The Champion West field was discovered in 1975, but its rich oil reserves lay dormant for 30 years, locked 6,500 to 13,000 ft (2,000 to 4,000 m) beneath the seabed in a complex web of

Figure 1. Shell Brunei drilled wells called fault scoopers in crestal locations near faults and completed them as Smart wells. (All graphics courtesy of Brunei Shell)
thin reservoirs deemed too expensive to develop. It is the largest undeveloped oil and gas resource in Brunei. The field is of strategic importance to Shell in terms of successful application of Smart technology. Hydrocarbons are found offshore in up to 1,000 shallow marine reservoirs distributed areally over 7.5 miles by 3 miles (12 km by 3 km). These vertically stacked, structurally dipping reservoirs are complex and contain various fluid fills ranging from gas only to gas with oil rims to oil.

Field development has been slow due to reservoir complexity and the need for a step change in development concepts to meet investment hurdles. To date, 25 development wells have been drilled from five drilling sites, with eight wells executed as part of Brunei Shell Petroleum Company Sendirian Berhad’s (BSP) latest completed development phases.

Recent Champion West campaign
The most recently completed phases ended in June 2007 with five new snake oil wells and three gas wells on stream. A new unmanned Smart drilling platform with remote well-testing operations via a multi-phase flow meter was installed in 2005 to allow oil and gas export via two new pipelines to the Champion complex some 6 miles (10 km) away.

The five snake wells each achieved initial rates in excess of 12,000 b/d of oil, some of the largest BSP flowrates on record, while each well is targeting a 260- to 500-ft (80- to 150-m) thick oil column up to 5 miles (8 km) away from the surface location. The Champion West team delivered some of the longest wells in BSP history — up to 5 miles (8 km) along hole — each with up to four producing zones with full-flow control, pressure and temperature monitoring. The project also implemented a world first of integral running of Smart cables through swellable packers. The snake wells campaign was completed in 343 days, 49 days earlier than planned, and with around 21 miles (34 km) of hole drilled.

Three gas wells were also drilled along strike faults thus connecting many sands, with pressure variations of up to 5,076 psi across various sands, in crestal locations. These wells, known as “fault scoopers,” are also completed as Smart wells (Figure 1). Two of these producers have been completed as the world’s first six-zone intelligent completions, allowing production from individual zones and commingled production. This type of completion is expected to realize increased recovery and a reduction in life-cycle cost through real time monitoring and production optimization and a reduction in well intervention.

Enablers for success
The development of Champion West evolved over time, building on field experience acquired
Figure 2. Snake wells weave laterally through vertically stacked, structurally dipping reservoirs at a fraction of the cost of multilateral wells (Diagrams courtesy of Brunei Shell Petroleum)
in previous phases. A stepwise approach was key to the successful implementation of new technologies. Key elements of the Smart field included the well design, the completion hardware, and the surface equipment and modeling/communication tools. The introduction of a new element to the design was done with the knowledge of other elements working.

The well design evolved over time — from deviated wells to horizontal wells and finally to snake wells — in an attempt to increase recovery and make the development attractive to shareholders. The snake wells were laterally weaving (“snaking”) extended-reach horizontal wells that drain a number of vertically stacked, structurally dipping reservoirs (Figure 2). This created multiple drainage points in each of the sands and effectively achieved a similar drainage pattern to a multilateral well at a fraction of the cost.

The wells were completed with multiple hydraulically controlled inflow control valves that can be operated remotely from shore and the Champion complex. Swellable packers replaced the external casing packers used initially and created zonal isolation, reducing rig time taken to run the liner (Figure 3). In addition, the completion included permanent downhole gauges for monitoring annulus and tubing pressure for each of the zones as well as distributed temperature sensing (DTS) to monitor temperature along the entire well. Optical pressure gauges were also deployed successfully as part of a field trial. End-to-end support of the Smart system was put in place to ensure the smooth running of the Smart field with a dedicated multidisciplinary team providing a one-stop shop for any problems with the system.

Step changes were also made in the control, modeling and surface facilities with remote operation of Smart downhole and surface testing equipment implemented in the campaign. A multiphase flow meter, which enables routine well testing to be carried out with minimal production deferment, was successfully commissioned. Production Universe models (data-driven mathematical models) were built to estimate flow rate on a continuous basis. Testing of both oil and gas wells through the multiphase meter is now possible, with testing done at rates of up 12,500 bpd with a gas fraction of 10%. As liquid rate declines, gas fractions of up to 98% can be managed.

Variable inflow control valves in the well not only facilitated initial clean-up but also were used to balance drawdown along the well bore to prevent early gas and water breakthrough. If gas or water breakthrough occurs, zones can be preferentially flowed, extending production life and leading to a significant increase in reserves.

Some additional unexpected benefits were realized through the use of Smart completions. For example, the exact location of a leaking gas lift valve in an oil completion was identified using DTS, allowing its replacement at reduced rig time. In another well, the flexibility of the well design enabled the effective shutoff of water-bearing zones that were encountered because of slight departures from the planned well trajectory. Through modification of the planned segmentation, an expensive re-drill was avoided.

With the high degree of reservoir complexity in the field, the need for appraisal was recognized to ensure optimal placement of the wells relative to fluid contacts. Execution of essential appraisal activities was incorporated into the planned development wells on an opportunity basis, thus eliminating the need for expensive dedicated appraisal wells. This provides increased confidence that future planned wells will realize their objectives.

When drilling these complex wells, which were constantly pushing the limits, integrated
Figure 3. A smart completion at a Champion West snake well optimizes production choices.
planning and execution of the program was essential. In recent phases, continuous optimization of the well path was necessary to ensure all targets were intersected optimally. Iterative calibration of torque and drag modeling throughout the well delivery process was key to ensuring the successful positioning of all the hardware in relation to the reservoir targets. The platform design was made with the knowledge of the rig to be used for this campaign. This provided, for example, ample deck space and set-back capacity and offline make-up facilities, all allowing high rig efficiency. Neodene-based mud was used for the key hole sections, which provided a highly inhibitive system with minimum formation damage and a stable wellbore environment for drilling these very long horizontal sections. These were all key to the successful completion of the campaign.

Conclusion
The application of Smart fields technology enabled development of previously uneconomic hydrocarbon accumulations. New concepts were implemented successfully in a stepped approach that provided a platform for future growth. A key contributor to the success of the project was the multi-disciplinary teamwork facilitated through the co-location of the entire well delivery team (from planning to execution) with the subsurface team, thus allowing iterative design and optimization while drilling. Close collaboration with the rig contractor and key service providers, combined with key staff continuity, ensured successful deployment of this array of technologies. Further technological progress is planned through the maturing of other well designs.

Champion West is now contributing up to 20% of BSP’s current oil production, with a significant proportion coming from eight recently drilled wells, with each well exceeding its initial flow rate. Payback of initial investment was realized within a few months of first production.

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