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Collaborating Authors
Results
Summary 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.
- North America > Canada > Alberta (0.68)
- North America > United States > Texas (0.46)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
Rigorous Estimation of the Initial Conditions of Flowback Using a Coupled Hydraulic Fracture/Dynamic Drainage Area Leakoff Model Constrained by Laboratory Geomechanical Data
Zhang, Z. (University of Calgary) | Yuan, B. (University of Calgary) | Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Williams-Kovacs, J. D. (University of Calgary)
Abstract 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 byrepresenting 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.
- North America > United States > Texas (0.68)
- North America > United States > California (0.67)
- North America > Canada > Alberta (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Greater Peace River High Basin > Upper Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)