Quantification of diagenesis impact on the reservoir properties of the Jurassic Arab D and C members (Offshore, U.A.E.). Issue 2 (18th March 2013)

• Record Type: Journal Article
• Authors: Nader, F. H.; De, E.; Gasparrini, M.; Liberati, M.; Dumont, C.; Ceriani, A.; Morad, S.; Lerat, O.; Doligez, B.
• Is Part Of: Geofluids. Volume 13:Issue 2(2013:May)
• Page Start: 204
• Page End: 220
• Publication Date: 2013-03-18
• Subjects: Hydrogeology -- Periodicals; Sedimentary basins -- Periodicals; Fluids -- Migration -- Periodicals; Groundwater flow -- Periodicals; Geothermal resources -- Periodicals; Fluid dynamics -- Periodicals; Earth -- Crust -- Periodicals; 551.49
• DOI: 10.1111/gfl.12022
• Languages: English
• ISSNs: 1468-8115

Abstract

<abstract abstract-type="main" xml:lang="en" id="gfl12022-abs-0001"> <title>Abstract</title> <p>An increasing need exists to quantify the impact of diagenesis on complex and heterogeneous geological reservoirs and to predict the related field‐scale porosity‐permeability distribution. Development of approaches to quantify diagenetic events is an important step towards the construction of integrated numerical reservoir models predicting the impact of successive diagenetic events on petrophysical properties at various scales. This article describes two distinct approaches, which allow capturing, quantifying and explaining reservoir heterogeneities of the Jurassic Arab Formation (offshore oilfield in Abu Dhabi, U.A.E.) at the field and plug scale. Based on a classical diagenesis study, whereby the major diagenetic phases were characterized, distribution patterns were highlighted to further explain reservoir heterogeneities through a set of 2D interpolation diagenesis maps across the field. The best reservoir properties are encountered in the central‐northern (grainstones with syntaxial calcite overgrowth cement – typical of Arab D) and south‐western (dolostones – typical of Arab C) parts of the oilfield. Following another independent approach at the scale of the plug, quantification of rock components and description of the pore space connectivity and geometry are obtained by 2D and 3D image analyses, μ‐CT and pore network modelling. This latter approach resulted in a better understanding of the effect of anhydrite dissolution on the pore structure of the investigated dolostone. The overall, presented workflow provides valuable constraints for assessing reservoir heterogeneities in statistical field‐scale models.</p> </abstract>