Naturally fractured reservoirs are more difficult, complex and expensive to evaluate using numerical simulation when compared to conventional reservoirs. There are well known approaches, dual porosity and dual permeability system in which two grids - one for the fractures and another one for matrix – are used to model the behavior of fracture reservoirs characterized by initial high production followed by a steep decline and then low production for many years. However, most of the time these approaches require a large amount of input data in addition to being computationally too expensive and time consuming in field applications utilizing many grid blocks to model.

This paper presents a new pseudo-approach in which a single porosity model can be used for modelling of naturally fractured reservoirs with some modification in the absolute permeability and relative permeabilities. The absolute permeability of the single porosity model is enhanced to capture the effect of permeability from the fracture. This can be a multiplier globally applied to all blocks or local enhancement around the wells having high fracture intensity. Initially the flow is mostly coming from the fracture network so the first "fracture dominant" relative permeability or combination of fracture/matrix relative permeability is used, and later in the lifetime of the reservoir, when the flow transitions to primarily matrix flow, a second "matrix dominated" relative permeability is used to control the fluid flow. The key in this approach is to find the time/date which flow diverted from fracture to matrix. This can be determined from the overall oil rate of the field. After finding the correct date, then the relative permeability is altered from "fracture dominant" to "matrix dominant" recurrently on that time.

The new approach is applied to an onshore matured field in Indonesia. The numerical model has the total grid blocks of 1.2 million, 75 wells and around 700 thousand active grid blocks. The original single porosity model could not match the field historical data while dual porosity could captured it correctly. Numerical simulation is utilized along with the new method in a single porosity model for history matching of the field and the results are compared with the dual porosity model of the same model. The absolute permeability enhancement and the first relative permeability curves are used as matching parameters.

The results of this study show that both models having same/similar production and pressure profile. Liquid rate, oil rate, water cut, GOR and average pressure are compared. Furthermore, the runtime for the field case improved by 75%. The total runtime of the new approach was 22 hours resulting in significant speed-up compared to the dual porosity runtime of about 4 days. This approach is going to be used for few other fractured reservoirs in the future where time and/or fracture data are limited.

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