Porosity And Permeability Variations in a Lower Cretaceous Limestone Reservoir, Onshore Abu Dhabi, United Arab Emirates
- Stephen N. Ehrenberg (Khalifa University of Science and Technology)
- Document ID
- Society of Exploration Geophysicists
- SEG/AAPG/EAGE/SPE Research and Development Petroleum Conference and Exhibition, 9-10 May, Abu Dhabi, UAE
- Publication Date
- Document Type
- Conference Paper
- 93 - 96
- 2018. Society of Exploration Geophysicists
- reseroir characterization, Middle East, porosity, permeability
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- 34 since 2007
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This document is an expanded abstract.
The upper zone of the Lower Cretaceous Kharaib Formation (46-54 m thick in the studied wells) is a major oil reservoir in several giant oilfields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oilfield (Fig. 1).
Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity loss in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) near the base and top of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level.
Most (95% of) poro-perm data from the studied wells lie within Lucia rock-fabric class 3, showing distinct, but relatively subtle, differences between texture groups, whereas a subordinate portion of the data from the upper, mud-poor part of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of: (1) a diagenetic model for porosity controls, (2) the use of a modestly higher poro-perm transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3), and (3) recognition of the scattered and widely varying occurrence of exceptionally high permeabilities in the upper reservoir.
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