Oil and gas field developments in the 21st century gained from the benefits of new technologies in reservoir characterization, including: intelligent field data, fine resolution geologic and mega-cell simulation modeling, and super-computing computer clusters. This paper elaborates how these technologies have been fully utilized - in the building of the geologic and simulation models for a giant carbonate oil field - and in understanding well and reservoir behaviors, as well as quantifying inter-reservoir communication between two carbonate reservoirs. The model building process includes: Facimage matrix permeability; fracture characterization; conditioning to dynamic permeability from pressure transient tests and flow-meter profiles; Thomeer function based water saturation distribution; and matching intelligent field well production, injection and pressure data. The fine layers resolution model allows capturing of detailed heterogeneity in wells as well as minimizing the error associated with model upscaling. Use of smart and assisted history matching tools - coupled with the powerful hardware - make possible the use of different discriminators to quickly test the following: possible baffles and barriers, high flow layer and/or local permeability enhancement. These geological features are not easy to map. Matching of numerous intelligent field well production/injection data and pressure improves the reliability of this simulation model. A simulation model that could both reproduce short- and long-term production performance enables a wider application - to support operations and proactive management of the field - as an outcome of utilizing these proven technologies.


Reservoir characterization is the foundation of any reservoir simulation model since a reservoir model is only as good as the underlying geological model. Reservoir characterization includes rock characterization and fracture characterization. In Saudi Aramco, subsurface geoscientists commonly utilise both facies and petro-physical rock typing (PRT) for rock characterization. However, a novel approach, developed in-house (Clerke et al. 2009), has successfully characterized the Arab D carbonate reservoirs in Saudi Arabia. This method analyses all pore systems with the Thomeer function (Thomeer. 1960) using an extensive mercury injection capillary pressure (MICP) data set. Thomeer parameters are then generated for each grid cell and in turn used to calculate permeability, relative permeability and water saturation. The main advantages of this method over other available techniques are that it efficiently describes multi-modal pore systems and was developed based on basic physical principles.

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