Partnerships and acquisitions are but one facet of the contractors' race to supply seabed separation, boosting and processing services. Materials science, marinization and redundancy also play a part in their efforts to make reliable seabed-to-shore systems a reality. Jennifer Pallanich looks over the latest subsea systems and controls offerings Aker Solutions, Cameron, FMC and GE have lined up.
The crux of the production equation comes down to how to extract more oil and gas from the reservoirs. 'Used to be, you drilled a subsea well, you put in a subsea system. The problem is, you produce it and then it just declines,' Sanjay Bhatia, director of planning and business development for FMC Technologies, says. 'Let's put some pumping and boosting down there so we can accelerate and get more production.'
Subsea processing covers five basic categories: the aforementioned boosting, as well as separation, seawater injection, compression and multiphase metering. Bhatia believes processing will be a key enabler in increasing reservoir recovery. That said, he adds: 'Customers have a way to go to figure out how they're going to use this technology.'
Safety is another reason operators are considering seabed processing. Analysis work to date suggests that 'from an HSE perspective, it will introduce very large benefits compared with a platform because you're removing the people,' says Svenn Ivar Fure, SVP for subsea products at Aker Solutions.
One of the big dreams is seabed-to-shore, and seabed processing plays a huge role in bringing that dream to reality. 'If you're going to eliminate the platform - and that's our long-term vision - you realize very quickly that there's going to be a lot of rotating equipment on the seabed,' points out Manuel Terranova, SVP global regions and sales - drilling & production for GE Oil & Gas. '[Aker/GE's] Blue C serves as a historic milestone in the elimination of the topside facilities.'
Fure believes subsea processing technology will be a 'prerequisite' to operating in Arctic conditions for several reasons: it will need to be reliable and to work all season without needing intervention work or repairs. 'That's the ultimate challenge,' he says. Additionally, the cost of using conventional solutions in an Arctic setting could be prohibitive compared to seabed technology, Fure adds.
Interest in subsea gas compression is emerging, a phenomenon that can be attributed to a landmark project like Ormen Lange planning to use the technology as well as the number of gas plays in Russian waters and the North Sea as well as offshore Australia.
Aker and GE are co-developing the Blue C subsea compressor for the Statoil-operated Ormen Lange field in the Norwegian Sea, with Aker developing the train and GE developing the compressor.
The Aker-designed train will test this fall with gas from the Ormen Lange field (see inset below). At that point, Fure says, the train will be qualified for subsea use.
Aker's station pilot
Statoil awarded the contract for a subsea compression station pilot to Aker Solutions in July 2006. The Ormen Lange project is intended to evaluate whether a subsea compression station, at 900m water depth, is a viable alternative to an offshore platform.
The Ormen Lange gas field, for which Norske Shell is the operator, started production in September 2007 and reached full production in November 2009. Later in the production phase, the challenge at Ormen Lange will be to boost the well stream to maintain production of gas and condensate from the reservoir. This is where a subsea compression station comes into the picture.
The subsea compression station pilot, currently being built at Aker Solutions' yard in Egersund, Norway, is identical to one of four trains on the proposed full-scale subsea compression station. The pilot train will measure 35m x 6.5m x 13m and weigh 1100t when assembled.
After assembly and testing in Egersund, the pilot will be transported to the Nyhamna onshore terminal, where it will undergo endurance testing in a purpose-built test pit.
The subsea compression station pilot train has a capacity of 15-20mmcm/d and a compressor shaft power of 12.5MW. A water system at the Nyhamna pit provides a continuous flow of seawater into and out of the test pit for cooling of the subsea equipment during operation.
The pilot will be operated with the real wellstream composition received from the Ormen Lange onshore facilities; the test facilities are equipped to emulate slug production, sand production and other operating conditions for the future Ormen Lange subsea compression station.
The process system is directly exposed to the wellstream, and the process equipment is designed to handle varying composition of unprocessed hydrocarbon gas and liquid, produced water, sand production and chemicals injected at the wellheads. The main design principle for the process system has been to include an inlet separator/slug catcher that protects the compressor against liquid and sand/fines that would lead to excessive wearing and reduced availability. The liquid and sand/fines removed in the separator is boosted by a variable speed driven centrifugal pump.
The process equipment and piping is arranged to avoid pockets/ dead legs and prevent build-up and clogging of solids in the liquid piping and ensure that any liquid condensation in the gas lines is sloped back to the separator vessel. The pump module is elevated below the separator module to satisfy the net positive suction head requirement.
Subsea mechanical connections and ROV operated isolation valves are included to allow for separate retrieval of the process modules.
The mechanical clamp connectors used are a variation of both single and multi bore types depending on the function and size of the connecting piping.
The arrangement of the power modules simplifies the interfaces between modules and reduces both cable lengths and high voltage electrical wet mate connections where possible. The arrangement of the high voltage wet mate connection mechanisms allows separate retrieval of each power module.
In May, the 12MW compressor for the Ormen Lange pilot has completed phase one of three test validation sessions at a GE facility in France, Terranova says.
The Ormen Lange pilot test, slated to begin 1H 2011, will run one to two years, and will cover different scenarios like different gas fractions and slugs. 'We'll throw everything at it to see how it performs,' Fure says. 'It will be a lot of fun for the engineers. They will love it.'
The train is scheduled for installation in 2014 in 1000m of water, but it still needs further testing and for the partners and operator to offer a final investment decision on the subsea compression scenario for Ormen Lange.
Other projects have been in the spotlight as well, including FMC's current seabed processing projects for Total's Pazflor development offshore Angola and Petrobras' Marlim field, offshore Brazil. For Total's Pazflor project offshore West Africa, FMC is providing gas and liquid separation with seabed boosting under a deal awarded in 2008. In addition to those, FMC has four other seabed processing projects on its CV: a water/ oil separator with sand handling and boosting for Statoil's Tordis project in the Norwegian North Sea, gas/liquid caisson separators with ESPs for Shell's BC-10 project offshore Brazil as well as Shell's Perdido project in the Gulf of Mexico, and horizontal ESPs on the seabed for Petrobras' Cascade-Chinook project in the Gulf of Mexico.
Tom Munkejord, director of process systems for FMC, sees the Marlim project as particularly important because of the field's heavy oil composition (see inset below). The project represents the first use of desanders and hydrocyclones on the seabed as well as the first time to inject clean water back into the reservoir. The project is calling for a lot of technology qualification work, he adds.
In 2009, FMC Technologies won a $90 million contract to provide subsea processing for Petrobras' Marlim field in the Santos Basin. The development of Marlim began in 1985. It is Brazil's largest offshore field, sprawling over 130km2. Today, FMC is designing and manufacturing innovative technologies to enable Petrobras to achieve its goal of maximizing production and recovery rates at this mature field. This includes delivery of a separation and sand management system that will use a novel pipe separator design, licensed and developed by FMC Technologies in cooperation with Statoil.
Marlim is the sixth subsea processing project awarded to FMC Technologies since 2005 and it will achieve a number of milestones for both FMC and the oil and gas industry, including the first:
The whole project has a tight execution schedule as well, with a target installation in August 2011. 'Marlim is not seen as a pilot. Marlim is rather seen as a first commercial application in a heavy oil brownfield project,' Munkejord says.
Looking at the next generation of subsea processing, Munkejord expects to see a focus on water polishing, water treatment and separation of heavy oil.
A matter of size
Cameron believes its approach to seabed separation makes it a more elegant and installable solution than the 'macro' systems that weigh in at 1000 tons. 'These are very large systems that aren't really installation friendly,' says David Morgan, Cameron's subsea division general manager. 'Our approach to separation is a compact approach.'
John Byeseda, senior principal engineer, subsea processing in Cameron's subsea division, calls compact separation a key to subsea separation and processing. Gary Sams, Cameron's process systems division director of R&D for oil and water, says one of the not-sosecret secrets of downsizing the kit is: 'The more cyclonic spin we can put in, the smaller we can get. Up to a point.' Sams expects more units in the future will rely on cyclonics.
Electrostatics is another means of separation; in this case, high voltage forces water to coalesce from oil. The Cameron compact solution uses both methods.
Cameron's micro-approach is a 200 ton two-phase separator. It is designed for 10,000ft water depth and 10,000psi shut-in pressure and uses ESPs or mudline based pumps.
Cameron estimates a unit could be ready for delivery within 18 months to two years after receiving an order. 'We're at a point now where we think this is proven technology,' Morgan says, noting the system draws almost completely on pre-qualified technology. It uses CameronDC power - which was the first all-electric sybsea tree control system - for the controls. 'The controls respond much more quickly, helping us to manage the liquids in the system,' Morgan observes.
The next step is a target application, Morgan says. The subsea systems are 'all fingerprinted to a specific reservoir,' so it makes no sense to build from spec, he says. 'You really need the support of the customer. We've done as much development as we can.'
Morgan says Cameron is 'seeing the industry more interested in two-phase (separation) at the moment. From a commercial perspective, we're most likely going to see two-phase tested and employed before we see a lot of threephase separation.'
And then there's the fourth phase, Sams notes. 'It's going to become more important in subsea separation and processing as well. People are going to produce solids,' he says. Byeseda adds: 'It's troublesome topside, and it's even more so on the seabed.' Cameron's Natco and Petreco product lines have technology for solids removal and processing.
Separation is a technology Cameron feels it can shine in (see inset below); in Morgan's words: 'We know how to marinize this technology.'
A prototype of the Compact Electrostatic Separator Plus sits in Cameron's newly opened $14 million technology center, part of the processing division, in Houston.
'We started with a vertical vessel,' Gary Sams, Cameron's process systems division of R&D for oil & water, says. The system relies on electrostatic processes that grow water droplets in the electrostatic field and separate them out as efficiently as possible. The upright vessel, he says, had great coalescence, but a low efficiency. Now, the vessel sits at an angle, and the insides have been simplified. 'As complicated as this looks, the process is really dirt simple,' Sams says. To date, Cameron has been issued one patent on the design and has two patents pending.
It has a 90% separation efficiency, Sams says, capable of taking a 30% water cut down to 3% as the stream moves through two vessels. 'Just the cyclonics by themselves give us almost 60% reduction,' Sams adds. Part of what makes the electrostatic system work so well is that it can rapidly separate water from the other phases. But making it happen efficiently was a bit tricky, Sams says. When water is coalesced in an electrostatic field and then removed from the electrostatic field, he says, the water decoalesces. It is necessary, he adds, to separate the water from the other phases while it's still in an electrostatic field. 'Once we understood that concept, the rest of the technology fell into place,' Sams says.
As of early June, two units were on their way to Brazil for Petrobras, which has participated in the joint development project. The Petrobras threshold was 15% water cut. 'Most of the time when we're running this, we're under 10%,' Sams says.
The units will first be used onshore for testing before Petrobras moves them to an offshore facility for debottlenecking.
Not only is Cameron investing in R&D internally for all-electric systems like CameronDC, communications systems, flowline connectors and HIPPS (high integrity pressure protection system), the company has been snapping up other companies that offer unique or niche technologies for subsea processing, such as the 2004 purchase of Petreco and the 2009 purchase of Natco. 'Their suite of technology is going to help us in the subsea processing arena as well,' Morgan says.
Other acquisitions include access to flowline access technology via the purchase of DES Operations in Aberdeen. DES's patented MARS (Multiple Application Re-injection System) allows connectivity of a variety of subsea processing modules via existing subsea chokes in either the trees or manifolds. Cameron says the advantage of this technology is it does not disrupt the existing seabed equipment to connect these subsea processing modules into the field, which saves both lost production and construction vessel cost.
FMC sees boosting 'as a strategic element for us', Munkejord says. For boosting, FMC teamed up with Swiss pump specialists Sulzer, a collaboration since 2007 to develop a world-class subsea pump by combining the best pump and motor packaged for subsea boosting applications, according to the company.
Reliability is job number one
Establishing subsea reliability rests on the cornerstones of robust systems tested to perform well beyond the capacity they would be tasked with in real life, along with backups, Fure says. 'Predictive maintenance' akin to that used in the aviation industry has potential in the subsea industry, he adds.
For instance, he says, monitoring systems can detect vibrations or shaking or noise. 'Usually none of these installations makes a lot of noise, so if you have microphones there, you can monitor it.'
Morgan believes customers would like to see more subsea processing equipment used 'so they can get a flavor for the reliability of the equipment.' For now, Morgan says, reliability means a unit can work reliably at least four or five years subsea before needing maintenance. 'To do that, you're going to have to prove this technology in that environment, and that is just now starting to be done,' Morgan says.
Long-term reliability, Terranova believes, requires expertise in materials sciences. 'That's a highly specialized domain,' he says. In the world of materials sciences, that means coatings, composites, ceramics, specialty material welding, nanotechnology and advanced manufacturing techniqes, he says. GE has applied this approach in other industries and is now applying it to subsea kit, particularly boosting, processing and compression, he says (see inset below).
Because obsolescence is a major challenge for the industry, GE Oil & Gas' Manuel Terranova, SVP for global regions and sales - drilling & production says, GE decided to shift from proprietary controls to open standards for its subsea communication system. GE was recognized with one of Offshore Technology Conference's coveted Spotlight of New Technology spots for its SemStar5, which is the first subsea control system that relies on open standards for hardware and software. Terranova believes this new design alone vaulted GE from being a number three or four player in the subsea control market to number one.
The SemStar5 is in production, with a dozen already built; Statoil is the launch customer and has 88 units on order for the Tordis-Vigdis development. The order represents the largest subsea retrofit program and replaces controls that are 15 to 18 years old.
The SemStar5 is based on a common Ethernet with a Unix platform and a star-based topology. It has remote monitoring diagnostics capability. 'We designed it to be a computer on a network which can be looked at from anywhere in the world,' Terranova says. It can generate more data on the seabed for compression or separation, he says.
'Remote monitoring diagnostics is the way of the future.'
A big boost
All systems require pumps. As Morgan puts it: 'It's all about the pump.' Cameron has teamed up with Curtiss-Wright EMD, a business unit of Curtiss-Wright Flow Control and Leistritz for multiphase pumping solutions. Curtiss-Wright integrates its high-power, harsh environment canned-motors with Leistritz heavy-duty twin-screw multiphase pumps, and Cameron integrates the motor-pump assembly with its subsea products into an offshore system. Cameron says the joint venture with Curtiss-Wright also brings high power electrical distribution expertise for its separation and pumping systems.
In 2003, FMC bought CDS, which supplied separation products, and recently acquired motor specialists Direct Drive Systems, known for its permanent magnetic motors. 'DDS brings in a good motor that we can latch onto the pumps,' Bhatia says. Brad Beitler, VP of technology at FMC, expands on this: 'They're compact, and they're efficient.'
'I think the rotating equipment piece of this will be the spearhead into the processing field as this matures,' Terranova says. Twin-screw technology - the SUV of the pumping segment - will play its role, he believes.
Processing is going to require more power consumption on the seabed. 'If the long-term vision is to eliminate the platform on the surface, you've got to have the power grid topologies on the seabed,' Terranova says. 'Transformers, switch gear, all the things you'd see in a powerplant substation. It's got to be on the seabed, and it's got to last.'
Any subsea power solution will likely rely on specialty materials for reliability in the power connection points because 'seawater and power don't mix', Terranova says. GE is investigating AC, DC and hybrid AC/DC solutions.
'Aker Solutions is taking a system approach to power supply, distribution and conversion on the seafloor. We see great benefits by working together with the key power engineering suppliers to marry their power technology with our subsea engineering and marinization technology,' Fure says.
Instrumentation is another component that requires some thought. Bhatia notes FMC is focusing on building up the instrumentation. Instrumentation will allow for measurement of critical flow elements, including flow-rates, pressure, temperature, equipment condition and other factors that allow the operator to enhance operations and increase production and recoveries.
Finally, without controls systems, there is no subsea processing. 'You need the communications to be real-time and available on demand. If you don't have a control system, you can't produce hydrocarbons. It's that binary,' Terranova says.
The slow uptake of the subsea processing market has been a bit discouraging, Morgan says. For example, it was a hot topic when oil was first in the $80/bbl range, but when the price collapsed in 2008, fewer companies were talking about subsea processing.
'But we've seen a real increase in interest in the last four or five months as the price of oil settles down around $70-$80/bbl.' OE