Moored in water depths ranging from 20 to 1,500 m (66-4,921 ft) across the entire spectrum of floating production environments, FPSOs may be offshore’s most versatile production technology. Today, 30 years after the first FPSO installation, there are 111 FPSOs on station - more than all other floating production methods combined.
Some recent FPSO projects have taken the vessels into new frontiers. The ABS-classedSanha FPSO is the first liquefied petroleum gas FPSO. The Capixaba, moored in 1,340 m (4,396 ft), of water, has taken the FPSO system to greater depths. And in terms of production capacity, the Agbami FPSO, now under construction, has a design capacity of 250,000 b/d of oil. Now, a new Petrobras project appears poised to push the FPSO across its next frontier into the ultra deepwater US Gulf of Mexico.
How, under what conditions, and in what form would the first FPSO enter the US GoM? The industry has long speculated about these particulars.
Petrobras has stated that plans for its Cascade and Chinook fields include an FPSO, at least in Phase I development, although there are no commitments as yet. At the very least, such talk indicates that post-Katrina thought looks favorably on FPSOs for the US Gulf.
Criteria
Post-Katrina, the Minerals Management Service (MMS) and the United States Coast Guard (USCG) criteria for the next generation of offshore platforms increased significantly, though this is due less to a stricter MMS and USCG and more to improved knowledge about the forces of Gulf storms, says Bret Montaruli, vice president of engineering for ABS Americas in Houston.
“The regulatory attitude hasn’t really changed, inasmuch as they still allow the operators to choose the environment to which they design, and their metocean criteria,” says Montaruli. “That said, MMS and USCG are definitely taking a much closer look at your data. I wouldn’t say they are stricter than before, but as there are a number of metocean databases, they are taking great care to be sure the one you use has the latest information and is appropriate for the specific location. This generally means higher criteria because there was a step increase in the data when the Katrina information was released.
“Regulatory thinking doesn’t favor one solution over another,” he adds. “For example, if someone were to design an FPSO for the Gulf that could withstand the 100-year storm criteria at the site, stay on location, and meet all the safety factors, I don’t imagine the Coast Guard would oppose it. Until now, no one has proposed that. There are a number of FPSO ideas in the pre-FEED stage at present, and all are talking about disconnectable solutions.”
ABS has classed the majority of the world’s disconnectable FPSO systems.
Conditions
“Compared with the North Sea, the North Atlantic, or even Brazil, day-to-day conditions in the GoM are fairly benign, but freak events like loop currents and hurricanes make for extremely harsh survival conditions. The concept of the disconnectable FPSO has been successfully applied in other areas of the world with these type events. They are called typhoons in China and cyclones in Australia, but it’s basically the same kind of event,” says Sipke Schuurmans, chief engineer with FPSO owner/contractor SBM-Imodco in Houston.
Considering its risk-limiting value, a disconnectable solution does not come at a very high premium over a permanent mooring, says Francis Blanchelande, SBM president. “Some parts of a disconnectable system cost less. The mooring pattern, for example, has to withstand lower conditions than if it were permanently moored. Some parts cost more, particularly the whole disconnection system. Overall, a disconnectable solution costs a small additional difference compared with the huge risk of experiencing what happened in the Gulf two years ago.”
The difference in operating expenses between the two systems also is minimal, he adds, primarily taking into account crew training for disconnecting the turret.
SBM says the total disconnection time is about 24 hours, including time for standard pre-abandonment procedures like depressurizing and flushing flowlines, as is done for any facility preparing for the approach of a hurricane. “The final steps of disconnection, that is the disconnection of the risers and the release of the buoy, is only a matter of hours,” says Schuurmans. “The final release of the buoy itself is actually a push-button operation and can be delayed until the last moment.
“Knowing what hurricanes can do to stationary assets, and having heard how difficult it is becoming for operators to get full insurance cover for their assets, we say the disconnectable FPSO is like a cheap form of insurance for offshore production, as it allows the operator to take the asset out of harm’s way,” he adds.
The two main types of disconnectable systems use internal or external turrets. External turret systems typically have a swivel and connections in an integrated structure projecting from the vessel’s bow. When the vessel disconnects, it leaves the riser floating in place. Internal systems have a turret that is integrated with a moonpool-type opening in the foreship. Upon disconnection the mooring buoy, which is mounted beneath the vessel, floats down to an equilibrium depth of about 50 m (164 ft) where it should function to support the chain legs and risers below the surface tempest.
The deepwater question
“One advantage of the internal disconnectable solution is better protection of the risers because the turret is inside the hull,” says Shashank Karve, president and CEO of Modec International Llc in Houston. “At the moment, we are considering internal-turret disconnectable FPSOs for the Gulf.”
Modec and SBM each have several disconnectable FPSOs operating in South China Sea’s “typhoon alley” and the cyclone corridor offshore Australia. Although there are no disconnectable FPSOs in very deep water, let alone ultra deepwater, operators indicate that water depth may be the most minimal of all the challenges to installing an FPSO in the GoM.
“I don’t see it taking a tremendous change in technology to extend what we are using now, say offshore Australia, to take a disconnectable FPSO into very deepwater,” says Karve. “On the ship side, the connect/disconnect won’t change much. The big changes will be to the mooring system, where the issue will be to get the required buoyancy.”
Operators report a variety of systems under study, including the use of much bigger buoys or more buoyant risers and mooring lines. While no one is talking about composite risers yet, there are some novel solutions being evaluated. One of these potential solutions is considering combining conventional steel risers with flexible jumpers at the top end.
Disconnect vs. DP
There is a precedent for using a dynamically positioned (DP) FPSO and eliminating the mooring system altogether. There are two extended well test vessels with DP currently in service, although neither is used for production. They both work in the Mexican sector of the Gulf for Mexican state oil company, Pemex. Operators, however, think they could take too much time and be too much trouble for long-term installation.
“My sense is that a DP unit will be a lot more costly than a disconnectable system,” says Karve. “There is greater capex because, for example, it has huge thrusters, their control systems, and the required redundancies. Beyond that, there are significantly higher opex costs. Besides needing DP-1 rated personnel, which in itself is difficult to find, you have high maintenance costs. Keeping a DP unit on station requires a lot of power. Yes, you can use produced gas for power, when there is gas and when your plant is operating properly. To cover the rest of the time, you need to be able to switch quickly from gas to a second fuel.”
On the other hand, Karve says, “As a short-term solution for early production, a DP unit isn’t out of the question.”
SBM’s Schuurmans agrees: “We ran our cost numbers, indicating that a disconnectable FPSO is a more cost-effective solution than a DP unit, certainly when you factor in opex costs related to thruster maintenance, fuel costs, and additional personnel. We can only see that a DP unit makes sense for short project durations with few risers,” he says. “When you go out to install a riser system typical for deepwater development and a buoy to support the system after a disconnection, the costs of adding a mooring system to this are relatively small. In addition, a mooring system makes the requirements for the quick disconnect features less critical. As for a DP unit, disconnection needs to be possible within minutes to cater to drive-off scenarios.”
Moving the oil to shore
One big advantage of an FPSO solution is its independence from the oil pipeline grid. In light of some of the regulatory requirements for operating in the Gulf, that independence is raising a stumbling block - how to get the oil to shore.
Though the FPSO itself is not subject to the Jones Act, which requires vessels trading between US ports to be US-built, flagged, and manned, the shuttle tankers hauling oil from the FPSO will be.
There are product tankers under construction at National Steel and Shipbuilding in San Diego and others soon to begin at Kvaerner Philadelphia, but whether they will be pressed into Gulf shuttle service remains unknown. The only alternative to conventional tankers at the moment appears to be the US-flag articulated tug-barge (ATB) fleet.
In an ATB, the tug is attached physically to its barge through a pin-in-slot connection that allows the combined vessel to flex as it goes through the waves. Though a proven technology, ATBs have not yet been used in deep-sea offloading. Normally an ATB loads in port, and the tug connects only after the barge has achieved loaded draft. In loading at sea, the tug would have to disconnect from the barge at a certain point in the operation and wait for it to be filled, a concept operators currently are puzzling over.
“ATBs are a viable solution to the shuttle tanker problem,” says ABS’ Montaruli. “We don’t see any major issues surrounding this application, though some aspects will need sorting out with the regulatory bodies, for example manning issues. The barge normally is unmanned in an ATB, but there will be certain barge operations during loading/unloading in the FPSO scenario in which you will have to be manned,” he explains. “Another example is oil transfer. The operation of transferring oil from an FPSO to an ATB or shuttle tanker offshore has not been done in the US GoM. This will receive close scrutiny by regulatory bodies as well as classification society rules.
Arctic a long way off
Industry and class alike are beginning to tackle questions about producing from the arctic. Though intriguing, the possibility of seeing an arctic FPSO, or indeed any arctic floater, going online is still years away, say operators. There is significant experiential data on offshore arctic production, but it dates to the last big effort in the field, exploration of the Beaufort Sea in the late 1970s and early 1980s. Some of the equipment developed at that time is still around, like ABS-classed Molikpaq, a bottom-founded structure now deployed offshore Sakhalin.
“The majors are just now starting to show interest and acquire acreage in the arctic. They still have to make drilling plans and find suitable vessels to go up there and work. So, at the very earliest, I don’t think we will see anything going into the arctic in less than five years, and more likely 10,” says Karve, who has worked on a number of arctic concepts for exploration, drilling, and production. “A lot of work has been done for the arctic, but all that technology will just stay sitting on a desk somewhere until the drilling starts,” he says.
Joe Evangelista
ABS
