Document Type


Date of Award


Degree Name

Doctor of Philosophy in Civil Engineering - (Ph.D.)


Civil and Environmental Engineering

First Advisor

Jay N. Meegoda

Second Advisor

Bruno M. Goncalves da Silva

Third Advisor

Liming Hu

Fourth Advisor

Matthew J. Bandelt

Fifth Advisor

David Washington


This dissertation consists of two major parts: Firstly, experimental investigation of four major shale softening mechanisms and quantifications of structural parameters. Secondly, numerical simulations of nano-scale flow behaviors using the previous experiments determined parameters based on modified pore network modeling.

Hydraulic fracturing is widely applied to economical gas production from shale reservoirs. Still, the gradual swelling of the clay micro/nano-pores due to retained fluid from hydraulic fracturing causes a gradual reduction of gas production. Four different gas-bearing shale samples are investigated to quantify the expected shale swelling due to hydraulic fracturing. These shale samples are subject to heated deionized (DI) water at 100°C temperature and 8.2 MPa pressure in a laboratory reactor for 72 hours to simulate shale softening. The micro and nano-pore structures change during shale swelling, and the porosity decreases after shale treatment. The porosity decreases by 4% for clayey shale, while for well-cemented shale, the porosity only decreases by 0.52%. The findings show that the initial mineralogical composition of shale plays a significant role in the swelling of micro and nano-pores and the pore structure alteration due to retained fluid from hydraulic fracturing.

Secondly, the permeability of shale is of significance in the gas extraction process. The shale gas permeability is usually obtained based on Darcy flow using standard laboratory permeability tests that do not account for different transport mechanisms and anisotropic effects in shale due to nano-scale pore structure. However, this method cannot reflect the variations in transport mechanisms and anisotropic effect in shale due to additional nano-scale pore structure into consideration. In this study, the permeability of shale is simulated by a pore network model. Pore structure characteristics can be described by specific parameters, including porosity, pore size, pore throat distribution, and coordination number. The anisotropy is incorporated into the model using a coordination number ratio, and an algorithm is developed for connections of the pores in the shale formation. The proposed three-dimensional pore network model is verified by predicting hydraulic connectivity and comparing it with several high-pressure permeability tests. Results show that the prediction of the anisotropic model is closer to the test results than that of the isotropic model. The predicted permeability calculated by numerical simulation is consistent with the measured permeability.

Finally, the production rate with time for three formations and the negative effect of shale softening on gas production is analyzed, respectively. Then the historical production data from Eagle Ford Shale, Haynesville Shale, and Longmaxi shale are compared. A modified PNW model is developed to simulate each shale formations' flow properties using realistic reservoir parameters. The simulation results have a similar decline rate compared to actual historical production data, and the effect of softening of shale matrix is also incorporated. These results can predict how shale softening impacts the production rate of different conditions and provide a clear picture of how reservoir properties influence the overall production rate within nano-scale.