It has been a hard grind for subsea market players in the past few years, but signs of a let-up are on the horizon.
Four years since the oil price collapse of 2014, the subsea market is beginning to spark back into life as operators sanction new developments around the world, supported by improvements in project economics and increased cash flows.
Better collaboration between operators and contractors has seen subsea field architecture simplified, leading to further opportunities for growth.
Research by Rystad Energy suggests that the subsea market will be a top performing oilfield service segment in the years to come. The analyst expects the subsea market to outpace other market segments from 2018 to 2023 with 10% yearly growth, compared to 6% for the oilfield service markets in total.
The market for subsea equipment (e.g., the procurement of subsea wellheads, subsea trees, manifolds and control modules) is expected to lead growth with as much as 12% year-on-year increases.
The market for subsea umbilicals, risers and flowlines (SURF), including their procurement and installation, follows close behind subsea equipment with an expected 11% yearly growth, Rystad Energy said.
This growth will be supported by a new wave of subsea developments over the coming years, which will have subsea trees at their core.
After activity levels fell to only 240 subsea trees installed globally in 2017, Rystad Energy forecasts that more than 350 subsea trees will be installed per year by 2021. The market for subsea trees is expected to grow by 8% per year from 2017 to 2023. The U.K. and Norway will drive the growth through 2021, after which South America will take the lead. Global demand for oilfield services is projected to hit $642 billion in 2019, of which the subsea market will account for 4%.
Of the projects that E&P companies are expected to commit to over the next four years in Norway and the U.K., Rystad Energy expects 53% of the offshore greenfield E&P expenditure to be for subsea tieback projects. This is a significant increase from 30% in the 2010 to 2018 period.
Norway leads the way
Equinor and its partners have decided to invest about $165 million in a Vigdis subsea boosting station, expected to come online in the first quarter of 2021. OneSubsea has been awarded the engineering, procurement and construction (EPC) contract for the supply of the industry’s first all-electric actuated subsea boosting system. Vigdis has been producing oil through the Snorre Field for more than 20 years.
Field production will be boosted by almost 11 MMbbl of oil. The boosting station will be connected to the pipeline to enhance the capacity between Vigdis and Snorre A, and it will help bring the wellstream from the subsea field up to the platform.
The scope of the contract includes a pump station with a manifold foundation and protective structure as well as a pump module, topside equipment, umbilical and all-electric controls with electric actuation. Work began in Bergen, Norway, in December 2018, and the first delivery is scheduled for February 2020.
Equinor also is championing its Snorre Expansion Project, and in early 2018 TechnipFMC was awarded an EPC contract for the scheme, covering the delivery of subsea production systems including six subsea templates and subsea production equipment.
TechnipFMC also claimed a contract from Equinor for the Johan Sverdrup Phase 2 development, located in the Norwegian sector of the North Sea at a water depth of 120 m (394 ft). The contract covers the delivery and installation of the subsea production system including integrated template structures, manifolds, tie-in and controls equipment.
TechnipFMC CEO Doug Pferdehirt highlighted ongoing efficiencies in the company’s operations. In the company’s third-quarter 2018 results report, he said, “We also successfully delivered two additional iEPCI [integrated engineering, procurement, construction and installation] projects in the third quarter—Trestakk and Visund Nord—both with Equinor on the Norwegian Continental Shelf. On Trestakk, our first awarded iEPCI project, we successfully delivered a fully commissioned subsea system utilizing only a single season of marine operations.
“Visund Nord was delivered in just 21 months from concept selection to first production; this was a new fast-track record for Equinor. An important factor in the success of these projects was the strong collaboration with our partner, Equinor, and the integrated capabilities of TechnipFMC.”
TechnipFMC was recently awarded an iEPCI contract from Lundin Norway for the Luno II and Rolvsnes development, located in the North Sea at a water depth of 110 m (361 ft). The contract covers the delivery and installation of subsea equipment including umbilicals, rigid flowlines, flexible jumpers and subsea production systems.
In the U.K. sector, OneSubsea was awarded an EPCI and commissioning contract for a subsea multiphase boosting system by TAQA for the Otter Field.
OneSubsea and its Subsea Integration Alliance (SIA) partner, Subsea 7, will supply and install a subsea multiphase boosting system, including topside and subsea controls, as well as associated life-of-field services. The project will result in a 30.5-km (19-mile) subsea tieback to the TAQA-operated North Cormorant platform. This will be the longest subsea multiphase boosting tieback in the U.K. North Sea.
Meanwhile, Aker Solutions has been awarded a master contract to support the delivery of a subsea compression system for the Chevron Australia-operated Jansz-Io Field offshore Australia. The first service order under the master contract will be for FEED of a subsea compression station that will boost the recovery of gas from the field. The FEED scope will also cover an unmanned power and control floater as well as overall field system engineering services. The field control station will distribute onshore power to the subsea compression station.
Advances in thermoplastic composite pipe (TCP) solutions also are helping to cut costs for subsea installations.
Airborne Oil and Gas’ TCP jumper is breaking through in deepwater applications around the world and is now expanding into West Africa following successful projects in the North Sea, Gulf of Mexico (GoM) and Asia. The disruptive technology provides considerable benefits in the application of a well jumper, where the flexible TCP jumper can be cost-effectively transported and installed subsea. The jumper is flexible, enabling installation without the need for metrology. This allows it to be prepared up front and installed directly after installation of the adjacent subsea components, such as manifolds, thereby reducing time to first oil. The jumper concept offers opportunities to prepare longer length on reel and cutting down to size in-country to deploy multiple jumpers in support of larger field layout.
Meanwhile, Magma Global, another manufacturer of TCP, has teamed up with TechnipFMC to collaborate on the development of the core element of its hybrid flexible pipe solution.
It will be used to address the challenges of the Libra Field in the Santos Basin presalt area offshore Brazil and other major deepwater projects. Brazil’s Libra Field, operated by Libra Oil & Gas, is a deepwater presalt environment and considered to be one of the most challenging projects for the industry. The new hybrid flexible pipe incorporating Magma’s m-pipe will deliver robust risers and flowlines with increased performance while offering significant overall reductions in the product installed cost. This will be achieved by combining the chemical resistance and fatigue performance of Magma’s high-end carbon fiber PEEK TCP with the stability and strength of flexible steel armor.
Subsea tree technology
The subsea tree sector also has seen further moves by the main hardware manufacturers to streamline their offerings and reduce costs.
Baker Hughes, a GE company (BHGE), released its Aptara TOTEX-lite subsea system, a suite of new lightweight, modular technologies designed for the full life of field. The Aptara TOTEX-lite subsea system includes the lightweight compact tree, modular compact manifold, composite flexible risers, standardized fatigue-resistant wellhead system, modular compact pump and subsea connection systems.
The Aptara Lightweight Compact Tree system has a significantly reduced footprint compared with traditional deepwater subsea trees, which means 50% less weight and the potential to reduce Totex (capex + opex) by more than 50%.
The Aptara tree also allows operators to evolve the tree system to suit changing reservoir conditions. Its unique industry-first design involves a flow path and caps for the tree that integrate functionality, such as high-integrity pipeline protection, or add boosting capability to reduce overall development costs or increase reservoir recovery.
“In recent years, our industry has made good progress in lowering the cost of subsea projects to the point where they have become more competitive with onshore developments,” said Neil Saunders, president and CEO of BHGE’s Oilfield Equipment business, in a press release. “While the gap has narrowed, we are taking that to the next level with Subsea Connect, making long-lasting, sustainable change and driving value from concept to commissioning and over the full life of the field.”
Smart subsea operations
There are also a whole host of smaller companies providing technology for smarter subsea operations. Norway’s Seabed Separation has released a dual pipe separator (DPS) technology that makes oil separation more efficient. By removing and treating water locally, all transport from the well or field is for oil and gas only.
This will reduce costs and increase revenues by enabling increased oil recovery and accelerated production. This business effect will be especially significant in subsea, where the DPS opens up for new production tie-ins on existing infrastructure.
Seabed Separation has received support from Lundin, Wintershall and Aker BP as well as public funding to commercialize the concept. A full-scale pilot was successfully tested at Equinor’s Porsgrunn test facility near Oslo in 2017 using fluids from the operator’s Troll Field.
Springing into action
Total also has been maintaining its reputation for offshore innovation. The operator is aiming to make significant savings in various areas, including water injection, thanks to the SPRINGS (Subsea PRocessing and INjection Gear for Seawater) project, the first-ever subsea sulfate removal and treated seawater injection unit that has been successfully tested by a deepsea pilot.
By removing a surface-based high-pressure water injection line, this solution will lower the development costs for satellite reserves that are more than 50 km (31 miles) away from an FPSO by more than 20%. Reducing development costs for fields located far from existing production locations requires the intensification of subsea processing. Total partnered with Saipem and Veolia to meet the challenge.
The SPRINGS subsea unit is designed to operate in up to 3,000-m (9,843-ft) water depths, treat and inject up to 60,000 bbl/d of seawater filtered to one-thousandth of a micron.
Subsea power grid
In another industry breakthrough, Siemens has successfully concluded the first phase of its subsea power grid shallow-water test in Trondheim, Norway.
Siemens, in collaboration with industry partners Chevron, Equinor, Exxon Mobil and Eni Norge, is in the final stages of a program to develop a barrier-breaking system that will become the world’s first subsea power grid designed for distribution of medium voltage power using pressure compensated
“There will be more subsea compressors, pumps, processing plants and, in the future, entire production facilities placed on the seabed, all of which require power,” said Frode Tobiassen, head of subsea at Siemens, in a press release. “This development is what we are preparing for with the subsea power grid.”
The underwater power grid consists of a subsea transformer, subsea switchgear, subsea variable speed drive, subsea wet-mate connectors, and a highly reliable remote control and monitoring system that includes cloud-based user dashboards and data analytics.
Following the downturn in 2014, a period of rationalization of subsea companies took place, and there were several tie-ups between major companies. This trend toward greater cooperation has continued, and Schlumberger and Subsea 7 are looking to form a joint venture (JV) that builds on the success of the SIA, which was established in 2015.
The SIA combines the subsurface expertise, subsea production systems and subsea processing systems of OneSubsea with the SURF systems capabilities of Subsea 7.
The proposed JV will create a unique life-of-field offering that includes autonomous subsea technology, digitally enabled remote surveillance and production monitoring, and inspection, maintenance and repair services.
BP and Aker BP also have entered into a pact to explore ways of developing pioneering new technologies together. The companies expect to invest in technological advancements, including developments in digital twins, advanced seismic techniques and processing, and subsea and robot technology.
Aker BP was formed in 2016 through the combination of Det norske oljeselskap and BP’s Norwegian E&P business.
BP and Enpro Subsea announced the execution of a global frame agreement aimed at providing an enhanced subsea architecture and smart standardization using Enpro’s flow access module (FAM) technology.
Enpro Subsea supplied the FAM technology to BP on the Kepler K3 project in the GoM, enabling project-specific technologies to be added to BP’s standard subsea trees and manifolds to support BP in achieving sanction to first oil in less than 12 months.
On the Kepler K3 project, BP used FAM technology to install multiphase metering, water cut metering and sand detection at the christmas tree end of a 3-km (2-mile) single spur tieback in addition to hydrate remediation and flow assurance hydraulic intervention module adjacent to the manifold. This removed the costs, risk and schedule associated with modifying standard hardware or adopting the dual flowloop alternative.
Following the success of the Kepler K3 project, Enpro and BP are now collaborating on follow-up FAM projects, including BP’s Ariel 6, which is due to be installed later this year.
For questions or comments on this story, contact Executive Editor Jennifer Presley at firstname.lastname@example.org.
This story first appeared in E&P magazine's "2019 Offshore Technology Yearbook" issue, which published in May. Read the other "2019 Offshore Technology Yearbook" articles:
Operators Foresee Vast Potential
New Generation of Offshore Drilling Tools Targets Safety, Wellbore Conditions
Platforms Enter a New Cycle
Subsea Sector Recovery Underway (story above)
Americas and Middle East Put Offshore Back on the Map
The Vlot anaerobic digestion project is anticipated to capture, clean, and convert methane from manure that would otherwise escape to the atmosphere on the Vlot Calf Ranch and dairy farm into RNG.
Hydrogen is seen as a cleaner alternative to fossil fuel-based sources, but its most sustainable form—green—is also the most expensive.
The 17 winning Scottish projects will produce nearly 25 GW in the next decade, helping to provide low-carbon power in line with a U.K.-wide goal to cut emissions to net zero by mid-century.