Rock Typing Classification and Hydraulic Flow Units Definition of One of the Most Prolific Carbonate Reservoir in the Onshore Abu Dhabi

Abstract

Abstract Defining the flow and distribution of fluids in porous media has always been of key importance in modeling and predicting the performance of oil and gas reservoirs. Based upon the rock-fluid interactions, reservoir rocks have to be classified into separate flow units called rock types. This task is particularly complex in carbonates as they are generally impacted by diagenesis and cannot be represented by a single porosity permeability relationship per litho-facie. Establishing accurate rock types in carbonates, therefore, requires integration of various petrophysical data with the available rock, fluid and geological information. Various techniques have evolved in the industry for formulating rock-types (Pittman, RQI, FZI, Lucia, Winland, etc.), each technique offering its benefit depending on the nature and variety of data available. This paper presents a newly adopted workflow to formulate an RRT definition for a carbonate reservoir by integrating data from MICP, CCA, petrophysical logs and lithofacies information. The workflow involves associating the pore throat size distribution evaluated using MICP data with the measured porosity and permeability values utilizing the Winland R35 equation. Hydraulic flow units are identified using the Stratigraphic Lorenz Plot, based on the change of flow and storage capacity slopes. Pc, PTR, Phi and K discriminators were established and were used to as cut-offs for defining intervals representing good and poor facies. The new methodology helped to achieve a very good match (>80%) of water saturation from the initialized model with the log derived saturations in all wells drilled thus far in Reservoir-A. The methodology further helped optimize the number of effective rock types required to effectively delineate the field dynamic characteristics, helping reduce run time and anticipated convergence issues.