Many tight or shale gas wells exhibit a linear flow regime that can last for years. However, production analysis in unconventional oil reservoirs, such as the Bakken, shows that the linear flow regime is not the only dominant flow regime. Field data suggest that the duration of boundary-dominated flow influenced by the stimulated-reservoir volume (SRV) and compound-linear flow generally overshadow the early-time linear flow regime. Depending on the fracture network or SRV patterns, formation linear flow in unconventional oil reservoirs may only last for a few months but contribute about 30% of the total estimated ultimate recovery (EUR).
This study develops a procedure for identification of different fracture network patterns and inference of related flow parameters based on analytical methods. The reservoir description so derived is transported to a numerical reservoir-flow simulation model to capture the effects of compaction, multiphase flow behavior, and various flow regimes in an unconventional oil reservoir system.
This coupled approach helps illuminate reservoir performance, which allows insights into history matching. In particular, we demonstrate (a) fracture network patterns and flow regime diagnosis through rate-transient analysis; (b) coupled numerical reservoir simulation with analytical modeling results for performance-constrained history matching; (c) sensitivity analysis on the heterogeneity effect, compaction effect, and multiphase flow effects; and (d) field application of the proposed procedure on Bakken wells.
This proposed method demonstrates that analytical methods should be used before undertaking a detailed numerical reservoirflow simulation study. This understanding paves the way for much improved reservoir characterization in unconventional oil reservoirs.