar for CD4 injection and 90 bar for CO2 injection) for each thin section of Marcellus Shale. The reason we performed this subtraction was that scattering intensity at each condition contains information of accessible pores, inaccessible pores, and matrix heterogeneity as schematically shown in Fig. 5. Only scattering intensity contributed from accessible pores was mainly affected by gas injection due to considerable change of SLD contrast between injected gas and surrounding shale solid matrix at different pressure conditions (Eberle et al., 2016; Liu et al., 2019; Mastalerz et al., 2012; Ruppert et al., 2013; Zhang et al., 2017; Zhang et al., 2015). A note of caution – we expected small errors to result after the subtraction because we expected scattering intensity at the highest pressure to be slightly higher than that at the contrast-matched condition. Thus, the absolute values of pore volume distribution, porosity, and surface area for the accessible pores may be slightly underestimated in this study. Figs. 6 and 7 show the scattering intensity profiles subtracted by scattering intensity at the highest pressure for each gas of each sample. For the thin section cut parallel to the bedding, the I(Q)s have trivial changes at pressure < 47 bar, and the I(Q) obviously decreased when pressure is 80 bar under methane injection (Fig. 6a). Small changes of the I(Q)s under CO2 injection were observed when pressure was smaller than 41 bar, and a significant decrease of the I(Q) at the condition of liquid CO2 at 69 bar was also captured (Fig. 6b). The I(Q) of the thin section cut perpendicular to the bedding, however, continuously decreased with increasing methane pressure (Fig. 7a). The changes of the I(Q)s under CO2 injection of the thin section cut perpendicular to the bedding (Fig. 7b) were quite similar to that of the thin section cut parallel to the bedding.

Fig. 3. Schematic of spatial correlation between 3D ellipsoidal scattering profile and sample cutting direction for the tested Marcellus Shale (Modified from Gu and Mildner, 2018).

also, the sample was put in an arbitrary direction in the plane perpendicular to the incident beam. It may be impossible to reduce 2D data through the sector-average to obtain the 1D data. Thus, the pore information along the bedding direction could only be partially obtained from the circular averaged 1D scattering intensity for the thin section sample cut perpendicular to the bedding. The obtained 1D scattering intensity was therefore expected to be smaller than that of the sector averaged 1D scattering intensity along the long axis (bedding direction), but to be higher than that of the sector averaged 1D scattering intensity along the short axis (direction normal to the bedding) (Gu and Mildner, 2018). The results of pore properties along the bedding direction were therefore expected to be underestimated in this study. 3. Results and discussion 3.1. Experimental scattering data Fig. 4 shows the background-subtracted I(Q) of two thin sections cut parallel and perpendicular to the bedding of Marcellus Shale. The background was estimated by the asymptotic intensity at the high Q

3.2. Anisotropic property of shale matrix pore structure Compared to conventional fluid invasion methods, using the smallangle scattering method can extract quantitative information of total rock pores, including both accessible and inaccessible pores (Anovitz and Cole, 2015). Fortunately, there are well-established scattering model and data analysis software package for small-angle scattering data analysis to determine structure properties. Shale pore structure

Fig. 4. Background-subtracted 1D scattering profiles of two thin sections cut parallel and perpendicular to the bedding of Marcellus Shale under vacuum condition (Abbreviations: para = sample cut parallel to the bedding, perp = sample cut perpendicular to the bedding). 4

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Fig. 5. Schematics of fluid injection in the accessible pores of the rock matrix. (above) Three phases including 1) solid matrix, 2) inaccessible pores, and 3) accessible pores with pressurized or adsorbed fluid, coexist with increasing fluid pressure. (below) Only single-phase, 1) accessible pores with pressurized or adsorbed fluid exist with increasing fluid pressure after the subtraction of scattering intensity of the highest tested pressure or contrast-matched pressure.

sphere for model fitting for the shale sample cut parallel to the bedding. The reason is that the 2D scattering profile is isotropic on the projection of x-y plane from the view of the z-axis (Fig. 3), which suggests randomdistributed and random-shaped nanopores in the shale matrix in that view. The assumption of spherical pore shape is reasonable and straightforward to account for the apparent and average structure of nanopores in that direction, which is equivalent to the direction normal to the bedding. However, the assumption of pore shape is spheroid with an aspect ratio of 1.3 for model fitting for shale sample cut perpendicular to the bedding. We used the spheroid pore assumption because of anisotropic 2D scattering profile on the projection of the x-z or y-z plane from the view of the y-axis or x-axis (Fig. 3). Nanopores have either elongated pore shape or oriented pore population or both showing in the direction parallel to the bedding. As the limitation of the data reduction procedure mentioned in the previous section, the assumption of spheroid pore shape may be reliable to account for the apparent and average structure of nanopores in the directions parallel and

properties, including pore number and/or volume distributions, surface area, porosity, fractal dimension, and pore accessibility, can be successfully quantified based on reasonable assumptions. In this study, the pore volume distributions (PVDs) of the total pores of two thin sections were obtained by model fitting of the I(Q) using the maximum entropy (MaxEnt) method in the IRENA package with no specific distribution function (Ilavsky and Jemian, 2009). Here, the background-subtracted I (Q) can be expressed as:

I (Q) = N (ρs∗ − ρp∗ )2

∫ V 2 (r ) f (r ) P (Q, r ) dr

(1)

where N is pore number density; ρs∗ and ρp∗ are SLDs of the matrix (approximate 3.94 × 1010 cm−2 for the tested Marcellus Shale) and the pore (expect zero under vacuum and assume SLD of bulk gas at different pressure conditions); V(r) is pore volume; f(r) is size distribution; r is pore radius; and P(Q, r) is form factor. Note that the shale matrix is heterogeneous and complex, and thus nanopores in the matrix should have different shapes. In this study, the assumption of pore shape is the

Fig. 6. 1D scattering profiles of the thin section cut parallel to the bedding under (a) CD4 and (b) CO2 injections. (scattering intensities were subtracted by the scattering intensity of 200 bar for CD4 data; scattering intensities were subtracted by the scattering intensity of 90 bar for CO2 data). 5

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Fig. 7. 1D scattering profiles of the thin section cut perpendicular to the bedding under (a) CD4 and (b) CO2 injections. (scattering intensities were subtracted by the scattering intensity of 200 bar for CD4 data; scattering intensities were subtracted by the scattering intensity of 90 bar for CO2 data).

which were 2.5 and 1000 Å for this current study. Here, we determined the cumulative porosity by adding the binned porosity from small pores to large pores as an incremental addition. Cumulative surface area was determined by adding the binned surface area, in reverse, from large pores to small pores, since the surface area is different from different length scales of probing fluid molecules based on invasive penetrating methods (Thommes et al., 2015). Fig. 9 shows the estimated results of apparent cumulative porosity and surface area of the two thin sections cut parallel and perpendicular to the bedding. It was found that the difference of cumulative porosities between the two thin sections is small when pore diameter is within 10 Å and both porosities are < 1%. Cumulative porosities significantly increased and the porosity difference became significantly higher when pore diameter increased from 10 to 30 Å, which is in the first peak region (Fig. 8). The porosities continuously increased with increasing pore size when pore diameter was higher than 30 Å. The results indicate that the total porosities are mainly contributed from pores with a diameter larger than 10 Å for both the thin section samples. The final difference between the cumulative porosities is about 3%. The apparent total porosities were estimated to be 3.5 and 6.9% for the thin sections cut parallel and perpendicular to the shale bedding, respectively. In other words, the total porosity of direction normal to the bedding is 3.5% and of the bedding direction is higher than 6.9% for the measured Marcellus Shale. A higher total porosity along bedding direction

Fig. 8. PVDs of total pores of thin sections cut parallel and perpendicular to the bedding of Marcellus Shale.

perpendicular to the bedding. The upper and lower limits of pore diameter d were set as 5 and 2000 Å, respectively, during the fitting, where the relationship between d and Q is d = 2π/Q. As shown in Fig. 8, the apparent PVD of the two thin sections shows a bi-modal shape with the first and second peaks at pore diameters 10–20 and 40–50 Å, respectively. The volume distribution of the thin section cut perpendicular to bedding is higher than that cut parallel to bedding over the measured pore range, indicating the pore properties are greater along the shale bedding direction than that of normal direction to the bedding. The results of this study are consistent with the results of previous studies using the shale samples obtained from Eagle Ford Shale Formation (Anovitz et al., 2015) and Marcellus Shale Formation (Gu et al., 2015). Furthermore, we calculated the apparent cumulative porosity and surface area of the two thin section shale samples based on obtained PVD results. The cumulative porosity and surface area at a particular pore size can be estimated by:

∅i = N

Si = N

∫r

∫i

i

f (r ) V (r ) dr

min

rmax

f (r ) A (r ) dr

(2) (3)

Fig. 9. Cumulative porosity and surface area of the total pores of the two thin sections cut parallel and perpendicular to the bedding of Marcellus Shale (Note: left axis for solid lines and right axis for dotted lines).

where ∅ is porosity; S is surface area; i is the data point at a certain pore size r; rmin and rmax are the lower and upper limits of pore radius 6

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suggests that the fluid transport capacity could be relatively high along the bedding direction. This direction-dependent nanoscale fluid transport capacity is consistent with the macroscopic findings, e.g., permeability, where a higher permeability was usually observed along the bedding direction using shale core samples (Kwon et al., 2004; Ma et al., 2016; Pan et al., 2015; Wang et al., 2016b; Zhang and Scherer, 2012). It was found that the cumulative surface areas generally increase with decreasing pore size. For large pores at a wide range (diameter > 100 Å), the cumulative surface areas of both samples are minimal. When the pore size is < 30 Å, the cumulative surface areas dramatically increase as pore diameter decrease until ~7 Å for the both tested samples. The results demonstrate that the surface area is primarily from the pores with a size smaller than 30 Å for the shale samples. And the difference of apparent surface areas between the thin section samples mainly locates in the first peak region (Fig. 8). If we assume the probing length scale of 5 Å and use the measured shale density through helium injection of about 2.1 g/cm3, the apparent total surface areas are 42.8 m2/g and 88.8 m2/g for the thin sections cut parallel and perpendicular to the shale bedding, respectively. In other words, the total surface area along bedding direction is more than twice the value of the surface area along the direction perpendicular to the bedding plane.

injection are shown in Fig. 10. Although we used 5 Å as the lower limit during the model fitting, the captured low pore limit was about 100 and 70 Å for the thin sections cut parallel and perpendicular to the shale bedding, respectively. From Fig. 10, for both the thin sections, it was found the PVD of the accessible pores has a decreasing trend as pore size increases in the pore range from ~200 to ~2000 Å. For the shale sample cut parallel to the bedding, there were variations of PVDs as a function of CD4 pressure, as shown in Fig. 10a. Based on the model fitting results, no apparent pore volume changes were found for pressures of 20 and 47 bar methane injections. The volume fractions at the pressures of 20 and 47 bar are even slightly higher than that under vacuum at the pore size near 200 Å. However, an obvious pore volume decrease was captured with 80 bar methane injection as illustrated as the green curve in Fig. 10a. The apparent cumulative porosities for 20 and 47 bar methane injection are quite similar to the vacuum condition, while an apparent lower porosity profile for the 80 bar of CD4 environment was estimated, as illustrated in Fig. 11a. Consistently, the apparent cumulative surface areas within the pressure of 47 bar are similar when the pore size is greater than ~300 Å. The cumulative surface area (estimated based on the detected pore size of 100 Å or probing length scale of 100 Å) at 47 bar seems slightly higher than those under vacuum and 20 bar conditions. Similar to the porosity results, the cumulative surface area at 80 bar is smaller than those of other pressure conditions. From Fig. 10b, there were also variations of apparent PVDs as a function of CD4 pressure for the shale sample cut perpendicular to the bedding. However, there were decreases in both apparent cumulative porosity and surface area with increasing CD4 pressure for the sample (Fig. 11b). The decreasing trends are approximately linear (dark red dots and lines in Fig. 14). Comparing the two shale samples, it was found that volume distribution, cumulative porosity, and cumulative surface area of the accessible pores of the thin section cut perpendicular to the bedding were reasonably higher than those cut parallel to the bedding (Figs. 10, 11, 14), which is consistent with the results of the total pores for the two shale samples (Figs. 8, 9). From these estimated results, the decreases of accessible porosities with increasing methane pressure for both the thin section samples will hurt methane transport in shale nanopores. However, a higher accessible porosity in the bedding direction indicates that a higher capability of methane transport should be found along the shale bedding direction as well, regardless of the changes of accessible porosity with the change of gas pressure. We want to point out that all these measurements are under hydrostatic conditions with an absence of external stresses. For in situ subsurface conditions, effective and deviatoric stress should be coupled with the hydrostatic pore pressure to determine overall gas transport properties in shale gas reservoirs. Further investigation should be conducted under in situ stress and pore pressure conditions to reveal the impact of alteration of pore properties on gas transport. For apparent surface area results, the probing length scale is 100 and 70 Å for the thin sections cut parallel and perpendicular to the bedding due to the limitation of SANS measurement described in the previous section. Using the measured shale density of 2.1 g/cm3 the apparent cumulative surface area of the accessible pores was approximately 0.3 and 0.7 m2/g for the thin sections cut parallel and perpendicular to the shale bedding, respectively. These values are < 1% for those of the total pores with a probing length scale of 5 Å. The results suggest that, although similar trends as a function of gas pressure were found for surface areas comparing to porosities (Figs. 11, 12), the tiny changes of surface area in the meso−/macropore ranges due to the pressure changes of methane may have a minimal impact on methane adsorption capability in these pore size ranges.

3.3. Alteration of the accessible pore structure by gas injections Methane and CO2 were injected into the shale samples under in situ measurements to extract the dynamic structure alteration of the accessible pores as a function of gas. In one of our previous studies (Liu et al., 2019), we characterized the structure evolution of the accessible pores for the Marcellus Shale powder sample, which only gives the average information of the pore structure changes under gas injection conditions. In this study, thin section shale samples were used to analyze the anisotropic pore structure change under different gas injections. 3.3.1. Methane injection The PVDs of the accessible pores under methane injection were obtained by model fitting of the I(Q)s subtracted by the I(Q) under 200 bars of CD4 using Eq. 1 for the measured specimens. The SLD contrast used for the model fitting at each pressure condition is listed in Table 2. In this study, we used the bulk density of CD4 for the SLD estimation at each pressure condition. Thus, the changes of the PVD under different pressure conditions were mainly affected by the combined effects of pressurization, sorption-induced swelling or shrinkage, and pore-filling of gas molecules (Liu et al., 2019). Since all the I(Q)s were subtracted by the I(Q) at 200 bar of CD4 environment rather than the I(Q) under the contrast-matched condition (CD4 pressure was higher than 200 bar in this condition), the changes of the PVDs were limited within the pressure range between 0 and 200 bar. Due to a relatively higher I(Q) without subtracting background at a higher CD4 pressure in the high Q region, after the intensity subtraction, only a limited pore size range is “visible” and can be quantitatively characterized to extract pore structure properties. The reason could be the introduced scattering background or the scattering signal of gas densification confined in the fine nanopores under high-pressure gas injection (Bahadur et al., 2016; He et al., 2012; Zhang et al., 2015). The estimated apparent PVDs of the two thin sections under CD4 Table 2 SLD contrasts at different pressures under CD4 injection. Temperature (K)

Pressure (bar)

SLD of bulk CD4 (×1010 cm−2)

SLD contrast (×1010 cm−2)

293.15 293.15 293.15

20 47 80

0.17 0.42 0.76

3.77 3.52 3.18

3.3.2. CO2 injection The PVDs of the accessible pores under CO2 injection were also obtained by model fitting of the I(Q)s subtracted by the I(Q) under the highest tested pressure (90 bar of CO2) for the measured samples. The 7

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Fig. 10. PVDs of the accessible pores of two thin sections at different pressures under CD4 injection: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding.

Fig. 11. Cumulative porosity and surface area of the accessible pores of the two thin sections under CD4 injection: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding (Note: left axis for solid lines and right axis for dotted lines).

SLD of bulk CO2 at each pressure condition was used for model fitting and the SLD contrasts are shown in Table 3. For the shale sample cut parallel to the bedding (Fig. 13a), the apparent volume distributions have variations when CO2 pressure is smaller than 41 bar, and the differences may be small when the pore size is greater than ~1000 Å. The volume fraction at 41 bar is obviously smaller than those under lower pressures at the pore size within 200 Å. It was found that the volume distribution profile nearly disappeared at the condition of

Table 3 SLD contrasts at different pressures under CO2 injection. Temperature (K)

Pressure (bar)

SLD of bulk CO2 (×1010 cm−2)

SLD contrast (×1010 cm−2)

293.15 293.15 293.15

21 41 69

0.11 0.25 2.01

3.83 3.69 1.93

Fig. 12. (a) Surface area and (b) porosity of the accessible pores as a function of gas pressure under CD4 injection. 8

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Fig. 13. PVDs of the accessible pores of the two thin sections under CO2 injection: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding.

Fig. 14. Cumulative porosity and surface area of the accessible pores of two thin sections under CO2 injection: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding (Note: left axis for solid lines and right axis for dotted lines).

the pore size of ~600 Å (Fig. 13b). When the pore size was greater than ~600 Å, the volume fraction was somewhat unchanged above the pressure of 21 bar. It was found that the change of PVD at the liquid phase of CO2 (69 bar) was entirely different between the two shale samples cut in different directions. Only a portion of pore volume (diameter < ~600 Å) was filled with liquid CO2 for the thin section cut perpendicular to the bedding (Fig. 13b) compared to full pore-filling liquid CO2 in the sample cut parallel to the bedding (Fig. 13a). The results indicate a lower degree of wettability of liquid CO2 along the bedding direction, especially at a larger pore size (> 600 Å). From Fig. 14b, the apparent cumulative porosity and surface area decrease with increasing pressure which agrees with the apparent PVD results for the thin section cut perpendicular to the bedding. When CO2 pressure was < 41 bar, the rates of decrease in pore properties were quite similar between the thin section samples (Fig. 15). However, there were remaining amounts of the cumulative porosity and surface area at the condition of 69 bar for the sample cut perpendicular to the bedding (the green lines in Fig. 14b). At the condition of liquid CO2, cumulative porosity was mainly from the pores with a size > 300 Å for this sample (Fig. 14b). The result suggest that capillary condensation may only occur within pore diameters around 200 Å for the sample cut perpendicular to the bedding. We also found that the gas injection-induced decreasing rates of apparent porosity and surface area were greater for CO2 injection than methane injection for this sample (the blue dots and lines in Figs. 12 and 15), which is similar to the results of the sample cut parallel to the shale bedding. It indicates a higher impact resulted from combined effects of sorption-induced matrix swelling and sorptive gas occupation in nanopores for CO2 injection compared to methane injection along the bedding direction as well. This also implies a higher

69 bar (the green line in Fig. 13a), in which CO2 is in the liquid phase at room temperature condition. The results suggest small changes of PVD under the gaseous phase of CO2, which are similar to the results of PVD under CD4 injection. As soon as the CO2 reaches liquid phase, however, most of the accessible pores are filled with CO2 at 69 bar for the sample cut parallel to the bedding of Marcellus Shale. The results of the apparent cumulative porosity and surface area are consistent with the results of the apparent PVDs. As shown in Fig. 14a, both cumulative porosity and surface area gradually decrease with CO2 injection till 41 bar and become almost zero at the pressure of 69 bar. The significant decreases of volume distribution, cumulative porosity, and cumulative surface area imply that accessible pores with a diameter larger than 100 Å are completely filled with liquid CO2 along the direction perpendicular to the shale bedding, where capillary condensation could occur in the nanopores over the detected pore size range. It was also found that the changes of apparent porosity and surface area within 50 bar are bigger for CO2 injection than methane injection for the sample cut parallel to the bedding (the red dots and lines in Figs. 12 and 15). Compared to methane injection, these results suggest a higher degree of the combined effects of sorption-induced matrix swelling (pore shrinkage) and pore-filling of gas molecules during CO2 injection over the detectable pore size range along the direction normal to the bedding. This should be caused by a higher adsorption capacity of CO2 than methane in shale nanopores. However, since the surface area of the accessible pores is < 1 m2/g in the meso−/macropore ranges, the difference of adsorption capacity between CO2 and methane may be trivial. For the shale sample cut perpendicular to the bedding, apparent volume distribution decreased with increasing pressure of CO2 within 9

International Journal of Coal Geology 219 (2020) 103384

S. Liu and R. Zhang

Fig. 15. (a) Surface area and (b) porosity of the accessible pores as a function of gas pressure under CO2 injection.

volume fraction after gas injections is lower than that for the initial condition within the pore sizes of ~30 and ~50 Å for the samples cut parallel and perpendicular to the bedding, respectively (Fig. 16). The results suggest possible permanent damage to nanopores during gas injections for both shale samples. The apparent cumulative porosity decreased from 3.5% to 2.8% for the thin section cut parallel to the bedding, from 6.9% to 5.4% for the thin section cut perpendicular to the bedding (Fig. 17). The irreversible changes of pore properties are mainly within the first peak of the PVD for the sample cut parallel to the bedding (Fig. 16a) and within the first and second peaks of the PVD for the sample cut perpendicular to the bedding (Fig. 16b), which are within the meso−/micropore size ranges. Therefore, the shale bedding direction could have a higher degree of nanopore damage than the direction normal to the bedding during methane and CO2 injections for the measured Marcellus Shale. The results are expected because the bedding direction has more pores than the perpendicular direction.

adsorption capacity of CO2 than methane along the bedding direction. However, the differences of adsorption capacity between CO2 and methane as well as under different pressure conditions may be small due to the limited surface area in the meso−/macropore size ranges. Regarding a higher accessible porosity at each pressure of CO2 for the thin section cut perpendicular to the bedding, compared to that cut parallel to the bedding (Fig. 15), shale bedding direction has a higher degree of gas transportation during CO2 sequestration, which is consistent with methane injection discussed in the previous section. By comparing methane and CO2 injections, the capability of CO2 transport in nanoscale shale pores is more difficult than for methane in both directions, as implied by the results of the measured Marcellus Shale.

3.4. Pore structure damage due to gas injections Gas injection is a process of hydrostatic compression of the shale matrix, and gas depletion is a process of depressurization of the shale matrix. This pressure loop can potentially change the shale matrix structure, including damaging the pore structure because of residual stress. To investigate whether the pore has permanent damage or not, we compared apparent PVDs and cumulative porosity and surface area before and after methane and CO2 injections for the two thin section samples (Figs. 16, 17). From the inserted figures in Fig. 16a and b, the volume distributions show almost no change before and after gas injections when the pore size is higher than ~100 Å. However, the

4. Conclusions In this study, two Marcellus Shale thin section samples, cut parallel and perpendicular to the bedding, were measured for characterization of shale matrix anisotropic pore structure with methane and CO2 injections using in situ SANS measurements. We found that the porosity and surface area of the total pores along the bedding direction were higher than those normal to the bedding over the detected pore size

Fig. 16. PVDs of the total pores of the two thin sections before and after gas injections: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding. 10

International Journal of Coal Geology 219 (2020) 103384

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Fig. 17. Cumulative porosity and surface area of the total pores of the two thin sections before and after gas injections: (a) sample cut parallel to the bedding; (b) sample cut perpendicular to the bedding (Note: left axis for solid lines and right axis for dotted lines).

range between 5 and 2000 Å. This can be inferred from the anisotropic feature of the measured Marcellus Shale in nanoscale. Under the conditions of methane and CO2 injections, the porosity and surface area of accessible pores generally decreased with increasing gas pressure for the two directions. These results suggest that, in nanoscale, methane transport will be more efficient at lower pressure if we only consider pore properties and don't consider external stress conditions. The degree of microscopic inhibition of CO2 transport (incremental pressure during CO2 sequestration) is higher than that of microscopic acceleration of methane transport (decremental pressure during methane production), due to higher combined effects of sorption-induced matrix swelling and gas occupation in shale nanopores for CO2. A higher porosity of the accessible pores along the bedding direction indicates a higher capability of gas transport (both methane and CO2) along the bedding direction compared to the direction normal to the bedding regardless of the tortuosity of nanopores and external stresses. Under the condition of liquid CO2, capillary condensation could occur within the overall detected pore size range 100–2000 Å along the direction perpendicular to the bedding while within a portion of pore sizes around ~200 Å along the bedding direction, indicating possible anisotropic wettability nature of the measured Marcellus Shale in nanoscale. In addition, the bedding direction could cause greater irreversible damage of nanopores than the direction perpendicular to the bedding after methane and CO2 injections for the measured shale samples.

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