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To achieve optimal production from tight or unconventional reservoirs, it’s important to determine the permeability, pore pressure and state of stress of rock strata, including the caprock and underlying intervals.  Doing so will lead to properly designed hydraulic fracturing treatments, realistic predictions of well performance, and a basis for normalizing reservoir contribution when evaluating completion and stimulation effectiveness. 

 

A time-honored way to derive the necessary reservoir information is to conduct in-situ pressure transient tests.  Since it is difficult to inject fluid into or withdraw fluid from the pore network of ultra-tight rock, hydraulic fracture propagation can be used to provide the injection event.  A hydraulic fracture bypasses wellbore damage and near-wellbore stress concentrations and connects wellbore to a significant portion of the reservoir layer thickness.  Evaluating the pressure falloff response of small-scale hydraulic fractures enables reservoir transmissibility (kh/u) to be evaluated by a variation of the impulse testing method.  As well, the minimum principle stress is derived by identifying fracture closure.    

 

Consequently, diagnostic fracture injection testing (DFIT) has been used extensively in unconventional reservoir plays to gain insight into stress and transmissibility - yet with mixed results.  The presenter will briefly outline the basic theory and implementation process of DFIT and then discuss practical considerations that strongly influence the value we derive from these tests.  Examples will be used from DFIT projects in Eagle Ford, Bakken and Poland.  Items to be covered may include: