Abstract
Fracture injection testing has been used in the Oil & Gas industry for decades. In conventional reservoirs fracture injection testing has been a standard practice since important information related to the fracture job design is directly dependent on the outcome of the test (fluid efficiency & leak off coefficient). In this testing method, commonly known as a MiniFrac, fracturing fluid is pumped at typical treatment rates, with a total injection volume of approximately 200 bbls, and pressures are recorded during injection and after pump shut-in.
This study examines the results of a Minifrac conducted in a vertical well in the Marcellus Shale and illustrates how MiniFrac testing can play a useful role in fracture diagnostics in the Marcellus Shale and possibly in other shale formations. In the test case, a volume of 160 bbls of water was pumped at 10 bbls/min; and fracture height growth was infered using wireline temperature logs. The temperature logs showed fracture height containment and these results were validated using pressure response data generated throughout the test. Closure time was estimated to be 6 min and the onset of radial flow was determined to be 4.6 days using a combination of standard fracture diagnostics plots and the pressure derivative. Moreover, a numerical and analytical match of the test was performed and it was interesting to see how the results showed excellent agreement with the field data. Finally, a sensitivity evaluation to pump rate & job volume was performed using a calibrated analytical model, and these results showed fracture closure time is more sensitive to the type of fluid injected and less sensitive to job volume. These results are encouraging and suggest the application of MiniFrac testing in the Marcellus shale, and possibly other shale formations, may be an effective tool in hydraulic fracture diagnostics.
