BP is refurbishing some of its most mature, but also most valuable, North Sea hardware, starting with its 30-year-old Magnus platform – the largest single-piece steel structure ever fabricated for the UK North Sea and still its most northerly
Those deployed to work there in the early days say Magnus was viewed as the ‘jewel in the crown’ of BP’s North Sea assets, and that the opportunity to work there was the most desirable Upstream job BP had to offer, even taking into account the long helicopter journey. Now BP’s oldest UK asset, Magnus has been producing since 1983. The 1978 development submission envisaged the asset producing until the mid-1990s, so Magnus has already surpassed that original expectation by 18 years. Magnus’s longevity has been due to the emergence of new technologies for increasing the rate of oil recovery. The technologies of water injection and, from 2003, water-alternating-gas enhanced oil recovery (WAG-EOR) have been the cornerstones of the operation’s impressive production performance to date (see page 30 for more on enhanced oil recovery). At discovery, BP estimated original oil in place at between 845 million and 1.15 billion barrels of oil. As a result of enhanced oil recovery, the teams now estimate that 1 billion barrels may be recoverable – around 62% of the oil in place. The WAG-EOR programme accounts for a quarter of Magnus’s current production, making it one of the most successful globally. The gas injected by Magnus is all imported from BP’s Schiehallion, Foinaven and Clair fields in the area west of Shetland (WoS), via the Sullom Voe terminal in the Shetland Islands. Schiehallion is being re-developed as part of the Quad204 project (see page 51 - This link opens in a new window for a map highlighting ￡1 billion of UK investment in Quad204), and Clair is the subject of one of BP North Sea’s largest-ever investments. The WoS area is a key part of BP’s North Sea strategy for the future, but the region’s remoteness means much of the group’s investment there would not have been feasible without Magnus’s ability to handle WoS gas. While enhancing recovery from producing areas is the backbone of Magnus’s extended life expectation, that future will also allow BP to continue producing from the deeper and more complex areas of the Magnus reservoir.
"Magnus is absolutely key strategically to the region and wider BP business. To be able to reliably produce the existing Clair Phase 1 and Foinaven fields, the new Clair Ridge field and Glen Lyon floating production, storage and offloading vessel, we need a reliable Magnus in order to handle gas from those assets."- Dave Goodwill
“Thirty years after it produced its first oil, Magnus is one of the most important assets BP has in its streamlined North Sea portfolio, for two key reasons,” says Dave Goodwill, vice president of operations, BP North Sea. “Firstly, there are still significant reserves to be recovered from the reservoir, so Magnus still offers major value to the company. “Secondly, Magnus is absolutely key strategically to the region and wider BP business. To be able to reliably produce the existing Clair Phase 1 and Foinaven fields, the new Clair Ridge field and Glen Lyon floating production, storage and offloading vessel, we need a reliable Magnus in order to handle gas from those assets.” Magnus has stood the test of time – physically as well as commercially, successfully enduring the harsh and hostile waters of the northern North Sea for 30 years. It was designed, completed and fitted out to withstand 100-year storm conditions, meaning waves of up to 31 metres (101 feet) and winds of up to 100 knots. Now, the North Sea business plans to equip Magnus for a further generation. It is about to undertake a major overhaul of the operation to set it up for the next 20 years. In what will be the most extensive offshore fabric maintenance programme ever carried out in the North Sea, BP will progressively renew and refurbish much of the platform, from the asset’s 27-year-old nitrogen generation plant right down to its accommodation.
The programme will involve some 500,000 manhours and 12 months of near-continuous shifts. The North Sea business will then work systematically to renew and refresh the fabric of the asset on a large-scale-project basis, clearing the way to embark on new drilling and the value-adding work that will see Magnus maximise its potential. “Magnus’s age means it has one of the world’s most extensive inspection programmes, and one of the world’s most extensive fabric maintenance programmes,” says Wissam Al Monthiry, one of Magnus’s offshore installation managers. “The renewal programme will enable us to do everything we need to do to set up Magnus for the next part of its life and keep it operating safely. “We are bringing in a lot of new people to help take it forward, while continuing to draw on the expertise and knowledge of people who have been part of Magnus for a long time, both on and offshore. “Magnus has changed with the times. From the 1980s to the present day, it has adapted to its environment, taken advantage of advances in engineering to help overcome huge technological challenges and is shaping up for a new decade.” A model of BP’s management of a valuable late-life asset, Magnus is now looking at a future well into the 2020s and beyond. The approach is likely to be replicated on other assets in the mature North Sea, in line with BP’s approach of focus on its core portfolio in the region.
"Magnus’s future is assured by its vital role as a hub for BP North Sea’s west of Shetland gas, but it is also underpinned by the remaining potential of the Magnus reservoir itself. To tap that potential, the asset has an active drilling programme, with wells planned out to 2018."- Matt Dunning
“Magnus’s future is assured by its vital role as a hub for BP North Sea’s WoS gas, but it is also underpinned by the remaining potential of the Magnus reservoir itself,” says Matt Dunning, senior petroleum engineer, North Sea. “To tap that potential, the asset has an active drilling programme, with wells planned out to 2018 and others under evaluation for later drilling phases beyond that. “The future planned wells are WAG wells (injectors and producers), designed to target areas that have previously been waterflooded and which will now be injected with more gas to increase overall recovery,” Dunning says. “We also have ‘attic wells’ that will target higher areas of the field that BP believes may not have been reached by the original waterflooding and that could hold residual untapped oil. “In addition, the reservoir team is employing the latest in four-dimensional seismic technology to identify areas of the reservoir that have not been swept and making interventions where appropriate, to continually identify new opportunities and maximise the recovery from Magnus’s wells.”
An early giant
Located in the northern North Sea in blocks 211/12a and 211/7a, Magnus is approximately 160 kilometres (100 miles) northeast of the Shetland Islands. The UK’s most northerly-situated platform, it lies 480 kilometres (300 miles) south of the Arctic Circle and just a few kilometres from platforms over the maritime border with Norway. BP was awarded a licence to drill in the block in 1972 in what was only the UK’s fourth licensing round, and discovered oil in May 1974. Magnus’s resources made sure it easily earned its place as one of the early ‘giants’ of the North Sea, but the field’s location so far north meant it was initially viewed as a ‘marginal’ field that required a financially compelling development solution. The reservoir’s long and narrow shape, delineated with BP’s seven appraisal wells, initially suggested nothing less than a two-platform development would work, but, two years of economic and engineering studies later, BP selected a single-platform development with subsea-completed wells, and construction commenced in 1980. The project cost ￡1.3 billion. Floated out of the construction yard at Nigg Bay, Scotland, in March 1982, the Magnus structure weighed 40,400 tonnes. More than 1,000 individuals worked on the operation to hook up the structure with its 31,000-tonne topsides, and Magnus produced its first oil on 15 August 1983, exporting via the Ninian Central pipeline. At its peak, from the mid-1980s to the mid-1990s, Magnus produced 156,000 barrels per day of oil, 12,000 b/d of gas condensate and 60 million cubic feet per day of gas. In 1995, the limited number of well slots on the platform led BP to expand the subsea system. This allowed further injection wells to be drilled and the development of South Magnus field, which came onstream in 1996. The Magnus Extension Project (MEP) in 2006 added an extra four well slots, serving eight new wells, to the platform, enabling further development of the WAG scheme. North West Magnus followed, coming onstream in 2009.