Project details

 Impact of stratigraphic, sedimentologic and diagenetic heterogeneity on flow in carbonate reservoirs

Carbonate reservoirs are typically more complex than their siliciclastic counterparts due to the pore network that is linked to the biological origin of the carbonate grains, and to post-depositional diagenetic processes that can clog existing primary porosity, or improve porosity by promoting dissolution of unstable carbonate phase. Porosity inversions are common.

The complexity of carbonate petrophysical properties represents a challenge for the oil and gas industry: to optimise the production from carbonate reservoirs, predictions of rock properties away from the existing wells are needed. But in rocks where lateral and vertical heterogeneities are common, this is difficult.

Our project is part of the ExxonMobil (FC)2 Alliance. In the framework of the alliance, we aim at simulating multi-phase flow in geologically realistic carbonate reservoirs. The outcrop analogues for the selected reservoirs have been studied by other members of the alliance, and are located in Morocco and in Italy. Petrel models of the reservoirs have either been produced by other team member, or (when needed) can be upscaled using forward sediment models such as CARB3D.

The specific goals of our research project are to be able to simulate a number of different scenarios, and to test the impact on flow of each heterogeneity type by turning them on and off in the model. Thus, we can predict what would happen if the reservoir is produced with water, CO2, or a mixture of both.

Dr. Peter Fitch is the lead investigator on this project, and Drs Matt Jackson and Gary Hampson (Imperial College) provide the modelling and reservoir engineering steer for the project. Dr. C├ędric John is providing steer on aspects of carbonate sedimentology.

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