SPE 163609 A Generalized Framework Model for Simulation of Gas Production in Unconventional Gas Reservoirs

Unconventional gas resources from tight sand and shale gas reservoirs have received great attention in the past decade around the world, because of their large reserves as well as technical advances in developing these resources. As a result of improved horizontal drilling and hydraulic fracturing technologies, the progresses are being made towards commercial gas production from such reservoirs, as demonstrated in the US. However, understandings and technologies needed for effective development of unconventional reservoirs are far behind the industry needs, e.g., gas recovery rates from those unconventional resources remain very low. There are some efforts in the literature on how to model gas flow in shale gas reservoirs using various approaches from modified commercial simulators to simplified analytical solutions, leading to limited success. Compared with conventional reservoirs, gas flow in ultra-low permeability unconventional reservoirs is subject to more nonlinear, coupled processes, including nonlinear adsorption/desorption, non-Darcy flow (at high flow rate and low flow rate), and strong rockfluid interaction, and rock deformation within nano-pores or micro-fractures, coexisting with complex flow geometry and multi-scaled heterogeneity. Therefore, quantifying flow in unconventional gas reservoirs has been a significant challenge and traditional REV-based Darcy law, for example, may not be in general applicable. In this paper, we will discuss a generalized mathematical model and numerical approach for unconventional gas reservoir simulation. We will present a unified framework model able to incorporate all known mechanisms and processes for twophase gas flow and transport in shale gas or tight gas formations. The model and numerical scheme are based on generalized flow models using unstructured grids. We will discuss the numerical implementation of the mathematical model and show results of our model verification effort. Specifically, we discuss a multi-domain, multi-continuum concept for handling multiscaled heterogeneity and fractures, i.e., using hybrid modeling approaches to describe different types and scales of fractures from explicitly modeling of hydraulic fractures and fracture network in simulated reservoir volume (SRV) to distributed naturally fractures, microfractures, and tight matrix. We will demonstrate model application to quantify hydraulic fractures and transient flow behavior in shale gas reservoirs. Introduction Even with the significant progress made in producing natural gas from unconventional, low-permeability shale gas and tight gas reservoirs in the past decade, gas recovery remains very low (estimated at 10-30% of GIP). Gas production or flow in such extremely low-permeability formations is further complicated by many co-existing processes, such as severe heterogeneity, large Klinkenberg effect (Klinkenberg, 1941), nonlinear or non-Darcy flow behavior, adsorption/desorption, strong interactions between fluids (gas and water) molecules and solid materials within tiny pores, as well as microand macrofractures of shale and tight formations. Currently, there is little in basic understanding on how these complicated flow behavior impacts on gas flow and the ultimate gas recovery in such reservoirs. In particular, there are few effective reservoir simulators currently available or few modeling studies (e.g., Kelkar and Atiq, 2010) in the industry for assisting reservoir engineers to model and develop the unconventional natural gas resources. Shale formation is characterized by extremely low permeability from subnanodarcys to microdarcys and is different for different type of shales, even under the similar porosity, stress, or pore pressure. As summarized by Wang et al. (2009), the permeability of deep organic-lean mudrocks ranges from smaller than to tens of nanodarcys, while permeability values in