Spontaneous imbibition of water and determination of effective contact angles in the Eagle Ford Shale Formation using neutron imaging
Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron imaging to measure the spontaneous imbibition of water into fractures of Eagle Ford shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order differential equations was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective contact angles that were slightly higher than static contact angles due to effects of in-situ changes in velocity, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that average fracture widths are not satisfactory for modeling imbibition in natural systems.
Key Wordsspontaneous imbibition effective contact angle neutron imaging Eagle Ford shale rock fractures
Unable to display preview. Download preview PDF.
This work was supported as part of the Center for Nanoscale Controls on Geologic CO2 (NCGC), an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Basic Energy Sciences (No. DE-AC02-05CH11231). Victoria H. DiStefano acknowledges a graduate fellowship through the Bredesen Center for Interdisciplinary Research at the University of Tennessee. Vitaliy Starchenko was supported by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences, Chemical Sciences, Geosciences, and Biosciences Division. Edmund Perfect’s research was sponsored by the Army Research Laboratory (No. W911NF-16-1-0043). The views and conclusions contained in this document are those of the authors and should not be interpreted as representing the official policies, either expressed or implied, of the Army Research Laboratory or the U.S. Government. The U.S. government is authorized to reproduce and distribute reprints for government purposes notwithstanding any copyright notation herein. We acknowledge the support of the National Institute of Standards and Technology, U.S. Department of Commerce, in providing the neutron research facilities used in this work. A portion of this research used resources at the High Flux Isotope Reactor, a DOE Office of Science User Facility operated by the Oak Ridge National Laboratory. We would also like to thank Andrew Kolbus, Salesforce, Robert Brese, UTK & ORNL, and Xiaojuan Zhu, Office of Information Technology at UTK, for assistance with Python, the Keyence VR-3100, and MATLAB, respectively. The final publication is available at Springer via https://doi.org/10.1007/s12583-017-0801-1.
- Abdallah, W., Buckley, J., Carnegie, A., et al., 2007. Fundamentals of Wettability. Schlumberger Oilfield Review, 19(2): 44–61Google Scholar
- Chen, C., Wan, J. M., Li, W. Z., et al., 2015. Water Contact Angles on Quartz Surfaces under Supercritical CO2 Sequestration Conditions: Experimental and Molecular Dynamics Simulation Studies. International Journal of Greenhouse Gas Control, 42: 655–665. https://doi.org/10.13039/501100001809CrossRefGoogle Scholar
- Dubiel, R. F., Pitman, J. K., Pearson, O. N., et al., 2012. Assessment of Undiscovered Oil and Gas Resources in Conventional and Continuous Petroleum Systems in the Upper Cretaceous Eagle Ford Group, US Gulf Coast region. Vol. No. 2012-3003. US Geological Survey, 2011, Reston, VAGoogle Scholar
- Ergene, S. M., 2014. Lithologic heterogeneity of the Eagle Ford Formation, South Texas: [Dissertation]. The University of Texas at Austin, Austin, TexasGoogle Scholar
- Handy, L., 1960. Determination of Effective Capillary Pressures for Porous Media from Imbibition Data. Pet. Trans. AIME, 219(7): 75–80Google Scholar
- International Organization for Standardization, 1997. Geometrical Product Specifications (GPS)—Surface Texture: Profile Method—Terms, Definitions and Surface Texture Parameters. International Organization for Standardization, Geneva, SwitzerlandGoogle Scholar
- Jurin, J., 1717. An Account of Some Experiments Shown before the Royal Society: With an Enquiry into the Cause of the Ascent and Suspension of Water in Capillary Tubes. Philosophical Transactions of the Royal Society of London, 30(351–363): 739–747. https://doi.org/10.1098/rstl.1717.0026Google Scholar
- Kang, M., Perfect, E., Cheng, C. L., et al., 2013. Diffusivity and Sorptivity of Berea Sandstone Determined Using Neutron Radiography. Vadose Zone Journal, 12(3). https://doi.org/10.2136/vzj2012.0135Google Scholar
- Mamontov, E., Vlcek, L., Wesolowski, D. J., et al., 2007. Dynamics and Structure of Hydration Water on Rutile and Cassiterite Nanopowders Studied by Quasielastic Neutron Scattering and Molecular Dynamics Simulations. The Journal of Physical Chemistry C, 111(11): 4328–4341. https://doi.org/10.1021/jp067242rCrossRefGoogle Scholar
- U.S. Energy Information Administration (EIA), 2017. Drilling Productivity Report. For Key Tight Oil and Shale Gas Regions. [2017-9-8] (2017-4). https://www.eia.gov/petroleum/drilling/archive/2017/04/#tabs-summary-2Google Scholar