The industry is acutely aware of the challenges faced by operators undertaking so-called megaprojects. With many blighted in past years by well-publicized soaring costs and schedule overruns, the offshore sector today is still painfully going through the brutal process of addressing those issues and their causes so it can eventually pick up the pace of exploration and development once more.

But it also has often conveniently been ignored by many of the industry’s more Philistinic observers that the majority of these and other more “conventional” offshore projects have been true technological pioneers, employing innovative solutions that were absolutely essential to produce oil and gas.

Eni’s Goliat project offshore Norway is a case in point. Some of the criticism aimed at the company during its challenging development of the world’s northernmost offshore floating production facility—and the first oil project in the Barents Sea—was more akin to the scorn legend attaches to the biblical giant Goliath when he called out the Israelites, only to be confronted by the diminutive David. We all know how that story ended.

Eni is no David-sized underdog, however. A giant in its own right, the company has had to dig deeply into its reserves of project experience to overcome this Goliathan headache.

Slow burner
As with all major field developments, it’s a long-term investment that can take a long time to come to fruition. In Goliat’s case, the story began back in 1991 when Eni first got involved in the Barents Sea. That program culminated in the company submitting a record 40 applications for the area in 1997, resulting most significantly with the award of Production License 229 (PL229), which would reveal the Goliat discovery three years later in 2000.

It took about nine years from then before Eni’s plan for development was approved by the Norwegian government and a further seven years before the project was brought onstream in March 2016 as the first surface production facility in the country’s Arctic Barents Sea sector (Statoil’s subsea-to-shore Snow White gas field came onstream in 2007). Eni holds a 65% stake as operator in PL229, while Statoil holds the remainder.

Taken from when Eni first submitted its application for Goliat’s license area, that’s nearly 20 years for the rewards to start flowing—by no means an unusual period for an oil company to have to plan ahead.

But even Eni has to admit that its luck in terms of the development’s timing could have been better, sat almost entirely within a period in which—with the very unfair advantage of hindsight—offshore project costs soared on the back of an unprecedented and sustained upward oil price curve before the current and equally sustained price collapse.

Negative equity
A report by analysts Bernstein Research earlier this year nicely illustrates this point. Fields brought onstream during 2015—and the report said 2016 will be just as bad—suffered from simple negative equity.

Those that started up last year did so “at an average oil price that was $53/bbl lower than when they were approved, the greatest negative position in oil industry history,” the report stated. This negative equity metric, based on how much the oil spot price moved between project approval and project first production, is a strong driver of decisions on whether to go ahead or not with the development of new fields. 

The obvious result is that these existing fields recently brought onstream such as Goliat are generating much less cash flow than originally planned.

At peak more than 600 personnel were working offshore during the hookup and commissioning phase for the Goliat Field last year, with the Floatel Superior drafted in to ensure enough manpower was available onsite. (Source: Eni Norge)

Breakeven costs
As a result, within a week of Eni happily trumpeting the flow of first oil from Goliat, located 85 km (53 miles) northwest of Hammerfest, CEO Claudio Descalzi was having to reassure analysts in an investor briefing that the project’s breakeven cost was less than $50/bbl. Some analysts had put the breakeven figure at anywhere between $75/bbl and $95/bbl, figures that Eni always declined to comment on. 

Stressing that the company’s overall breakeven costs were coming down fast because of the ongoing market adjustment, Descalzi said that the average breakeven on Eni’s projects across the board had now been brought down from $45/bbl to $27/bbl, with the onshore figure at about $15/bbl and the figure for shallow and deep water put at a combined $30/bbl.

Descalzi went on to admit Goliat was “very complex,” with its breakeven cost “the highest that we have now. But it is below $50/bbl and is in production.” He pointed out that less than a week after first oil in March 2016 it was producing 90,000 bbl/d and closing in on the plateau production target of 100,000 bbl/d, so its operational performance and efficiency so far are looking good.

The Goliat FPSO unit was close to its 100,000 bbl/d production capacity within a week of coming onstream in March this year, with 22 wells eventually to feed the facility via eight subsea templates. (Source: Eni Norge)

The project’s complexity impacted Goliat’s schedule as much as its cost. Not only did the capex figure climb nearly 50% higher than Eni’s first estimate to about $5.6 billion, but the onstream date shifted back by about two years from its original target date. Even though it was on location as of May last year, the process of bringing the facility onstream was delayed several times, toward the end because of problems with its electrical system.

However, although no endorsement, those schedule and budget overruns are not out of the ordinary for such large and complex offshore projects. Ernst & Young confirmed in research nearly two years ago that 64% of oil and gas megaprojects (more than $1 billion) at that time were facing cost overruns to complete, while 73% were suffering schedule delays.

With the plunge in oil prices that occurred after that report, the conditions for a perfect storm were created that impacted not only Goliat but virtually every offshore project of any scale since then.

With that in mind it is admirable but not surprising, given its long-term strategy focused on basin-opening projects, how Eni has stuck to its guns with its pioneering development in the cold waters of the Barents. The operator has consistently looked at the full life-cycle returns on its projects when weighing them, and with a planned production life for Goliat of a minimum 15 years, the operator expects to more than cover its total investments as well as a likely return on its investment.

Largest circular FPSO
Goliat is instantly recognizable for its use of the distinctive Sevan 1000-design circular FPSO unit, currently the largest and most sophisticated example of its kind in the world.

With a storage capacity of 1 MMbbl of oil, the 18-deck facility will eventually receive production from 22 subsea wells (17 have so far been completed) connected to eight subsea templates in 350 m to 400 m (1,148 ft to 1,312 ft) of water. Of the total, 12 are oil producers, seven are water injectors and three are gas injectors.

The 64,000-ton platform was built at the Hyundai Heavy Industries yard in Ulsan, South Korea, and is 115 m (377 ft) in diameter and 100 m (328 ft) tall, with the unit held in place by 14 anchor lines.

The Sevan 1000-design Goliat FPSO unit weighs 64,000 tons, has 18 decks and is the largest and most sophisticated of its kind yet put into operation. (Source: Eni Norge)

The environmental aspects of operating in the Barents Sea have been paramount from the start and influenced Eni to opt for solutions including powering the fully winterized facility from shore via a 110-km (68-mile) high-voltage 75-MW subsea cable, which itself weighed 6,000 tonnes. (See below to read “Offshore power is shore thing,” a sidebar featured in this month's cover story.)

Other aspects include the offloading system, with the hose reeled out and in for each individual oil export
operation as well as the use of three dedicated and fully winterized dynamically positioned shuttle tankers.

Such decisions have helped reduce estimated CO2 emissions by about 50% compared to alternative solutions, helped also by any produced gas (up to 3.9 MMcm/d [137 MMcf/d]) and water (up to 126,000 bbl/d capacity) being reinjected back into the reservoir.

Barents upside
There is definite upside to Goliat and the surrounding waters as it continues on its productive life, with the field currently estimated to contain reserves of about 180 MMbbl of oil but with that figure expected to rise.

According to Descalzi, “around Goliat we still have a lot of structures. That is oil that will be ready to be linked to Goliat in the future, so we will continue to have the plateau. That is our aspiration,” he said. 

The field represents a genuine breakthrough for the Norwegian sector and its ambitions to build and sustain oil and gas production from the Barents Sea as output from its established mature continental shelf continues to gradually decline.

In response to the issues that have so challenged Goliat and its peer projects around the world, the industry is now—finally—making tangible progress.

In the Barents itself, Eni’s Goliat project partner Statoil has managed to dramatically cut estimated development costs on another oil development in the vicinity, Johan Castberg. The operator has in fact driven down breakeven costs for its development projects across its portfolio to less than $50/bbl, according to CEO Eldar Saetre.

Capex reductions
Speaking at the Subsea Valley conference in Norway early in April, Saetre said, “In 2013 we had an average breakeven price for the portfolio of about $70/bbl, including Johan Sverdrup.

“Today the breakeven point has been reduced to about $40/bbl. In the meantime we have sanctioned several projects with an average breakeven of less than $30/bbl. This is quite impressive with improvements of more than 40% and with capex reduction on the Trestakk project of 30% and typically 30% to 50% cost reductions in the portfolio.”

It is doing this, as are all of its offshore peers, by reworking concepts, finding new ways to work internally, challenging solutions and addressing projects from the subsurface to the facilities and onward. 

Saetre continued, “Today more than 80% of the capex in the portfolio is at $50/bbl. To get even further, we continue to depend on more technology development, new and innovative solutions, and engineering.

“On Johan Castberg we have been able to reduce the breakeven price from above $80/bbl to below $45, and it is heading
below $40/bbl. We have reduced the capex by 60% by selecting a floating production concept combined with cost-efficient subsea solutions and an efficient drainage strategy.”

The company’s Snorre expansion 2040 project is another example where a subsea solution has been selected, allowing Statoil to optimize and mature the project.

Past mistakes
The work also is being done elsewhere. “On Peregrino 2 in Brazil, a project we have been working on intensely, we have seen breakeven prices coming down from approximately $70 to less than $45 in about a year,” Saetre said. “We’re making a lot of changes in our operating model to make sure that the current improvement sticks and that we don’t repeat the mistakes of the past.”

Looking to the future, Saetre was perhaps speaking for the entire industry when he commented that it was essential for Statoil to keep investing. “I need to push the final investment decision button so that the barrels are actually in place when we need them and we can capture the upturn in the environment.”



Offshore power is shore thing

When it comes to powering installations from shore, operators are increasingly happy to flip the switch.

Using electricity from shore to power offshore facilities rather than generating it onsite is a solution that’s been around for well over a decade.

Production facilities have mostly generated their own electricity by burning fossil fuels to run their onboard equipment such as diesel-powered generating units or gas turbines. But shore-based electrification solutions—when the development case fits—hit the spot when it comes to today’s environmental requirements and the need to continue reducing or eliminating CO2 emissions.

There is also a simple practical design and cost requirement to keep facilities’ weights to a minimum while maximizing use of the available footage with platform topsides remaining among the most expensive real estate per foot in the world.

Eni’s Goliat platform is no exception, so the decision was taken to power it from shore, removing the requirement for a power equipment footprint topsides.

ABB carried out the completion and commissioning of the crosslinked polyethylene (XLPE) subsea cable system that connects the FPSO unit to the Norwegian mainland’s power grid. It is the most powerful and longest power-from-shore AC cable in the world, with ABB saying the high-voltage (123-kv) system, among other advantages, can reduce estimated CO2 emissions by half while suffering only low electrical losses.

The 75-MW three-core cable AC system includes a 105-km (65-mile) long static seabed section in up to 350 m (1,148 ft) of water as well as a 1.5-km (.93-mile) long dynamic section reaching up from the seabed to the FPSO unit.

Goliat is not the original pioneer here though. The Norwegian sector has been one of the flagbearers for power-from-shore solutions since 2005, with ABB delivering the world’s first such solution that year using a high-voltage DC (HVDC) power transmission system. This was a 70-MW link to Statoil’s Troll A platform, 70 km (43.4 miles) off Norway’s west coast.

That was followed five years later by the company delivering the world’s first AC power-from-shore dynamic cable connection to Statoil for the operator’s Gjøa floating facility. That flowed 40 MW of electricity over a 101-km (63-mile) long cable system fed by the Norwegian grid.

Nexans also has been heavily involved, supplying its kit for the Valhall Field complex’s major revamp completed in 2013. Nexans manufactured and installed 293 km (182 miles) of HVDC subsea cable and a separate fiber-optic cable for the power link. The 150-kV DC cable was installed using the Skagerrak cable-laying vessel, with ABB installing the converter stations.

Last year ABB also was awarded a contract for two 100-MW 80-kV cables that will stretch 200 km (124 miles) to a riser platform on Statoil’s Johan Sverdrup Phase One oil development, due onstream in 2019.

High-voltage 75-MW subsea power cable is loaded onto the laying vessel’s turntable before installation between the Norwegian mainland electricity grid and the Goliat platform 105 km away. (Source: ABB)

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Read the other May E&P cover stories:

‘The most boring company in the Gulf’

Global offshore market spend set for upturn

Fighting back with innovation