As the lower for longer oil and gas price environment persists, pushing some high-dollar offshore developments out of reach, subsea tieback development potential is leaving the door wide open for oil and gas production growth.

Some experts say the world is ripe for subsea developments, with tiebacks limited only by the capacity of their host facilities.

In the U.S. Gulf of Mexico (GoM) alone, at least 10 projects could become subsea developments between second-half 2016 and 2018, according to Houston-based Quest Offshore, which flagged BP’s Mad Dog 2 and Anadarko Petroleum Corp.’s Shenandoah among the near- and medium-term possibilities. This could mean a much-needed payday for some project management, engineering and construction companies along with subsea tree manufacturers as the need grows for deepwater developments to meet energy demand in the medium term.

“Adding three or four subsea trees is a far more economical solution to increasing production compared to other options out there,” said Caitlin Shaw, senior director of market research and data division for Quest Offshore.

Although the number of global tree awards and infill wells has fallen in recent years due to a downturn-driven spending cutback, aging and increasing subsea infrastructure is expected to spawn more global subsea tree installations.

There have been more than 3,000 subsea tree completions in the past 10 years, and another 1,300 could be installed by 2020, according to Shaw, who noted water depths also are getting deeper.

“A lot of the opportunities in North America are brownfield opportunities,” Shaw said. Similar opportunities exist elsewhere, including the North Sea, Africa/Mediterranean region and offshore Brazil. “Since 2008, roughly 30% of global subsea trees have gone to this type of activity. … These trees don’t traditionally come with extra infrastructure,” such as tens of kilometers of pipeline and production umbilical.

Some companies—including large independents like Anadarko—are identifying tieback opportunities for new fields.

Tieback potential

Subsea tiebacks is one of the areas that Anadarko CEO Al Walker said gives the company “strong line-of-sight for attractive capital-efficient, short-cycle oil investments as crude prices recover.”

The company has identified up to 30 low-cost tieback opportunities in the GoM. These, according to Anadarko’s second-quarter 2016 operational report, include:

  • Caesar/Tonga, five to eight wells. Located in the Green Canyon area, the field had record production of 55,000 bbl/d in the second quarter;
  • K2, four to seven wells plus two potential new fields. This Green Canyon area development produced more than 28,000 bbl/d, an eight-year record high;
  • Heidelberg, three to six wells plus two potential new fields. Also located in Green Canyon, Heidelberg—which reached first oil in January—includes two drill centers tied back to a truss spar via an 8-in. flowline and steel caternary risers; and
  • Lucius, three to seven wells plus one potential new field and third-party developments. The Keathley Canyon area field surpassed its 80,000 bbl/d nameplate capacity last quarter. Its six subsea wells are tied back to a truss spar.

Subsea tiebacks are also proving to be crucial to unlocking barrels in the GoM for Noble Energy Inc., which brought the two-well Gunflint oil development online in mid-July. The field, which joined the Big Bend and Dantzler subsea tiebacks, is ramping up and is expected to hit gross production of at least 20 Mboe/d, Noble said.

“This is the third Middle Miocene tieback to commence production in the past 12 months, contributing to the almost doubling of our Gulf of Mexico volumes this year,” said Gary Willingham, executive vice president of operations for Noble.

Noble’s GoM sales volumes for the second quarter skyrocketed by 125% compared to a year ago to average nearly 27 Mboe/d.

Shifting priorities

It is these types of developments that subsea-focused companies are depending on to stay afloat.

Technip CEO Thierry Pilenko recently addressed his company’s clients’ shifting priorities brought on by current market environment. The company expects to see more phased developments and more tieback opportunities emerging, particularly in the GoM.

In addition, “preference will be given to shorter-term subsea projects, brownfield, extension of life and tieback to existing facilities,” Pilenko said speaking on the market outlook during the company’s latest earnings call. “Pressure on cost will be tactical, taking advantage of the overall industry deflation, but also structural, through improved efficiency, FEED-focused design, standardization and alternative sourcing or fabrication.”Technip believes merging with FMC Technologies will give birth to a new generation of subsea solutions that does just that, while also lowering project costs and enhancing life-of-field productivity. The transaction is expected to close in early 2017.

The subsea services provider reported “strong subsea activity” across the regions where it operates, with vessels active on the Kraken and Edradour projects in the North Sea, Girassol Resources Initiatives offshore Angola, TEN offshore Ghana and the Moho Nord project offshore Congo plus renewed charters for the Skandi Niteroi and Skandi Vitoria pipelay vessels offshore Brazil.

Although Technip’s subsea revenue fell by nearly 12% for the quarter, the situation is expected to improve as commodity prices rebound and supply chain deflation give the company confidence.

“We are therefore seeing continued focus from clients seeking to get upstream projects to work—notably fast-track projects like tiebacks and brownfield but also larger strategic investments,” Pilenko said in a statement.

Technip increased its adjusted subsea revenue 2016 guidance to between about $5.3 billion to $5.6 billion from about $715 million to $760 million.

Changing subsea

However, it appears that the lower commodity price environment already has begun to usher in a different breed of subsea design.

In their market analysis, both Shaw and Pilenko foresaw more projects being carried out in phases. Mad Dog Phase 2, Exxon Mobil’s Liza development, Noble’s Leviathan and Statoil’s Snorre 2040 were among Shaw’s examples.

Instead of large 40-well subsea projects with an FPSO vessel, the industry will perhaps see two or three phases spread across five or six years, Shaw said. Breaking the large projects into phases makes substantial capital investments a little easier for oil companies to digest, she said, while also providing more supply chain transparency regarding projects in the queue.

The new era also could see more subsea collaboration and consolidation, with companies opting to combine expertise, efforts and energy on innovation solutions. This already is happening: Technip-FMC, the Aker Solutions-ABB partnership, and OneSubsea, now a Schlumberger Co.

Another future subsea strategic adjustment involves maintaining hubs by leveraging lower input costs to maintain or improve existing facilities, Shaw said.

“The effects of that won’t be immediate, but we do see these efforts moving forward,” she added.

—Velda Addison