A new technique is presented to calculate fracture porosity in naturally fractured reservoirs using composite system analyses.

The concept outlined here is to inject a viscous solution (e.g. polymer) which will not invade the matrix rock, but remains in the fractures. Subsequent falloff tests can then be used to determine the bank radius of the polymer in the fractures and thus fracture porosity from material balance. In the early 1980's Marathon Oil Company performed a number of polymer injectivity tests in naturally fractured reservoirs. In several cases, apparent bank radius was much larger than anticipated. This observation lead to the technique proposed in this paper.

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