HGS Int''l Dinner June 21, 2004; Agbami Discovery, Nigeria

HGS International Group Meeting June 21, 2004
Westchase Hilton, 9999 Westheimer, Houston Social Hour 5:30 PM, Dinner 6:30 PM
Agbami Field, Nigeria – Addressing Challenges and Uncertainty<?xml:namespace prefix = o />
David Grimes (speaker), Elliott Ginger, and John SpokesChevronTexaco Overseas Petroleum
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Agbami Field was discovered in late 1998, approximately 105 km offshore Nigeria in the Gulf of Guinea. The field is located in Blocks OPL216 and 217 in approximately 1500 meters of water. The structure is a northwest to southeast trending detachment fold anticline covering an area of 180 km2 at spill point. The discovery well, the Agbami No. 1, was drilled by Star Deep, a wholly owned subsidiary of Texaco, Inc. acting as technical advisor to FAMFA, an indigenous Nigerian oil company. Star Deep brought Petrobras in as a partner and followed the discovery with three appraisal wells and one sidetrack in Block OPL216, plus Statoil drilled the Ekoli 1 well into the same structure in adjacent Block OPL217. In late 2003 and early 2004, drilling resumed with ChevronTexaco, also through Star Deep, adding the first 2 wells from the development plan. After a short drilling pause to acquire seismic data, these wells will be followed by further development drilling later in 2004. All wells to date have penetrated oil bearing sands. The field is a world class development opportunity with significant resources.
 

The pay intervals at Agbami field consist of two principal zones.  The primary reservoirs are in the 17 million year (MY) sands and contain about 80% of the reserves. These objectives include slope channel, slope fan, and basin floor fan facies that offer both stacked and isolated reservoir objectives. Secondary reservoirs are present in the 13MY/14MY/16MY sands. These shallower productive zones are comprised of channel and levee-overbank facies.
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Seismic Data Issues
The seismic reflections from the shallower, secondary reservoirs occur above the water bottom multiple and are of relatively good quality. Amplitude extractions of both near and far angle data match predicted AVA models. We can interpret stratigraphic and fluid changes from the seismic data at this level.
However, the seismic data from the deeper, main pay intervals in the 17MY interval suffer from several data limitations. Principal among these is significant multiple energy contamination. Multiple generating surfaces exist not only at the water bottom, but also at other shallow horizons below mudline. The energy from these multiples occurs at the same time as the main pay interval primary reflections over much of the field, seriously degrading the data, especially in the pre-stack domain. Earlier processing of the data during the exploration and appraisal phases of the field, while attenuating the multiples, did not adequately resolve the problem. Consequently, extracted amplitudes from the 3D seismic data did not follow expected Class II AVA behavior. Recent reprocessing efforts by ChevronTexaco using a Gaussian beam method for attenuation of the multiples have given encouraging results that should allow better characterization of the reservoirs from seismic in future reservoir models.
Additionally, wavelet estimations from the seismic data indicate that the frequency content is relatively low, limiting the ability of the seismic to resolve pay sands. Multi-sand intervals tend to image as low frequency, high amplitude far-angle reflectors with typically two or three sands imaged by one peak-trough-peak seismic event.  The minimum sand thickness detectable at the main pay intervals in these data is about 30 meters.
Also, reflectors from the inboard limb of the fold at the northwest end of the structure have diminished stacked amplitude responses and in general, the inboard limb is less well imaged than the outboard limb. Shallow toe thrusts north of the field appear to be masking far offset traces which would normally contribute to the expected high amplitude far angle reflections of oil bearing sands. To record higher angle traces in this area, and hence better map the sand distribution, we are proposing to re-acquire data parallel to this thrust front.
 
Reservoir Modeling
With the limited frequency content of the seismic data, stratigraphic information from seismic was restricted to the identification of thick, sandstone-prone fairways that were mapped throughout the field area as architectu