,
O. Al-Jelani
, and Y. Al-Mehari
by
J. Grötsch ,
O. Al-Jelani
, and Y. Al-Mehari
ABSTRACT
In the framework of the integrated reservoir characterization study (IRCS) for a giant Lower Cretaceous oil field in Abu Dhabi, a key deliverable was a sedimentological and diagenetic model of the field to be used as input for 3-D geological modeling of the stacked reservoir zones. Integrated 3-D reservoir characterization in carbonate fields is a topic of ongoing discussion whereby data preparation, data requirements, as well as actual static and dynamic modeling procedures vary considerably in the industry, in general, and from field to field, in particular. One of the more often raised issues is the link between a bio-facies based models incorporating depositional and sequence stratigraphic characteristics and its link to the 3-D petrophysical property distribution. In this paper, the concept of reservoir rock type based modeling is introduced as a missing link between static and dynamic modeling. Such rock-type based 3-D models can equally provide vital input for further seismic and geo-mechanical modeling.
INTRODUCTION
In the field, a number of key uncertainties have been identified including the sequence stratigraphic architecture, depositional geometries and diagenetic bodies in the Upper Thamama reservoirs, lateral/vertical variability and prediction of porosity and permeability, the structural style with fault and fracture distribution and its impact on fluid flow. In order to reduce these uncertainties, an integrated reservoir characterization study (IRCS) was initiated in order to provide a detailed computer based 3-D reservoir geological model for the Upper Thamama reservoir zones of the field, which can serve as a basis for flow simulation, field development planning and long-term reservoir management purposes.
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Fig. 1: Structural map of the field showing the top of Reservoir Zone B. |
The field is located in the onshore area of Abu Dhabi about 110 km to the Southeast of Abu Dhabi Island (Fig. 1). Sweet oil with 39° API was discovered in 1965 in the Thamama Reservoirs. The field is an elongated faulted anticline with the longer axis trending Northeast - Southwest. It is about 30 km long and 10 km wide. At top Thamama level, the flanks dip 3-5° on the western and eastern side and 1 - 2° on the northern and southern side. The main phase of structural deformation is believed to have started in the Upper Cretaceous during the deposition of the Cenomanian-Turonian Ruwaydha Formation and ended during the late Upper Cretaceous. However there is strong evidence that structural tilting was ongoing during major parts of the Tertiary.
The main oil bearing zones are within the porous intervals of the Kharaib and Shu’aiba Formation (Fig. 2). They are in general bound at the top and bottom by dense argillaceous limestone intervals with a thickness ranging from 30 to 45 ft.
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Fig. 2: Cross section through the field showing the main reservoir zones of the Upper Thamama Group in the field. |
The Thamama Zone B (Upper Kharaib Fm. ) is the main oil bearing and producing reservoir in the field. It can be subdivided into an upper and a lower unit based on their depositional facies and reservoir properties, predominantly change of permeability. The lower part consists of less heterogeneous porous mudstones to wackestones with only moderate amounts of skeletal debris. Debris becomes more abundant towards the top. In general, the permeability is significantly lower ranging from 1-14 mD. The upper unit consists of heterogeneous bioclastic wackestones to grainstones with a pelletoidal texture as well as algal lumps, rudistid and coarse bioclastic bearing layers. The thickness of Zone B ranges between 191 ft in the crestal area and 165 ft down flank. The average porosity and arithmetically averaged permeability vary from a maximum of 34% and 363 mD in the crestal area to a minimum of 20% and 10 mD down flank.
