Subsea tieback projects are likely to deliver nearly one-fifth of new crude barrels by 2035.
A go-to solution for unlocking smaller hydrocarbon pools near existing offshore assets, subsea tiebacks make attractive investments, Sandeep Patni, Shell’s subsea team lead, said during the "Subsea Tiebacks, Increased Production, Lower Costs & Risks, Greater Optionality" panel at the Offshore Technology Conference (OTC) on 4 May.
Einar Michel, Rystad Energy’s offshore market analyst and offshore vessel product manager, said tiebacks are expected to provide about 19% of total crude production by 2035, up from about 13% this year. And growth in tieback production is expected to be fueled by increases around the globe over the next few years.
Subsea-tieback production is expected to grow by 113% in South America from 2026 to 2030, 81% in the Middle East, 29% in Asia, 20% in Europe, 6% in Oceania, 2% in Africa, and 1% in North America, he said.
Looking to 2027 and 2028, there is the expectation for a large growth in subsea-tree awards, with many of those earmarked for tieback projects, he said.
Mike Ellis, strategy and pursuit manager at Subsea 7, said tiebacks are attractive investments because they can unlock “stuck” projects. “Our customers have an ambition to move quickly from discovery of first oil to first production. And there is no better case to do that than subsea tiebacks,” he said.
Katie Pelliccio, Chevron Angola’s general manager for facilities engineering, called tiebacks portfolio levers. “We see tiebacks as a portfolio lever to help offshore developments become more competitive. Tiebacks enable us to achieve first production faster. Tiebacks help us preserve capital and not spend that capital on unnecessary surface scope. And tiebacks also help us get more out of our existing infrastructure by increasing that value for decades to come,” she said.
Donald Craig, subsea technology manager at BP America Production Co., said subsea production has become increasingly central to future output. It enables the industry to bring to market production from challenged, smaller, and distant reservoirs. “The role of subsea continues to expand,” he said, noting tiebacks will be required to sustain production host facilities in the future.
Over the years, lessons learned and technology innovations have helped operators fine-tune their subsea tieback planning.
Maggie Sheridan, manager of operations engineering at Murphy Oil Corp., said it’s important to design tieback systems for stability and risk, which goes beyond designing for first oil. And while flow-assurance risks change over time, something to keep in mind is a strategy for metering hydrocarbon volumes in multi-owner situations. “One of the overlooked pieces across the field for subsea tiebacks is allocation strategy. It becomes incredibly complicated. You have multi-field, multi-interest systems.”
The days of fiscal custody transfer at the facility, along with well-calibrated oil and gas export meters, are over, she said. “With subsea tiebacks and host facilities, that allocation confidence really needs to be designed as part of the initial project,” Sheridan said.
And while the standard approach has historically been to lay dual flowlines, she said single flowlines may be the future of oil subsea tiebacks, even if it increases the risk. Methods to mitigate that risk include better fluid sampling, digital tools, sophisticated modeling, and sensor data, Sheridan said. “More and more single-line tiebacks as the pools get smaller and smaller is where subsea tiebacks are going.”
Shell’s Sandeep Patni said the economics of a single-flowline tieback are appealing if the risks are understood and mitigated. This shift, he said, was only possible due to the data gathered over the decades.
“We said, ‘Okay, why do we need dual flowlines?’ So we started understanding the risk and how to manage it, or mitigate, for a single-flowline solution. Once we did that as an industry, we as Shell have moved to a single flowline as a base case with dual flowline only as an exception. This really, really decreased the cost for some of the subsea tiebacks; otherwise they wouldn't be economical,” he said.
Deploying new technologies into subsea tiebacks requires careful consideration. Pelliccio said technology needs purpose, and a business case must be made for its use. She cited as an example the 20,000-psi all-electric systems Chevron deployed on its Anchor project in the US Gulf of Mexico.
“We did not deploy this technology for technology's sake. There was a business case. There was value around bringing value more online, and that particular concept was needed in order to overcome the technical hurdles to unlock that value. Tieback should be no different,” she said.
Subsea7’s Ellis said that technology being deployed in subsea tiebacks needs to be proven, or it risks derailing the schedule. Declines in funding research and development is discouraging, he said.
“When it's time to go fast, that is not the time to be doing research and development, trying new things. If you want to move fast, as you do on subsea tiebacks, you want to have field-proven technologies. We've got to find ways to invest in those things that we want to do, and we want to invest in them outside the project cycle,” he said.
