Few doubt that deep and ultradeepwater developments will have their time again but, according to present forecasts, final investment decisions (FID) for new deepwater facilities will be a rare sighting for a while.

That’s not to say that deepwater projects are not on the drawing boards of companies, with many being further “reengineered” into lower cost versions while their owners wait for better times (BP with its Mad Dog Phase 2 development in the Gulf of Mexico [GoM] being a case in point).

But until the industry has managed to reduce its costs enough to overcome an oil price that many believe is now set to stay at its current level for at least the next year, few are likely to get project sanction any time soon.

About 75% of deep water uneconomic
The accepted fact is that, at present, even at an oil price of $60/bbl, about 75% of deepwater projects were uneconomic as of mid-2015, according to a Goldman Sachs report at that time.

Recent announcements have shown just how much excess there is to cut out. On Statoil’s Johan Castberg development, the operator has revealed that costs have been slashed from a huge $11 billion to circa $5 billion or $6 billion. Although an admirable reduction, it immediately begs the question as to how costs had been allowed to soar so high in the first place.

The field lying in the Barents Sea within the Arctic Circle is now set to be developed—although not yet sanctioned—using an FPSO vessel with an FID set for 2017, according to CEO Eldar Saetre. Previously, the operator had been considering a production semisubmersible unit as an alternative option. It is also likely that offshore offloading of the oil has helped to further reduce the costs as opposed to the alternative plans, which have included a possible pipeline to shore to a new standalone oil terminal.

Johan Castberg is located about 240 km (149 miles) northwest of Hammerfest in northern Norway and is comprised of the former Skrugard, Havis and Drivis fields, all within Production Licence 532. The field is estimated to contain recoverable reserves of up to 600 MMbbl of oil.

FID delays
A similar path is being followed by BP, which has two production semisubmersible units on the drawing board in the GoM, including Mad Dog Phase 2 and also its Hopkins discovery.

The operator originally planned to make a decision by early 2016, with Mad Dog Phase 2 already having been delayed several times over the past two years for further redesigns and cost-reduction efforts.

But the continued freefall in oil prices last year, and no sign of a recovery, means it is now unlikely to make any investment decision until later this year at the earliest, if not in 2017. The second phase of Mad Dog in Green Canyon Block 780 was originally planned to be developed using a large production spar, but that plan was ditched after its costs soared billions of dollars beyond its original planned budget.

Less is known about Hopkins, but the deepwater discovery in GC 627 lies about 319 km (198 miles) south-southwest of New Orleans and was last year put on a fast-track development process, only for the operator to now hit the brakes this year.

Deferred capex of $380 billion
BP’s move is representative of the entire global upstream industry at present. According to Wood Mackenzie (WoodMac), the low oil price environment and other factors have caused companies to stall 68 upstream projects—many of them in deep water. These represent a combined capex of $380 billion.

“The impact of lower oil prices on company plans has been brutal,” said Angus Rodger, principal analyst of upstream research for WoodMac, in a recent report. “What began in late 2014 as a haircut to discretionary spending on exploration and predevelopment projects has become a full surgical operation to cut out all nonessential operational and capital expenditure.”

In second-half 2015, 22 major projects, including 10 in the North Sea, joined the list of 46 deferred projects already identified by WoodMac as of mid-2015—when oil was trading at about $60/bbl.

Many of the FIDs for these projects have been pushed back to at least 2017, delaying first production to a likely date anywhere between 2020 and 2023.

Twenty-nine deepwater projects stalled
Examples it listed of delayed projects included Statoil’s Aasta Hansteen Field offshore Norway and the Mariner Field in the U.K. North Sea from 2017 to second-half 2018, citing increased costs.

WoodMac’s list also included the deferral of the development of the Golfinho Area offshore Mozambique and Eni’s Kashagan Phase 2 project in the Kazakh sector of the Caspian Sea as well as projects offshore Angola.

A sizeable number of the stalled projects are high-cost deepwater developments, it stated, with the number of these project deferrals jumping from 17 in June to 29 at year-end 2015.

WoodMac said more project delays and investment spending cuts are highly likely this year as a sub-$35/bbl oil price forces companies into survival mode.

Cost reduced
But substantial cost reductions on major deepwater developments already have been achieved.

Shell is a case in point on two of its highest profile projects underway in the GoM—Stones and Appomattox. The company produces more than 50% of its deepwater production from the Gulf, according to Martijn Dekker, Shell’s vice president for appraisal and hydrocarbon maturation, out of the company’s total deepwater production figure of 370,000 boe/d (2014).

On Appomattox, sanctioned in July 2015, Shell said it has reduced its total cost by 20% through supply chain savings, design improvements and by reducing the number of wells required. The 650-MMboe field is the first development in the Norphlet play, with the semisubmersible four-column production platform to be Shell’s eighth and largest floating deepwater facility in the GoM. Appomattox is expected to hit average peak production of about 175,000 boe/d once it ramps up to full speed by around the end of this decade.

Lessons learned
The company achieved the savings largely by using advances and lessons learned from its previous four-column facilities such as the recently built Olympus tension-leg platform (TLP) used on its Mars B Field as well as ensuring a high degree of design maturity before construction.

A specific example given by Dekker highlighted a focus on design, equipment and scope specifications with increased standardization. This saw competitive scoping on the Mars/Ursa project’s deepwater wells save about $95 million last year alone, he said.

With these and other cost reductions, the go-forward project breakeven price is currently estimated at about $55 per barrel Brent equivalent—still higher than today’s price but expected to be within the expected oil price range from 2017 onward.

Savings of $1 billion
On Shell’s Stones project, Dekker pointed out the company achieved capex savings of $1 billion through measures such as simplified and innovative well designs and supply chain savings on the FPSO and subsea systems.

Stones will be the world’s deepest oil and gas development in 2,900 m (9,600 ft) of water and is expected to initially produce about 50,000 boe/d via its newbuild FPSO unit once it comes onstream later this year.

Other efforts Shell already has made to make its deepwater facilities operate more efficiently in the GoM include a program to improve its logistics and materials management—an initiative that saved it an estimated $60 million in 2015, Dekker said. The fall in costs within the industry over the past year also has helped, he added, with Shell achieving a 40% saving in the GoM on electric wireline services—equating to about $50 million.

Offshore