One of the top concerns for carbonate reservoir evaluation is the effect of rock texture on permeability, capillary pressure and relative permeability. Recent advances in log analysis combined with new logging sensors that are sensitive to carbonate rock texture have led to an improved workflow for petrophysical analysis of carbonates. The authors have earlier described an approach to estimating permeability in carbonates from borehole NMR logs and electrical images, and have earlier studied the relationship between NMR T2 distributions and capillary pressure curves in carbonates. Additional enhancements have been made to this workflow to include estimates of relative permeability by modeling invasion of mud filtrate utilizing a fluid flow model in combination with array resistivity logs. Analyzing relative permeability in conjunction with formation permeability and capillary pressure leads to new insights in log-based rock typing for comparison with Special Core Analysis (SCAL) data. This workflow is presented in the form of a case study of a carbonate well in the UAE. The workflow will be reviewed in its entirety with particular emphasis on the relationship between log rock texture and permeability, capillary pressure and relative permeability. Introduction Many of the giant carbonate fields of the Middle East are undergoing Enhanced Oil Recovery (EOR) via water flood, gas injection and/or combinations of both to improve ultimate oil recovery. The advance of fluid fronts in fields undergoing EOR typically varies within the formation layers, with permeability usually being the controlling factor. Decades of experience with routine and special core analysis, surveillance logging and production logging have confirmed the critical role permeability plays in hydrocarbon recovery and Masalmeh et al. (2003) examine the effect relative permeability and capillary pressure play in EOR. Several authors, Gyllensten et al. (1999) and Haro (2004) have proposed various methods for estimating permeability from wireline logs and one of the most common is to identify rock types, which each have a particular porosity-permeability relationship. The workflow presented here facilitates various forms of rock typing. Marzouk et al. (1997) presented a form of carbonate rock typing based on porosity partitioning that is consistent with the Dunham Classification (Dunham, 1962, Embry and Klovan, 1971). Amaefule et al. (1993) describe a more generalized rock typing method based on the Flow Zone Indicator (FZI) that delineates rock types from poro-perm relationships. Grotsch et al. (1998) have presented a rock typing scheme based on property cut-offs, thin section analysis, and high pressure capillary pressure data and pore-throat size distributions. These three forms of rock typing can be supported by the workflow presented in this paper and, in addition to these methods, there is potential to examine a new form of rock typing based on estimates of relative permeability. Carbonate Analysis Workflow The workflow presented has three basic steps and is described in detail by Ramamoorthy et.al. (2008). At each step of this workflow there are log displays and cross-plots to check results against available core data. These checks will be described for each step. Both routine core analysis (RCAL) data such as porosity, permeability and grain density, and Special Core Analysis (SCAL) data such as mercury injection capillary pressure (MICP), and relative permeability curves can be utilized during the workflow. Even though such core data may be available only on a few key wells in a given field, the fine tuning of parameters based on the detailed core-log analysis can normally be applied on a field wide basis.

The carbonate reservoirs pose various challenges in hydrocarbon exploration, development and production phases. Primarily, syn and Post-depositional processes like diagensis and bioturbation alter the original fabric of the rock to account for the variations in reservoir properties and rock qualities which impact the decision making for optimum production and development. Therefore, it is very important to understand the link between the geological controls and reservoir heterogeneity, quality and performance to better characterize, quantify and predict carbonate reservoir quality variation across the field.An attempt has been made to apply a rigorous methodology in the studied field of North Oman for the Middle Cretaceous Natih-A carbonate reservoir to understand the reservoir heterogeneity and properties and their impact on the water saturation profile variation with the help of borehole images, NMR (Nuclear Magnetic Resonance) and core measurements. This work aims at developing an initial field-wide understanding. The addition of new wells and acquisition of more data will help to validate the concepts evolved in this study in an integrated framework.The borehole micro-resistivity images were processed and interpreted to identify facies based primarily on variations on image textures in conjunction with conventional open hole logs and cores acquired. The conductivity data from the images were transformed into porosity distribution maps and histograms to capture the subtle porosity variations due to the heterogeneity in the formation, which were not able to be depicted by conventional open hole logs because of the resolution and azimuthal coverage. The images derived porosities and textural quantitative indicators among the three studied wells illustrated the heterogeneity variations from well-to-well and revealed a trend for diagenetic and bioturbation changes in terms of prospective flow units that were collaborated with core data.Afterwards, the need to understand the fluids distribution (saturation profile) and their production potential led to the integration of NMR data with the image derived results. The pore size distribution, bound fluid volume, and permeability measurement from NMR helped to understand the fluid saturation profile on studied wells.The conventional open hole logs were suggestive of variable hydrocarbon saturation profile not in an obvious relation to porosity variation and the advanced integrated analyses with borehole images and NMR helped in gaining a better control on understanding its nature. The analysis results suggested two prospective flow units in terms of bound fluid volume, pore size distribution and the textural variations. A few sub-units were also identified to address the minor heterogeneities which influence fluid flow through them.The methodology developed here helped in understanding the hydrocarbon saturation profile behavior on field scale and provided an opportunity to be utilized for optimal exploitation of the reservoirs. To date, the well B & C have been complet...