As deepwater operations near the 10,000-ft (3,050-m) level, seafloor equipment manufacturers consider a few design changes.

If opinions of those considered savvy about the subsea production systems market are only half correct, activity during the next 5 to 10 years will be exceptional. In fact, they're not just looking forward to major market growth. They're proclaiming it.
Take, for example, the second annual World Subsea Report, published in mid-February by UK offshore energy analyst Douglas-Westwood Associates (D-W). It remains hot news even today, partly because D-W, which prepared the report jointly with fellow UK data specialists Infield Systems, makes some pretty straight-ahead assertions:
• starting next year, worldwide capital spending for subsea systems will nearly double to more than US $10 billion annually through 2006, compared to the $5.3 billion operators spent only 2 years ago; and
• total subsea spending for the period 2003-2008 will be $47.8 billion, a market value hike of nearly 50% from the estimated $31 billion that will have been spent during the 5-year period ending Dec. 31.
But the figures could be even higher. Dominic Harbinson, study team leader, said operators are considering 581 subsea projects for development during the period 2002-2006. If all were to be approved, their combined value would exceed $51 billion.
And there's room for even more. The Infield Systems database contains an additional 174 offshore development prospects for the study period not included in the report's totals for which no development scheme has been announced.
"It's reasonable to assume that a large proportion of those projects would include subsea systems and could be approved and completed before 2006," he said, adding that quick turnarounds are possible, such as with Shell's North Sea Curlew B South satellite development, put onstream in 53 days, and Amerada Hess' deepwater Ceiba field off West Africa with its process facility, which went from initial discovery to first oil in 14 months.
The report indicated fairly widespread regional spending activity. It pegs Brazil as the subsea leader with a 21% share of the capital expenditures for 2002-2006, followed closely by the United Kingdom with 19%. The Gulf of Mexico is next, with 17%, then West Africa (15%) and Norway (11%).
Development drilling and completions leads off the operations segments for which the money will be spent, receiving some $22.4 billion, or 46% of the total, the report noted. Flow lines, both rigid and flexible, make up the next biggest segment with a value of about $15 billion, or 32%. This is followed by subsea trees, templates and manifolds and their associated controls and control lines, which account for the remaining $10.4 billion.
Reliability the key
It's a good bet that during the next decade, the leading edges of subsea systems technology will be stretched, particularly as working water depths approach 10,000 ft (3,050 m). Meanwhile, operators will try to specify off-the-shelf subsea equipment as much as possible. But more deepwater projects are prompting operators to seek some subsea equipment design changes.
Beefing up the connections
Randy Seehausen, technical sales manager for Dril-Quip Inc., Houston, Texas, said that the advent of the high-day-rate, dual-purpose dynamic positioning drilling units has pushed standards for drilling riser equipment and wellhead connections much higher to handle the increased bending, fatigue and anti-rotational forces involved in deepwater operations.
Wellhead equipment also must be capable of accommodating downhole challenges like shallowwater flow and pore pressure, fracture gradient and hydrostatic mud weight values that create complex deepwater drilling and completion needs, Seehausen said. Such conditions require additional casing strings and wellhead equipment capable of supporting them. What's more, adding more equipment above the wellhead - and thus, above the ocean floor - also stresses the need for higher-strength connections, particularly between the wellhead and the new types of seabed blowout preventers (BOPs) and risers, he said.
Several manufacturers are filling the requirement for added casing for pressurized water sands with wellheads that allow an additional casing string, hanger and seal assembly to pass through with the drilling BOP stack and riser in place, said Seehausen. Many of these beefed-up, "big bore" wellhead systems, one of which Dril-Quip manufactures, already are being used in areas with shallowwater flow problems.
New controls strategies
Jay Hursh, business development manager for Kværner Oilfield Products (KOP), Houston, said among technology changes likely to occur during the next few years will be a transition into alternative power systems for subsea controls, including use of electrical systems to succeed straight hydraulics.
With deeper water, said Hursh, operators are specifying increasingly longer offsets between subsea production systems and host facilities, be they floating or fixed. With longer offsets, he added, it becomes more critical to ensure that control systems power is reliable. Electrical conductors running to actuators will be the answer to problems inherent with hydraulic systems when longer transmission distances are added, he said.
And this demand for new power alternatives will grow, since the industry also is working to take certain topside components to the seafloor itself, including well fluids separation and processing equipment, Hursh said. Also, with longer offsets, fiber-optic technology will be required, and operators are looking at the ability to communicate with subsea electronics using off-the shelf hardware and software."Open architecture manufacturers, including KOP, are testing such equipment, he added.
Flow assurance features stressed
Mark Crews, vice president of technology for Cameron, said manufacturers are doing a creditable job of addressing the hardware issues associated with subsea systems, even as water depths increase. His company provided an ultradeepwater tree recently installed in 7,200 ft (2,196 m) in the Gulf of Mexico, a depth world record.
Crews said, "While the challenges to the equipment designers and manufacturers lie in providing reliable components for use, systems designers must use their equipment knowledge to provide an operable system which meets or exceeds project availability targets." One challenge to the design of an operable system is to consider flow assurance issues during all phases of field operation. The long offsets, he said, involved in regions where the push to deeper water has gone beyond existing infrastructure, such as in the Gulf of Mexico and West Africa, prompts operators to be concerned increasingly about alternative technologies to design for flow assurance in a cost-effective way.
"There is a growing need to incorporate flow assurance features into the subsea production system, particularly the modules that well fluids pass through before entering the tieback," Crews said. "In West African waters, for example, produced fluids are not particularly warm, so there's a tendency toward hydrate formation in the deep, cold water. There, operators must consider the cost tradeoffs of having flow assurance protection come with subsea system modules, in the form of chemical injection systems, subsea separation and the use of insulation or heated pipe to avoid having to intervene later if hydrates or paraffin plugs interrupt the flow at or near the subsea system."
Crews also believes that increasingly longer offsets will bring the opportunity to switch from traditional hydraulic controls to electric-powered subsea systems. He, like Hursh, also trusts that as operators transfer more topside equipment to the seafloor to help alleviate some of the flow assurance issues, the suitability of substituting electric power for hydraulics will accelerate. Off West Africa, he said, having smaller and fewer surface facilities can help lower operating costs.
On the drilling side, Crews said manufacturers like Cameron have developed new technologies to help keep floating drilling operations safer in deep water. One involves improving the use of surface-mounted BOPs for drilling deep holes from floating rigs.
"Essentially, you've got a casing riser extending from the surface stack on a floating vessel down to the seabed, where you have a sophisticated shut-off device as an environmental safeguard."
Another is an improvement on existing technology that involves a freestanding drilling riser, which enables a floating drilling vessel to disengage and move off the well quickly, should that become necessary.
Moving ahead by inches
Amin Radi, research and development director for ABB Vetco Gray, Houston, said operators can depend on equipment manufacturers to develop new subsea system technology. But he believes it will be done from a more practical standpoint than before, because operators resist too sharp a departure from field-proven technology, given deepwater operations' high-risk, high-cost nature. The watchword for deepwater development is reliability, he said. So new technologies will come in measured increments.
"Look at development of floating production facilities and all the subsea hardware that's connected to them," he said. "Six or 7 years ago, there were a handful of TLPs (tension-leg platforms) around the world, and only two in the Gulf of Mexico, in what then was considered deep water. Today, they're using spars and other floating production systems in far deeper water, particularly in the Gulf. But less than a decade ago, such equipment was still in the realm of the unknown - an emerging technology."
While organizations such as his conduct "dream to" research, Radi said new subsea equipment has to spring from established technology. So manufacturers' research dollars are going into equipment designs that can be field proven in only 3 to 5 years. That means adapting existing equipment.
However, once deepwater drilling activity approaches the 9,000-ft to 10,000-ft (2,745-m to 3,050-m) level with regularity, Radi said some new thinking about production facilities will be needed.
"Existing technology already allows you to drill and complete wells at those depths. But assuming you want to produce them, what do you use? The cost of TLPs or spar-type systems could become prohibitive. We may have to start thinking outside the box for 10,000 ft of water."
But ongoing drilling and completion technology changes like riserless drilling, slimhole drilling and expandable tubulars will impact subsea production system development, said Radi. Current wellhead and controls technology can be made to perform at those depths, but more widespread slimhole completions would require redesign of subsea production components for the smaller diameter wellbores," he said.
Meanwhile, companies like ABB Vetco Gray and its sister company, ABB Offshore Systems, are working on lighter subsea system components, using composites in place of steel for risers. They're also at work on electric systems to provide low-cost, reliable controls independent of water depth and stepout distances, Radi said.
Beyond the 'sound bites'
Brian Skeels, Subsea Systems technology manager at FMC Energy Systems, Houston, believes that once operations at the 10,000-ft water depth level - so often brandished in today's "sound bites" as the ultimate target for subsea technology - become more routine, moving into even deeper water won't draw as much attention.
"Beyond the 10,000-ft level, you're out on the abyssal plain, and from that point on, the seafloor in most cases deepens at a pretty gradual rate," he said. "So once we're working there routinely, the water depth factor won't be nearly as sexy. The key then will be systems reliability, and vitally important though that is, it just won't create the kind of dramatic headlines we see today."
But before that happens, Skeels does expect some noteworthy subsea system design changes. For example, he said that since electric power is not depth-sensitive and is gaining a history for underwater reliability, it will overtake hydraulics as the power source for controls beyond the 10,000-ft water depth level. But to that point, he said, hydraulics should remain the power source of choice, particularly for fields served by 10 wells or fewer that are linked by shorter offset distances.
As for increased use of fiber optics and composites, Skeels said overall prices must come down, unless a deepwater field requires huge arrays of subsea equipment and the payout is acceptable. However, the future for fiber optics, he said, will be in controlling downhole components, particularly under high-pressure, high-temperature conditions. And growth in using composites and other lighter-weight materials will be governed by specific deepwater applications, such as for risers and other surface links.
But Skeels expects a significant technology shift aimed at handling the long offset problems inherent in the Asia-Pacific area - "the forgotten market," as he calls it.
"There are huge reserves out there," he said. "And basically, they're in shallow water, and well pressures aren't a problem. But provided the right kind of economic incentives exist for both producers and equipment suppliers, emerging technologies will address subsea processing, offshore processing and dealing with logistics. Operators will have to move huge production volumes to the markets more efficiently. The distances are immense. The Far East is a relatively untapped horizon for the entire industry in terms of production and production technologies, including subsea systems."

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