Taming a Sea Lion

Since its discovery in 2010, the Sea Lion field offshore the Falkland Islands has been subject to a string of development options. Elaine Maslin looks at Premier Oil’s optimized final plan.

Ocean Rig’s Ocean Guardian semisubmersible drilling rig. Image from Ocean Rig.

Unlike the penguin logo of the company which discovered it, the Sea Lion field development concept has been something of a shape-shifting beast in recent years.

Rockhopper Exploration’s corporate Rockhopper penguin logo has changed shape just once – throwing its little flippers up in the air in delight in 2010, on the discovery of the Sea Lion field.

The shape of the Sea Lion development concept, however, has changed multiple times, going from a leased floating production, storage and offloading (FPSO) vessel, to a bigger FPSO, then a tension leg platform (TLP), then back to an FPSO and finally a scaled-down FPSO, as part of a phased development.

The bumpy ride is no surprise, considering the ups and downs of the oil market over the period from discovery to front-end engineering and design (FEED), the contract for which was issued in January.

The final concept, announced amid US$30/bbl oil prices, is a fit-for-purpose, safety first, functional specification, where savings made have been used to increase – or optimize – the scope.

Phase one of the project will use a converted Suezmax tanker, with 18 wells, costing $1.8 billion up to first oil ($2.2 billion total capex) as part of the two-phase “Sea Lion Complex” project targeting 520 MMboe. Phase two will use a converted very large crude carrier. Phase three, now called “Exploration Upside,” will target a further 400 MMboe unrisked, Pmean from the Isobel and Elaine discoveries. Premier is targeting a final investment decision for the Sea Lion Complex in 2H 2017 with first oil due in 2020.

Sea Lion hunting

Drilling in the Falklands, a self-governing British overseas territory contested by Argentina (which calls the islands the Malvinas), started in 1998, when, at $10/bbl, five discoveries, from a six-well campaign, were declared uncommercial.

Rockhopper Exploration – founded in 2004 – picked up two licenses (PL032 and PL033) in June 2005 and floated on the stock market in August 2005. By 2010, it had started what would become a 10-well, two-year exploration campaign, on the back of the Sea Lion that year, with a total seven successful wells, using Diamond Offshore’s Ocean Guardian semisubmersible drilling rig.

Sea Lion, 200km north of the Falkland Islands, sits in 450m water depth, on the eastern edge of the North Falkland Basin. In a 2011 capital markets presentation, Rockhopper said the field had 21% porosity and good permeability, at 200 millidarcy, with a water leg useful for pressure support through water injection, and high formation integrity, which would enable high deviation or horizontal wells. After initial concept select screening, Rockhopper was looking at a leased, converted FPSO development with some 24 subsea wells plus water injection wells and one gas injection well. Initial hopes were for first oil as soon as 2016.

Phase 1a – finally

Fiona MacAulay

In 2012, Premier Oil came on board, taking a 60% stake in Rockhopper’s North Falkland Basin licenses. At first, Premier Oil followed the FPSO route, considering a larger-scale FPSO. But, in 2014, the game changed to a 30,000-tonne TLP concept, with a $5.2 billion price tag. This would mean taking on another partner, to help fund the project.

However, when the oil price fell, so did the concept. By returning to a FPSO, the partners would avoid the need to bring in another partner required for a costly TLP project. Sea Lion was back to a leased FPSO, with 50-60,000 b/d capacity, as part of a phased development.

Fiona MacAulay, chief operating officer, Rockhopper Exploration, joined the firm in 2010, just after the discovery well, and has led the entire appraisal campaign and then farm out to Premier Oil, now operator, with Rockhopper as subsurface lead.

“We went back to an FPSO and gave ourselves a limit of what we can do for up to $2 billion capex,” she says. “We went down the line of an FPSO with 12-14 wells. It was clear at that point we could still get the price down and by the end came out with a revised project at $1.8 billion.” This would see Phase 1a tap 160 MMbbl, with peak production at 60,000 b/d and 12-14 wells over a 15-year field life. But even then, the team decided to go further, making more savings, working closely with contractors.

“We have had a great response from our contractors,” says David Hartell, senior development manager, Premier Oil. “Often people do not make a choice of contractors until during FEED. We have done something different. We have selected our contractors in the select phase, or pre-FEED. We did partly reimbursable engineering studies and pricing, etc., with contractors in competition with each other, then went to formal tender.”

SBM Offshore was selected as the FPSO contractor in January, with an 18-month FEED contract. If all goes well, subject to final investment decision (FID), SBM Offshore also has a frame agreement with Premier to go straight into construction and then lease. Mid-February, Subsea 7 was awarded the subsea umbilicals, risers and flowlines (SURF) FEED contract and National Oilwell Varco the flexibles FEED contract. The subsea production system contract is due to be announced in Q1.

“Picking the four main contractors pre-FEED means they can work together in the FEED phase,” Hartell adds, “which is something others don’t necessarily do. This will enable efficiencies not just within the companies but also collaborative sharing and looking for value.”

The low oil price has also helped reduce costs of course. A large chunk of the project cost is drilling, at $1.2 billion for 18 wells, which is a “significant improvement” in cost compared to a year ago, Hartell says. After pitting four FPSO contractors against each other, Premier got pricing down some 30-40%, with about the same reduction seen in the subsea installation and subsea equipment costs.

“That’s in combination with us trying to specify facilities to functional needs, with not a lot of bells and whistles,” Hartell says. “The facilities meet UK safety requirements, but it’s very fit for purpose. That’s a change for the industry. People got a bit relaxed at $100/bbl, engineers like a lot of features. In a low oil price you can’t do that. You need safety first and functionality needs to be fit for purpose. Instead of specifying so many out puts and what it should look like, specify functionality and let the outputs be tested by the business case.”

Reducing the costs has also meant being able to increase the scope initially envisioned based on a $2 billion project and add the Northwest flank to the project.

Phase 1a Sea Lion development, will tap 220 MMbbl, compared to 160 MMbbl previously, with peak production at 85,000 b/d, compared to 60,000 b/d, and 18 wells (11 producers, six water injectors and one gas injection/producer) compared to 12-14 wells. The project life has also been extended from 15 to 20 years. Of the 18 wells, 13 are due to be pre-drilled in order to be able to reach plateau production within the first year.


An early concern on the field had been the waxy crude it will produce. But, Hartell says, technology and chemicals development in the past 2-4 years has made the task far simpler. Part of the SURF order is to include heated risers. Sea water, for injection, will also be heated to about 60-70°C on the topsides, to prevent any wax clogging the reservoir. As the field ages, produced water will itself be hot, so less heating will be required. The onboard crude storage tanks will also be heated.

Because of the remoteness of the Falkland Islands, exploration campaigns to date have been managed and supplied out of Aberdeen – some four weeks sailing away. But, while this seems like an unnecessarily long journey, it’s more reliable than using other bases and they’ve had no logistics issues to date, MacAulay says.

However, the cost of manning a production asset this way will be high, which has meant the team has been looking closely at remote monitoring, remote diagnostics and remote control on the vessel, seeing where it is possible to perform work from a central office in, say Aberdeen. “You could easily have a control room in Aberdeen,” Hartell says, “monitoring data so you can have a reduced size of staff offshore, and on a longer term scale going through the data looking at trends and performance envelopes, identifying maintenance.” You could go further and have your onshore control room looking after multiple assets and maybe have health care contracts with major equipment vendors, such as compressors, who will monitor their equipment.

Future phases

Premier Oil’s latest exploration campaign has proven yet more oil in the North Falkland Basin, which will help feed future phases – including phase three, called “Exploration Upside.”

The latest drilling campaign, using Ocean Rig’s Eirik Raude semisubmersible, made the Zebedee and Isobel/Isobel Deep discoveries.

Zebedee was discovered in March 2015, in the south, followed by the Isobel Deep/Elaine discovery well in May 2015. Due to the successful Isobel Deep encountering higher than expected reservoir pressures and a reservoir influx, it was cut short but then returned to. Jayne East was spudded, but never drilled, due to being replaced by the Isobel Deep re-drill.

The Isobel Deep re-drill, the most significant of the 2015-16 finds, was 4.2km from the Isobel Deep discovery well. Five F3 reservoir fans were intercepted: Irene, Emily, Elaine South, Isobel and Isobel Deep. 27m of net pay was discovered in Emily, Isobel and Isobel Deep. Reservoir pressure was confirmed to be greater than in Sea Lion, Rockhopper said in its announcement about the find.

Chatham, in the northern area, was due to be the next well to be drilled. It has been deferred following Premier Oil’s early termination of the Eirik Raude contract over operational issues. Chatham, which is north of Phase 1a, would determine if there is a gas cap on the west flank as well as looking at a deeper horizon beneath Sea Lion, MacAulay says.

“The indications are that area [Isobel] has got enormous amount of potential and could be bigger than Sea Lion. Even in Sea Lion, there are underlying reserves we haven’t put in to the development plan,” she adds.

Of course, it wouldn’t be right not to mention the weather in this British territory. Despite being in a pretty remote location, the metocean and meteorological environment is not harsh. The North Falkland Basin is sheltered to a degree by South America and is further from the South Pacific than the southern Falklands – which means rigs can work year-round. In fact, studies suggest both wave height and wind are lower than in the central North Sea.

“There is a lot of oil in a relatively benign environment. There is instability with Argentina, but in terms of security in other places, this is benign,” MacAulay says.

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