One of the first commercial subsea separation systems paves the way for future offshore advances.
Years of trials, tests and pilots mark a trail of careful technology growth for subsea separation that will provide a building block for the elimination of costly offshore production platforms.
Without this step, long-distance subsea tiebacks would be impossible. Without subsea separation, Norway can't reach its goal of more than 55% recovery from reservoirs, said Tore Halvorsen, vice president of FMC Kongsberg Subsea AS in Kongsberg, Norway.
FMC Technologies recently landed a US $100 million contract with Statoil for the installation of a subsea separation, boosting and injection (SSBI) system for Tordis field in the North Sea.
The system is part of a campaign that will allow Statoil to raise production from the Tordis subsea field from 49% of resources to 55% of resources, or 39 million bbl of additional oil under an improved recovery program. FMC's separation system will account for 19 million of those additional barrels of oil.
The separation system uses compact separation technology from CDS Engineering. FMC acquired a 55% interest in that company in 2003.
The gains come from removing water subsea from the wellstream and reinjecting it into a sea floor disposal well. That lowers back pressure in the system and allows faster flows. The elimination of surface separation gear also saves platform space and lowers weight-support requirements.
Also, as water production increases in a typical subsea field, it fills pipelines and hampers oil production.
Separation system
From the reservoir, the oil-gas-water production goes to a pipeline inline manifold that will be installed at Tordis next summer. The manifold can route production either directly to the Gullfaks C field platform or to the SSBI. Following the installation of the manifold, pipelines and umbilicals, the company will install the SSBI in October 2007.
Four suction anchors, one at each corner, will hold the SSBI in place and keep it level. With the manifolds, the total installed weight is 900 tonnes.
At the separator, the production stream enters a hydrocyclone that separates most of the gas from the production stream. The spinning action is slow enough that sand in the mixture will not erode the equipment, Halvorsen said. The gas can then be routed outside the gravity separation tank, thereby obtaining a more efficient separation process.
The hydrocyclone is also slow enough that water and oil won't form an emulsion to slow separation.
A conventional gravity tank separates water, oil and sand. On a platform, he said, an operator can send personnel out with shovels to remove sand from a separator. At Tordis, special nozzles flush out the sand into a special desander tank. The sand slurry can then be piped to the water disposal line, downstream from the pump, where it will be forced down the water disposal well.
After separation, the system pumps the water to the disposal well where 135?8-in. casing takes it down to the Utsira water reservoir. The oil and remaining gas are re-mixed and pumped to the Gullfaks C platform.
The Tordis system can handle 200,000 b/d of liquids, or 60,000 b/d of separated oil. It also has the capacity to handle half a metric ton of sand disposal a day, Halvorsen said.
Electric power for operation comes from the Gullfaks C platform.
A subsea multiphase flowmeter tests the incoming stream to prepare the separation system settings. A level monitor in the separation tank determines water and oil levels to control the water pump and the multiphase pump speed.
In all, the SSBI control module handles 51 distinct functions and reports the status of its operations back to the platform.
Each module in the system can be separately removed and taken topside for repair or replacement.
Significance
Step-by-step, subsea processing can lead to an offshore oil and gas field future without offshore production platforms, Halvorsen said.
It will help revitalize older fields by accessing more, smaller reservoirs and transporting oil longer distances, since water removal will inhibit the formation of hydrates in lines. Large, older reservoirs with high water cut are a prime target.
A number of the oil fields on the Norwegian Continental Shelf produce a lot of water, he said, and the liquid constrains the processing capability of the floating production, storage and offloading (FPSO) vessel. Under those conditions, adding another satellite field would be difficult without subsea separation. That's the role the Tordis system plays at Gullfaks C as well.
Another installation for subsea processing units is likely offshore Angola on Total's Block 17.
The French company needs three processing units to treat light oil in the deepwater block before moving it the long distance back to the Girassol FPSO.
Even though the basic elements are the same, each installation must be adjusted to the reservoir it serves. It must be tuned for water, oil, gas, sand and fluid ratio changes over time. CDS Engineering built a full-scale test lab in Holland just to test different fluid mixes.
Compression
Gas opens more opportunities than oil since there are more areas where subsea separation can replace platforms.
With separation at the commercial stage, the next major step in the offshore innovation chain is subsea compression. FMC has signed an agreement that will allow it to use Siemens offshore compression system Troll A, Halvorsen said. It must handle gas wells, remove water, compress the gas and move the gas to shore. It ships some 848 Bcf (24 Bcm) of gas a year. "If subsea compression and separation had been ready 15 years ago, Troll A would probably not have been built," Halvorsen said.
If Troll A is huge, Shtokman, which lies 373 miles (600 km) offshore in the Barents Sea, is a monster. With 105 Tcf (3 Tcm) of gas reserves, it will produce 2.4 Tcf (67.5 Bcm) of gas a year.
Shtokman, he said, will need 218 psi of pressure at the onshore plant gate. Reservoir pressure will start around 2,321 psi, but when it drops to approximately 1,813 psi, pressure will need boosting.
The vision for Shtokman for development around 2012 is to use both subsea separation and compression and move the gas directly to the beach. Subsea compression can be added when it is needed, probably around 2020.
Ormen Lange, in the Norwegian Sea, also is under development. As in other fields, gas production is linked to reservoir pressure. When gas pressure reaches minimum inlet pressure at the onshore station, the operator will have to move in compression equipment. That probably will occur around 2014 or 2015. Subsea compression is a prime goal for Ormen Lange to avoid the cost of another Troll A-sized platform and to move the gas 75 miles (120 km) to shore.
The Norwegian government estimated the cost of Ormen Lange with a platform and all equipment at $1.35 billion. Subsea processing and compression would cut that figure in half, Halvorsen said.
Shtokman and Ormen Lange probably will both use the same system of acceptance. Norsk Hydro will test subsea compression at Ormen Lange until 2011. If it works, it will go to commercial operation. If it doesn't pass the test, the company still can build the compression platform.
That testing already is going on. Norsk Hydro has built a pit at its onshore plant site for Ormen Lange, and it will install a compression unit, fill the pit with water and observe how it performs before the more expensive offshore installation. FMC is one of the companies bidding on that pilot project.
Halvorsen believes the Siemens compression unit has an advantage. Where most compression systems have separate motor, shaft and compressor, the Seimens system comes in a single container. The compressor uses a common shaft with the motor. It has magnetic bearings, and rotating seals aren't exposed to gas pressure differentials.
For a topside compression unit, the normal maintenance interval is a year. For the subsea system, that interval is 4 to 5 years, and it can be pulled as a single unit.
Electricity
Power may be the biggest obstacle to long-distance subsea tiebacks. Halvorsen said he was convinced the subsea compression technology will stand up to the test. A bigger problem is reliable electrical power.
Shtokman, for example, will need 240 MW of power to run its subsea plant, and the technology is not available yet to provide that power. That electricity drives motors, and varying frequencies determine the speed of the motors.
For the future, the industry (ABB, Siemens and others) is looking at converting AC shore power to DC, sending it offshore to a platform and converting it back to AC. DC power isn't affected as greatly by the distance of the line.
For a field like Shtokman, conversion equipment would require at least a small platform at the field. The alternative would be a power generation vessel running on diesel or gas and set on top of the field.
Wave power is a possibility in some parts of the world, but that might not be possible with the pack ice in the Barents Sea.
Future
"It's very exciting technology. It's enabling technology for future fields," Halvorsen said. Still, any company has to take the steps one at a time and prove up one piece of technology before matching it with another. "Subsea is like space. You can't make a mistake. You have to design as if everything can go wrong," he added.

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