Practical Use of Simulators for Characterization of Shale Reservoirs

Abstract

Shale gas/oil wells are a challenge due to the complex reservoirs and well completion designs. Commercial simulators with new automatic features play an important role in shale reservoir characterization. These commercial simulators include special features for modeling horizontal, multi-fracked shale wells with simplified user interfaces. The primary goal of this paper is to compare the simulation of transient and boundary dominated flow with analytical solutions through specialized rate function plots. These comparisons provide a straightforward means for testing the accuracy of automatic gridding features and the simulation methodology. If simulators can match idealized reservoirs accurately, then confidence improves in the matching of actual field cases that may vary from idealized reservoir behavior. In this work, we tested the accuracy of these simulator features by making numerous simulation runs for various geological and geometric scenarios. We considered different simulation gridding and system models to correctly represent the transient linear flow and its effect on the analysis. Some general gridding rules were developed. This work investigates the use of an effective permeability equation from analytical solution and its application to several wells in reservoirs located in the Bakken, Barnett, and Eagle Ford formations. Simulation was used to confirm the equation’s accuracy and to show its applicability in fractured shale reservoirs. Results from this investigation should help engineers select the best automatic features to accurately represent shale wells and then cross check the results using the analytical solution. This study also expanded our understanding of flow behavior in production data which may be used to improve modeling shale wells for better agreement with the analytical solutions.

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

“…The authors use flowing material balance to calculate fracture volume. Water data presented in our paper showed boundary-dominated flow (BDF) while gas is flowing in the fracture (two-phase flow), which is not the case in the paper by Clarkson and Williams-Kovacs (2013). This study presents a method for calculating fracture properties using water data (flowback and production) for two-phase flow.…”

“…The study by Clarkson and Williams-Kovacs (2013) calculates fracture volume with water data, with the assumption of singlephase water flow. The authors use flowing material balance to calculate fracture volume.…”

Assessment of Eagle Ford Shale Oil and Gas Resources

“…The hydraulic fracture was explicitly modeled such that the fracture conductivity decreases from the center to the tip in the fracture (Y-Z) plane (Honarpour et al 2012). The fracture width was set as 2 ft for calculation purposes; Alkouh et al (2012) shows that reservoir models with the same fracture conductivity but different fracture widths yield similar results. Reservoir Properties Reservoir properties, such as thickness, porosity, and water saturation, were calculated from type logs for all production regions and compared with the literature.…”

Coupled Geomechanics and Fluid Flow Model for Production Optimization in Naturally Fractured Shale Reservoirs

“…The natural fracture permeability was calculated using the fracture permeability equation (Equation 3.13, pg. 27) with an assumed value of 0.001 md-ft. fracture conductivity (Alkouh et al, 2012;Rubin, 2010;Erdle, 2013) and a grid width of 2,000 ft.…”

“…The natural fracture conductivity was assumed to be 0.001 md-ft following work by Alkouh et al (2012), Rubin (2010), and Erdle (2013). The fracture spacing was defined at 50 ft. and the grid width was defined as 2,000 ft.…”