The use of pressure data to understand reservoir flow characteristics has been evolving since Darcy's Law was published in 1856. Welltesting has evolved from straightline methods to sophisticated interpretation models which use Log-Log pressure and derivative diagnostic plots to recognize flow regimes. This allows analysis to be performed on a valid subset of the data.

It has long been known that reservoir fluid flow alone will very rarely if ever create a Bourdet derivative slope of greater than one. Mohamed et al (2011) showed that for tight shale gas mini-fracs, the derivative slope during fracture closure is equal to 3/2. This diagnostic signature is readily apparent in Mini-Frac tests of the Alberta oilsands caprock which flags it as a nonreservoir geomechanical effect.

Mattar (1997) showed reservoir flow has a characteristic shape on the primary pressure derivative plot: the primary pressure derivative data continuously declines for all reservoir flow regimes. The primary pressure derivative appears to stop declining while the fracture is closing and resumes declining after the fracture is closed (it can increase for the forced closure case).

Barree et al (2009) uses G Function and Square Root plots and their derivatives to indentify flow regimes as the basis for establishing fracture closure. This sounds familiar to Bourdet's pressure derivative rationale.

This paper shows these methods compliment conventional PTA and give consistent repeatable mini-frac solutions for oilsands caprocks. The incorporation of fracture solutions into PTA programs is another step forward to delivering reliable, consistent analysis for mini-fracs, however, these solutions only exist for falloff whereas the 3/2 slope and primary pressure derivative also work for flowback assisted fracture closure.

Several examples will be presented to illustrate that Pressure Transient Analysis is a useful tool for resolving Mini-frac data, especially the start and end of fracture closure.

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