Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition

Joanna McFarlane; Victoria H. Distefano; Philip R. Bingham; Hassina Z. Bilheux; Michael C. Cheshire; Richard E. Hale; Daniel S. Hussey; David L. Jacobson; Lindsay Kolbus; Jacob M. Lamanna; Edmund Perfect; Mark Rivers; Louis J. Santodonato; Lawrence M. Anovitz

doi:10.1021/acsomega.1c04177

Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition

Joanna McFarlane, Victoria H. Distefano, Philip R. Bingham, Hassina Z. Bilheux, Michael C. Cheshire, Richard E. Hale, Daniel S. Hussey, David L. Jacobson, Lindsay Kolbus, Jacob M. Lamanna, Edmund Perfect, Mark Rivers, Louis J. Santodonato, Lawrence M. Anovitz

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Abstract

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 water-wet 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.

Original language	English
Pages (from-to)	32618-32630
Number of pages	13
Journal	ACS Omega
Volume	6
Issue number	48
DOIs	https://doi.org/10.1021/acsomega.1c04177
State	Published - Dec 7 2021

Funding

This article has been authored by UT-Battelle, LLC, under Contract DE-AC05-00OR22725 with the U.S. Department of Energy (DOE). The U.S. Government retains and the publisher, by accepting the article for publication, acknowledges that the U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide license to publish or reproduce the published form of this article or allow others to do so for U.S. government purposes. DOE will provide public access to these results of federally sponsored research in accordance with the DOE Public Access Plan ( http://energy.gov/downloads/doe-public-access-plan ). Work by L.M.A., M.C.C., and V.H.D. was supported by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, Chemical Sciences, Geosciences, and Biosciences Division. A portion of this research used resources at the High Flux Isotope Reactor and Spallation Neutron Source, DOE Office of Science User Facilities operated by Oak Ridge National Laboratory. Access to neutron and X-ray imaging was provided by the Center for High Resolution Neutron Scattering, a partnership between the National Institute of Standards and Technology and the National Science Foundation under Agreement No. DMR-1508249. Work done by J.M.L., D.S.H., and D.L.J. was supported by the National Institute of Standards and Technology and the NIST Physical Measurement Laboratory. E.P. acknowledges support from the Tom Cronin and Helen Sestak Faculty Achievement award.

Funders	Funder number
M.C.C.
Tom Cronin and Helen Sestak Faculty Achievement
National Science Foundation	DMR-1508249
U.S. Department of Energy
National Institute of Standards and Technology
Office of Science
Basic Energy Sciences
Physical Measurement Laboratory
Chemical Sciences, Geosciences, and Biosciences Division

UN SDGs

This output contributes to the following UN Sustainable Development Goals (SDGs)

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10.1021/acsomega.1c04177

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McFarlane, J., Distefano, V. H., Bingham, P. R., Bilheux, H. Z., Cheshire, M. C., Hale, R. E., Hussey, D. S., Jacobson, D. L., Kolbus, L., Lamanna, J. M., Perfect, E., Rivers, M., Santodonato, L. J., & Anovitz, L. M. (2021). Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition. ACS Omega, 6(48), 32618-32630. https://doi.org/10.1021/acsomega.1c04177

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title = "Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition",

abstract = "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 water-wet 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.",

author = "Joanna McFarlane and Distefano, {Victoria H.} and Bingham, {Philip R.} and Bilheux, {Hassina Z.} and Cheshire, {Michael C.} and Hale, {Richard E.} and Hussey, {Daniel S.} and Jacobson, {David L.} and Lindsay Kolbus and Lamanna, {Jacob M.} and Edmund Perfect and Mark Rivers and Santodonato, {Louis J.} and Anovitz, {Lawrence M.}",

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McFarlane, J, Distefano, VH, Bingham, PR , Bilheux, HZ, Cheshire, MC, Hale, RE, Hussey, DS, Jacobson, DL, Kolbus, L, Lamanna, JM, Perfect, E, Rivers, M, Santodonato, LJ & Anovitz, LM 2021, 'Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition', ACS Omega, vol. 6, no. 48, pp. 32618-32630. https://doi.org/10.1021/acsomega.1c04177

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T1 - Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition

AU - McFarlane, Joanna

AU - Distefano, Victoria H.

AU - Bingham, Philip R.

AU - Bilheux, Hassina Z.

AU - Cheshire, Michael C.

AU - Hale, Richard E.

AU - Hussey, Daniel S.

AU - Jacobson, David L.

AU - Kolbus, Lindsay

AU - Lamanna, Jacob M.

AU - Perfect, Edmund

AU - Rivers, Mark

AU - Santodonato, Louis J.

AU - Anovitz, Lawrence M.

PY - 2021/12/7

Y1 - 2021/12/7

N2 - 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 water-wet 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.

AB - 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 water-wet 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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Effect of fluid properties on contact angles in the eagle ford shale measured with spontaneous imbibition

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UN SDGs

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