OSLO, Norway—Norway, like the rest of the offshore world, has spent the last two and a half years suffering through the worst downturn since it began producing oil more than 40 years ago. That appears to be over now.
Terje Sᴓviknes, Norway’s minister of petroleum and energy, told people gathered at this month’s Subsea Valley Conference that he expected the number of plans for development and operations (PDOs) to be filed this year to be double that of the mere five put forward in 2016. While this is a modest increase, it indicates that either the worst of the recession is over, the industry has finally come to terms with the lower oil price in terms of development costs—what Sᴓviknes called “efficiency gains”—or a bit of both.
The minister was upbeat about the upcoming licensing round with 93 blocks in the Barents Sea to be made available, making this northerly region the next big thing in the Norwegian offshore sector. And he pointed to new activity in two arenas where Norway has always punched above its weight—R&D and exports.
The Demo 2000 technology development program, created by the Research Council of Norway (RCN) at the turn of the century during an earlier new project drought, has had another cash injection of NOK100 million (just under US$12 million). RCN has reported 44 applications for funding under the scheme.
In a move that acknowledges the growing importance of the offshore renewables sector, Norway has merged the international marketing and networking organizations for its oil and gas (INTSOK) and renewables (INTPOW) industries into a new organization—Norwegian Energy Partners.
Even with the reduced level of activity worldwide, new developments continue to be funded in Norway. Three projects—Johan Sverdrup, Trestakk and Alta Gohta—which are at different points in the development spectrum received special attention here in the form of what the Subsea Valley organization dubbed “master classes.”
Sverdrup is one of the biggest—and maybe the biggest—current offshore developments in the world, but its significance may extend well beyond its 2 Bbbl to 3 Bbbl of oil in place. Operator Statoil, working closely with main partner Lundin Norway, has managed to shave significant costs off the overall price tag for this big four platform plus subsea development, making it a model for how others might be able to tackle such a large project.
According to technical director Trond Stokka Meling, the original NOK123 billion (US$14 billion) figure for Phase One— based around three platforms with projected production of 440,000 bbl/d—has been cut to NOK97billion (US$11 billion) and Phase Two—which is due to add another 220,000 bbl/d—has seen its estimated project cost reduced from NOK80 billion (US$9 billion) to just NOK40 to 55 billion (US$4 billion to $6 billion). This has sliced the overall per barrel development cost for an estimated $25/bbl, making it profitable at any projected oil price.
Some of that cost cutting has been achieved by plans to use Allseas’ new heavy-lift vessel Pioneering Spirit for single lift topside installation on three of the platforms, maximizing completion of the decks before offshore activities and reducing the number of offshore working days.
Phase 1 also includes a major subsea water injection system consisting of 10 wells, while later development of the Kvitos and Geitungen satellites are now expected to make use of the new low-cost CapX subsea concept. There will also now be a permanent seabed reservoir monitoring system covering 80% of the field area.
Statoil also showed off its newly developed cost-cutting skills by getting the Trestakk subsea tieback project on the development ladder with the PDO approved on the first day of this event. Project director Havard Stensrud said costs have been reduced by 50% from the original estimate—although at least one-third has been due to market forces since the oil price crash—and with additional reservoir work increasing reserves by 30%, the net present value of the field has jumped by 60%.
The project is a classic North Sea small field, which has been long on the drawing board. Discovered more than 30 years and approved in 1987, it had to wait for the development of the Asgard Field to provide the infrastructure required to bring it onstream. It passed the first development hurdle in 2010 and by 2014 was seen as part of a joint development scheme with Wintershall’s Maria subsea field, but the crash sent the cost up and the field back to the drawing board.
Then things changed. An improved business case included an extension to the operational life of the Asgard A semi to 2030 without drydocking plus reduced market rates for drilling and operations sent the breakeven price down to $27/bbl and the project going ahead.
But there were other improvements. Umbilical costs were reduced by linking through an existing seabed facility, copying designs from Sverdrup for the template and christmas trees—the now standard vertical trees—saved on redesign and the use of inline tees with flexible tails knocked 40 days of offshore vessel operations. Many of these improvements were achieved through extended FEED work by Forsys, now re-absorbed into the bigger TechnipFMC organization.
Further into the future will come Lundin’s Alta Gohta in the Barents Sea. This is a most unusual offshore reservoir made up of cave-like structures, known as kartstified carbonates, more commonly found onshore. An improved understanding of the subsurface was achieved through the use of seismic contractor CGG’s TopSeis technique, which separates acoustic sources and hydrophones onto different vessels.
This will be developed with some form of floater with subsea wells, likely at least five templates including one on the nearby Fellicudi Field, but any decision on the facility will likely await a decision by Statoil on its nearby Barents Sea prospect John Castberg. Both gas lift and gas injection are planned, and Lundin is interested in a possible all-electric production.
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