A Novel Approach for Estimating Formation Permeability and Revisiting After-Closure Analysis of Diagnostic Fracture-Injection Tests
- HanYi Wang (University of Texas at Austin) | Mukul M. Sharma (University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- August 2019
- Document Type
- Journal Paper
- 1,809 - 1,829
- 2019.Society of Petroleum Engineers
- Normalized Stiffness Plot (NS Plot), Pressure Transient Analysis, Permeability Estimation, Diagnostic Fracture Injection Test (DFIT), After-Closure Analysis
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- 136 since 2007
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Estimating reservoir-flow capacity is crucial for production estimation, hydraulic-fracturing design, and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results might not be representative at a field scale because of reservoir heterogeneity and pre-existing natural-fracture systems. Diagnostic fracture-injection tests (DFITs) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low-permeability reservoirs, after-closure radial flow is often absent and this can result in significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: Carter leakoff and constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure; therefore, G-function-based models and subsequent related work can lead to an incorrect interpretation and are not capable of consistently fitting both before- and after-closure data coherently. Moreover, current after-closure analysis relies on classic well-test solutions with a constant injection rate. In reality, a “constant injection rate” does not equal “constant leakoff rate into the formation,” because more than 90% of the injected fluid stays inside the fracture at the end of pumping instead of leaking into the formation. The variable leakoff rate clearly violates the constant-rate boundary condition used in existing well-test solutions.
In this study, we extend our previous work and derive time-convolution solutions to pressure-transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that the G-function and the square-root-of-time models are only special cases of our general solutions. In addition, we found that after-closure linear-flow and bilinear-flow analysis can be used to infer pore pressure reliably but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation-flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds significant value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.
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