The Hibernia oil field is located 315 kilometers (200 miles)southeast of St. Johnaans, Newfoundland, Canada in 80 meters of ater. It is estimated to contain approximately 3 billion barrels of oil, of which 615 million barrels are currently considered to be recoverable from two principal sandstone reservoirs (Hibernia and Ben Nevis/Avalon). Average daily production is expected to plateau at 135,000 BOPD and field life is anticipated to exceed 20 years. The Hibernia reservoir, the main producing interval, is distinguished as a complexly faulted, compartmentalized fluvial-deltaic system. Geophysical, geological and production data have been critical to reservoir characterization efforts required for efficient reservoir management. Two 3D surveys, high-resolution vertical seismic profiles and dipole sonic data are some of the key geophysical data utilized in early characterization efforts. A strategically-targeted core program and wire line acquisition of formation pressure data have also been crucial to reservoir management. Permanent down-hole gauges in oil producers provide real-time production information for model update and analysis. Rapid model updating is critical in operations and a key work process issue. A fifty-four fault 3D earth model of the Hibernia formation has been built. Seismic attributes and inversion results are used as constraints on the geostatistically populated earth model. This model can be rapidly updated incorporating geological and petrophysical data from development wells. The updating of velocity information, oilin- place mapping and fault seal analysis can also be performed rapidly. The model is used as input to a reservoir simulator to analyze multiple production scenarios and to identify key uncertainties. This paper will discuss how critical geophysical, geological and production data are incorporated into the reservoir characterization and model updating process.
The Hibernia oil field was discovered by a Chevron-operated well in 1979. The field was delineated by nine additional wells over the following five year period. The current owners of the field are Mobil, Chevron, Petro-Canada, Canada Hibernia Holding Company, Murphy Oil and Norsk Hydro. Development drilling began in July of 1997 from a gravity based structure, with first production in November of that year. Average daily production is expected to plateau at about 135,000 BOPD and a field life anticipated to exceed 20 years. The data acquired from two 3D seismic surveys over the field (1981 and 1991 vintage) show a complexly-faulted, southplunging anticlinal structure (Figure 1). The field is estimated to contain approximately 3 billion barrels of oil-in-place, of which 615 million barrels are currently considered to be recoverable from two principal Lower Cretaceous reservoirs (Hibernia and Ben Nevis/Avalon). The Hibernia reservoir, at approximately 3700 meters subsea, is composed of multiple, stacked, coarse to fine-grained, fluvial channel and bar sands (Figure 2). Porosities average approximately 16 % and reservoir permeabilities range from hundreds of millidarcies to several darcies. The Ben Nevis/Avalon reservoir, at approximately 2400 meters sub-sea, is dominated by very fine- to fine-grained sandstones deposited in shallow to marginal marine settings. The Ben Nevis/Avalon is characterized by complex faulting and large thickness variations across the field.
Incorporation of key geophysical, geological and production data are critical to effective reservoir characterization and management. Reservoir characterization efforts have focused on the Hibernia reservoir, the primary producing interval, during ramp-up to full production. Detailed reservoir models and simulations are con