In a diagnostic fracture injection test (DFIT), a relatively small volume of fluid is injected into the subsurface, creating a hydraulic fracture. After the end of injection, the pressure in the wellbore is monitored for hours or days. The pressure measurements are used to infer properties of the formation, including the leakoff coefficient, permeability, fracture closure pressure (which is related to the magnitude of the minimum principal stress and the net pressure), and formation pressure. These are key parameters for hydraulic fracture design and reservoir engineering in shale.

During period #1, a fracture has not formed and wellbore storage controls the pressure behavior. The leakoff point occurs at #2, the fracture propagation pressure is reached at #3, and the ISIP (initial shut-in pressure) is reached at #4. DFIT analysis is primarily interested in analyzing the trends in pressure that occur in the hours and days after shut-in.

Petroleum engineers and hydrologists are familiar with different types of “pressure transient tests” in which pressure trends over time are used to infer formation properties. For example, the simplest pressure transient tests are production or injection tests, in which fluid is injected or extracted at constant rate from the well. In these conventional well tests, the fluid pressure remains below the minimum principal stress and a fracture is not formed.

You might wonder, why do we need to use a fracturing test to infer permeability? Why not just use a conventional production or injection test, in which a fracture is not formed? The reason is that in very low permeability formations, it is very difficult to inject or produce fluid at sufficient rate. If injection is performed, pressure will build up rapidly until a fracture forms, unless an impractically low injection rate is used. If production is attempted, the rate will be too low to get meaningful results.