Identifying natural fractures and assessing their impact on flow behavior in hydrocarbon reservoirs have been one of the key challenges in defining the field development strategy. Failure to correctly represent the natural fractures when working on a reservoir development plan can lead to poor performance and failure to analyze reservoir response. Pressure transient testing is widely recognized as a core competency in the oil industry as it provides subsurface specialists with valuable information regarding the reservoir properties, well connectivity to the reservoir and extent of reach into the reservoir.

When borehole image (BHI) data triggers a signal that fractures are seen in wells but flow rates do not show production dominated by fractures, the engineers working on the reservoir need to pay attention to pressure transient tests. Depending on the contrast between fracture permeability and matrix permeability, pressure transient analysis in a fractured reservoir can show clear dual porosity behavior, or the effect can be masked by the wellbore storage. The latter happens when the contrast between the matrix permeability and the fracture permeability is small.

The two parameters which characterize a dual porosity model are the storativity ratio, ω, and the inter-porosity flow coefficient, λ. The average value of λ for the vertical wells studied is 25*10−4, confirming a low contrast between fissure and matrix permeability. For the storativity ratio, a typical value is between 0.001% and 0.1%. An average of 0.03% has been calculated from the well tests.

With the results from pressure transient tests, BHI and core description, fractures have been defined as mild with relative low-intensity. Numerical modeling on a field sector was employed to test the impact of the fractures on production.

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