The determination of the preferential flow direction in a reservoir becomes a very important subject for the development of an oilfield, especially for the selection of the optimum exploitation strategy taking into account that porous media is a very complex environment in which representing the flow behavior of fluids becomes a tough task, mainly in carbonates where the distribution of fractures, lithology changes and diagenesis play a major role in this topic.

Naturally Fractured Reservoirs (NFR) represent a great technical challenge for the petroleum industry because they behave as a heterogeneous medium with a strong influence of diagenesis, a term that encompasses fractures, dissolution, compaction, dolomitization, cementation and recrystallization to conform a reservoir with totally different distribution of properties. The dynamic data must be evaluated in order to match with the static model achieving a good reservoir characterization.

In this paper we present a way to determine the preferential flow direction by the monitoring of the field through permanent real-time downhole gauges that allowed the identification of the interference between wells in a deep naturally fractured reservoir that originally did not show any degree of communication. Suddenly, after some producing time, the field demonstrated a great level of interference among wells and as a consequence, the determination of the preferential flow direction was possible through Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA). Emphasizing the Palacio-Blasingame1  type curves (PBTC), in which we compare the results obtained using this analysis with its standard form and the one achieved with Material Balance Time (MBT). Additionally, Fetkovich2  decline type curves were also used in the rate analysis.

Finally, a comparison of the geological model with the dynamic data was also applied to further enhance the quality of the data. The results showed conclusive preferential flow direction with the wells tested.

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