Date of Award

8-2018

Degree Type

Dissertation

Degree Name

Doctor of Philosophy

Major

Energy Science and Engineering

Major Professor

Lawrence M. Anovitz

Committee Members

Annette S. Engel, Edmund Perfect, Andrew G. Stack

Abstract

Subsurface models can be used to improve the efficiency of oil and gas extraction and geological carbon sequestration in shale formations. However, models are limited by a lack of information about how pores store organic matter and how fluids access and interact with those pores through fluid transport. Neutron scattering and neutron imaging were combined with conventional methods of geochemical analysis to investigate organic matter storage, pore-solvent interaction, and fluid flow in shales. To investigate organic matter storage and pore-solvent interactions, porosity in shale was examined after solvent extraction with neutron scattering and compared to unextracted samples. Additionally, Gas Chromatography ─ [dash] Mass Spectrometry was used to determine the amount and type of organic matter extracted with various solvents. We found that longer chained hydrocarbons may be stored in pores greater than 270 nm [nanometers]. We also found that the organic solvents used in extraction procedures caused changes in shale pore structure, including a decrease in porosity. This was predominately attributed to matrix-bound kerogen swelling to fill spaces once occupied with bitumen.Fluid flow was also measured to determine critical parameters for subsurface models. Neutron imaging was used to measure spontaneous imbibition of various fluids into shale fractures of different orientations. Imbibition data was then fit to a model and contact angles, an important parameter for fluid flow modeling, were determined. The fit of the model was heavily influenced by the width of the fractures. However, lack of variation among the imbibition rate with various fluids indicated that the rate was relatively unaffected by chemical reactions at the solution/mineral interface. Calculated contact angles for various fluids in the Eagle Ford Shale ranged from about 60° to 89.6°, with differences arising due to fluid properties and orientation of the bedding in the shales. These studies have led to a better understanding of parameters influencing organic matter storage and fluid flow in shales necessary for accurate subsurface modeling.

Comments

Portions of this document were previously published as journal articles.

Orcid ID

http://orcid.org/0000-0001-6023-9716

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