Oddbjorn Skilbrei, Richard Chia,Brunei Shell Petroleum
Kirby Schrader, WellDynamics
Earlier this year, WellDynamics successfully installed a five-zone horizontal SmartWell completion for Brunei Shell Petroleum designed to boost recovery from the Iron Duke field.
Iron Duke is located approximately 50 km offshore Brunei. Well ID-19 is one of several development wells targeting five main stratigraphic units located over several fault blocks.
The original well concept was a 4 1/2-in. commingled monobore completion to allow for future through-tubing access. Early in the campaign, however, it was recognized that the reservoirs were far more compartmentalized than previously thought, with distinctly separate fluid contacts and pressure regimes. This discovery led to a shift in the completion design to one that would allow for selectivity.
Iron Duke well development schematic.
Due to the long delivery time associated with multi-zone surface controlled selective completions, the well was initially completed as a single zone with a 7-in. liner. This design provided the flexibility to re-complete into an intelligent completion at a later stage.
A rapid oil decline and gas-to-oil ratio (GOR) increase were observed after production start-up. This indicated the ultimate oil recovery expected from the gas cap drive was unachievable using a commingled production approach. Reservoir simulation had shown that controlling the GOR on a reservoir unit level would allow more of the oil to be produced. The well needed to be re-completed and was a prime candidate for a SmartWell completion design.
Particular challenges were the well's total depth and long "fishhook" shaped horizontal section. An important objective was that no intervention should be required later on in the life of the completion. Coiled tubing shifting tools could be used for the horizontal section, but this would add substantial risk and operational expense. Therefore, the SmartWell system needed to be reliable throughout its proposed life cycle and to handle comfortably the multiple zones.
WellDynamics' Digital Hydraulics system was selected, following substantial reliability analysis using failure modes and effects analysis and qualification testing.
The Digital Hydraulics System requires no downhole electronics and, with three hydraulic control lines, is able to control as many as six downhole interval control valves (ICVs). If further expansion had been required, four control lines would have increased the system capability to 24 zones.
The initial completion design for the ID-19 well.
One additional control line was needed for the installation of an optical fiber distributed temperature sensing (DTS) system with a full loop from surface to total depth and back to surface to improve resolution.
Color-coded control lines
To help simplify installation operations, each line of the Inconel control line flatpack was color-coded during fabrication, and two of the control lines were specified to an extra smooth bore to assist DTS fiber deployment after installation. Compatibility of the hydraulic fluid and optical fiber was confirmed early on as well as the compatibility of the entire system to hydraulic oil and isopropyl alcohol necessary for the fiber deployment phase. Packers, ICVs, and cast protector clamps were all designed to support and protect the four hydraulic lines and the additional I-wire required for quartz pressure and temperature gauges. The 9 5/8-in. packer, the four 7-in. packers, and all ICVs were fabricated using 13% chrome to minimize corrosion in the existing downhole conditions.
All SmartWell components were designed to minimize use of crossovers and additional equipment during the completion installation. To minimize rig time, sub-assemblies were built and tested on-shore, taking into account the maximum lengths allowed for transpor-tation in Brunei and the ease of handling offshore on the tender drill-ing barge. Splice subs, specifically designed for the top of each sub-assem- bly, kept control line flatpack, stripping, and handling to a minimum during installation offshore, thereby reducing total rig time by an estimated three days.
Back-up equipment was supplied for each size of the completion components. All control lines and hydraulic connections, valves, and control manifolds were assembled, pressure and function tested, and installed using the same hydraulic fluid in order to eliminate contamination. Control line ends and splices were specifically prepared to aid pumping down the optical fiber.
Prior to running the completion, particular attention was given to cleaning up debris in the well created from milling during the removal of the old completion and perforating of the new intervals. The completion fluid was kept clean, and use of thread dope was minimized during running of the completion. Care was taken to get the completion to bottom over the horizontal section. The main concern was conveying the multiple packers and valves to setting depth while protecting the control lines when running through the top of the liner and across producing zones.
To handle complications of space out due to the depth, inclination, and the close proximity of some zones, a special no-go sub (with the facility for control line bypass) was included to land on the 7-in. liner top. This eliminated the need for wireline or coiled tubing correlation using radioactive pip tags or other methods.
Several different companies supplied the DTS system, the quartz pressure and temperature gauges, the packers and valves, and other auxiliary equipment. As such, close coordination and monitoring was vital.
The installation was successful, and the completion is believed to be one of the first wells in the world to have surface control and monitoring in all five zones. All five packers were set successfully; the five ICVs function tested, and all pressure and temperature gauges were operating after the production tree and surface control lines were connected.
ID-19 started production in mid-July. Three zones have been tested individually and commingled together using the SmartWell capability, and all equipment is functioning as required and specified. An extension to the drilling jacket is being installed in the near future that will allow the planned addition of a fully remote-controlled surface acquisition and control system on the unmanned platform.
An extensive production testing and optimization program is being carried out to achieve the desired oil recovery increase and operational cost savings. A 15-20% increase in overall recovery is expected, compared to that of a conventional completion.