When a market has plunged 79% from where it was just three years ago, the first thing to get cut almost immediately is company headcounts followed by brutal contract negotiations. Industry collaborations are launched to share the R&D load, and standardization initiatives are undertaken in a bid to cut out the deeprooted cancer that is soaring cost.

The above actions have all been in full effect since the subsea trees market collapsed after the stellar years of 2012-13 that saw nearly 1,000 trees awarded over that period, according to FMC Technologies in one of its latest presentations.

That spectacular demise was highlighted by Cowen and Co. in its latest analysis of the sector, with a forecast decline of 26% in tree awards in 2016 from the already depressed prior year. “In 2016, total tree awards are expected to be 113, down 26% from 153 in 2015,” the company stated in an industry overview released in late March. “This implies total awards will be down 79% from the cyclical high of 551 in 2013.”

Battle for larger prizes
The larger tree award projects (valued at more than $150 million) are set to prove a cutthroat battleground for FMC and its rivals OneSubsea, GE Oil & Gas, Aker Solutions and Dril-Quip over the course of the next two years (2016-17). These are expected to include:

  • Eni’s Coral project offshore east Africa’s Mozambique in the Rovuma Basin, where plans include six subsea wells and a floating LNG facility followed later by its larger Mamba project (up to 21 trees);
  • Shell’s 100,000 boe/d Vito floating production project in the Gulf of Mexico’s (GoM’s) Mississippi Canyon area (up to 14 trees);
  • BP’s Mad Dog Phase 2 in the GoM (up to 22 trees);
  • Exxon Mobil’s Hebron project offshore Newfoundland and Labrador in the Jeanne d’Arc Basin, being developed via a standalone concrete gravity-based structure but including the Hebron Pool 3 Phase 1 subsea tieback project;
  • Eni’s Zohr Phase 1 early development offshore Egypt, requiring five trees and expected to be followed by its Shorouk project off Egypt (up to 24 trees);
  • Hess Corp.’s Equus project offshore Australia (up to 18 trees);
  • Tullow Oil’s Greater Jubilee project offshore Ghana (up to six trees);
  • Shell’s Bonga South West offshore Nigeria (up to 48 trees); and
  • Statoil’s Johan Castberg offshore Norway (up to 31 trees).

These and other similar sizeable projects needing at least an estimated five subsea trees are expected to account for 56 of this year’s subsea awards, according to Cowen and Co., but again that figure for this year is down from 112 trees in 2015.

Cowen and Co. said in its analysis that while 2017 is expected to show a 55% improvement to 175 subsea trees, “We note that visibility is limited and low commodity prices may result in further project deferrals or cancellations.”

Automated subsea future
Despite the shorter-term lack of visibility, classification society DNV GL said subsea is seen as a key technology for the upstream sector, particularly due to the E&P industry’s increasingly automated and digital future progression.

According to its new Technology Outlook report, the society indicated that the industry should expect particular evolutions in subsea production system technology by 2025, especially around smarter subsea tie-ins as well as fully automated drilling operations, simpler and smarter completions, and the autonomous inspection of pipelines.

Referring to the industry’s actions so far on costs, firstly by cutting its headcount and renegotiating contracts and secondly by more collaboration and standardization, Bjørn Søgård, segment director for subsea and floaters at DNV GL, said during a talk in Oslo, “We are now about to enter a third stage characterized by a willingness to open up for radical new ideas that can reshape industry processes. We believe that in the longer horizon, offshore production and processing systems are going down to the seabed as a cost-effective and safe alternative for platforms and floaters.

“Subsea systems have traditionally been quite simple from a control and monitoring perspective. This simplicity has enabled subsea systems to deliver reliable production from 5,000 wells around the globe.”

Søgård continued, “Currently, subsea system integrity and main flow parameters are monitored from remote control rooms 24/7, but according to the DNV GL report, by 2025 subsea solutions are expected to rely actively on monitoring and data analytics. Digitalization will be a game changer also for subsea by 2025, helping the industry to achieve optimum flow conditions for stable production.”

Qualification drive
Referring to Norway, where the Norwegian Petroleum Directorate believes that subsea tiebacks represent the most relevant solution for 68 out of 88 currently undeveloped discoveries on the continental shelf, DNV said in a separate initiative that new subsea technologies and systems should be qualified before use to build confidence that they will function as intended. It is calling for a standardized system qualification approach, with joint industry effort to drive faster take-up of new subsea technology and value creation.

The classification specialist is proposing a three-step industry effort to enable more effective technology development and implementation in the field:
• Establish common industry principles and consolidate a common framework for system qualification founded on existing industry procedures;
• Develop a methodology to standardize system qualification for common use across the upstream oil and gas industry; and
• Pilot and demonstrate the developed methodology and roll out a recommended practice.

“The subsea industry needs to overcome key challenges such as cost reductions, enabling increased recovery and complex field developments. At the same time, the future trend still points toward more complex systems, which require integrating process, power and control systems subsea,” said DNV GL’s Tore Myhrvold.

“Developing a standardized approach to subsea technology qualification will enable companies to leverage on each other’s qualification efforts and results, reduce the overall development time and ultimately enable faster innovation in the subsea sector,” he added.

Previous experience has shown that focus on qualification in the early phases of development reduces risk of failures in later phases of testing, avoiding potentially expensive fixes.

Offshore