A New Approach for the Simulation of Fluid Flow In Unconventional Reservoirs Through Multiple Permeability Modeling

Shale reservoirs are characterized by ultra-low permeability, multiple porosity types, and complex fluid storage and flow mechanisms. Consequentially the feasibility of performing simulations using conventional Dual Porosity Models based on Darcy flow has been frequently challenged. Additionally, tracking of water in shale continues to be controversial and mysterious. In organic-rich shale, kerogen is generally dispersed in the inorganic matter. Kerogen is different from any other shale constituents because it tends to be hydrocarbon-wet, abundant in nanopores, fairly porous and capable of adsorbing gas. However, the inorganic matter is usually water wet with low porosity such that capillary pressure becomes the dominant driving mechanism for water flow, especially during hydraulic fracturing operations. This work presents a technique of subdividing shale matrices and capturing different mechanisms including Darcy flow, gas diffusion and desorption, and capillary pressure. The extension of this technique forms a solid and comprehensive basis for a specially-designed simulator for fractured shale reservoirs at the micro-scale. Through the use of this unique simulator, this paper presents a micro-scale two-phase flow model which covers three continua (organic matter, inorganic matter and natural fractures) and considers the complex dynamics in shale. In the model, TOC is an indispensable parameter to characterize the kerogen in the shale. A unique tool for general multiple porosity systems is used so that several porosity systems can be tied to each other through arbitrary connections. The new model allows us to better understand the complex flow mechanisms and to observe the water transfer behavior between shale matrices and fractures under a microscopic view. Sensitivity analysis studies on the contributions of different flow mechanisms, kerogen properties, water saturation and capillary pressure are also presented. Introduction In recent years, unconventional resources have played a significant part to balance between the increasing energy demand and the shortage of production from the conventional reservoirs in the United States (Wei et al. 2013). Hydrocarbon from organic rich shale is one of the most significant unconventional resources. The successful development of shale reservoirs is greatly attributed to horizontal well drilling and hydraulic fracturing operations. In industry, effective hydraulic fracturing for shale wells is performed mainly through injecting slickwater under high pressure. However, generally the recovery of fracturing fluid is quite low. King (2012) suggested that the water might be trapped in the small pores and the micro-fractures of shale. Besides, evidence shows that there is a high concentration of chloride salts in the flowback fluid, while it cannot be explained either from the composition of fracturing fluid (mostly fresh water) or from the constituents of shale and the salinity of formation brine (King 2012). Wang and Reed (2009) propose that there exist four pore systems in the organic-rich shale: inorganic matter, organic matter (kerogen), natural fractures and hydraulic fractures. It is also suggested that the organic matter is oil wet and that single oil or gas phase flow without residual water is dominated in kerogen fragments. However, the inorganic matrix is mostly considered as water-wet (Kalakkadu et al. 2013). Through the approach of Molecular Dynamics Simulation and with the initial condition of water and NaCl, Hu et al. (2013) suggested that water could be filled in the larger pores in the kerogen through capillary condensation but no water enters the smaller 0.9 nm kerogen pores. Water exists in the inorganic MgO pores in the liquid phase; meanwhile, there is a much higher ionic concentration in the inorganic matter than that in the kerogen. In shale gas reservoirs, the source of shale gas can be thermogenic, biogenic or combined source (Darishchev et al. 2013). Natural gas is usually considered to exist in three forms: compressed gas in pores and fissures, adsorbed gas in the organic and inorganic matter, and dissolved gas in the kerogen (Javadpour 2009; Zhang et al. 2012). Usually it might be reasonable