The world’s oceans are the planet’s last great frontier. Only around 10 per cent of the sea floor has been mapped and we probably know more about the dark side of the moon than the seas that cover 71 per cent of the Earth’s surface. But one thing is certain – there is still much subsea oil and gas to recover.
Offshore drilling is technically difficult and expensive, and is set to become even more so as the industry is forced into deeper, ever-more remote waters to counterbalance declining production in mature shallow-water basins.
While there is no cheap and easy technological solution to these challenges, operators are gradually adopting changes that are enabling them to cost-effectively target reservoirs over a much wider area, tying back subsea wells both to fixed platforms in shallow waters and to floating infrastructure in deeper water.
A combination of high oil prices coupled with rising surface facility costs and advances in technology have helped fuel a boom in so-called subsea developments in recent years. In the UK, for instance, the sector has 53,000 employees, more than 750 companies and is worth £8.9 billion in products and services.
Globally, investment in ultra-deep water developments, which can be up to 3km below the surface, is expected to capture 48 per cent of total subsea capital expenditure from 2013 to 2017, in contrast to 37 per cent between 2008 and 2012, according to UK-based industry analysts Infield Systems.
Some of this investment is being channelled into development of new technologies and materials that will make oil and gas extraction at great depths financially viable yet safe both for operating personnel and the environment. In recent years, operators have focused on bringing many of the processes formerly carried out at the surface down to the seafloor.
We are looking at new materials, new construction methods, new welding techniques, as well as higher strength steels, as projects go deeper and encounter higher pressures
One of the first examples of the current generation of subsea technologies appeared in 2007 when US engineers FMC Technologies supplied a full-scale commercial subsea separation, boosting and injection system to Norway’s Statoil. The device separates out the seawater, cleans it and injects it into a low-pressure aquifer, while boosting the pressure of recovered oil and gas mixture to 1,000psi for the 16-mile trip to the Gullfaks field for processing.
North Sea oil fields now depend heavily on enhanced oil recovery (EOR) techniques, and in this case the FMC system boosted total recoverable oil by 19 million barrels.
Next year, Statoil hopes to install the next generation of technology, the world’s first subsea gas compression station in the Åsgard field off the coast of Norway. Two advanced 11.5-megawatt compressors will boost falling gas pressures in the Midgard and Mikkel satellite reservoirs, thereby prolonging the life of the field and increasing gas recovery by the equivalent of 280 million barrels of oil. The developers say the project avoids the need to build a new, large semi-submersible platform and will reduce operating costs.
However, this technology was dealt a blow last month when Royal Dutch Shell postponed a project to provide subsea compression at Ormen Lange, the second-largest Norwegian gas field. “The oil and gas industry has a cost challenge,” says Odin Estensen, chairman of the Ormen Lange management committee. “This, in combination with the maturity and complexity of the concepts and production volume uncertainty, makes the project no longer economically feasible.”
Although the pioneering subsea compression system, also designed by Aker Solutions, promises to reduce capital and operating costs, and enable greater production, it still faces considerable technological challenges. It will have to pump gas from wells at a depth of 2,790 to 3,600 feet some 75 miles to onshore processing plants and be available 97.6 per cent of the time, with maintenance taking place only every four or five years. A daunting challenge even for compressors based onshore.
Low-salinity water flooding of oil reservoirs is another EOR technique that is gaining ground. Normal seawater creates electrical charges, because salt is a conductor of electricity, causing oil to stick to the rock walls, thus reducing the quantity that can be recovered. But if low-salinity water is used instead, the charge is lowered and the oil is more easily liberated from the rock. The International Energy Agency estimates that an additional 42 million barrels of North Sea oil could be recovered using this technique.
One of the biggest problems facing subsea projects is the provision of a reliable, safe power supply to drive and control the pumps, compressors, separators and other processing equipment that has traditionally been kept on platforms on the surface. German multinational engineering and electronics conglomerate Siemens has developed what it calls a subsea power grid that combines electricity transmission with control and communications elements, while Swiss engineering giant ABB has entered a five-year programme with Statoil to develop a similar system.
Subsea engineering firms are working on a range of new technologies. “We are looking at new materials, new construction methods, new welding techniques, as well as higher strength steels, as projects go deeper and encounter higher pressures. We are also witnessing the emergence of composites and carbon fibre,” says John Mair, technology development director at engineering firm Subsea 7. “You are going to see new developments in underwater communications, fibre optics and acoustics, especially for the Arctic.”
If the polar ice cap continues to recede, large-scale drilling in the Arctic Circle will soon become a reality and could account for as much as 20 per cent of the world’s undiscovered but recoverable oil and natural gas resources. Indeed, by 2030, the majority of oil reserves will be in as yet undeveloped or undiscovered fields and extracted using additional EOR techniques, according to the International Energy Agency.
Advanced technologies look set to play a pivotal role in the future, but will only do so if they are cost efficient. This will depend on continued high oil prices and therefore seems likely, but is far from assured.
SUBSEA COMPRESSION IN ÅSGARD FIELD
Last summer, 125 miles off the coast of Norway, a 30,000-square-foot steel structure was sent plunging to the ocean floor. By next year it will house a giant compressor that will pump an estimated £18 billion worth of gas from a mature offshore field.
Analyses show that, towards the end of 2015, the pressure in the Midgard and Mikkel gas reservoirs in the Åsgard field will fall below levels required to sustain a stable, high level of production.
Until now the solution has been to install gas compressors on an existing platform or to build a new staffed compression platform. Instead, Statoil and Aker Solutions are developing a subsea gas compression unit that will be installed on the seabed next year – the first time this has been attempted anywhere in the world.
The technology represents a quantum leap that can contribute to significant improvements in both recovery rates and lifetime for a number of gas fields
By situating the compressor close to the wellheads, recovery rates will be better than if it were on the surface, and cheaper to build and operate, according to Acker Solutions.
“The technology represents a quantum leap that can contribute to significant improvements in both recovery rates and lifetime for a number of gas fields,” the company says. It is expected that the project’s two state-of-the-art 11.5-megawatt (MW) subsea compressors will increase recovery by around 280 million barrels of oil equivalent, similar to the output from a medium-sized North Sea gas field.
Qualification testing began in 2005, followed by a lengthy testing programme at Statoil’s Kårstø laboratory facilities from 2008. Most recently, a water-filled test pit was built at the same laboratory to simulate subsea conditions.
The project is estimated to cost 15 billion Norwegian crowns (£1.5 billion), about the same price as a compressor on a new platform. However, a semisubmersible platform weighs in at around 30,000 tonnes, some five times more than the subsea compression station. It will also require far less energy to operate, 25MW compared with 41MW for a platform.
There will be no atmospheric emissions or discharges into the sea from the subsea station, further reducing its environmental footprint. Power-related annual CO2 emissions will be around 109,000 tonnes compared with 200,000 tonnes for a platform.
Furthermore, the subsea station will be safer as it is operated remotely and will not, like a surface platform, require a full-time on-board crew.
Technical barriers, the high capital cost and difficulties with integration into existing infrastructure have held back subsea production for years. Although the new technology has yet to earn the full confidence of operators, as Shell’s decision to postpone its Ormen Lange compression project demonstrates, the decision by Statoil to press ahead with a fully sanctioned, commercial project should set a valuable precedent.