Establishing Key Reservoir Parameters With Diagnostic Fracture Injection Testing
- Bahareh Nojabaei (Pennsylvania State U) | C. Shah Kabir (Hess Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Americas Unconventional Resources Conference, 5-7 June, Pittsburgh, Pennsylvania USA
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 1.2.2 Geomechanics, 5.6.4 Drillstem/Well Testing, 1.2.3 Rock properties, 3 Production and Well Operations, 5.8.4 Shale Oil, 4.1.5 Processing Equipment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.1.2 Separation and Treating, 5.8.2 Shale Gas
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Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a very short time period, initiating a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture closure pressure, and the fracture pseudolinear-flow period leads to the initial reservoir pressure.
In most tests, wellhead pressure (WHP) measurements are used because of cost considerations. A wellbore heat transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pfb) during the injection period. As expected, the pfb always turns out to be higher than the fracture closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.
A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than its transverse counterpart.
Unconventional shale gas reservoirs present unique challenges to transient testing primarily because of very low-matrix permeability, which is in the nanodarcy range. In contrast, the shale oil reservoirs have permeability in the microdarcy range. However, higher oil viscosity makes the mobility of the two systems comparable. The ultra-low mobility coupled with complex well architecture presents real challenges for devising transient tests that can yield the desired formation and geomechanical parameters within a practical time frame.
To this end, the industry has adapted Nolte's (1979) minifrac test, originally intended for conventional formations, to meet the challenges that the shale reservoirs present. In the literature, the short-term test has been given various names, such as the minifrac test, fluid leakoff test, and DFIT, among many others. For consistency, we refer to it as DFIT. DFIT entails inducing a hydraulic fracture by injecting a small volume of fluid into the formation and shutting the well in for a long-duration falloff. Typically, this type of test allows estimation of pfb, pfc, initial reservoir pressure (pi), the leakoff type, and some measure of formation conductivity. Of course, the injection period leads to the determination of pfb, whereas the falloff analysis yields the remaining parameters.
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