John Bradbury takes a look at activity in the North Sea – across Norway and the UK.
Johan Sverdrup - an artist's impression. Image from Statoil.
By the middle of 2016 it was evident that despite the downturn the North Sea’s biggest project was steaming ahead.
But industry gloom isn’t far away either: a report by PwC, which canvassed 37 oil and gas leaders across the North Sea Basin – in Norway, the UK, and Holland – recently suggested a two-year window of opportunity remains before much of the remaining North Sea potential could be lost through decommissioning of aging infrastructure.
While significant levels of optimism persist about the future of the basin, the PwC report, “A Sea Change,” found executives calling for closer cooperation among operators, contractors and governments, and for changes in leadership. “Our respondents recognized that a change of guard at the top is essential if the industry is to successfully disrupt its ‘we’ve always done it this way’ mentality and become a force for innovation and re-invention while demonstrating entrepreneurial and forward-thinking leadership,” said the PwC report.
The study calls for the creation of a “super joint-venture vehicle,” which is seen as key to consolidating smaller and fragmented assets under one operator, which almost sounds like a call for a state oil company. PwC found evidence of an industry “…keen for the regulator to lead from the front,” and “There is an expectation from industry that the regulator not only sets a holistic framework for the basin, but is more assertive to change behaviors.”
The Ivar Aasen jacket has already been installed. Image from Det norske.
GE Oil & Gas was the latest major contractor to collect a deal to deliver services to Norway’s Johan Sverdrup megaproject. Surface wellheads, xmas trees and related services will be supplied by GE. Although the contract value was undisclosed – but is likely to be measured in millions of dollars – GE said the deal was a multi-year contract for supplying hardware for “multiple wells.” Reports have indicated 35 production and injection wells are required for phase one at Sverdrup and the GE supply scope is for 23; FMC Technologies is supplying 13 trees and wellheads.
Separately, construction has started on the four bridge-linked platforms for the first phase of the 1.7- 3 billion bbl project. At Kvaerner Stord, Norway, steel plates were cut for the 19,000-tonne utility and living quarters (ULQ) topsides, one of four installations for Sverdrup’s first phase.
Kvaerner and KBR combined won a deal for complete delivery of the ULQ in June 2015. Meanwhile, at Kvaerner Verdal, three of the four steel platform jackets are being constructed for the remaining three riser, drilling and process platforms. Spain’s Dragados Offshore is constructing the final jacket for the ULQ.
Apply Leirvik in Norway is building the accommodation module for the ULQ. Topsides for the riser and process platforms are being built by Samsung Heavy Industries. Norwegian firm Aibel is constructing topsides for the Sverdrup drilling platform. Development drilling for the first 35 phase one wells started in March.
Recently, Statoil indicated a reduction in capex for Sverdrup phase one, from NOK 123.2 billion (US$14.4 billion) at PDO submission, to NOK 108.5 billion ($12.7 billion) at present.
Partner Lundin Petroleum reported in May that a de-bottlenecking study suggested a potential increase in processing capacity from 315,000-380,000 b/d to 440,000 b/d of oil for phase one. Sverdrup phase one is due onstream at the end of 2019. This year concept selection for phase two at Sverdrup is due – a study for which is underway by Norway’s Aker Solutions.
The Ivar Aasen project, an artist’s impression. Image from Det norske.
Earlier this year saw first oil from the Goliat field, the first surface development in the Barents Sea using a Sevan Marine round-hulled FPSO (floating production, storage and offloading) tapping an estimated 174 MMbbl of oil and the first project to be operated by Eni Norge, offshore Norway.
The next start up is likely to be Ivar Aasen, another NOK 18.025 billion ($2.1 billion) fixed platform project offshore Norway, which will also tap the West Cable discovery and the Hanz accumulation in a second phase. It is due onstream in Q4 2016, and is operated by Det Norske.
Aasta Hansteen, using an eight-slot, deepwater spar, was approved for development in 2013, and is due onstream late 2018, costing an estimated NOK 3 billion ($350 million).
Next will be the 225 MMboe Gina Krog development, using a fixed platform and an FSO (floating storage and offloading). It is due to come onstream in Q1 2017 with oil offloading and gas export via Sleipner A, at cost of NOK 31 billion ($3.6 billion)
Martin Linge will follow in 2018. It is a structurally complex, high-pressure, high-temperature field operated by Total, which gained development approval in June 2012, is currently costed at NOK 34.8 billion ($4 billion), and will be developed with a fixed platform and an FSO, with power from shore. Rich gas will be exported via pipeline into the UK Frigg system and landed at St Fergus, while oil and condensate will be tanker-offloaded. Production well drilling started in September 2014, using the Maersk Intrepid jackup, with six wells due to be ready before production start-up, which is scheduled for 2018.
Det norske’s Alvheim FPSO, soon to be part of Aker BP. Photo from Det norske.
The Gina Krog development. Image from Statoil.
This summer saw the Norwegian Petroleum Directorate acknowledge a new type of platform – an unmanned installation - could be permitted offshore Norway. This new concept for Norway, but widely used in the Dutch and UK sectors, will be deployed on the Oseberg Vestflanken 2 project for which a plan for development and operation was approved by the Ministry of Petroleum and Energy in June (Read more: Less is more). The installation - 9km from the main Oseberg field center – is due onstream in 2018 operated by Statoil and will tap 110 MMboe of reserves – 62 MMbbl is oil, and 7.8 Bcm is gas.
Norway’s Barents Sea Johan Castberg field encompassing the earlier Havis and Drivis discoveries and 110km beyond the Snohvit field off northern Norway, is still subject to conceptual studies, including an FPSO. Reserves, according to the Norwegian Petroleum Directorate, are 85.9 MMcm (540 MMbbl) but an onstream date – originally touted for 2018 – is still unknown since it has been delayed several times.
For the Johan Castberg project, Statoil’s current capex forecast is down 50-60% from NOK 100 billion ($11.6 billion) back in 2013 to NOK 50-60 billion ($5.8-7 billion) at present reflecting cuts in industry costs as the oil price has tumbled in the last two years (Read more: De-engineering).
While two new significant projects are due onstream – BP’s £3 billion ($4 billion) Quad 204 redevelopment, West of Shetland, using the new build Glen Lyon FPSO (due onstream this year) and its Clair Ridge development (expected online at the end of 2017) – activity in the UK is, more broadly, at a much lower level.
Maersk Drilling’s Maersk Inteprid jackup has been drilling on Total’s Martin Linge project. Photo from Maersk Drilling.
Chevron recently signaled that it has abandoned a plan to use a new bridge-linked platform for an EOR (enhanced oil recovery) project at its Captain heavy oil field. Instead Chevron, which had earlier issued tenders to four platform bidders, revealed that it has instead opted for a lower cost concept, based on brownfield modifications to the existing Captain A facility.
But, Maersk is progressing its $4.5 billion, three-platform Culzean development, for which first steel was cut earlier this year at Sembcorp Marine Offshore Platforms, formerly known as SMOE, in Singapore.
Ithaca Energy is progressing its Greater Stella area development to tap the Stella and Harrier fields with a converted floating production unit, the FPF1, which was due to leave the Remontowa yard in Gdansk, Poland, in July and transit to the UK North Sea field.
Two other UK projects, the Kraken heavy oil development by EnQuest, and the Catcher project by Premier Oil, both using FPSOs also, are due onstream in 2017.
EnQuest shaved $425 million off the original $3.2 billion Kraken cost earlier this year. The converted integrated turret FPSO, which will be leased from and operated by Malaysia’s Bumi Armada to EnQuest, departed dry dock in December last year and is on course for departure from Singapore in 2016. Bumi is converting a recently built ice-class tanker for the conversion. It will use an NOV buoy turret mooring with 16 risers and Framo swivel stack. Four production wells are due to be available at first oil.
Premier Oil has also been shaving costs off its project, Catcher. The project, involving a new-build FPSO on contract from BW Offshore and with Aibel fabricating the topsides, is now forecast to cost $1.35 billion to first oil, after a 15% reduction in costs. Catcher will be a 22 subsea well project (14 producers and eight water injectors) expected to produce 96 MMboe over its lifetime.