The development of shale plays in North America has achieved great success in satisfying increased energy demand. With the advances in experimental approaches, investigation of microstructures in organic-rich shale has identified several different pore types and the abundance of pores from the nanometer to the micron scale. Yet current modeling work for such reservoirs is mainly performed with dual porosity models based on Darcy's law. In addition, a great discrepancy between simulation results and production data persists. Because flow regimes in porous media are quite sensitive to pore size, the flow mechanisms in shale reservoirs are considerably more complex than Darcy flow and the feasibility of conventional models has been frequently challenged. This work presents an integration of realistic multi-porosity and multi-mechanistic treatments to resolve the conundrum of fluid flow in shale.
Based on a unique reservoir simulator, a micro-scale multiple-porosity model for gas flow in shale reservoirs is presented in this paper. The model consists of three separate porosity systems: kerogen, inorganic minerals, and natural fractures. Inorganic and organic portions of the shale matrix are represented by sub-continua with different characteristics considering pore structures, fluid storage and flow mechanisms. In the kerogen gas desorption, diffusion and Darcy flow occur simultaneously. Through considering the different pore families in the kerogen, the effects of nanopores and microporosity are incorporated into the model. In addition, a novel gridding scheme has been specially designed to recognize the complex structures. To accomplish this, the grid incorporates randomly distributed kerogen in the shale matrix and different continua are tied to each other via arbitrary connectivities. Through changing the properties of both matrix and fracture, a unified concept of dynamic apparent permeability of shale matrix is proposed. The derived concept allows the design and function of the Micro-Scale Model to be extended to the reservoir scale model containing hydraulic fractures. The more realistic gas production forecasts using the workflow presented in this paper indicate significant differences from that of conventional models. The ability to more accurately simulate the complex flow mechanisms using the proposed techniques will allow operators to better predict and enhance ultimate recovery from shale reservoirs.
The development of gas shale plays is much more difficult than that of conventional reservoirs, and horizontal well and hydraulic fracturing technologies are indispensable to obtain profitable production rates in shale gas reservoirs (King 2010). However, so far there is no acceptable theory system to sufficiently evaluate and forecast shale gas production (Passey et al. 2010), since there exist a lot of complexities and uncertainties for such kind of reservoirs.