fax 01-972-952-9435. AbstractTraditionally, downhole porosity measurements are made through nuclear/acoustic logs (both wireline and logging-while-drilling) and cores.In homogeneous carbonates, log porosity is generally a good substitute for core data. However, in heterogeneous carbonates with complex pore systems resulting from leaching/dissolution, cementation, and dolomitization, discrepancies exist between log-and core-derived porosity. Moreover, thin-bedded layers of high and low porosity, which are found to have a pronounced effect on reservoir production, are routinely unidentifiable on conventional logs because of their limited vertical resolution capabilities (2-3 feet).An innovative methodology has been developed to generate a porosity log with a minimum vertical resolution of 0.2 inch that also takes into account the azimuthal heterogeneities of the carbonate reservoir exposed in a wellbore. To achieve the high-resolution porosity log and entire porosity spectrum around the well, borehole images are used as external constraints after calibration with log porosity and resistivity. This methodology has significant applications in carbonate reservoir characterization. First, the identification of thin intervals of very high (related to high permeability) and low (dense, stylolitic) porosity is possible. Second, vuggy and moldic porosity can be quantified, and third, carbonate facies and reservoir rock types can be characterized. Several case studies from the U.Cretaceous I L. Cretaceous reservoirs and Upper Thamama Reservoirs highlight the effectiveness of the methodology to characterize porosity heterogeneity. Known porosity variations from core and mercury injection data confirm the heterogeneity demonstrated on the high-resolution porosity log. Since most carbonate reservoirs exhibit considerable porosity heterogeneity, this methodology has significant potential application to improve reservoir characterization in many areas.

In order to improve oil recovery from the main oil producing reservoir of an offshore Abu Dhabi field, two gas injection pilots have been tested. To explain their relative performances, a combination of classic tools (cores, electrical logs) and high-tech tools (DSI, FMI, CT-Scan) as well as 3D seismic have been used to further investigate the reservoir anisotropy in one of the pilot area. The logs indicate the presence of a fracture system. The full comprehensive core versus log calibration allows to extend the results found to the non cored intervals. The combination of the classic and high-tech tools leads to a better understanding of reservoir behaviour and heterogeneities. Introduction In order to improve the oil recovery from the Lower Arab Formation (D2), two gas injection pilots have been tested on a field offshore Abu Dhabi. One behaved as expected (Multidirection) while the second one (Figure 1) showed an unidirectional dolomitic layer D2a1 (2 to 5m thick). The data from three wells (Figure 1) have been used for the study in order to investigate:the cause of reservoir anisotropy in the second gas injection pilot, based on three well cores and logs analysis.why the reservoir top dolomitic layer does remain unswept after more than 20 years of oil production,the sharp contact between the top dolomitic layer (D2a1) and lowermost dolomitic one (D2a2), appearing as a stylolitic contact, with electrical facies image similar to the X Ray Core Tomography scan (CT scan) image. The available set of data consists in a Dipole Shear Imaging (DSI) log recorded in the side-track of the gas injector well and associated to three core-sponge; a Formation Micro Imager (FMI) log recorded in the side-track of a previous pilot oil producer; a set of conventional cores with an available High resolution Dipmeter Tool (HDT) log (recorded in 1984) in that latter well and a recently acquired 3D seismic. This paper describes the combined analysis and presents the results acquired for a better understanding of the reservoir behaviour and heterogeneities. Main Results Per Well Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Main Results Per Well Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form.

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