While it offers a theoretically coherent concept, subsea processing can seem fragmented. Elaine Maslin spoke to Intecsea about how the company views the broader picture.
Statoil’s Åsgard project. Image from Aker Solutions.
Huge strides have been made in the subsea processing arena in the past year: subsea compression, both dry and wet gas, was achieved on Statoil’s Åsgard and Gullfaks projects, respectively, offshore Norway late 2015.
Subsea processing has been high on the agenda for a number of years, spurred on by deepwater prospects, the potential for longer subsea tiebacks and even developments in Arctic waters.
Yet, despite the gains made, progress has not been as fast and widely spread as many have wanted or expected, and there are still technology gaps, ranging from water treatment and chemical injection facilities to subsea power distribution.
Work continues, however, in spite of 18-months of across-the-board budget cuts, and technology developers are working to fill the gaps. The pace might be slower, but this might work out for the better, suggests Larry Forster, technology specialist for deepwater oil and gas, Intecsea, Houston. There has also been a shift in greater interest from greenfield projects to brownfield projects driven by the current market conditions, he says, which could make deployment easier.
“In a higher oil price environment, the emphasis is on getting production online quickly and implementing whatever technology is available, within reason,” Forster says. “Now, the smart money is on taking a step back and looking for better solutions so that when the oil price returns, they have the right solutions.”Yes, projects are being challenged, he says. But there are some operators taking a step back and taking a long-term view, in which subsea processing plays a big role. And it’s not all big players, he says.
The Åsgard subsea compression template. Photo from Statoil/by Øyvind Hagen.
An increasing focus for subsea processing, given the current market environment, is in brownfield modifications, where there is an opportunity to increase production, but also where there is a lack of space or power on existing topsides facilities. By marinizing water treatment, chemical injection, pumps, power distribution, separation, etc., you no longer need space topside for these components, says David McLaurin, subsea engineer, Intecsea, Houston.
Statoil’s Gullfaks subsea wet gas compression project offshore Norway, for which OneSubsea produced a wet gas compressor, is a good example, Forster says. “This wet gas compressor went in relatively late in the life of the field,” Forster says. “It serves a cluster of fields in the area. That compressor is expected to increase recovery by 22 MMboe and extend plateau production by about two years. There is an upfront investment, and additional cost to install and maintain equipment, but the prize is substantial.”
However, there are hurdles. The first is having available infrastructure to support additional processing capabilities. On Gullfaks this was possible. However, Intecsea is working with a client who would like to add boosting to an existing facility, but it doesn’t have the power or space to support the new equipment. The next hurdle is the fact that there are still many pieces of the subsea processing puzzle to be completed, not least raw sea water treatment.
Subsea water treatment
A Gullfaks compressor station, ahead of installation last year. Photo from OneSubsea.
Subsea water treatment, for sea water injection, is a goal for the industry. “If you could install a module, which treats sea water subsea and uses a single phase booster pump to feed an injection well, you would no longer need topsides facility modification, or a major shut down during construction,” Forster says. You would also no longer need the flowlines usually required. “Water treatment is the key,” McLaurin says. “But, it requires chemicals and filters and you need to keep up all that equipment. So, there are some reliability concerns and qualification is 4-8 years down the road.”
“A lot of details are involved, getting the chemicals for treated water just right, even if it is going straight back into the reservoir,” Forster adds. “It might be that the reservoir is sensitive to salinity or other components that didn’t get removed, which could cause problems. Both treatment and monitoring, to make sure the chemistry is right, need some ongoing work.”
For produced water, which you might want to treat and reinject, the chemistry is even more difficult, as it has hydrocarbons in it. “An even longer term goal is to be able to release treated produced water directly to the sea in vicinity of subsea wells and that’s going to be very sensitive to a lot of things,” Forster says. “You are going to have to make sure you do that right.”
Due to the environment they are in, deepwater subsea wells require various chemicals. “The first challenge is the cold ambient sea water temperature, so there is a chance produced oil and gas with water in it will cool and hydrates could form,” Forster says. To prevent hydrates, methanol and monoethylene glycol are often used. Then there’s wax formation, which needs to be mitigated, in addition to corrosion, scale and aspheltene inhibition requirements.
Typically, people look to topsides for chemical storage and for pumping and distribution, using a steel tube umbilical to get the chemical to the well. For long-distance tiebacks, alternatives are being looked at, such as having a subsea module and storage on the seabed with a distribution network and pumps. “To qualify a subsea chemical injection system, qualifying subsea chemical pumps will be a big challenge,” McLaurin says. “When they are topside, we know they have about a two-year design life and we can replace them. Subsea, it’s an intervention problem. Also, there is the chemical replacement problem.” You could size storage tanks to reduce the number of times you have to restock them, but that’s another expenditure and space requirement that wasn’t there before, he adds.
“An alternative to chemical injection, however, could be electrical heating for flowlines and other flow components in the system,” Forster says. “If you can keep the flow path above a certain temperature, you reduce and maybe even eliminate the need for hydrate inhibitors.”
McLaurin says trace heating, which has already been deployed and is in use, seems to be the way flowline heating is moving, because it is more efficient. The alternative is the “direct” method, where you put heat into the flowline, using the flowline as the resistive current path.
Joining the dots
But, enabling subsea processing is far from being about the individual parts of the system. For subsea processing to work, the complex sub-systems need to be able to work as part of a whole.
“It is a bit of a paradox,” Forster says. “Whereas introducing subsea processing equipment is introducing complexity to the system, the challenge is getting the system out there and simplifying the packaging and design so that the interfaces between components can be standardized and consistent. Then if you want to add a module, you just add it. Ideally, you would be able to pick this module from any vendor and be confident it can plug and play.” How the systems are supported, in terms of subsea robotics, is also changing. While the industry would now struggle without remotely operated vehicles (ROVs), autonomous underwater vehicles (AUVs) are starting to appear like they will play an increasing role, and potentially move toward being resident in the subsea environment, instead of being deployed from a vessel.
Of course, with those subsea vehicles, along with the increasing array of sensors and the data they produce, big data is entering the fray and it is perhaps perfect timing. This not only involves getting the appropriate sensors marinized and on the subsea equipment, but also getting the data back to the host facility and beyond and then being able to make use of that data.
“The more sophisticated controls systems are making that easier to do, getting the right information from the subsea system. Then, a significant area of development is having the software to interpret it and make use of it in real-time,” Forster says. “Many operators are making some really good in-roads in this new data arena.” But, it’s a big job and there are obstacles, ranging from initially overwhelming operators with information to bringing in software applications, such as surveillance by exception. “The software can process the data process just enough so that the situations, which need human attention are identified and displayed. It’s the first step–and it’s the tip of the iceberg,” Forster says.
“For deepwater fields that are very concentrated, cost intensive and prolific, it only makes sense to echo investment in the field with comparable investment in managing the information that comes out of it. It is not a debate.”
Get kit wet
While the orders might not yet be flooding in for new subsea processing systems, there is still interest and ongoing work. Indeed, McLaurin points out: “It is interesting how, when the sector sees a downturn, unlike other industries, it enables research and development in this type of equipment.”
For Forster, who worked on deepwater technology with Shell before joining Intecsea, new technology needs to be exposed to field conditions as soon as possible to help get future development, however. “There are projects going in now where the requirements are not as severe as the deeper fields, so go ahead and install more sophisticated technology to aid research and development when you’re not so exposed in the event of a failure, because it’s relatively easy to replace components with simpler options if you encounter problems.”
NEL, near Glasgow in the UK, has been leading research in subsea separation and production water re-injection or discharge and has an ongoing joint industry project to develop subsea water quality measurement devices up to technology readiness level five, which would be a key enabler.
Subsea separation itself also not new. It was first tried on the Troll Pilot (Statoil), then first used in anger on the Tordis field offshore Norway in 2003-7, followed by Pazflor (Total), Marlim (Petrobras), and Perdido – Great White and BC10 (Shell). A Marlim 2 is in study phase, but on the “backburner.” Indeed, on Tordis and Marlim separated water is also then re-injected and sand dealt with through handling and then re-injection, all subsea, using FMC Technologies’ equipment.