The application of rate-transient analysis (RTA) concepts to flowback data gathered from multi-fractured horizontal wells (MFHWs) completed in tight/shale reservoirs has recently been proposed as an independent method for quantitatively evaluating hydraulic fracture properties. However, the initial fluid pressures and saturations in the fracture network, and adjacent reservoir matrix, are generally unknown at the start of flowback, creating significant uncertainty in the quantitative analysis of flowback data. A possible approach to recreate these initial conditions is to simulate fluid leakoff during hydraulic fracture propagation (during the stimulation treatment) and subsequent shut-in period prior to flowback. In this study, we present a semi-analytical flow model, coupled with a hydraulic fracture (‘frac’) model and constrained with laboratory-based geomechanical data, for evaluating the initial conditions of flowback.
In previous work, a semi-analytical model based on the dynamic drainage area (DDA) concept was used to simulate water-based fluid leakoff from a MFHW into a tight oil reservoir with minimal mobile water (Montney Formation) in Western Canada during and after fracturing operations. The model assumes that each fracturing stage can be represented by a primary hydraulic fracture (PHF, containing the majority of the proppant), and adjacent non-stimulated reservoir (NSR) or enhanced fracture region (EFR, area of elevated permeability in reservoir caused by the stimulation treatment). Each region was represented by a single-porosity system. The DDA propagation speed within the PHF during the stimulation treatment was constrained through the use of a simple analytical frac model. While this approach was considered novel, several improvements, and additional laboratory constraints, were considered necessary to yield more accurate predictions of flowback initial conditions.
In the current work, the modeling approach described above was improved by
representing the EFR with a dualporosity system and
fully coupling the frac model (used for PHF creation and propagation) with the DDA model for fluid leakoff simulation into the EFR.
Improvement 1) was considered necessary to more realistically represent the spatial distribution of fluids in the EFR and associated saturations and pressures. Improvement 2) was considered necessary to more realistically control PHF propagation speed. Finally, to ensure that model geomechanics were properly constrained, a comprehensive suite of previously-gathered laboratory data was utilized. Laboratory-derived propped (PHF) and unpropped (EFR) fracture permeability/conductivity data as a function of pore pressure, as well as fracture compressibility data, were used as constraints to the model. The improved model was re-applied to the tight oil field case and yielded more realistic estimates of flowback initial conditions, enabling more confident history-matching of flowback data.
The results of this study will be of importance to those petroleum engineers interested in quantitative analysis of flowback data to accurately obtain fracture properties by ensuring that models are properly initiated.