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AAPG GEO 2010 Middle East
Geoscience Conference & Exhibition
Innovative Geoscience Solutions – Meeting Hydrocarbon Demand in Changing Times
March 7-10, 2010 – Manama, Bahrain

Flow Units Characterization in a Dual Porosity-Permeability Carbonate Reservoir: A Case Study from Western Offshore, India

Ajay Kumar1; Aks Kakani1; Calvert Stefan1; Sutapa Bhadra2; Arpana Sarkar2; Chandramani Shrivastva2

(1) BGEPIL, Mumbai, India.

(2) DCS, Schlumberger Asia Services Ltd., Mumbai, India.

Understanding the distribution of flow units in complex carbonate reservoir is of utmost importance in development planning and production optimization. The variation in reservoir properties along with the texture in carbonate reservoirs is a clear manifestation of the complex diagenetic changes the carbonates were subjected to. Proper analysis of the impact of such processes is imperative for decent reservoir characterization and subsequent dynamic modeling.

There is little correlation between pore volume, geometry, grain size, shape and sorting in case of the carbonate reservoirs. The facies variation as identified on the image logs add to the heterogeneity of the reservoirs and give rise to different flow units conceptually. Determining facies type and distribution is necessity for effective reservoir management. Conventional logs alone are insufficient to identify and characterize the facies types, porosity distribution etc. The present study outlines a technique to integrate heterogeneity analysis with dual porosity to provide accurate and quantifiable permeability units of the reservoir.

Study area is situated in northern part of western offshore basin, India. It is oil producing carbonate reservoir having different units. The reservoir is heterogeneous in nature with high and low porosity units. An integrated formation evaluation technique using LWD, NMR, Electrical Imaging and Formation tester data, improved the understanding of reservoir heterogeneity. Image data shows different degree of diagenesis in carbonates resulting in complex textural variation. Porosity analysis from borehole image and NMR measurements show intensive solution activity and provides porosity distribution and quantification of vuggy fraction.

In order to link log data to the hydraulic properties of the reservoir and to provide useful and consistent porosity analysis in carbonate, pore system has been partitioned into three components: micropores, mesopores and macropores based on their pore throat diameter. Permeability is then reconstructed based on various porosity distributions. Porosity partitioning permeability analysis shows good match with MDT mobility as well as core permeability as compared to TIMUR and NMR derived permeability. Integrating the entire data set differentiates quantifiable flow units and results in better reservoir characterization. This is a novel methodology to differentiate permeable units in such heterogeneous carbonate reservoirs.