Industry re-assessing technology needs for ultra deepwater projects
Jeremy Beckman - Editor, Europe
Subsea projects are proliferating and going deeper, according to speakers at the recent Subsea Europe conference in London. But there are concerns over whether technology is ready for the next frontier.
Howard Wright, Analytical Services manager for Infield, suggested that the average water depth for subsea completions worldwide was now around 1,000 m (3,281 ft). In recent years, he said, West Africa has been the most significant region for subsea growth, and the industry is expanding into remoter areas such as the Arctic and Western Australia. Nevertheless, Europe remained the subsea world leader, he pointed out, with 30% of newly completed global subsea wells. Much of this was due to increased development drilling off Norway over the past year.
Despite these positives, there was a significant decrease in subsea tree awards globally last year, he claimed, due to the prevailing economic uncertainty. “Without the Petrobras/Cameron frame agreement, the decline would have been even more noticeable.” However, with oil prices recovering and stabilizing in recent months, a lot of prospective subsea oil projects now make sense to investors, although the same does not apply to gas projects, with gas prices moving in the opposite direction. “This presents a particular risk in the North Sea,” he said.
Wright foresaw independents playing an increasingly important role in the North Sea’s subsea future. “The main challenge to be faced is ageing infrastructure. Most of the fixed facilities have a design life of 25 years, which has been exceeded in many cases. Over the next 10 years, therefore, condition monitoring will become more important. Being able to tie back new projects into existing infrastructure is also important – particularly in terms of the liabilities associated with that infrastructure.”
One bright spot could be subsea well intervention. Numerous new speculative vessels are coming onto the market, Wright pointed out; with research suggesting that subsea wells are under-performing dry tree wells by 25%. Norway, led by Statoil, remains the dominant sector for subsea intervention, he said, but he also predicted increased demand off West Africa, the NorthWest Shelf, and Brazil.
Technology transfer
Chevron Subsea Systems Manager Peter Blake said the UK had accounted for the largest number of the company’s subsea wells worldwide until overtaken by Angola last February. Technical breakthroughs in each of Chevron’s UK fields had led the company to spread its belief in subsea globally, he added, citing as examples the Alba field’s pipeline bundle, high-pressure flexible risers on Galley, and mixed templates on Strathspey.
“We now have three operated subsea assets on the UK shelf in Strathspey, Captain, and Alba, which collectively account for 50% of our subsea R&D spend in Europe. Among our potential projects, Rosebank and Lochnagar west of Shetland will also be subsea, if they go ahead.” Production in this remote, hostile area, he added, would require advances in technologies such as raw water injection, multi-phase transportation, and high integrity pressure protection systems.
Blake pointed out that most of the company’s recent subsea innovations had been deployed first outside the North Sea. In a couple of cases, Chevron had attempted to transfer these technologies to its UK fields, notably all-electric subsea and raw water injection systems for Captain and Alba. However, the outcome was disappointing both times – “the brownfield modifications were more expensive than we had anticipated,” Blake said, with little positive impact in terms of production.
Testing times
Alex Hunt, Engineering Technology manager, BG Group, also presented a wish-list of new technologies suited to hostile environments and deeper water. The first of these was subsea high-pressure/high-temperature production systems. “A number of HP/HT fields are outside the range of jackups,” he said, “which means we have to look at full facilities platforms (instead of subsea step-outs for the development). This can be expensive, unless you have a large enough reserves base.
“Statoil’s Kristin in the Norwegian Sea was one of the first floating HP/HT projects with subsea trees. In terms of producing fields, Kristin is currently the highest temperature – 162º C (325º F) – while Thunder Horse in the GoM is the highest pressure, at 1,035 bar (15,000 psi). Over the longer term, we see temperature as the main challenge.”
Hunt said BG was looking at equipment solutions in the near term for two fields, one rated at 170º C (338º F) and 1,620 bar (23,496 psi), another at 200º C (392º F) and 970 bar (14,068 psi). “In both these cases, temperature might be the easier problem to solve. Even a few degrees higher, however, demands a large degree of qualification testing, and that’s expensive.”
Water depth was Hunt’s other chief concern. “More fields are being developed in depths beyond 2,000 m (6,561 ft),” he said. “The current record is held by Independence Hub in the GoM, at 2,240 m (7,349 ft). Now Shell has completed a subsea production well at 9,800 ft (2,987 m), which will be brought onstream in 2010 through Perdido. So we are getting close to the 3,000 m (9,842 ft) barrier for subsea equipment.
“At water depths of less than 2,000 m, there is a wide choice of subsea equipment available, with lots of bits and pieces to play with to assemble for different solutions. Beyond 2,000 m, however, a lot of the older stuff … has not been qualified for operations in 3,000 m of water. So the toolbox is a lot more restricted for 2,000 m and beyond.”
Third on Hunt’s list was subsea processing, which is featuring increasingly in ultra deepwater projects – he cited BC10, Perdido, and Petrobras’ Cascade/Chinook as examples. He pointed out that the deepest seabed pump installation so far was on BP’s King project in the GoM at 1,700 m (5,577 ft), which will soon be overshadowed by Cascade/Chinook at 2,500 m (8,202 ft). “Petrobras found that the largest pumps that can withstand pressures at this depth are electric submersible pumps, which it plans to install in cradles on the seabed.”
Hunt also drew attention to Total’s Pazflor in Angolan offshore block 17, the first field to be developed with subsea pumps and separators on the seabed. All these technologies require a high volume power supply, he pointed out, which underlined the logic of all-electric subsea power systems. “With Total’s K5 subsea development offshore the Netherlands, the all-electric subsea system is only 3 km (1.9 mi) from the platform and uses seawater return.
The next step, Hunt suggested, is electric downhole valves, which are being developed by Halliburton and Baker Hughes, but are not yet ready for the market.
“We also need more qualification testing. In all these projects there is a 1.5-MW prime mover, and the power needed will be much greater for future projects. Take Ormen Lange in the Norwegian Sea. The next phase (in around 2016) is being designed with three to four 15-MW subsea compression units, each comprising a 12-MW compressor and a 3-MW pump.
“Going from 2-15 MW is an order of magnitude difference. This development work started in 2006 – how many of us would have started a technology development 10 years ahead?”
Hunt also pointed out that the compressors would have to fit into huge subsea templates – Aker Solutions is developing the architecture for the processing equipment, with GE/Vetco Gray responsible for the subsea electrical power distribution equipment.
Staying on the power theme, Hunt noted that BP’s King seabed pumping system was powered by variable-speed drives on the platform, with the electrical supply fed through six cores in a combined power cable. But the next generation of ultra deepwater projects probably will need subsea variable-speed drives, transformers, and switchgear. ABB, GE/Vetco Gray, and Cameron are working on various DC and AC power solutions, he said. “If we end up with a combination of AC/DC, we will also need (subsea) converters and inverters, most of which we don’t have.”
Summing up, Hunt said the industry needed more qualification, more testing, and that will take time and money.
“We also want to do this nearer term rather than longer term, and that effort will have to be collaborative. For some of these applications, we must look at a bespoke solution rather than taking something that we already know today and putting it in a tin box.”