Natural gas is stored in shales in different ways: (1) gas adsorbed in the kerogen material, (2) free gas in inorganic inter-particle and intraparticle (matrix) porosity, (3) free gas in a pore network developed within the organic matter or kerogen, (4) free gas in microfracture and slot porosity, and (5) free gas stored in hydraulic fractures created during stimulation of the shale reservoir. An additional storage element is provided by gas dissolved in kerogen. These observations and the dominant nanoscale porosity in shale reservoirs were the focus of the present research and led to the following original developments:
1. A method for calculating an adsorbed porosity based on the strict definition of porosity, i.e., ratio of pore volume to bulk volume. Mathematical expressions for both intrinsic and scaled to bulk volume adsorbed porosities are presented in this thesis.
2. A physics-based quintuple porosity model for handling storage and fluid flow in shale gas reservoirs. The governing equations that describe the gas mass balance in the quintuple porosity model are presented in detail.
3. 2D radial and orthogonal numerical simulation fully implicit models built from scratch for handling the different types of porosities mentioned above and diffusion of gas dissolved in kerogen.
The adsorbed porosity mentioned in item 1 above is based on calculation of the thickness of the methane adsorbed monolayer and the size of organic pores in shales at a given pressure and temperature.
The complexity of quintuple porosity shales radial and orthogonal numerical models mentioned in items 2 and 3 above is high but they account successfully for viscous and non-Darcy flow in shale nanopores (slip flow and Knudsen diffusion). Consequently, they help to provide a better understanding of the flow mechanisms occurring in these reservoirs.
Real data from Devonian gas shales are used to illustrate the effect of free gas, adsorbed gas and dissolved gas in kerogen in a material balance crossplot of P/Z vs. cumulative gas production.
It is concluded that not taking into account all the porosities mentioned above plus diffusion of gas dissolved in kerogen can lead to pessimistic values of original gas in place (OGIP) and recoveries. This has been the case of Devonian shales in the Appalachian Basin in North-Eastern United States where hydraulically fractured vertical wells have been producing for several decades far beyond original expectations. In many cases fluid flow has been observed to go on for 25 years without reaching boundary dominated flow.