Integration of Natural and Hydraulic Fracture Network Modeling with Reservoir Simulation for an Eagle Ford Well

Abstract

URTeC 1563066 A data-rich horizontal well in the Eagle Ford Shale was chosen to evaluate Schlumberger's Unconventional Fracture Modeling (UFM) module through an integrated workflow of 3-D natural and hydraulic fracture modeling coupled with reservoir simulation. Initially, a geo-cellular model was constructed using 3-D seismic data, stratigraphic correlations, whole core, and open-hole well log data to distribute reservoir properties. Interpretation of the dual-OBMI acquired in the lateral combined with mudlog data indicated the presence of (at minimum) a partially open natural fracture network controlled largely by seismic-scale structural features encountered by the well. A Discrete Fracture Network (DFN) model was built to characterize the spatial variability in natural fracture intensity and orientation using 3-D seismic and OBMI interpretation. The DFN and geo-cellular models were combined with perforation and cluster spacing, fluid and proppant types, and treatment data in order to generate hydraulic fracture networks using the UFM. Microseismic data recorded during the completion showed event height coverage between 150’-300’ and were used to calibrate modeled hydraulic fracture heights. Multiple UFM runs were generated and results indicated varying degrees of hydraulic fracture complexity, height, length, and proppant distribution on a stage-by-stage basis. Hydraulic fracture geometry appeared to be most sensitive to variations in natural fracture intensity and orientation. Sensitivity runs were also performed to document the impact of stress orientation, stress anisotropy, and stress shadowing (intra- and inter-stage) on the distribution of hydraulic fractures. The UFM hydraulic fracture properties generated for each cluster were incorporated into a coordinate grid system with local refinement within the reservoir simulation model. Additionally PVT data, pressure dependent permeability, computed hydraulic fracture conductivity, 3-phase relative permeability, and non-propped stimulated rock volume (SRV) were included to develop a history match on oil, gas, and water production volumes. A forecast was run to observe pressure depletion, drainage patterns, saturation changes, and fracture contribution.