The Norwegian Continental Shelf, like every other sector, has been on a dramatic diet for the past two years.

The slimming plan adhered to by Norway’s technologically pioneering offshore industry is all about reducing the crippling weight of cost, something that for decades has been the sector’s only real downside. Like all diets, there’s no getting around the fact that to achieve the end goal, the slimmer has to stick to the plan or risk excess fat returning—and excess is something the upstream business can no longer afford.

With the oil industry’s focus falling on Norway for the Offshore Northern Seas (ONS) event in Stavanger, it was time to step on the scales and tick off some milestones. Statoil did not disappoint, having worked hard to get itself into better shape.

The company’s CEO, Eldar Satre, was chief cheerleader at the show, and his passion on the subject was clear. “We face new realities but also new opportunities, so this is a time to lead and also to shape the industry,” he said. “Culture and collaboration are key to the success of this transition: culture because fundamentally we have to change how we work; collaboration because the challenge is bigger than any challenge the company can do on its own.”

Exposed

He admitted, “On the opening day at the last ONS two years ago the oil price was almost $100/bbl. But the low oil price has exposed us all. We need a culture where we allow improvement, irrespective of where we are in the commodity cycle.”

Those words have been heard a little too often in recent years from various companies, with some dismissed as being little more than lip service to keep stakeholders at bay until the oil price turned upward once again.

However, with no upturn likely in the short term—if at all—Statoil and its partners have gotten on with the job and are producing tangible results that those improvements are taking effect.

A high-profile case in point is the operator’s success in reducing the development cost of Phase 1 of its giant Johan Sverdrup project by 21% to NOK 99 billion (US$12 billion). It’s done this, it said, while also managing to expand the full plan by adding an additional processing platform to the development’s production capacity.

The 21% cut in forecast capex on the four-platform Phase 1 to NOK 99 billion is a reduction of NOK 24 billion (US$2.9 billion) from when the original plan for development and operation (PDO) was submitted along with an estimate of NOK 123 billion (US$14.9 billion).

Breakeven of $25/bbl

It also means the operator and its partners have achieved an impressive breakeven price for Johan Sverdrup’s Phase 1 of less than $25/bbl—an astonishing figure compared to Norway’s offshore megaprojects of the past, which often had equivalent figures at least double this amount.

Contributing to this has been a focus on areas such as debottlenecking and optimizing the Phase 1 processing facility, resulting in the oil production capacity being raised from its original range of between 315,000 to 380,000 bbl/d to 440,000 bbl/d. Other improvements came from higher drilling and well efficiencies as well as better project planning and execution. Phase 1 production is planned for late 2019.

Statoil also has delayed the full-field development’s schedule by about six months to further improve it but maintains that the full development’s onstream date is still targeted for 2022. The PDO for Phase 1 originally called for project presanction of future phases this year, with an investment decision by year-end 2017. According to the updated plan, the project presanction will now be made in first-half 2017 with a final investment decision reached and the PDO submitted during second-half 2018.

With the addition to the plan of the extra processing facility—already agreed by the field partners but still subject to a formal presanction decision—Johan Sverdrup’s eventual full-field production capacity is put at 660,000 boe/d. This compares to the original range of 550,000 bbl/d to 650,000 bbl/d.

Challenging Every Element

Lower end recoverable reserve estimates also have been firmed up and raised to a slightly higher range of between 1.9 Bboe and 3 Bboe, added Margareth Ovrum, the company’s executive vice president for technology, projects and drilling.

She said the improvements in cost had been achieved “by challenging every single element.” This has resulted in another impressive forecast breakeven figure for the full development of less than $30/bbl.

“At the same time, we want to stay on schedule for full-field production start and for establishing an area solution for land-based power by 2022 as per conditions stated in the approved PDO for Phase 1,” she stated.

“It’s a massive project. We’re spending NOK 24 billion per year on it. But it is running to plan, and we have completed 31% of the first phase so far,” said Ovrum, who pointed out that more than 70% of the Phase 1 contracts had gone to Norwegian companies.

She also stressed that further reductions might be on the way. “We still see further room for improvement. There’s no time to relax,” she said.

Other End Of The Scale

Toward the other end of the project development scale but reflecting the same focus on cost, Statoil also confirmed within the same 24-hr period that it had brought onstream a relatively small two-well subsea tieback project at half the development cost originally envisaged when it was first considered. It also was four months earlier than scheduled.

The operator gave itself an early Christmas present by confirming first production from the Gullfaks Rimfaksdalen Field well ahead of the planned startup on Dec. 24.

With the original development cost put at an eyebrow-raising NOK 8.8 billion (US$1 billion), hindsight begs the question as to why those costs were ever thought acceptable at any time.

However, according to Arne Sigve Nyland, Statoil’s executive vice president of development and production, this was dramatically reduced through an intensive cost reduction exercise to NOK 4.8 billion (US$580 million) at the time of the submittal of the PDO. Since then, the good work has obviously continued, with the project’s development cost now further reduced to NOK 3.7 billion (US$445 million), a much more acceptable figure.

Recoverable reserves from Gullfaks Rimfaksdalen are put at about 80 MMboe, mostly gas. Statoil is the operator with a 51% stake with its partners Petoro (30%) and OMV (19%). The standard subsea template development sits in a water depth of about 135 m (443 ft) with two gas production wells flowing and with the possibility for the tie-in of two further wells. The wellstream is connected to an existing pipeline leading to the Gullfaks A platform.

30-project Pipeline

Looking farther ahead, Nyland also went on to highlight that Statoil currently has 30 projects in the nonsanction phase, where it also has brought its focus on costs to bear. According to Nyland, so far it has reduced the estimated breakeven cost for these 30 potential developments from $70/bbl to $41/bbl.

Referring to the cost efficiencies on Gullfaks Rimfaksdalen, Nyland admitted that when the project was first mooted it was clearly at a time of “higher oil prices but also higher costs.” The oil price downturn, he said, has been “a true wakeup call for the entire industry,” which for Statoil has meant having to improve its ways of working with its partners and suppliers.

Gullfaks Rimfaksdalen is perhaps symbolic of what can be achieved. The end result, he concluded, is that the project “is a sign of recovery—not of the market but that the industry is recovering. We are gradually regaining our competitiveness on the Norwegian Continental Shelf.”

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