Integration of Microseismic-Fracture-Mapping Results With Numerical Fracture Network Production Modeling in the Barnett Shale

Abstract

Abstract This paper presents the results of integrating microseismic fracture mapping with numerical production modeling of fracture networks in the Barnett shale. Microseismic fracture mapping has shown that hydraulic fracture treatments create large-scale fracture networks in the Barnett shale1–2. In this paper an approach is presented, where the fracture network measured with microseismic mapping is approximated with a numerical production simulator that discretely models the network structure in both vertical and horizontal wells. The work includes a production history match of a vertical Barnett shale well, where the microseismic mapping results were directly used to approximate a fracture network in the reservoir simulator, resulting in an estimate of effective fracture network length, average fracture conductivity and effective drainage area. In addition, a parametric study for horizontal wells is presented to show how fracture network size and density, fracture conductivity, matrix permeability and gaps in the network affect well productivity. Simulations on the effect of fracture face damage along the network, the effect of non-darcy flow in the network, and tapered fracture network conductivity that decreases away from the well are also included. The numerical model was also used to simulate how a pressure buildup test would appear based on given fracture network properties, which could be a useful diagnostic to evaluate the effectiveness of the fracture network. The results of this work illustrate how different fracture network characteristics impact well performance, which is critical for improving future horizontal well completion and fracturing strategies in the Barnett shale. This could include optimizing the number of fracture stages along the lateral, length of the lateral, treatment sizes, and perforation strategies as well as enhancing fracture network conductivity and the effectiveness of re-fracture treatments. The work also shows how microseismic mapping results can be integrated with production modeling, thereby providing a tool for more realistic infill drilling and well placement studies in the Barnett shale or similar types of reservoirs. Introduction The Barnett shale is currently one of the most prolific unconventional reservoirs in the U.S. Although the production continues to expand geographically, the core area of the Barnett gas play is located in North Texas around the city of Ft. Worth. The Barnett shale is a Mississipian-aged black, organic-rich shale at depths of about 6,500 ft to 8,500 ft. It serves as its own source, seal, and reservoir3. Lithologically, it consists of siliceous shale, limestone, and minor dolomite3. Because of the ultra-low shale matrix permeability (permeabilities of about 10 to 100 nano-Darcy), this reservoir needs to be hydraulically fractured in order to be productive. Typical vertical-well fracture treatments are large 20,000 to 50,000 barrel light-sand waterfracs4. Roughly two-hundred wells in the Barnett shale have been mapped with microseismic imaging over the past several years. The fracture mapping allows for direct measurement of the fracture network orientation, height, length and width5–8. The results have been used to determine well spacing, offset well locations, refrac candidate idenfication, staging strategies and real-time changes to fracture treatment design and execution in both horizontal and vertical wells. The fracture mapping results showed that the hydraulic fracture growth is complex in the Barnett Shale1–2. Understanding the impact of the fracture network properties on well performance is critical to successfully developing and optimizing production in the Barnett shale.