The Skarv FPSO is BP’s first Norwegian greenfield project since 2001. Elaine Maslin explains the details.
Sitting just 50km from the Arctic Circle in 350-450m of harsh waters, the Skarv FPSO is a milestone for BP. It is the firm’s first greenfield project in its Norwegian unit since the Tambar field came onstream in 2001 and is thought to be one of the most northerly of the group’s global developments.
According to BP, it is the world’s largest harsh-water floating production, storage and offloading vessel, at 295m long, 51m wide and weighing in at 74,000 tons. It has a storage capacity of 875,000 barrels, oil production capacity of 85,000 b/d and gas production capacity of 19MM cu m/d (670MMscf/d). It came onstream on December 31, with the first export of gas on January 6 and five wells producing by the end of February.
During the year, a total of 17 wells will be active, seven as oil producers and four as gas injection, with the first oil offtake by shuttle tanker expected during March. Production is expected to ramp up to about 125,000 boe/d per month within the first six months, reaching an expected maximum daily rate of about 165,000 boe/d by year end.
It has been a long time coming. The Skarv oil and gas field was discovered in 1998 followed by the nearby Idun field a year later. Together they are estimated to contain about 100MMbbl of oil and condensate and about 48 billion cu m (1.5Tcf) of rich gas, according to BP. A NOK 30 billion PDO (plan for development and operation) was submitted in 2007 to jointly develop both fields, estimated to contain about 100MMbbl of oil and condensate and about 48 billion cu m (1.5Tcf) of rich gas.
Aker Solutions carried out front end engineering design and detail engineering and procurement, covering the vessel’s topsides (18,000 tons), hull (based on Aker’s Tentech 975 design and weighing 49,000 tons) and living quarters. South Korea’s Samsung Heavy Industries carried out the fabrication and installation of the hull and topsides. The turret and mooring system was designed by SBM Offshore and built at the Keppel Shipyard in Singapore.
The turret, weighing 7500 tons and standing 77.4m high, was designed to take mooring loads of 5500 tons and has 21 riser/umbilical slots (14 phase one and 8 spare). Keppel described it as “the largest internal turret in the world in terms of its rated mooring loads.”
The hull’s structure, turret and 15 mooring lines, hooked to suction anchors on the seabed, were all designed to withstand three combined potential eventualities: a total loss of power and therefore use of thrusters, 100-year storm conditions, and the vessel not being in optimal position to the prevailing weather conditions.
“The structural integrity of the FPSO and its mooring lines are designed to be maintained in all those circumstances,” said Pat McHugh, Skarv project director. “That is an unusual demand and what we have, therefore, is one of the highest-strength mooring systems ever installed.”
While a large part of the Skarv development, the FPSO and mooring system is only 50% of the project – the rest is beneath the rough waves of the Norwegian Sea.
VetcoGray, a GE Oil & Gas business, and JP Kenny carried out the engineering, construction and testing of the project’s 17 wellheads and tree systems, five subsea templates with integrated manifolds (fabricated at Burntisland Fabricators), and an 85km, 26in. gas export pipeline system including: flowlines, control umbilicals, and control systems for workover and tie-in.
Subsea 7 and Acergy, before their merger, were awarded much of installation work. As Subsea 7, the firms carried out the engineering, fabrication, and installation of 42km of single flowlines, consisting of 35km, 12in. and 10in. diameter, clad, production flowlines and 7km, 10in. diameter, carbon-steel, gas-injection flowlines. A direct-electrical heating cable was also attached to the 13km Idun flowline.
Subsea 7 also carried out installation of subsea structures, control umbilicals, dynamic umbilical and flexible risers; the tie-in and precommissioning of all flowlines, risers, control umbilicals and the gas export pipeline. Technip carried out the engineering, procurement, and construction of the flexible pipelines, manufactured by Flexi France, and associated equipment.
This infrastructure is spread over 15sq km, with the 17 wells (seven oil producers, five gas producers and four gas injectors) at a distance of between three and 14km from the FPSO with 13 risers and 40km of infield flowlines.
As part of the installation, and as a result of significant scouring on the seabed from fishing, some 1.25 million tons of rock dumping was required, prior to and post subsea infrastructure installation, with some 37,000 tons still to be deposited in the second quarter of this year.
Like many major projects, Skarv has had its set-backs. Production was originally planned to start in the third quarter of 2011.
The project started in earnest with first steel cutting of the hull at Samsung’s yard in 2008. The project remained on track through delivery of the main turret sub-assemblies to Korea, their installation, and the transport of the FPSO to Norway, which arrived on schedule March 1, 2011.
Production drilling started in the field in 2010 with Dolphin Drilling’s semisubmersible, Borgland Dolphin, and then Transcoean’s semisubmersible, Polar Pioneer, which will continue drilling this year.
However, McHugh said: “Once the FPSO arrived in Stord (the Aker Stord yard), we found that the finishing work was more extensive than expected because of some pipe work repairs, which had to be carried out. Consequently, we stayed in Stord for some weeks longer than initially planned.”
Corrective work included repairs to flange leaks in the turret and topsides of the vessel, and repairs on the riser pull-in winch, but this then had a knock-on effect on the project.
“As a consequence of staying longer in Stord than had been expected, we did not get the FPSO moored in the field until late-August 2011,” said McHugh.
“This, in turn, meant that we rescheduled the pulling-in of flexible risers to start in September 2011. At this point, a combination of crane problems and bad weather conspired against us, such that by mid-November 2011 we had only managed to pull in three of the thirteen risers.
“Then the weather turned completely against us and we were unable to complete any more risers until mid-April 2012. By the end of May 2012, we had completed all of the riser connections and then progressed to complete commissioning, and started production by the end of 2012.
“With the exception of “rock dumping” activities to level out the undulating seabed, offshore work is difficult during the harsh winters between October and April. But huge seas and high winds are liable to disrupt a work schedule at other times of year, too.”
Limited access to equipment and services were further unforeseen hindrances. Geir Edvardsen, Skarv transport and installation manager for BP, was reported as saying that engineering firms already working to full capacity was a prime result of the delay.
“In addition to the difficulty in getting hold of vessels and rigs, there is tremendous pressure on engineering services,” he said. “The vendors say they do not have the capacity to take on more assignments.”
In addition, there was a “challenging bed (space) situation due to extension of the scope of the project work in parallel with the needs for beds for ongoing routine vessel maintenance,” said BP.
Despite the delays, the project was carried out with an excellent safety record, said BP. With a total recordable injury rate of just 0.27, the project was seen as a huge success The expected field life is 25 years, but there are already additional prospects lined up to be exploited once ullage (storage) capacity is freed up on the FPSO, said BP.
According to project partner PNGiG: “Including the volumes in the discoveries and mapped prospects, total recoverable resources within the Skarv area are estimated to be 20.5MM cu m oil and condensate and 76 billion cu m gas.”
Potential tie-ins include the discovered Snadd South, Snadd North and Grasel structures – all mostly gas – said PNGiG.
BP said: “There is additional exploration potential. Decision will follow once completion of interpretation of seismic survey for 2013 and the outcome of further studies.
“Timing of (additional) tie-ins is dependent on availability of gas processing/export capacity on Skarv and is scheduled for around 2020.”
BP Norway is operator and has a 23.84% interest with partners Statoil (36.17%), E.ON E&P Norge (28.08%) and PGNiG Norway (11.92%) holding the rest. OE