The main parameters of interest derived from a diagnostic fracture injection test (DFIT) are minimum in-situ stress, reservoir pressure, and permeability. The latter two can only be obtained uniquely from the transient reservoir responses, often requiring days to weeks of test time. The DFIT flowback analysis (DFIT-FBA) method, a sequence of pump-in/flowback (PIFB), is a fast alternative to the pump-in/falloff (conventional) DFIT for estimating minimum in-situ stress and reservoir pressure. Because the properties of the fracture are unknown, reservoir permeability cannot be estimated directly and therefore well productivity index (PI) has been reported in previous DFIT-FBA studies. The goal of the current study is to develop a methodology for estimating reservoir permeability and fracture properties from a DFIT-FBA test.
In this study, a fully coupled hydraulic fracturing, reservoir, and wellbore simulator was used as a first step to identify critical mechanisms operating during the flowback period of a DFIT-FBA test. Subsequently, findings from the simulator were used to develop an analytical solution to estimate reservoir permeability, fracture surface area, open fracture stiffness, and contact pressure. The analytical model relies on a new rate-transient analysis (RTA) technique that accounts for the dynamic behavior of the fracture and changing leakoff rate during the before-closure period. The proposed approach was validated against a simulation case, and its practical application was demonstrated using a field example performed in a tight reservoir.
The reservoir permeability and fracture surface area, derived from the analytical model at the contact point, agree within 2% of the simulation model input. The field example examined herein exhibited flow regimes similar to the simulation case, and fracture surface area, open fracture stiffness, contact pressure, minimum in-situ stress, reservoir pressure, and permeability were all obtained in a fraction of the time required by conventional DFITs.