TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractThis paper presents an integrated approach using the 3D seismic and well data to enhance our understanding of the lateral and/or vertical distribution of the Tar Mat. The study was carried out utilizing a recent stat-of-the-art, high resolution and high quality 3D ocean-bottom seismic dataset (OBC) acquired offshore Abu Dhabi and several wells with an excellent suite of logs, thousands of feets of core data and geochemical studies. A Model Based Acoustic Impedance Inversion was conducted following the 3D seismic reservoir mapping. A comprehensive porosity prediction analysis and validation were conducted for each well. The observation of the abrupt destruction of porosity in the well data associated with Tar Mat presence in the core led to the idea of computing the porosity derivative cube from the seismically predicted porosity cube. This significant and dramatic change in porosity associated with the Tar presence suggested that this porosity destruction might be visible in the seismically predicted porosity cube. The derivative of the porosity volume after post-stack Impedance inversion was generated to visualize the rate of changes in porosities. The high negative porosity derivative in a highly porous section may represent the top of a Tar mat. The high positive porosity derivative values also can be used to indicate Tar free developed porosity. Good match was found between the generated porosity derivative volume and the top tar from wells. Cross-plots between the seismic acoustic impedance and porosity for all wells (including Tar wells) suggest difficulty to distinguish between Tar and lithology change for porosities less than 12.5%. The lateral Tar distribution was found to be predictable utilizing this approach, through blind test well validation. The seismic Tar mat prediction on the porosity volume has provided new and important interpretation of the top of the Tar in the inter-well region and for the static model. Different Tar prediction schemes from seismic have been evaluated for further refinement. Differentiating tight rocks from the porosity plugged with tar remains ambiguous in the lower reservoir tight rocks. Therefore, a detailed sampling and geochemical analysis of the tar is being performed on the core to determine its base.

In recent years, advanced and integrated seismic processing and interpretation workflows have been adopted in ADNOC. The application of new processing routines to legacy seismic data has shown to be valuable in improving the quality of the seismic data. This improvement has had a positive impact on our understanding of complex geological settings, in particular in areas where salt movement has had an influence on the structural framework of the field. In this paper, case studies are presented for salt-related structures in Abu Dhabi. Salt structures have been classified into three classes according to their complexity and each of these classes asks for a different type of seismic data volume and a different interpretation workflow. With the help of better reprocessed seismic data and seismic attribute analysis, complex structural uncertainties are better appraised, allowing less operational problems in wells due to drilling through faults and more optimal field development plans.

This work describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic azimuthal anisotropy. The ultimate objective of this study was to attempt to map permeability multiplier inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi. The azimuthal seismic anisotropy for fracture prediction method showed fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method's ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated. The study interval exists in the dense zone of the Upper Jurassic reservoir with total thickness of 120'. The fractures evidence have been compiled from well data, such as Core, FMI, orthogonal shear sonic, production test, multi-arm caliber….etc. Present day stress is captured from induced fractures direction, borehole breakout, offset field stress map, Eocene structure map and world stress map. All compiled information's indicated maximum horizontal stress of N10°-30°E direction. The four sectored wide azimuth seismic data set have been fitted to an ellipse to find out the fast and slow velocity direction and the difference between those velocities. The Interval Velocity is sensitive to Lithology, porosity, pore fill; the Vint-Slow is sensitive to the minimum horizontal stress. The lower the VINTslow, the less the minimum horizontal stress, which allows the fracture apertures to be more open. It is observed that the seismic anisotropy map for fractures showed a dominated direction (NNE-SSW) that match with present day stress field. The azimuthal Vint records current day stress field, not paleo-stress field. Good correlation between well permeability multiplier and the fractures map, particularly at the two reference wells. Following the analysis of the azimuthal seismic anisotropy maps such as azimuthal amplitude and interval velocity, a good correlation has been observed between the seismic anisotropy components and the production well test. The two seismic anisotropy components that showed a great deal of link with the computed well permeability multiplier are the computed slow interval velocity and the anisotropy azimuth deviation from the known present day stress. Therefore, the following equation has been written to invert those azimuthal seismic components into permeability multiplier. The resulted map showed match at both input wells and one blind well.

The post stack seismic fracture prediction method consistently shows fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method's ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated. This paper describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic structure attribute maps. The ultimate objective of this study was to attempt to map permeability scalar inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi. The studied field is not developed, but the subject reservoir was sparsely sampled with logs, limited well tests, limited cores, one FMI and one full waveform sonic. We have studied and analyzed the well based fracture detection results. The well analysis included FMI study, Stoneley waveform, well production tests and core images. The likely fractured layers were identified at the lower dense part of the reservoir. Well seismic synthetics were generated and the fractured layers were found to exist in less than one cycle. Following the fractured layers identification in the seismic cube, an intensive seismic attribute analysis was conducted. The studied seismic reservoir attributes includes spectral decomposition analysis of Amplitude and Phase followed by structure attributes such as Coherency, Curvature, Amplitude change in X or Y and Azimuth. Here we report and analyze the fracture prediction results for Carbonate reservoir. A consensus results from borehole ellipticity, Seabed ramp and near Seabed seismic structure map versus known regional stress will be presented as guide of current stress direction. Based on the extracted fracture map from seismic, the current stress direction and the well permeability scalar, a 1km x 1km permeability scalar map was generated.

Defining the range of uncertainty is a crucial part in the oil field development particularly for carbonate reservoirs that have limited well data and with the absence of dynamic data. It is very important to develop an in-depth understanding of the range of uncertainty of all reservoirs parameters such as: - Structure uncertainty - Lithofacies and reservoir rock types - Static reservoir attributes population technique (Porosity, Permeability, & Water Saturation) Although outcrops and analogs are often employed to define reservoirs model parameters, it is still challenging to define and agree on the relationship between modeling parameters and their distribution ranges. This paper addresses the impact of uncertainty of different modeling parameters on the volumetric calculations and full field development scenarios starting with structure model. Various areal and vertical uncertainties were investigated to set the structure uncertainty ranges. Then, the identified depositional environment models were used as guides to set the uncertainty ranges for each lithofacies association. The reservoir rock types were directly affected by both structure and lithofacies association models. Different ranges of variations were used for each rock type within each reservoir layer to ensure capturing the lateral and vertical reservoir heterogeneity and to propose multi distribution scenarios for each reservoir tock type within non-cored intervals/areas. The petrophysical parameters were conditioned to the reservoir rock types model. So, they were directly affected by multi scenarios of RRT models. In conclusion, 20 volumetric estimates were calculated and evaluated to define the probabilistic scenarios P10, P50, and P90 that will be used to investigate the full field development scenarios.