Oil and gas producers face higher risk as they venture into deeper water to find bigger prospects that require larger, more expensive floating platforms to produce. It's an arena where weight savings is crucial and delays are increasingly expensive.

BP is launching the world's largest floating platform over Thunder Horse field in Mississippi Canyon 778 and 822 in the Gulf of Mexico. The platform over BP's Atlantis, in Green Canyon 743, will be the second largest. The company already launched the world's two largest spar platforms for Holstein field in Green Canyon 645 and Mad Dog in Green Canyon 782.

BP completed final assembly for Thunder Horse, including the mounting of the platform on the base, at the Kiewit Shipyard in Ingleside, Texas, the only shipyard available with a 90-ft (27-m) hole at quay-side that would allow a float-out of the fully assembled platform.

A full assembly at quay-side eliminates the expense of bringing a heavy-lift vessel to the deepwater field site, the time-delay risk of weather challenges, and the monetary and time risk of the lifting vessel dropping a module into water so deep it can't be recovered.

Solution

One company, sendit llc, offers a similar solution that could lower costs, weight and risk by sending out the platform substructure - semisubmersible, spar, tension-leg platform or even a fixed tower - to the field site ahead of the platform topside. It would then use a heavy transportation vessel or cargo barge to bring out the single-level platform deck, float the topside over the partially submerged substructure, raise the substructure to mate with the topside and raise both to working height above the water.

Tor Persson, president and principal consultant for the company, has applied for a patent for the technique and technology, and he is in active talks with operators about moving on the first offshore installation.

Listing advantages over the traditional two-level deck complex and heavy-lift assembly, he said the new technology:

• Reduces wind-catch area by about 30%;

• Lowers the center of gravity;

• Allows increased air gap between the sea and platform because of the lower center of gravity;

• Allows a fully assembled and commissioned topside to be installed with tugboats;

• Gives the operator a substructure designed for submergence, which could occur in case of another Hurricane Ivan in the Gulf of Mexico; and

• Gives the operator the option of retrieving the topside complex for reuse or demolition.

Topside

The topside is an enclosed single deck, engineered to float, with an X-truss configuration running from opposing corner to opposing corner. The X-truss forms provide bracing for the system with two sets of bulkheads crossing the topside. The design allows the operator to cut an opening for the moon pool at the junction of the X-truss when the platform has been raised to its final elevation. In addition, fluids tanks, compresssion equipment and other gear can be mounted between the bulkheads for efficient use of the deck area. Arctic rigs currently put the same components in closed spaces and have heating, air-conditioning and venting systems that will remove concentrations of fumes.

"Additional levels or higher sides can be added to the basic X-truss topside design," Persson said.

Once the topside is mounted on the substructure and raised to the final elevation, the panels making up the circumference walls are no longer needed for flotation and opening can be cut for ventilation or access, if required.

The X-truss offers another plus for the operator, since the truss beams can serve as skids that allow the drilling rig to move across the deck to different locations.

Depending on the substructure used, the construction company would build recessed supports in each of the X-truss members of the generic topside to fit the platform on the substructure chosen for the platform.

Installation

Once the substructure arrives at the production site crews hook it up to the mooring lines or tension-leg tendons in the traditional manner.

As the transportation vessel brings the topside section to the location, the on-site crews ballast the substructure to a weight of 50 tons and allow it to submerge while a team of tugboats support the submerged weight. Ideally, those would be dynamic positioning tugboats.

When the topside section arrives, the transportation vessel allows it to float off - also guided by tugs - over the submerged substructure. At this point, winches from the same tugs attach to both the topside and substructure individually.

Crews then connect lifting lines through the recesses in the topside to the substructure. Then, the tugs pull the substructure up to mate with the topside.

Once the two sections are mated, the crews de-ballast the substructure, allowing the platform to rise to final working elevation. That buoyancy capacity for the in-place design of the platform is sufficient for lifting operations.

If the topside has a drilling rig, the rig can be used to lift the substructure into place while the tugs simply handle alignment of the topside and substructure.

All facilities, including a helicopter deck and a flare boom, will be installed in the fabrication facility.

Advantages

Among advantages, Persson said, a topside that the operator installs as a single unit lowers fabrication, transportation, assembly, completion and commissioning costs and reduces time to first production.

Additionally, tugboats are nearly always available for work, while an operator might have to wait for availability of a heavy-lift vessel for an offshore installation. The floatover concept also is less sensitive to weather, since the system includes motion compensating by the buoyancy of the substructure.

"My first priority was an efficient design, easy to install," he said.

The setup gains another advantage in weight savings and equivalent steel costs. The weight savings come in because the facilities are built into the floatover design instead of being placed as a separate module. The floatover gains more weight advantage since the drilling support module - mud pumps, shale shakers, etc. - is built into the design, also instead of a separate module. Those gains more than offset the lower weight of primary steel in the traditional structure.

That weight plays another part in the equation as well. Transporting a two-tier truss frame topside with a heavy-lift vessel can use up a large amount of the fatigue life of the topside, and the engineers have to design in more steel to make up for the fatigue factor, Persson added.

The idea of a floatover platform looks reasonable and efficient. He came up with the idea himself. "You need a well-defined problem, then you can find a solution," he said.

In this case the problem was the time, effort and risk in the traditional mounting technique for an offshore platform. "This is the solution. You figure what you want, then how to get there," he said.

His experience in the North Sea also played a part. Lifting topsides in the stormy North Sea can be a serious problem.

Considerations

There is not practical limit to the size of the topside, he said. Specific advantages can be realized for platforms requiring a lot of completion work to be performed offshore, platforms in remote locations or with restricting sea conditions.

As long as competition remains in the oil and gas business, and as long as deep water remains the hottest play in the business, the quest for more efficient, less expensive designs will continue. The floatover concept is another in a long chain of ideas worthy of investigation.

Comments