SPE-168966-MS Modeling Analysis of Transient Pressure and Flow Behavior at Horizontal Wells with Multi-Stage Hydraulic Fractures in Shale Gas Reservoirs

Handling flow through fractured media is critical for transient pressure and flow analysis in shale gas reservoirs, because gas production from such low-permeability formations relies on fractures, from hydraulic fractures and fracture network to various-scaled natural fractures, to provide flow channels for gas flow into producing wells. This study presents a numerical investigation of pressure and flow transient analysis of gas production from a horizontal, multi-staged well in shale gas reservoirs. A specialized three-dimensional, two-phase simulator is developed and used for this purpose, which incorporates known nonlinear flow behavior in shale gas reservoirs. First we discuss a multi-domain, multi-continuum concept for handling multi-scaled heterogeneity and fractures, i.e., using hybrid modeling approaches to describe different types and scales of fractures from explicit modeling of hydraulic fractures and fracture network in simulated reservoir volume (SRV) to distributed natural fractures, microfractures, and tight matrix. Then sensitivity studies of transient pressure responses and flow rates are presented with respect to hydraulic fractures geometry, stimulated reservoir volume (SRV), and natural fracture density. We will also compare the behaviors with two different interporosity flow assumptions, fully-transient and quasisteady state flow. Unlike conventional reservoirs, their difference cannot be ignored due to the extremely low shale matrix permeability and significant gas compressibility. Specifically, we will analyze a field example from Barnett shale to demonstrate the use of results and methodology of this study. Introduction Flow behavior in shale gas and tight gas reservoirs is characterized by single-phase (gas) and/or multi-phase (gas, gas condensate and/or brine) flow and transport in extremely low-permeability, highly heterogeneous porous/fractured, and stress-sensitive rock. The multi-scaled fractures, from hydraulic fractures/network to various-scaled natural fractures provide flow channels for gas flow into producing wells. Therefore, any unconventional reservoir simulator must have the capability of handling fractured media. The published modeling exercises in the literature have paid a lot of attention to model fractures in shale gas formations (e.g., Cipolla, 2009; Freeman et al. 2009a; 2009b; 2010; Moridis et al. 2010; Rubin, 2010; Wu et al. 2012, Wang and Wu, 2013). However, it should be pointed out that there have been very few studies carried out to address the critical issues how to accurately simulate fractured unconventional gas reservoirs or to select the best approach for modeling a given shale gas formation. Many of the modeling exercises use commercial reservoir simulators, developed for conventional fractured reservoir simulation, which have very limited capabilities of modeling multi-scaled or complicated fractured reservoirs. On the other hand, in order to simulate fractured unconventional gas reservoirs, more efforts on model developments are needed from new conceptual models to in-depth modeling studies of laboratory to field scale application. Double Porosity Model: Double-porosity model is an idealized model, originally proposed by Warren and Root (1963) and as shown in Figure 1. In the double-porosity model, a flow domain is composed of matrix blocks with low permeability, embedded in a network of interconnected fractures. Global flow and transport in the formation occur only through the fracture system, conceptualized as an effective continuum. This model treats matrix blocks as spatially distributed sinks or sources to the fracture system without accounting for global matrix-matrix flow.