Norway’s Seabed Separation says simple is the best way to go by exploiting an understanding of the well stream. Elaine Maslin reports.
Image from iStock.
Seabed Separation’s technology is a dual pipe separator (DPS) system, using multiple inclined pipes, with piping inside, to separate water from oil. Removing water from the well stream subsea means (if it can be re-injected or disposed of out to sea) increased production, fewer topsides facilities requirements and less subsea infrastructure and chemical injection, as the water no longer needs to be brought to surface and treated.
Asle Hovda, Seabed Separation’s CEO, says that by using many small separation pipes, instead of one large pressure vessel, you get over issues with water depth (and vessels so big they cannot be built or are impractical to handle).
The DPS can be flexible during field life – it could be used in series or parallel, and pipes can be added or removed. It would weigh less than a traditional gravity separator (by more than 75%, the firm estimates), cost less, and would reduce seafloor pumping requirements.
The idea is aimed at brownfield projects, to debottleneck topsides, or as an enabler for greenfield subsea projects. It could even be used as part of a so-called cold flow system, a concept popular around 2010.
The technology is based on an idea developed by Otto Skovholt in the late 1990s. In 2014, Skovholt conducted initial testing at the Institute for Energy Technology, outside Oslo, and received positive feedback from operators. Proventure, a Norwegian private equity firm, came onboard in 2015 and, together with business people in Trondheim, launched Seabed Separation (which now has support from Lundin, Aker BP (previously Det Norske) and public funding) to commercialize the concept.
In 2015-2016, a low-pressure full scale test pilot was designed and built and completed six weeks of testing at Sintef’s Multiphase Lab, with better than expected results. In February 2017, building of a full scale, high-pressure (100 bar) pilot unit was completed. It is installed in Statoil’s Porsgrunn (or P-Lab) test facility, south of Oslo, and will be used to verify the low-pressure test system, using real hydrocarbons and sea water. Testing, which was due to start on 18 April, will run into June and will help define the process operating envelope for as many different scenarios as they can throw at it.
“Our plan is to have the DPS unit available for commercial piloting mid-2018 for land operations,” Hovda says. “Soon after that we will have a unit available for offshore operations in the North Sea.”
The system isn’t just pipes, of course. First, where there’s gas, the free gas is stripped from the well stream. Then, the fluids go through an inlet arrangement, which slows down the fluids. Then, the fluids go into an inner closed end pipe. The internal pipe has outlets (perforations) through which the water drops out and down to an outlet at the bottom of the outer pipe, and the oil rises up and out through an outlet at the top of the outer pipe.
The inner pipe outlets would be arranged according to the application. By using pipe instead of a large separator, the water doesn’t have as far to go to drop out, the firm says. As the heavier water resists rising up, the oil travels over the top of it faster, says Jon Sigurd Berntsen, the firm’s chief technology officer. Sand could be flushed out through a dedicated sand flushing pipe. The pipes can be arranged in series or parallel, according to need for flow capacity and/or quality.
An indicative size topside facility is for 60,000 b/d (without gas) measuring 4 x 8m, 6 x 8m with a gas system. Its dry weight would be 11-tonne and operating weight 15-tonne (compared with 60-tonne dry weight for a standard topside separation vessel), with limited need for instrumentation and control, pumps or alarms, Hovda adds.
Berntsen, who has some 35 years’ experience working with produced water, says part of the job has been to work with operators to understand what is happening in their pipelines and separation systems to develop a correct methodology.
The firm’s goal is to achieve separated water clean enough to be discharged subsea – the Holy Grail. But, Berntsen admits, this will probably not be one step. But, because the water has been separated subsea, it no longer becomes a flow assurance issue, which means hydrate inhibitors wouldn’t need to be used.
Berntsen says that it is actually easier to separate water closer to the wellhead because, in most cases, there the water is more “pristine,” i.e. it hasn’t started to form an emulsion with the oil and other components.
“This is nothing new, it’s just applying knowledge and technology in the correct sequence, with no spinning,” Berntsen says.
Source: Seabed Separation