Modeling Gas Production from Shales and Coal-Beds

Advisor

Khalid Aziz

Abstract

Development of shale gas has transformed the energy outlook of US in the past decade. Identification of massive global resources and development of technology for economically producing gas from such sources is making a huge impact on the energy picture. According to EIA (EIA, 2011) the total gas resources of the world are estimated to be about 22,600 TCF of which 40% is now contributed by shale plays.

Shales have complex pore networks and distinct scales for fluid flow. There are at least four types of porosities present in shales: Inorganic porosity, nano-porosity within organic Kerogen and porosity associated with both natural and artificially created fractures. Also, significant gas is assumed to be adsorbed in the Kerogen. Naturally occurring shales have little matrix permeability though. Horizontal drilling assisted by multi-stage hydraulic fracturing make gas production from shales viable. This increases near well-bore conductivity and also stimulates the network of natural fractures.

Modeling fluid transport in shales is challenging. This is due to the combination of multiple porosities, gas desorption and slippage effects. We present two numerical schemes to simulate gas production from such systems. In the Single Porosity Model, we assume that there is only one distinct pore network and the gas desorbs instantaneously from the shale matrix as the reservoir depletes. In the Dual Porosity Model we consider two coupled porous networks with desorption in the organic nano-pores. Langmuir Adsorption Isotherm (Langmuir's 1916) is used to model the desorption process. Slippage of gas molecules within nano-pores is incorporated using Klinkenberg's Effect, (Klinkenberg 1941).

Single Porosity Model is observed to be less consistent with both pore networks and desorption process in shales. In Dual Porosity Model, natural fractures permeability (kf) significantly affects early stage of gas production and matrix-fracture flux coefficient (Dmf) controls the slow desorbed flux in later half of production. Also, high Langmuir's Volume (VL) increase production and delay pressure depletion within the reservoir.

We also present a scheme to simulate gas recovery from naturally occurring coal seams. Single porosity, two phase gas-water code with instantaneous desorption is developed to model initial-dewatering and depletion phase of a typical Coal-bed Methane well.