The future of many offshore developments hangs on extending the lives of mooring lines and risers.
With oil at USD 50/bbl, only the biggest deepwater discoveries can justify the cost of a new production platform, and even those projects demand an intense focus on shaving every possible cost to allow profitable development.
The few projects going forward now are generally sending the oil and gas to a platform built for an older field. The need to tie back production to aging facilities puts a premium on extending the life of critical components offshore, including the chains and lines that anchor floating structures and the risers providing a conduit for the pipes and lines running to subsea systems and export pipelines.
Two ideas for addressing those challenges were offered by papers presented at the 2017 Offshore Technology Conference (OTC).
One option literally would take a load off old risers, lifting a section of those long pipes near the ocean floor. The goal is to move the point of highest stress, the touchdown point (TDP), several hundred feet, which the paper by Chevron (OTC 27597) said could double the riser’s fatigue life. It analyzed the effect of doing that by lifting it using buoyancy devices or shortening the tube by removing a pipe segment near the top.
Another paper extended the expected life on those components by changing a key assumption used to calculate it. Longer lifespans can be expected based on a multiyear study that concluded that the method widely used to estimate the fatigue caused by passing currents—vortex-induced motion (VIM)—exaggerates the effect.
“Traditional prediction methods over-predict vortex-induced motion,” said Arun Antony of Houston Offshore Engineering, which is part of Atkins. “By realistically estimating the life, you can save money and reach an acceptable life” for deepwater equipment.
The paper (OTC 27889) used the data to show how more realistic estimates could be used to shave the cost of a new platform by reducing the cost of moorings a bit, and the riser by a lot. Changing assumptions allows a plan that would use a less expensive steel catenary riser (SCR) rather than a lazy wave design, which would be required if traditional calculations for VIM were used.
And he said the same methodology could be used to see if older hardware has more years of life than expected in it, but he is not aware of anyone who has done so.
Both papers have a connection with lazy wave riser designs, which lift a section of the riser in the water by wrapping buoyancy modules around the pipe. That change extends the life of the riser, but costs more.
The Chevron project is adding buoyancy modules later in the life of a riser to get the benefits of a lazy wave design. The Houston Offshore Engineering paper uses new data on VIM to make the case for using a lower-cost SCR rather than a lazy wave riser.
Petrobras, which uses lazy wave risers in its many ultradeep fields, reported that it is working to reduce the high cost of buoyancy by working on designs that use a minimum number of modules as part of its Subsea Cost Reduction Plan (OTC 27833).
Rethinking the need for buoyancy allowed Petrobras and its partners developing the huge Libra field offshore to switch to SCRs, saving on buoyancy modules and installation expenses, said Orlando Ribeiro, Libra project general managers for subsea wells and facilities, during an OTC panel.
Zone Fatigue
When determining the life of an SCR, close attention is paid to the TDP, the point of maximum stress, where the steel tube that is a mile or longer and moved around by waves, currents, and the motion of the platform, is connected to the subsea production system.
A paper by Chevron and 2H Offshore (OTC 27597), an engineering firm specializing in risers, offers two ways to alter the path of the pipe to move the TDP away from a spot which has been subjected to years of stress:
- Lifting a section of the riser using buoyancy modules that moves the TDP, delaying the day of reckoning
- Shortening the riser, by removing a joint or joints near its top, which also shifts the TDP
To realistically test these ideas, they used data from two risers on a deepwater platform in the Gulf of Mexico, one for production and the second for export. This allowed full fatigue analysis based on actual conditions at the platform and seafloor, from the local ocean conditions to soil conditions around the anchoring point.
Both methods change the path of the riser by lifting it. One approach adds buoyancy modules near the bottom. Another does so by removing one or more 40-ft sections of riser at the top.
While both methods could significantly extend the riser’s life, the paper said that adding “a large number of buoyancy elements close to the TDP led to the overall greatest benefit in fatigue life.”
While removing joints can be nearly as effective, it may reduce the strength of the riser. In one of the cases studied, removing only one joint “did not pass the preliminary strength case.” In another instance, the strength margin was reduced, but still acceptable.
Vortex Adjustment
The cost of the mooring lines and risers for an offshore platform can be significantly reduced, according to another paper based on a study that concluded that the effect of VIM on them is 10% to 20% less than widely assumed.
The OTC paper by Houston Offshore Engineering estimated that by using those VIM estimates and prices it gathered from suppliers, it would be possible to reduce the cost of moorings and risers for a semisubmersible platform producing 80,000 B/D in the Gulf of Mexico by about 18%, or USD 25 million.
The starting point of the VIM study funded by RPSEA (RPSEA A 5404)—a federally backed research group that partners with industry—was a common observation: “The motion predicted by engineering projections exceed the actual motion,” said Antony, who was the principal investigator on the project.
That work concluded the VIM was less than expected because earlier tests failed to consider that the motion was dampened by the resistance of water.
“When you try to move a riser in the water it will have friction in the water,” Antony said. That effect increases as more risers and lines are added.
Reduced motion means less fatigue and a longer expected lifespan. How much depends on the interaction of the sea conditions with the structure’s size and design.
By assuming a 10% reduction in VIM, it was possible within the specifications, which required a 25-year design life, to switch to a smaller-diameter chain connecting the polyester line to the platform and the anchor, saving USD 2 million, or 6% of the total mooring system cost.
The big saving was in the riser. By assuming less motion, it was possible to use an SCR rather than a more expensive lazy wave design, which would have been the choice if a standard motion estimate was used. That change saved USD 23 million. The savings were evenly split between the hardware and installation cost reductions.
By assuming a 10% reduction, the SCR design life was extended to near the 25-year goal. To reach, and exceed that level, the paper specified thick pipe to fortify the ends of the risers to mitigate fatigue at the TDP.
Data that account for dampening could also be used to recalculate the lifespans of cables and risers on older platforms to see if they really need to be replaced, he said. But that will require a willingness to recognize the old estimates were wrong.
While the RPSEA report has been well received—Antony said they are drafting a summary of it to add to the American Petroleum Institute recommendations for Design and Analysis of Stationkeeping Systems for Floating Structures (API RP 2SK)—there has been “some initial friction.” Methods that do not account for dampening have been around for a long time and it is “always easy to be on the conservative side.”
