In this presentation, a new method is introduced for interpreting diagnostic fracture injection test (DFIT) data. The method is based on results from a three-dimensional hydraulic fracturing simulator (CFRAC) that allows fractures to retain aperture after mechanical closure. After closure, an empirical, non-linear joint closure law is used to relate fracture aperture and stiffness to the effective normal stress. Fracture closure increases fracture stiffness, which, in low permeability formations, causes an increase in the pressure derivative. The resulting pressure signal in a G-function analysis plot has often been incorrectly attributed to fracture height recession or closing of secondary transverse fractures, leading to a misidentification of closure pressure. Based on simulation results, best practices are offered for estimating closure pressure, which are validated with a series of numerical simulations and field examples.
The implications are important for hydraulic fracture modeling. Using the new methodology, all historical DFIT data in a major unconventional play were reexamined and fracture closure pressure for interpretable tests needed to be adjusted upward by about 600 psi on average. This finding made necessary a reexamination of pressure-history-calibrated fracture models in which closure pressure was derived from the prior DFIT analysis. Yet the revised-upward in-situ stress greatly diminished or eliminated the need to aggressively invoke arbitrary adjustment parameters such as process zone stress in model calibration efforts.
In addition to the discussion on fracture closure, a system of DFIT consistency checks will be introduced to assess the reliability and robustness of interpreted reservoir stress (αh), pore pressure (pi) and fluid transmissibility (kh/μ). Field cases from various low permeability and unconventional reservoirs will be used to demonstrate key points.