Carbonate reservoir systems are typically made up of different lithology and porosity types. Each type of porosity has complexity of pore system; pore geometry, size, and size distribution and pore throat. Variety in pore type associate the variety of the main log analysis parameters; saturation exponent; n and cementation exponent; m as well as the variety of single and two phase fluid flow properties such as permeability, porosity-permeability transformer, relative permeability and capillary pressure.
Dealing with a heterogeneous carbonate as one unit has the constant value of n and m resulted in inaccurate determination of:
Fluid saturation and saturation profile.
Pay intervals.
Hydrocarbon reserve
On the other side, assuming heterogeneous carbonate has the same flow characteristics resulted in:
Unreliable prediction of permabilities and dynamic flow capacity
Ineffective reservoir management
Unreliable simulation model, if the model layers are not based on the variety of rocks and pore type.
Generally, recognizing the different pore and rock type through heterogeneous carbonate is one of the most difficult challenges. There are no universal applicable techniques to recognize the different rock types and flow units through heterogeneous rock. Conventional log response and traditional log interpretation do not have the ability to discriminate the different rock types. So, discriminating between rock types and flow units through heterogeneous carbonate, require integration for all the available data.
Miocene carbonate in the central part of the Gulf of Suez is an example of the heterogeneous rock. This paper demonstrates how the conventional log interpretations lead to improper perforation selection and ineffective stimulation. A simple approach has been established to define the reservoir using series of cross plots for the old wells logging and the production results. Moreover, the flow units from the recent cores, open hole and production logging, throughout Miocene carbonates confirm the discriminated flow units approach.
Differentiating the interesting pay intervals through out masses carbonate rocks admixture with evaporates is a challenging task. The interesting intervals are the intervals have potential hydrocarbon and reasonable productivity. With regard to the hydrocarbon potentiality, it has been interpreted using the well logging measurements. There is no direct tool to measure the hydrocarbon saturation (water saturation). Water saturation is an interpreted parameter that is highly affected by the accuracy of input parameters of the model used in the calculations. There are many saturation models, which range from a very simple one like Archie model and a very complex one like Waxman-Smits model. The choice between a suitable model is based on the rock and the geology of the reservoir. Generally, the common saturation models input parameters, could be listed as follows:
Formation water resistivity, Rw
True formation resistivity, Rt
The saturation exponent; n
The cementation exponent; m
Porosity.
This paper concern with the effect of the saturation and cementation exponent because these exponents related to the flow characteristic (productivity) in addition to hydrocarbon potentiality.
