Probing nanopore structure and confined fluid behavior in shale matrix: A review on small-angle neutron scattering studies

Journal Pre-proof Probing nanopore structure and confined fluid behavior in shale matrix: A review on small-angle neutron scattering studies

Hongwu Xu PII:

S0166-5162(18)31101-7

DOI:

https://doi.org/10.1016/j.coal.2019.103325

Reference:

COGEL 103325

To appear in:

International Journal of Coal Geology

Received date:

6 December 2018

Revised date:

24 October 2019

Accepted date:

29 October 2019

Please cite this article as: H. Xu, Probing nanopore structure and confined fluid behavior in shale matrix: A review on small-angle neutron scattering studies, International Journal of Coal Geology(2019), https://doi.org/10.1016/j.coal.2019.103325

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© 2019 Published by Elsevier.

Journal Pre-proof International Journal of Coal Geology manuscript #COGEL_2018_991

Probing Nanopore Structure and Confined Fluid Behavior in Shale Matrix: A Review on Small-Angle Neutron Scattering Studies Hongwu Xu Los Alamos National Laboratory, Earth and Environmental Sciences Division, Los Alamos, NM

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Abstract

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87545, USA

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Although continued growth in unconventional oil and gas production is generally

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projected, its long-term growth potential and sustainability have significant uncertainties. A

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critical problem is the low hydrocarbon recovery rates from shale and other tight formations using the horizontal well drilling and hydraulic fracturing techniques: < 10% for tight oil and 

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20% for shale gas. Moreover, the production rate for a given well typically declines rapidly within one year. The low recoveries and declining production of shale oil and gas reservoirs are

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apparently related to the small porosity (a few to a few hundred nm) and low permeability (10 -16 -

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10-20 m2 ) of shale matrix, which make the enclosed hydrocarbon fluids difficult to access. Hence, to enhance the hydrocarbon recovery from shale matrix, it is essential to study its nanopore structure and confined fluid behavior. Small- and ultra-small-angle neutron scattering (SANS and USANS) have emerged as a powerful method for characterizing shale nanopore structure and confined fluid behavior. Owing to neutrons' high penetrating ability and high sensitivity to hydrogen (and its isotope, deuterium), SANS/USANS can probe inside shale samples to characterize nanopores from 1 nm to 10 m in size and be readily combined with sample environmental cells to examine the fluid (hydrocarbon

Journal Pre-proof and water – frack fluid) behavior at relevant pressure-temperature (P-T) conditions. In this review article, an introduction is first given on the characteristics of shale matrix and the uniqueness of SANS/USANS compared with conventional methods. Then current studies on shale nanopore structure and confined fluid properties using SANS/USANS are summarized. Finally, an outlook and perspective on future research in this emerging area will be offered.

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Introduction

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Key Words: Shale, nanopore, fluid, small-angle neutron scattering

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During the past decade, production of oil and gas in the world, particularly U.S., has

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increased exponentially, mainly due to the rapid growth in production from unconventional

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reservoirs. According to the U.S. Energy Information Administration (EIA) (https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf), tight oil production in the U.S. has

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accelerated from less than one million barrels per day to more than five million barrels per day in

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2018. Similarly, shale gas production has also increased dramatically during this period (https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf). These increases are largely realized

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through implementation of unconventional production techniques, i.e. horizontal drilling and hydraulic fracturing. Despite the oil and gas price fluctuations in recent years, it is projected that unconventional oil and gas resources will continue to serve as a major component in the U.S. energy portfolio and will eventually help U.S. become a net energy exporter in the foreseeable future. Even though continued oil and gas production from unconventional reservoirs is projected, its long-term growth potential and sustainability have significant uncertainties (CuetoFelgueroso and Juanes, 2013; Cooper et al., 2016). This is due to complexities in key aspects of 2

Journal Pre-proof unconventional production, such as well production decline, well lifespan, drainage area, geologic setting, and environmental issues. It is estimated that > 90% of the original oil in place (OOIP) and  80% of the original gas in place (OGIP) will be left behind after the primary recovery from an unconventional reservoir (Chaudhary and Ehlig-Economides, 2011; Dong et al., 2013). The low production rates and low estimated ultimate recovery (EUR) are daunting problems for efficient energy production from unconventional oil and gas reservoirs.

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Due to its compositional heterogeneity, pore structure complexity, and tight and fine-

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grained nature, shale (and other tight rocks) presents significant challenges to petrophysical

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characterization and analysis (Arthur and Cole, 2014; Sun et al., 2017). In particular, pores at the

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nanoscales occur extensively in shale, and they are the host for hydrocarbon fluids (e.g. free and absorbed methane gas, which has a molecule diameter of 0.4 nm) (Barsotti et al., 2016,). It is

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suspected that nanopores in organic matter (OM) provide surface area for sorption and storage of

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hydrocarbons, thus contributing significantly to the hydrocarbon storage capacity and flow in shale formations (Milliken et al., 2013). However, it remains unclear how the nanopore structure

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controls oil and gas storage and how the extent and connectivity of nanopores (permeability)

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affect fluid flow and transport in shale matrix. To develop better reservoir management approaches that increase production per well and maximize its recovery (which will in turn lead to fewer number of wells), it is essential to achieve fundamental understanding of the nanopore structure of shale matrix and the underlying thermodynamic properties and transport processes of hydrocarbon fluids in shale nanopores. Such information is critical for estimating effective permeability of shale rocks, assessing potential for multiphase flow, and optimizing operational parameters such as well spacing, bottom hole pressures and pumping rate, to maximize hydrocarbon recovery.

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Journal Pre-proof Conventional techniques for characterizing nanopore structures include gas absorption and mercury intrusion (porosimetry/pycnometry) methods (Chalmers et al., 2012; Sinha et al., 2013; Rashid et al., 2015). While these methods can determine the size distribution, total volume and total surface area of nanopores, they are limited to measuring open pores (i.e. pores that are accessible by gas or mercury) only. Although transmission electron microscopy (TEM) can resolve features at nanoscales, it requires thin specimens that are transparent to electron beams,

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whose preparation involves destruction of bulk shale samples and frequently induces artifacts

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(Bernard et al., 2012; Chalmers et al., 2012). In addition, TEM cannot be readily combined with

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environmental cells containing fluid samples, particularly at high P-T conditions. This limitation

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also applies to the helium ion microscope (HIM), a relatively new technique that has been used to characterize the population of pores < ~10 nm in shale (Cavanaugh and Walls 2016). Other

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experimental techniques such as optical microscopic and X-ray/neutron microtomographic

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imaging lack necessary resolutions to infer structures and properties of nanopores and their confined fluids. As a result, most current knowledge of fluid behavior in shale nanopores has

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been obtained from computer simulations (Vlugt et al., 1999; Shapiro and Stenby, 2001; Xu et

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al., 2001; Düren et al., 2003; Fox and Bates, 2005; Teklu et al., 2014), with few experimental data available. In addition, most studies have only used simple fluids and/or simple pores. Although some models were developed to estimate fluid properties in relatively complex nanopores, including effects of pore proximity, they have not been verified by experimental data. Small- and ultra-small-angle neutron scattering (SANS and USANS) (Cole et al., 2006; Anovitz and Cole 2015) have emerged as a powerful tool for characterizing shale nanopore structure and confined fluid behavior (Clarkson et al., 2012; Mastalerz et al., 2012; Clarkson et al., 2013; Ruppert et al., 2013; Bahadur et al., 2014; Bahadur et al., 2015; Gu et al., 2015; Xu et

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Journal Pre-proof al., 2015; DiStefano et al., 2016; Eberle et al., 2016; Gu et al., 2016; Stefanopoulos et al., 2017; Sun et al., 2017; Bahadur et al., 2018; Liu et al., 2019; Vishal et al., 2019). Owing to neutrons' high penetrating ability and high sensitivity to hydrogen (and its isotopes especially deuterium), SANS/USANS can probe inside shale samples to characterize nanopores from 1 nm to 10 m in size and be readily combined with sample environmental cells to examine the fluid (hydrocarbon and water, the frack fluid) behavior at reservoir P-T conditions. In this review, an introduction is

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first given on the characteristics of shale matrix and the uniqueness of SANS/USANS compared

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with traditional methods. Next, current studies on shale nanopore structure and confined fluid

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properties using SANS/USANS are summarized. Lastly, an outlook and perspective on future

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research in this rapidly growing area will be offered.

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Shale Mineralogy and Nanopore Structure

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Shale, a fine-grained sedimentary rock, is comprised of flake-shaped grains of clay minerals (e.g. illite and smectite) and silt-sized grains of other minerals, including quartz,

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feldspar, calcite, dolomite and pyrite (Arthur and Cole, 2014). Figure 1 plots the mineral

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compositions of shale from various formations on the carbonate  quartz + feldspar  clay ternary diagram (Chermak and Schreiber, 2014). As is shown, shale mineral compositions are very diverse, ranging from mostly carbonates to mostly silica/silicates, with varying amounts of clay minerals. These variations can occur from basin scale to lithologies of a few centimeters (such as the light and dark layers of a Wolfcamp shale core, whose mineral compositions are plotted in Fig. 1), reflecting various lengths of sediment depositional periods or/and different sediment/organic matter sources during shale formation. In addition to inorganic minerals, an important component of shale is organic matter (OM), in the forms of kerogen, bitumen and

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Journal Pre-proof pyrobitumen/char (Arthur and Cole, 2014). The concentration of OM can be expressed as the percentage of total organic carbon (TOC) in the rock. It is generally believed that shales with TOC contents > 1 wt.% and preferably in the order of 2 wt.% or higher have enough storage capabilities of hydrocarbons and the potential for their extraction. Several studies show that there are some correlations between the content of TOC and those of inorganic minerals. Thus a quaternary diagram with the addition of TOC would be useful in linking the mineralogy with

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hydrocarbon storage capability for shale formations.

Figure 1. Mineral compositions of shales from various formations on the carbonate  quartz + feldspar  clay ternary diagram. Modified from Chermak and Schreiber (2014) with copyright permission from Elsevier. Plotted together are mineral compositions of a Marcellus sample and of the light and dark layers (which reflect different amounts of organic carbon) of a Wolfcamp sample, determined by quantitative powder X-ray diffraction (XRD). Powder XRD data were collected using a Siemens D-500 diffractometer (Cu K radiation, 45 keV, 40 mA; 2 range: 2-70°; step size: 0.02°; collection time per step: 12 seconds). Each powder sample was mixed with corundum powders, which acted as an internal standard, in a weight ratio of sample: corundum = 80 : 20. The contents of quartz, feldspar (alkali feldspar and plagioclase), carbonate (calcite) and clay (illite) were determined using the FULLPAT program (Chipera and Bish, 2002). 6

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Shale exhibits thin laminae or sheets along its bedding planes, which tend to control crack propagation and hydrocarbon flow from shale matrices in addition to mineralogy. At smaller scales, shale contains pores, associated with OM and various inorganic minerals (especially clay), that host the original hydrocarbon fluids and affect their flow behavior during hydraulic fracturing. Figure 2-left is a scanning electron microscopy (SEM) image of a large

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OM-rich pore (15-20 m) in the Marcellus Shale sample. In addition to OM, the pore contains

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pyrite, illite and unfilled spaces (smaller pores). Figure 2-right is a TEM image of organic carbon

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nanopores in the same sample. As is seen, various pores with sizes ranging from a few to tens of

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nanometers occur in the kerogen component of the shale. Since kerogen and hydrocarbon fluids are closely related in their biological origins, kerogen nanopores, which account for a large

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portion of the total porosity of a shale, are believed to be the major host for gas and oil (though

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the presence of oil is also associated with minerals, particularly clay). In particular, since the walls of these pores tend to adsorb hydrocarbon gas molecules, they likely host most of the gas

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formed during thermal maturation processes.

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Figure 2. Left: SEM image of a large OM-rich pore in the Marcellus shale sample; Right: TEM image of organic carbon nanopores in the same sample. The right figure is by courtesy of Huifang Xu.

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Small-Angle Neutron Scattering Neutron scattering is a versatile tool used in a number of disciplines including crystallography, physics, chemistry, biology and materials science. Unlike X-rays, which interact primarily with the electron cloud surrounding each atom in a material, neutrons interact directly with the nucleus of the atom. As a result, neutrons are more penetrating than X-rays, and can

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probe samples inside a sample environmental vessel (with varying pressure, temperature etc.)

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(Xu et al. 2007a, 2007b, 2010, 2013, 2015; Zhao et al. 2007, 2010), or/and measure deeply

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buried local structures within a bulk host material. Furthermore, since the scattering power of

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neutrons does not vary with the number of electrons in an element, neutron scattering is much more sensitive to the positions of hydrogen (or its isotopes particularly deuterium) and other light

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elements, making it well suited for studying hydrogen- and other light-element-containing phases

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(solid and fluid).

Of particular interest to shale research is small-angle neutron scattering (SANS) that can

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characterize shale nanopores and probe hydrocarbon fluids inside non-destructively. More

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specifically, by revealing the difference in scattering length density (SLD) between rock matrix and the pore space, SANS and USANS characterize pores with size ranges of 1–100 nm and 100 nm – 10 m, respectively (Cole et al., 2006; Anovitz and Cole, 2015). SANS is typically in the transmission, “pinhole” configuration in terms of neutron beam collimation and focusing optics (like pinhole cameras), while USANS is of Bonse-Hart type that collimates and analyzes the beam using multiple reflections from “prefect” silicon crystals (Radlinski, 2006). SANS/USANS measures the intensities of neutron beams scattered at angles very close to the direction of propagation of the incident beam (< 5°), i.e., I(Q), where the scattering vector Q = 4πsinθ/λ. For

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Journal Pre-proof geologically formed porous media (rocks), their SANS/USANS data can generally be treated by a two-phase (solid matrix / pore space) approximation with the polydisperse spheres model or Porod invariant method. A major application of SANS/USANS has been the determination of material fractal geometries (self-similarity) at small scales, which are ubiquitous in rocks, especially sedimentary rocks such as shale (Radlinski, 2006). Another important advantage of SANS/USANS is that it

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can measure not only open (connected) pores but also closed (isolated) pores that are

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inaccessible to fluids and cannot be measured by other techniques (which only measure the

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accessible pores that are greater in size than the probe molecules, e.g. N 2 in gas sorption

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analysis). This technique has been applied to study the accessibility of pores to gases (methane, carbon dioxide) and their diffusion in a variety of rock types including shale, coal and carbonate

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(Radlinski and Radlinska, 1999; Radlinski et al., 2004; He et al., 2012; Melnichenko et al., 2012;

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Bahadur et al., 2016). The fact that hydrogen (H) and deuterium (D) scatter neutrons with the

opposite signs of scattering amplitudes, provides a means of filling the open pores with mixtures

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of deuterated and protonated (D/H) hydrocarbons (e.g. CD4 and CH4 ) or water (i.e. D2 O and

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H2 O) to match the scattering of shale matrices, thereby only revealing the closed pores. This is particularly important for shale measurements, as a large portion of hydrocarbons may be stored in closed pores in shale. Since neutrons are highly penetrating, SANS/USANS can be readily combined with a sample environmental cell for in-situ measurements under external conditions (pressure, temperature, solution, gas etc.). Several fluid cells made of different materials (e.g. aluminum) have been used to combine with SANS/USANS to probe the interactions of hydrocarbon gases or water (the hydraulic fracturing fluid) with shale nanopores at various pressures. To

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Journal Pre-proof characterize the effect of uniaxial stress (i.e. overburden load on the subsurface rock) on fluid behavior in addition to hydrostatic pressure, Hjelm et al. have recently developed a flow-through compression cell for SANS/USANS experiments (Fig. 3) (Hjelm et al., 2018). Two sapphire windows are used for incident and scattering neutron beams to pass through the cell. It can supply hydrostatic pressures up to 500 bar and uniaxial stresses up to 100 bar, thereby emulating shale reservoir conditions.

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Shale specimens for SANS/USANS experiments can be in the form of powder or wafer

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(slice). The advantage of using powder samples is that the measurements can provide the

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representative, average information over a large depth of shale lithology and for all orientations

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of the grains. The use of wafer samples yields complementary location-sensitive information, with the thicknesses of the slices being optimized to minimize multiple scattering, which may

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complicate data interpretation (typically a few tenths of mm, depending on the shale

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composition).

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Journal Pre-proof Figure 3. Schematic of the flow-through compression cell assembly in cross section. Taken from Hjelm et al., 2018, with copyright permission from AIP Publishing. The ram assembly, containing a sapphire neutron window, applies stress on the sample that is placed between the ram and a fixed plate, which holds a second neutron window. Hydrostatic fluid pressure is applied through the fluid ports. The incident neutron beam passes through a channel in the ram assembly, sapphire window and sample. The scattered beam exits the sample chamber through the second neutron window.

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Shale Nanopore Structure Detailed studies of pore morphology (shape and size) and connectivity of shales are

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essential for understanding their gas/oil sorption/interaction characteristics, transport

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mechanisms and potential storage capacities. Shale pore structures are difficult to characterize

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because a major portion of their total porosities are distributed in nanopores associated with OM

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and various inorganic minerals (especially clay).

Clarkson et al. (2012) and Mastalerz et al. (2012) were among the first to investigate

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nanopore structures of shales using SANS/USANS. This technique had previously been applied

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to evaluate the porosity, pore size distribution and surface area of coals, which are also rich in OM (Radlinski and Radlinska, 1999; Radlinski et al., 2004; He et al., 2012; Melnichenko et al.,

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2012). Clarkson et al. (2012) conducted ambient-pressure SANS/USANS and low-pressure gas absorption measurements on three samples from the Triassic Montney tight gas reservoir in Western Canada. Surface area determined from gas adsorption is significantly less than surface area estimated from SANS/USANS, which is due in part to limited accessibility of the gases to all pores. The derived percentage of open (connected) porosity appears to correlate positively with the permeability measured by pressure and pulse-decay techniques, suggesting an important role of the pore structure of shale in controlling its permeability.

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Journal Pre-proof Built on the previous SANS/USANS applications to coal research, Mastalerz et al. (2012) measured two shale samples, as well as two coal samples for comparison, with high-pressure SANS/USANS using CD4 and CO 2 as the pressure media, complemented by N2 and CO 2 gas absorption. The results demonstrate that there is a major difference in mesopore (2–50 nm) size distribution between the coal and shale samples, while there is a close similarity in micropore (<2 nm) size distribution. However, the abundance of micropores in the coals is volumetrically

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10 times more than in the shales, reflecting different OM contents in the samples. The successful

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demonstration of the applications of SANS/USANS to shale research by Clarkson et al. (2012)

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and Mastalerz et al. (2012) laid the foundation for further investigations of size-specific pore

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accessibility and its relationship to shale permeability.

To characterize the complex pore structure of shales, Clarkson et al. (2013) conducted the

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first comparative measurements on a suite of North American shale reservoir samples (Barnett,

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Marcellus, Haynesville, Eagle Ford, Woodford, Muskwa, and Duvernay) using SANS/USANS, low-pressure N2 /CO 2 gas adsorption and high-pressure mercury intrusion measurements. Pore

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size distributions determined from gas adsorption for some samples do not agree with mercury

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intrusion results. This inconsistency may be due to the fact that mercury intrusion measures pore throat rather than pore size plus the compression of mineral grains during high-pressure mercury intrusion. Pore volume distributions derived from SANS/USANS are in good agreement with those from gas adsorption for the overlap region between the two measurements. SANS/USANS also reveal a fractal geometry for a wide range of pore sizes and the nm-scale spatial ordering associated with inter-layer spacing in clay minerals in some samples. Ruppert et al. (2013) characterized the nanopores of two Mississippian Barnett shale samples using SANS/USANS with CD4 and D2 O as the probing fluids. The two samples have

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Journal Pre-proof similar mineral compositions (quartz, illite, carbonate, pyrite and feldspar) and total pore size distributions, with > 85% of the pores of sizes > 250 nm being accessible to both CD4 and D2 O. However, they exhibit significant differences in CD4 accessibility to smaller pores. In one sample, CD4 penetrated the smallest pores as effectively as it did the larger ones. In the other sample, > 30% of the smaller pores were inaccessible to CD4 , though they were still largely penetrable by D2 O (Fig. 4). This disparity may be associated with the smaller size of D2 O

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compared to that of CD4 (small throats of large pores can also restrict the access by CD4 ), but it

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also implies that differences in nanopore structure occur between these samples, even though

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their total porosities are approximately the same. In particular, since OM is mostly hydrophobic

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whereas inorganic minerals, especially clay, are largely hydrophilic, this disparity may reflect different ratios of nanopores in OM versus those in clay between the two samples.

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Bahadur et al. (2014) investigated the nanoporosities of three Cretaceous shale powder

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samples with a grain size of ∼0.5 mm from Alberta, Canada. These three samples (S7, S9 and S11) have different amounts of mineral components, with S7 being carbonate-rich (calcite,

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dolomite and ankerite), S11 being quartz/feldspar-rich and S9 in between. The amounts of clay

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(illite, kaolinite and chlorite) and pyrite increase from S7 to S9 to S11, and so does the pyrite content. SANS/USANS revealed a hierarchical pore structure with length scales ranging from micropores (< 2 nm) to mesopores (2 - 50 nm) and to macropores (> 50 nm). Initial data analysis indicated that all the samples exhibit surface fractal geometry (The scattering intensity I(Q) for a fractal object follows a power law relation with the scattering vector Q: I(Q) ∼ Q -, where  is a measure of inhomogeneity of the fractal object.) with a fractal dimension Ds of 2.9 (highly rough pore−matrix interface)  a characteristic commonly found in sedimentary rocks. However,

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Figure 4. Comparison of the fractions of accessible pores ( AC) in a Mississippian Barnett shale sample by D2 O and CD4 . While D2 O and CD4 are equally accessible to pores > 100 nm (USANS regime), the accessibility of CD4 is smaller than that of D2 O to pores < 100 nm (SANS). Reprinted with permission from Ruppert et al. (2013). Copyright 2013 American Chemical Society.

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detailed data analysis provided evidence for the presence of non-fractal pores in the samples. Thus the authors used a more general model accounting for both fractal and non-fractal pores to

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fit the SANS/USANS profiles, yielding good fits (Fig. 5). These analyses demonstrate that the

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total porosity is dominated by the contributions from mesopores and micropores and the differences in total porosity among samples may be due to intra- and inter-particle porosity associated with the constituent minerals. Moreover, from the differences in the porosities measured by SANS/USANS (which measures total porosities) and He pycnometry (which measure open pores), the fractions of closed pores in the three shale specimens  S7 (calciterich), S9 and S11 (quartz/feldspar/clay-rich)  were determined to be 20%, 32% and 37%, respectively, which appear to correlate with variations in the major mineral contents. In

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Journal Pre-proof particular, the increased trend in closed porosity from S7 to S9 to S11 may be largely due to the

micropores

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macropores

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increased contents of clay and associated OM in the samples in this order.

mesoopores

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Figure 5. SANS/USANS profiles fitted with a more general model accounting for both fractal and non-fractal pores. The profiles are scaled vertically for clarity. The scale factors for S7, S9, and S11 are 0.1, 1.0, and 10.0, respectively. Reprinted with permission from Bahadur et al. (2014). Copyright 2014 American Chemical Society.

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Similarly, Bahadur et al. (2015) studied the microstructures of five New Albany shale samples that have different degrees of OM maturity using SANS/USANS. The results show that the total porosities decrease with increasing the maturity (corresponding to larger depth of burial and thus more-pronounced compaction of shale matrix) but then increase somewhat for postmature samples due to OM transformation and hydrocarbon generation. The results also indicate that pores can be fractal or non-fractal, depending on the pore size. Macropores (> 50 nm) and most of mesopores (2-50 nm) are surface fractals. By contrast, micropores (< 2 nm) are largely non-fractal, contributing significantly to the high-Q flat background, although it is generally believed that the magnitude of high-Q background is correlated with the content of hydrogen 15

Journal Pre-proof (from OM and clay) in the sample (due to the incoherent scattering of hydrogen). The authors developed a method to extract information on the size range and number density of micropores from the flat background, whose evaluation is important for accurate interpretation of the SANS data in general. Gu et al. (2016) presented an approach to characterize the characteristics of OM pores, including their porosity, specific surface area, pore size distribution and water accessibility, in

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several Marcellus shale samples using SANS/USANS. As described earlier, OM pores are

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believed to contribute significantly to the total porosity of gas shale and play a major role in

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defining its storage capacity. Through contrast matching of the shale matrix with appropriate

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D2 O/H2 O mixtures, the water-accessible (open) porosity was measured, and the difference between the total porosity and water-accessible porosity is water-inaccessible (closed) porosity.

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The same method was used to determine the open/closed porosity of the sample after being

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combusted at 450 °C to remove its OM. Comparison of the SANS/USANS data allowed quantification of OM porosity and water accessibility. Although OM is generally considered to

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be hydrophobic, the results indicate that OM pores of >20 nm can be water accessible.

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Measurements on samples with various OM contents show that OM pores can account for 2447% of the total porosity and occupy as much as 29% of the OM volume, confirming the key role that OM pores play in controlling shale porosity and the associated hydrocarbon storage and transport. Sun et al. (2017) employed SANS, helium pycnometry and CO2 /N2 gas sorption to investigate the pore characteristics of a series of shale samples from Longmaxi, China. By evaluating the differences in porosities determined by SANS and those by He pycnometry and gas sorption, the fractions of closed nanopores were determined to be in the range of 6.69-42.6%.

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Journal Pre-proof The results reveal a positive correlation between closed pore fraction and mass fractal dimension (Fig. 6), the latter of which measures the irregularity or inhomogeneity of shale nanopores and the diffusive transport of fluid therein. Moreover, the total porosity appears to correlate

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positively with the OM content, i.e. TOC  a relation also observed in other shale formations.

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Figure 6. Relationship between fraction of closed pores and mass fractal dimension of Longmaxi shale samples. Taken from Sun et al. (2017) with copyright permission from Elsevier. Most recently, Bahadur et al. (2018) determined the effects of shale mineralogy on the accessibility of water and toluene to nanopores in three Devonian Marcellus samples (quartz-, carbonate- and clay-rich) using SANS combined with contrast matching. Although these samples have similar mean pore sizes (pore diameters = 1.34-1.5 nm), the number density of pores of the clay-rich sample is much higher than those for the quartz-rich and carbonate-rich samples  consistent with the small grain sizes and layered nature of clay minerals. Contrast matching SANS with deuterated/hydrogenated water mixtures shows that while water accesses 70-80% of the large (> 80 nm) and small (~ < 2.5 nm) pores in all the three samples (Fig. 7 left), its 17

Journal Pre-proof accessibilities to the intermediate pores (~5–80 nm) decrease significantly, with the quartz-rich sample exhibiting the lowest accessibility at ~25 nm. At a given pore size, the clay-rich sample pores are the most accessible to water, then the carbonate-rich sample pores, and lastly the quartz-rich sample pores. By contrast, the reverse is true when deuterated/hydrogenated toluene mixtures were used as the contrast-matching fluids (Fig. 7 right), reflecting different degrees of wettability of minerals (to water or toluene), e.g., clay is highly water-wet. Since OM is highly

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oil-wet, it is expected that the variations in the OM content among these samples may also play

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an important role. Hence, different mineralogical characteristics of the producing intervals within

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a shale reservoir can significantly affect the accessibility of pores and thus may ultimately

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determine their hydrocarbon storage, transport and production.

Figure 7. The fractions of accessible pores in three Marcellus Shale samples estimated by: H2 O/D2 O (left) and toluene/d-toluene (right) contrast matching. Mar-1: quartz-rich; Mar-2: clay-rich; Mar-3: carbonate-rich. Taken from Bahadur et al. (2018) with copyright permission from Elsevier.

Confined Fluid Behavior in Shale Nanopore Structure Nanopores can affect the phase behavior of their enclosed fluids via nanopore confinement or capillary condensation. For a fluid in nanopores, with decreasing the pore size, 18

Journal Pre-proof there are more fluid molecules at or near the fluid-rock interfaces. Eventually, in pores of a few nanometers, the majority of the molecules will be in contact with the solid pore walls. With increasing influence of the surface/interface in nanopores, gases can deviate from bulk gas behavior, phase coexistence regions may shift, and critical points can be lowered. However, these drastic changes in physical properties, e.g., the decrease in the bubble-point pressure with reducing pore size, have been largely inferred from theoretical simulations due to the lack of

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appropriate experimental techniques (Brusilovsky, 1992; Sokhan et al., 2001). More recently,

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SANS/USANS, combined with high-pressure gas cells, has started to be used to examine gas

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accessibility and densification in shale nanopores with increasing pressure.

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Ruppert et al. (2013) examined the changes in SANS intensity of a Mississippian Barnett shale sample (the same samples used for Fig. 4) when pressurized with CD4 (Fig. 8). At low Q

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(large pore size), the intensity decreases steadily with increasing pressure from vacuum to 8,000

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psi (551.6 bar), indicating increased occupancy of the pores by CD4 in this pressure range. On further increasing pressure up to 10,000 psi (689.5 bar), the highest pressure tested, the intensity

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remains approximately unchanged, which suggests reaching of the so-called “zero contrast

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density” (zc), i.e., all the open pores accessible to CD4 are occupied and the difference in SLD between the matrix and pores is at the minimum. The markedly nonzero and Q-dependent scattering intensity observed at zc implies that a significant portion of the shale pores are inaccessible to CD4 ; they are either closed or their throats are too small for CD4 molecules to pass through. However, at high Q (small pore size), the scattering intensity becomes higher on increasing the CD4 pressure from vacuum to 3,000 psi (206.8 bar) and then exhibits smaller variations thereafter, resulting in the crossovers in scattering intensity at the low-/high-Q boundaries. This trend suggests capillary condensation or clustering of CD4 molecules within

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Journal Pre-proof micropores; the densities required to explain such scattering intensities would be even higher (∼1 g/cm3 ) than that of liquid CD4 (∼0.5 g/cm3 ). Although incoherent neutron scattering of CD4 may contribute to the intensity variations at low Q, its extent is expected to be minor, as the incoherent cross sections for both C and D are very small (vs. H, whose cross section is much

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larger).

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Figure 8. SANS patterns of a Mississippian Barnett sample (the same sample for Fig. 4) as a function of pressure with CD4 as the pressure medium. Note the different trends in the intensity variation with Q in the low- and high-Q regimes. Reprinted with permission from Ruppert et al. (2013). Copyright 2013 American Chemical Society.

Eberle et al. (2016) performed an integrated experimental and computational study of densification of methane in shale nanopores using SANS and density functional theory (DFT) calculations. In particular, the authors conducted the first direct measurements of the density of methane in shale samples that are within the dry gas maturation window. At a constant pressure of 33.8 MPa (338 bar), the density of methane in the large, inorganic or OM pores (low Q: < 20

Journal Pre-proof ∼0.1 Å−1 , > 2 nm) is similar to the bulk methane gas density (0.2343 g/cm3 ) at the same condition, apparently due to a simple, expected gas-filling process. In contrast, the methane density is 2.1 ± 0.2 (0.48 ± 0.05 g/cm3 ) times greater in the small (high Q: > ∼0.1 Å−1 , 1-2 nm), OM mesopores (Fig. 9), indicating methane densification or clustering. The measured density of the dense methane phase falls in the range predicted by DFT at the same pressure and pore sizes. Thus, the methane density increases dramatically with decreasing the pore size, especially in the

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range of 1-2 nm, where the OM pores are dominant. Moreover, DFT calculations show that this

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excess density largely persists to elevated temperature (373 K, 100 C), typical of shale gas

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reservoir conditions.

Figure 9. Calculated density of methane in pores at 33.8 MPa (338 bar) using the density of carbon atoms as in graphite and kerogen ( 50% less dense than graphite). The inset shows calculated methane density in the bulk and in 1.57 nm diameter carbon and kerogen pores as a function of pressure. The gray region indicates an estimate of ±0.05 confidence interval using the global fit to SANS data for the range of pore sizes of 1-2 nm. Reprinted with permission from Eberle et al. (2016). Copyright 2016 American Chemical Society.

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Journal Pre-proof Stefanopoulos et al. (2017) conducted neutron diffraction and SANS measurements of adsorbed CO 2 in a Marcellus shale sample along an adsorption isotherm of 22 °C and 60 °C and pressures of 25 and 40 bar. The results indicate that CO2 densification or capillary condensation occurred in all accessible pores (Fig. 10). With increasing Q or decreasing pore size, pores become increasingly inaccessible to CO 2 . At Q > 1 Å−1 (pore < 0.5 nm in diameter), all pores are inaccessible, as the kinetic diameter of CO 2 is 0.33 nm. At 22 °C, the CO 2 is liquid- like (as

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evidenced by additional peaks related to the short-range intermolecular ordering), rather than

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gas-like (no extra peaks), when confined in pores of 1 nm at elevated pressures. Many of the

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2.5 nm pores, 70% of 2 nm pores, most of the <1 nm pores, and all pores < 0.25 nm, are

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inaccessible to CO 2 . Comparison with the results of methane31 reveals that gas condensation in shale nanopores is sensitive to the size of gas molecule and possibly the extent of its interaction

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with pore wall.

Figure 10. Ratio of scattering intensity in CO 2 vs. under vacuum at 25 and 40 bar of a Marcellus shale sample with the flat background removed. Inset: The total scattering structure factor of CO 2 confined in shale at 25 and 40 bar; the structure factor at 40 bar has been shifted by 0.1 for clarity. Reprinted with permission from Stefanopoulos et al. (2017) (https://pubs.acs.org/doi/abs/10.1021/acs.est.6b05707). Copyright 2017 American Chemical Society (ACS). Further permissions related to this figure should be directed to the ACS. 22

Journal Pre-proof Conclusions and Future Research As demonstrated in the previous studies summarized above, SANS/USANS has emerged as a powerful method for characterizing shale nanopore structure and confined fluid behavior. Because of neutrons' high penetrating ability and high sensitivity to hydrogen, SANS/USANS can probe inside shale samples to characterize nanopores from 1 nm to 10 m in size and be readily combined with sample environmental cells to examine the fluid behavior in reservoir

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environments. The size, fractal character and accessibility of shale nanopores may be determined

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as functions of pressure, temperature and stress as well as shale/fluid type (e.g., shale

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mineralogy). In particular, via contrast matching, SANS/USANS can distinguish open vs. closed

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pores, the proportion and distribution of which largely determine the permeability of a shale matrix. Since a significant portion of hydrocarbons may be stored in closed pores, studying their

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ratios at shale reservoir conditions is important for more accurate estimation of the original

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oil/gas in place and for enhancing the ultimate hydrocarbon recovery. For the in-situ SANS/USANS experiments, although various pressure cells have been used, more sophisticated

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vessels need to be developed to truly emulate reservoir P-T-stress conditions. One development

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is the addition of a heating capability to our designed flow-through compression cell (Fig. 3), enabling examination of the effects of temperature on shale nanopores and their confined fluid behavior while under relevant pressures and stresses. Another potential upgrade is to improve it for handling liquid and gas simultaneously, which can thus be used to emulating the hydraulic fracturing process of shale gas. Due to its complexity and heterogeneity, shale nanopore structure presents tremendous challenges to its high-fidelity characterization. Further, the fluids hosted exhibit significantly different behavior due to nanopore confinement effects and fluid-rock interactions. Thus the

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Journal Pre-proof characterization of shale nanopore structures and confined fluid behavior requires an integrated approach using multiple techniques that provide complementary information across the length scales and at both in situ and ex situ conditions (Fig. 11) (Clarkson et al., 2012; Leu et al., 2016). Although SANS/USANS, coupled with P-T-stress cells, is a powerful technique, its data analysis is nontrivial and frequently model-dependent. Thus, to formulate reliable starting models, complementary information, obtained by other techniques (Fig. 11), is needed. For example,

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scanning electron microscopy can help resolve larger, complex features (smaller Q-values),

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where the resolution of SANS/USANS data

Total Porosity Open Porosity

Figure 11. Experimental techniques used to characterize shale nanopore structure and its enclosed fluid behavior. Modified from Clarkson et al. (2012) with copyright permission from Elsevier.

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Journal Pre-proof is limited. In addition, synchrotron-based small-angle X-ray scattering (SAXS), the sister technique of SANS, can offer high spectral and spatial (smaller samples) resolutions, due to synchrotron X-rays’ high intensity and coherence. The integrated studies using multiple techniques are essential for achieving a fundamental understanding of the thermodynamic properties and transport processes of hydrocarbon fluids in shale nanopores, which are expected to be vastly different from those of bulk fluids in conventional porous media. Although several

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studies have been conducted in this area (capillary densification) (Ruppert et al., 2013; Eberle et

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al., 2016; Stefanopoulos et al., 2017), further measurements need to be conducted using various

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hydrocarbon species (and their mixtures) and in wider ranges of P-T-stress conditions.

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Ultimately, the obtained results will serve as input parameters for modeling fluid flow behavior at the reservoir scale and lay the foundation for developing better operational strategies for

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maximizing the unconventional oil and gas recovery.

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Acknowledgments

I thank Rajesh Pawar, Rex Hjelm and George Guthrie (Los Alamos National Laboratory)

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for helpful discussions, and Ying-Bing Jiang (University of New Mexico) and Huifang Xu

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(University of Wisconsin at Madison) for acquiring the TEM/SEM images (Fig. 2). This work was funded by the Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, under Grant Number FWP FE-406/408/409. Los Alamos National Laboratory, an affirmative action/equal opportunity employer, is managed by Triad National Security, LLC, for the National Nuclear Security Administration of the U.S. Department of Energy under contract 89233218CNA000001. Declaration of interests

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Journal Pre-proof The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

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Highlights Characteristics of shale matrix

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Uniqueness of small angle neutron scattering compared with conventional methods

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Current status on studying shale nanopore structure and confined fluid properties using small-angle neutron scattering

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Outlook and perspective on future research in this emerging area

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