Analysis of the Pore Structures of Shale Using Neutron and X‐Ray Small Angle Scattering

Anovitz, L. M.; Cole, David R.

doi:10.1002/9781119118657.ch4

Cited by 15 publications

(14 citation statements)

References 161 publications

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“…All of the results exhibit the following features: (1) power‐law (i.e., the linear portion) scattering in the low‐to‐medium Q region before and after contrast matching; (2) multiple scattering (shown by the scattering curve flattening at very low Q and increased at slightly higher Q; Anovitz & Cole, 2015; Radliński et al, 1999; Sabine & Bertram, 1999), although the effect in the dry samples is reduced in the contrast‐matched analyses; (3) a decrease in scattering intensity after contrast‐matched fluid saturation in the low Q region ( Q < 3 × 10 − 4 Å − 1 ), which may also reflect the reduction in multiple scattering. Many previous (U)SANS studies on rocks showed power‐law scattering in the low‐to‐medium Q region as a result of surface fractal pore geometry at nm‐μm scales (cf., Anovitz & Cole, 2015, 2019; Radliński et al, 1999), and our data suggest that pores not invaded by solvents exhibit surface fractal properties as well. Changes in scattering intensities after contrast matching are also more evident in the Utica than the Bakken samples, indicating that the Utica samples are more fluid accessible to both n ‐decane and water.…”

Section: Resultssupporting

confidence: 70%

“…Previous SANS/USANS studies on shales mostly used thin sections (150–200 μm thick) or wafers (around 700 μm thick) to characterize pore geometry, either parallel or perpendicular to the shale lamination (Anovitz & Cole, 2019; Anovitz et al, 2015; Blach et al, 2018; DiStefano et al, 2019; Gu et al, 2015; Hall et al, 1983; M. D. Sun et al, 2018; Zhao et al, 2017). In this study, we used granular samples (hand ground with a mortar and pestle) to obtain orientation‐averaged pore structure information.…”

Section: Methodsmentioning

confidence: 99%

“…Previous SANS/USANS studies on shales mostly used thin sections (150-200 μm thick) or wafers (around 700 μm thick) to characterize pore geometry, either parallel or perpendicular to the shale lamination (Anovitz & Cole, 2019;Blach et al, 2018;DiStefano et al, 2019;Gu et al, 2015;Hall et al, 1983;M. D. Sun et al, 2018;Zhao et al, 2017).…”

Section: Sample Selection and Preparationmentioning

confidence: 99%

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Quantifying Fluid‐Wettable Effective Pore Space in the Utica and Bakken Oil Shale Formations

Zhang

Barber

et al. 2020

Geophysical Research Letters

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Combined (ultra‐) small angle neutron scattering measurements [(U)SANS] and a contrast matching technique were employed to quantify the porosity and pore size distribution from 1 nm to 10 μm and to differentiate accessible (open) pores and inaccessible (closed) pores with respect to organophilic and hydrophilic fluids for two Utica and two Bakken shale samples. The results indicate that around 40–70% of the pores in the Utica oil shales (mixed carbonate mudstone) are accessible to oil, and 34–37% of the pore surfaces are water‐wet. In contrast, the Bakken oil shales (mixed siliceous mudstone and carbonate/siliceous mudstone), which have high total organic carbon contents, have a higher proportion of isolated pore space that is not preferentially wet by oil or water, with less than 36% of the pores accessible to both fluids. In addition, for both formations, pores less than 3 nm in diameter are not oil accessible (organic matter related) but water accessible (clay tactoids related).

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Section: Resultssupporting

confidence: 70%

Section: Methodsmentioning

confidence: 99%

Section: Sample Selection and Preparationmentioning

confidence: 99%

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Quantifying Fluid‐Wettable Effective Pore Space in the Utica and Bakken Oil Shale Formations

Zhang

Barber

et al. 2020

Geophysical Research Letters

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“…Bredehoeft and Norton 79 expanded on this by providing estimates of permeability for fractured igneous and metamorphic rocks that range from 10 -12 to 10 -16 m 2 , and for unfractured equivalents ranging from 10 -17 to 10 -20 m 2 . Anovitz and Cole 80,81 surveyed the many techniques used to quantify pore features (e.g. advanced electron microscopy, X-ray, and neutron scattering) and indicated that the range in pore size measured in rocks (sedimentary, igneous, and metamorphic) can vary by approximately eight orders of magnitude from the nanometer scale to the millimeter scale.…”

Section: Nanopore Featuresmentioning

confidence: 99%

The Influence of Nanoporosity on the Behavior of Carbon-Bearing Fluids

Cole¹,

Striolo²

2019

Deep Carbon

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david cole and alberto striolo IntroductionPorosity and permeability are key variables linking the origin, form, movement, and quantity of carbon-bearing fluids that collectively dictate the physical and chemical evolution of fluid-gas-rock systems. 1 The distribution of pores, pore volume, and their connectedness vary widely, depending on the Earth material, its geologic context, and its history. The general tendency is for porosity and permeability to decrease with increasing depth, along with pore size and/or fracture aperture width. Exceptions involve zones of deformation (e.g. fault or shear zones), regions bounding magma emplacement and subduction zones. Pores or fractures display three-dimensional hierarchical structures, exhibiting variable connectivity defining the pore and/or fracture network. [2][3][4][5] This network structure and topology control: (1) internal pore volumes, mineral phases, and potentially reactive surfaces accessible to fluids, aqueous solutions, volatiles, inclusions, etc. [6][7][8] ; and(2) diffusive path lengths, tortuosity, and the predominance of advective or diffusive transport. [9][10][11][12] For solids dominated by finer networks, transport is dominated by slow advection and/or diffusion. [13][14][15][16] Despite the extensive spatial and temporal scales over which fluid-mineral interactions can occur in geologic systems, interfacial phenomena including fluids at mineral surfaces or contained within buried interfaces such as pores, pore throats, grain boundaries, microfractures, and dislocations (Figure 12.1) impact the nature of multiphase flow and reactive transport in geologic systems. 13,[17][18][19][20][21] Complexity in fluid-mineral systems takes many forms, including the interaction of dissolved constituents in water, wetting films on mineral surfaces, adsorption of dissolved and volatile species, the initiation of reactions, and transport of mobile species. [22][23][24] Direct observations and modeling of physical (transport) and chemical properties (reactivity) and associated interactions are challenging when considering the smallest length scales typical of pore and fracture features and their extended three-dimensional network structures. 25,26 The various void types and their evolution during reaction with fluids are critically important factors controlling the distribution of the fluid-accessible pore volume, flow dynamics, fluid retention, chemical reactivity, and contaminant species transport. [27][28][29][30][31][32] While fracture-dominated flow can be volumetrically dominant in shallow crustal settings 358 https://www.cambridge.org/core/terms.

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“…Shale formations are increasingly important for oil and gas recovery and as potential seals for geologic carbon sequestration . However, fracture propagation and flow modeling in these reservoirs are needed to improve recovery efficiency and sequestration reliability.…”

Section: Introductionmentioning

confidence: 99%

Effect of Fluid Properties on Contact Angles in the Eagle Ford Shale Measured with Spontaneous Imbibition

et al. 2021

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Models of fluid flow are used to improve the efficiency of oil and gas extraction and to estimate the storage and leakage of carbon dioxide in geologic reservoirs. Therefore, a quantitative understanding of key parameters of rock−fluid interactions, such as contact angles, wetting, and the rate of spontaneous imbibition, is necessary if these models are to predict reservoir behavior accurately. In this study, aqueous fluid imbibition rates were measured in fractures in samples of the Eagle Ford Shale using neutron imaging. Several liquids, including pure water and aqueous solutions containing sodium bicarbonate and sodium chloride, were used to determine the impact of solution chemistry on uptake rates. Uptake rate analysis provided dynamic contact angles for the Eagle Ford Shale that ranged from 51 to 90°using the Schwiebert−Leong equation, suggesting moderately hydrophilic mineralogy. When corrected for hydrostatic pressure, the average contact angle was calculated as 76 ± 7°, with higher values at the fracture inlet. Differences in imbibition arising from differing fracture widths, physical liquid properties, and wetting front height were investigated. For example, bicarbonate-contacted samples had average contact angles that varied between 62 ± 10°and ∼84 ± 6°as the fluid rose in the column, likely reflecting a convergence−divergence structure within the fracture. Secondary imbibitions into the same samples showed a much more rapid uptake for water and sodium chloride solutions that suggested alteration of the clay in contact with the solution producing a waterwet environment. The same effect was not observed for sodium bicarbonate, which suggested that the bicarbonate ion prevented shale hydration. This study demonstrates how the imbibition rate measured by neutron imaging can be used to determine contact angles for solutions in contact with shale or other materials and that wetting properties can vary on a relatively fine scale during imbibition, requiring detailed descriptions of wetting for accurate reservoir modeling.

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Analysis of the Pore Structures of Shale Using Neutron and X‐Ray Small Angle Scattering

Cited by 15 publications

References 161 publications

Quantifying Fluid‐Wettable Effective Pore Space in the Utica and Bakken Oil Shale Formations

Quantifying Fluid‐Wettable Effective Pore Space in the Utica and Bakken Oil Shale Formations

The Influence of Nanoporosity on the Behavior of Carbon-Bearing Fluids

Effect of Fluid Properties on Contact Angles in the Eagle Ford Shale Measured with Spontaneous Imbibition

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