Post-salt carbonate fields are produced by depletion for more than thirty years in Campos basin, Brazil. Usually, they have recovery factors lower than 10%. This article presents a naturally fracture reservoir (NFR) simulation study with undersaturated pressure with no active gas cap and a small aquifer. This work includes a reservoir decision analysis which was done using uncertainty analysis, assisted optimization, comparison among strategies and a reliability test to check how production strategy results behaves when uncertainty parameters are used.

The goal is to present a secondary recovery method to improve oil recovery for this field using the best strategy among water, gas, water and gas and immiscible water-alternating gas (IWAG) injection. Although those methods are highly used for carbonates among oil industries worldwide they are not commonly used in carbonates fields located offshore Brazil, especially in carbonates with oil or mixed wettability. Selection of the best production strategy for this reservoir was determined through a full-field simulation using a commercial simulator with double porosity model.

The main application of this work is the possible implementation of a new production strategy that can change paradigm at how carbonates are produced offshore Brazil. The results and conclusion are based on alternatives to maximize oil production and net present value (NPV).

Comparison among the production strategies indicated water injection as the best way to produce this type of reservoir. The results showed that this method is robust because its economic results did not alter when different parameters representing the major uncertainties were used.

Further studies and implementation of water injection as secondary recovery strategy can boost production at new and mature fields for the huge carbonate play located at the post-salt part of Campos Basin. Indeed, any successful production strategies for carbonates have potential to be extended to pre-salt fields.


Reservoir heterogeneities increase practical and theoretical problems for understanding fluid flow among rocks that contain them. NFR is highly heterogeneous and its characterization, production mechanisms, modeling and simulation are completely different from conventional reservoir. Reservoir production mechanisms in naturally fractured reservoirs are more complex than single porosity reservoirs because, in addition to matrix properties, fracture system properties and factors controlling fluid exchange between the matrix and fractures should be analyzed. Oil recovery factors at this type of reservoir vary greatly because its production depends on matrix flow, fracture system connectivity, matrix-fracture iteration, wettability and how those factors affect the main production mechanism.

Early identification of a fractured reservoir is very important to avoid field jeopardy; indeed if the correct treatment and production strategy are applied since the beginning of the field plan, the results will be reliable production curves, good reservoir management and higher recovery efficiency.

Depletion in a fractured reservoir generates fluid expansion; fluids are then transferred from matrix to fractures. Simultaneously capillarity, gravity, heterogeneity and capillarity continuity can increase or decrease fluid recovery from matrix system. If injection is performed, fluid injected can easily surpass matrix and reach fractures leaving a lot of bypassed oil what usually results in inefficient displacement.. This is the main reason why the use of secondary recovery for NFR and carbonates is limited in Brazilian's post-salt carbonate fields.

Pressure maintenance is important for reservoir management and this is valid for any type of reservoir, even NFR where higher pressure increases imbibition in spite of rock wettability.

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