BC-10 advances the SBOP cause
  from: Offshore Engineer
  by: Jennifer Pallanich
  Monday, July 07, 2008

Using surface BOPs carries a comparable risk to conventional BOPs on deepwater drilling and completions with moored rigs, and one supermajor believes it can save at least $50 million over the course of a three-year contract by using one. While an SBOP may not be the solution for all applications, Shell sees real potential for it offshore Brazil and, as OE’s Jennifer Pallanich reports, is currently demonstrating its faith in the technology on the BC-10 project.

This is not the first time Shell has used surface BOPs (SBOPs): the company used the technology with Stena Tay in 2003/04, using Southeast Asia waters as a proving ground for the technology (OE April 2004; OE February 2005). By adding a seabed isolation device, Shell was able to use an SBOP in the less than benign conditions offshore Brazil and in the Mediterranean offshore Egypt.

Shell opted to use the SBOP technology on its operated BC-10 field in the Campos Basin offshore Brazil because it allowed use of a moored third-generation rig and would allow multi-well drill centers to facilitate the planned batch operations at the field.

For BC-10, also variously known as Parque das Conchas and Shell Park since the four fields are named after shells found along the Brazilian coast, GSF Arctic I needed several modifications to accommodate the SBOP, explains Tor Taklo, well engineering superintendent for deepwater well delivery at Shell. These included removing the subsea BOP and 21in riser, removing the anchors, modifying the riser tension ring, adding an IWOCS umbilical reel, adding a surface BOP control system, and adding the new handling system for the SBOP.

Before GSF Arctic I underwent modifications, it was rated to work in 945m of water; following modifications, coupled with a pre-laid mooring system, the rig is able to work in water depths to 2250m.

‘The new elements are all based on known technology,’ Taklo says, adding the risk level of an SBOP is comparable to that of conventional deepwater drilling and completion operations with a moored rig.

Using the surface BOP system, Taklo says, means a third generation rig can work in water depths to 2250m.Water depths range from 1500-2000m at the BC-10 complex. By using the SBOP technology with a third generation rig, he says, Shell estimates it is saving $50,000-$100,000 per day on a three-year contract, which works out to somewhere between $50 million and $100 million in savings.

The seabed isolation device (SID) allows a 40 second disconnect, Taklo notes. But that wasn’t the only requirement for BC- 10. Shell wanted total well control throughout completions, the ability to perform batch operations, the ability to pressure test from the tubing hanger, a reduced dependence on the ROV, reduced exposure to people when installing the BOP stack in the moonpool, availability of electric and hydraulic power in the SID umbilical, and remotely operated SBOP connectors. Using a spacer spool the same height as the tubing head spool will improve batch efficiency, Taklo says.

The SBOP system has been tested to 6000psi.

The GSF Arctic I can handle 50ft joints of 16in OD riser, which will use Merlin connectors. While the connectors have been used in the past, a new design was qualified for use in the 16in drilling riser application, Shell notes.

The SBOP system comprises, from top down: rig diverter and compact ball joint; 9.1m stroke low-pressure triple-barrel telescopic joint; surface BOP stack; upper stress joint; bare 16in OD riser joint; 16in OD riser joint fitted with strakes for VIV suppression; 16in OD riser joint fitted with buoyancy; bare 16in OD riser joint; lower stress joint; the seabed isolation device connected to the umbilical and test hose run on riser; spacer spool for drilling or tubing hanger spool for completions; and slimbore subsea wellhead system.

Taklo expects the remaining wells to be drilled at BC-10 with Schlumberger’s PowerDrive rotary steerable system (RSS). For completions, he says, the first well will be drilled and completed in sequence with the remainder following in a batch approach. The development plan for the four-field BC-10 area calls for a phased approach to produce Shell Park’s six reservoirs, which contain 16-42°API oil. The Abalone field, with its lighter oil, is slated to go onstream first, which is less problematic for the FPSO, says Shell’s BC-10 venture manager Paul Dorgant. The lighter oil is easier to separate and process so it will require less heat input, he notes. There’s the added benefit, he notes, that the first fields planned to go onstream won’t likely require water injection.

Shell, which operates BC-10 with 50% with partners Petrobras (35%) and ONGC (15%), declared the BC-10 area commercial in 2005 and awarded contracts for phase one in 2006. The complex is due onstream producing the Abalone field by the end of the decade.

For the first phase, Shell plans nine wells to produce back to the FPSO, which will be moored in 1780m of water, and one gas injector well. Shell is leasing the FPSO from Brazilian Deepwater Floating Terminal (BDFT), a joint venture owned 51:49 by Single Buoy Moorings and Malaysia’s MISC Berhad. BDFT designed and converted the 100,000b/d FSO XV Domy which had previously served Total’s Amenam-Kpono project off Nigeria. The vessel has been renamed FPSO Espirito Santo, and BDFT will lease it to Shell and operate it under a 15-year plus options deal. The vessel is due for delivery late this year or early next year. The concession is for 27 years, and the field life is projected at 30 years.

The fields are in 1595m to 1925m of water, and the accumulations span over a large area of the block but with small to moderate recoverable amounts. The field plan for Phase I involves six production and one gas injection well at Ostra, two producers at Argonauta, and one in Abalone. Later, water injection and producer wells will follow in another sector of the Argonauta find.

Shell’s seismic interpretation software, 123DI, indicates ‘we have a highly faulted structure at Ostra,’ says Shell’s BC-10 production petrophysicist Lee Stockwell. ‘Ostra’s a bit of a jigsaw puzzle, the way it works.’

Situated 900m below the mudline, Ostra requires complicated well designs.

To make the field work, Dorgant says, Shell is using ESP caisson systems, which for one field will be paired with subsea separators to separate the gas from the oil to improve the ESP functioning. Argonauta, with its lower gas composition, will not require subsea separation. The caissons are 107m long.

‘All the fields require a substantial amount of boosting,’ Dorgant says, adding they need about 2000psi to overcome the backpressure of the water.

Putting ESPs in caissons is a more efficient use of flowlines as well as making it easier to manage intervention and downtime on the ESPs, Dorgant says. Six ESP caissons – two non-separated and four separated – are planned for phase one. Phase 2 will evaluate the use of different artificial lift technologies as well as ESP caissons, he added.With redundancy, he says, Shell can change out the ESPs in the caissons without affecting productivity.

‘ESP caissons are extremely important to this development,’ Dorgant says. ‘All of our boost is at the seafloor.’

That boost, courtesy the 1500HP ESPs, means heavier umbilicals. Shell worked to strike the right balance between strength and flexibility with the umbilicals, Dorgant says. The supermajor selected steel lazy wave risers and umbilicals paired with buoyancy to reduce the load on the connections. Dorgant notes the steel lazy wave riser means a lower riser count because the risers have larger throughput. Shell previously used lazy wave umbilicals at its Na Kika field in the Gulf of Mexico. The stretch in technology, Dorgant says, comes from the change in environment. Now, the steel lazy wave risers will attach to an FPSO, which is not heave-constrained, rather than to a semisubmersible platform as at Na Kika.

This year and next, Shell Park will also see the installation of two production manifolds, two artificial lift manifolds (ALMs), the six ESP boosting modules, 14 PLETs, 25 rigid jumpers and 10 trees in FMC’s new Enhanced Vertical Deepwater Tree (EVDT) design. Shell will also install 17 EVDTs at its Perdido development in the deepwater Gulf of Mexico.

The 5in production ID bore by 2in annulus ID bore, 10ksi EVDT has a concentric production bore and a retrievable flow module with a choke and/or multiphase flowmeter, says Jose Mauro, sales and marketing director for FMC CBV Subsea.

It also has quite a complex piping arrangement, he says, with 13 hydraulically actuated valves and two manual valves. FMC says its EVDT can accommodate 7in tubing completions and pressures up to 15,000psi within a 135/8in BOP stack, making it an economic and versatile subsea completion system. The EVDT supports Shell’s decision to use an SBOP as it allows ultra-deepwater completions to be performed from a small drilling rig.

The tubing hanger can be installed using a tubing head spool to provide flexibility for sequencing of events, or it can land into the wellhead, eliminating the tubing head spool.

Two manifolds have six modules of boosting (MOBOs). The MOBO-mounted subsea control module is for control of the MOBO and artificial lift manifold valves, gas/liquid leveling, system monitoring, choke position monitoring and PT/TT monitoring, Mauro says.

FMC is to complete the ten trees rated to 10,000psi to start delivery by 2Q 2008. Other deliverables, including the manifolds and boosting and separating systems, are expected to be ready by 4Q 2008.

While phase one is due onstream by the turn of the decade and is about halfway complete, phase two engineering work is ongoing as well, with contracts expected to be awarded sometime after the first phase begins producing.

Subsea 7 has the contract to fabricate and install six steel lazy wave risers, install 109m of mooring lines, install three dynamic and two static umbilicals, install the FMC manifolds, and fabricate and install 25 rigid jumpers.

Around the time BC-10 begins to flow, Shell also anticipates being in high gear with another field off Brazil: BS4, in the Santos Basin, where the company has announced the Atlanta and Oliva discoveries. A preliminary field development plan has been issued, and a test well is scheduled for next year or the year after.

Dorgant says the company is enthusiastic about the Brazilian landscape.

‘Presalt is the latest excitement that’s going through the Brazilian portfolio, and we’re certainly excited about it, too,’ he says. ‘Presalt is something you’ll be hearing a lot more about.’ OE

Click here to register to receive your own copy of Offshore Engineer each month.