Shell Looks to Future on Parque das Conchas

22 November 2011

The development of Shell’s BC-10 project in Brazil’s ultra-deep waters has seen the Anglo-Dutch major achieve some of the upstream industry’s most impressive technological advances of recent years.

With state-of-the-art technologies used both above and below the water line, the operator’s Parque das Conchas development is a project that the company readily admits has been one of its most challenging deepwater ventures ever, according to Shell’s BC-10 operations manager, Maria Pena.

Speaking at OTC Brasil in a presentation titled "BC-10: Today and Beyond,” Pena ran delegates through the process that eventually led to oil flowing from the pioneering project in July 2009, and discussed future plans.

The first phase entailed the development of three geologically complex, low-pressure reservoirs with heavier oil resources -- Abalone, Ostra, and Argonauta B-West -- in water depths of around 1,780 m (5,840 ft).

Producing via 10 wells, with an additional gas injector well, the fields today are pumping out around 70,000 barrels per day (b/d) (peaking at 93,000 b/d last year), although the leased FPSO has a capacity of 100,000 b/d of oil and 50 million cubic feet per day (MMcf/d) of gas. It can also store up to 1.4 MM bbl of oil.

Shell, which holds a 50% stake in the field along with its partners Petrobras (35%) and India’s ONGC (15%), is well under way with the second phase of development. This will see a fourth field developed (Argonauta O-North) with first oil expected to flow from that project toward the end of 2013.

According to Pena, the second phase will be just as challenging. "Phase 2 is keeping us busy but we are really looking forward to it. We are leveraging technologies used in Phase 1 on this next stage, including: subsea boosting; steel-catenary, lazy-wave risers; high-voltage umbilicals; and subsea multiphase metering.

"But we are also introducing new technologies including advanced permanent 4D seismic monitoring, which allows us to use 4D to maximize recovery from the field in the long-term. We are also going to use advanced tracer technology for long horizontal injectors to help optimize production and sweep,” Pena continued.

Oil in place on BC-10 is currently estimated at 1.1 billion barrels of oil equivalent (Bboe), with recoverable resources put at 300 MMboe of heavy oil. Phase 2 will see Argonauta O-North developed via 11 new wells (seven horizontal producers and four horizontal injectors) and subsea infrastructure tied back to the Espirito Santo floating, production, storage and offloading (FPSO) vessel. The second phase of development will essentially help Shell to sustain plateau production rates and keep the infrastructure full.

Argonauta O-North has similar heavy crude (16°-18° API) to that of its sister field Argonauta B-West, so the valuable lessons from the B-West development can be applied to O-North. It is anticipated that the four new caissons in Phase 2 will be similar and will recombine the gas to mix with the crude at the pump intake to stabilize the flow.

By comparison, the Ostra field produces 24° API crude while Abalone contains light gas condensate of 42° API gravity.

Parque das Conchas has, of course, featured many ground-breaking advances but perhaps of most significance was its "world-first” application of full-scale subsea oil and gas separation and boosting, enabling improved recovery by removing backpressure from the wells.

Artificial lift manifolds (ALMs) host the booster pumps that push the fluids up to the FPSO. The ALMs built for BC-10 weighed in at 140 tons and 235 tons for the Argonauta B-West and Ostra fields, respectively.

Underneath these are the massive separation caissons that lie beneath the seabed. Each is more than 100-m (330-ft) long. Each contains a 1,500-hp electrical, submersible, booster pump (ESP) to lift the produced fluid up through the risers to the FPSO. Some of these ESPs have been running for more than 17 months and still counting, added Pena.

The Ostra caissons played a dual role. These had a gas/liquid, centrifugal, cyclonic (GLCC) separator in the top that separated out a large percentage of the gas and routed it to a gas riser where it flowed naturally up to the FPSO. The GLCC concept was critical to the success of the project.

By removing the gas subsea, the formation of hydrates is minimized. Also gas slugging in the liquid riser is curtailed. After the gas is separated, the oil and water gravitates to the bottom of the caisson where the pump can then boost the liquids to the surface in a liquid riser.