Summary
The Champion East area offshore Brunei Darussalam consists of approximately 50 stacked, shallow, and intensely faulted heavy oil reservoirs. These reservoirs have been under development since 1975 and have to date produced just 9% of the oil initially in place. Over the period 1998-2003, Brunei Shell Petroleum (BSP) is embarking on a major redevelopment with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves.
An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points.
The primary development of Champion East is now nearing completion. The use of existing facilities and ultra shallow, long reach horizontal wells - with innovative sand exclusion and downhole intelligence - has achieved a 60% unit cost reduction over previous drilling campaigns in the area.
The only way to unlock another 5 to 15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of electric submersible pumps (ESPs).
Introduction
The Champion Asset comprises the Champion Field offshore Brunei Darussalam (Fig. 1) and all associated facilities and infrastructure, which also serve as an export hub for BSP's entire Offshore East production division. Oil production from the Champion Field averages approximately one-third of total BSP production. A large scope for recovery, mostly technology-driven, remains, even at low oil prices.
Subsurface, the area comprises a hydrostatic, heterolithic sequence of interbedded thin sandstones and mudstones (with reservoir flow units no more than 15 m thick and permeabilities ranging from 0.01 to 0.2 µm2 in lower shoreface sands to 0.5 to 5 µm2 in tidal channels) deposited in environments spanning a systems tract that extends from the outer shelf into the lower coastal plain. Other key features are significant lateral thickness variations, compartmentalization caused by syndepositional tectonics, and the presence of multiple growth faults.
The Champion field can be divided into two distinct parts (Fig. 2): Champion East, spanning a depth of approximately 200 to 1200 m, with hydrocarbons in some places seeping through the seabed and feeding a coral reef; and Champion Main, which encompasses a depth of approximately 1000 to 2000 m. Champion Main contains the mature core of the Champion field, where both primary and secondary (water-injection) recovery processes are well advanced and 28% of the oil initially in place has been produced. The main focus in Champion Main is on water-injection maintenance, production-system optimization, and scope for recompleting or sidetracking existing wells-all aimed at slowing the decline in oil production.
Most efforts in the area are, however, focused on the growth potential offered by shallow reservoirs. The Champion East area is much less mature than Champion Main, with a cumulative oil production to date of just 9% of the oil initially in place. Historically, Champion East is underdeveloped because of its subsurface complexity and heterogeneity (leading to erratic well performance), less favorable reservoir and oil properties [density of 930 g/cm3 (20° API) and viscosity between 5 and 15 mPa's], and a perceived lack of spare conductor slots, which would necessitate large investments in new infrastructure.
In 1995, it was estimated that an upfront investment in excess of U.S. $400 million would be required to advance the development of Champion East by accessing another 30 million m3 of undeveloped reserves. Out of this total, 40% would be required for new facilities, and the remaining 60% would be for drilling new wells. This hurdle essentially halted further developments (between 1992 and 1997, just one well was drilled in the area), and it was obvious that major changes were required to all the fundamentals (average reserves and rates per well, well costs, and facilities costs) to break this deadlock. The case for change, together with plans for possible solutions, is further described in Ref. 1.
Reservoir Modeling Technology
Traditionally, Champion East had been modeled with 2D methods of mapping gross interval properties for groups of reservoirs ranging in thickness from 20 to 40 m, using the previous 3D seismic survey shot in 1983 (relatively poor resolution) and well correlation methods based on lithostratigraphy. However, these methods often can prove unreliable in deltaic reservoirs that have undergone synsedimentary tectonics.
The previous major Champion East infill drilling campaign (1990-92) was relatively unsuccessful because approximately 35% of all target reservoirs were found to be either nonexistent, water-bearing, or depleted. It then became clear that it was necessary to understand the structure, sequence stratigraphy, and fluid distribution of these reservoirs in greater detail. Two key data acquisition activities occurred in 1994: a high-resolution 3D seismic survey and the retrieval of some 350 m of continuous cores to review the sedimentology and high-resolution sequence stratigraphy, as described in Ref. 2.
After screening studies to establish the correct priority and level of detail required, Shell's proprietary reservoir modeling software (GEOCAP-MoReS) was used to provide detailed 3D reservoir models for reservoir simulation. A total of 16 models were built and history matched (with approximately 50,000 grid cells each) between 1996 and 1999; together, they covered the entire area, with boundaries positioned (generally at sealing faults) to minimize crossflow effects. This allowed fast optimization of reservoir development plans by identifying connected oil in place and transmissibility for individual reservoir flow units, such as an upper shoreface sandbody or a tidal channel, which have remained undrained from previous development.
Determination of Reservoir Flow Units from Core Data: A Case Study of the Lower Cretaceous Sandstone Reservoirs, Western Bredasdorp Basin Offshore in South Africa
