Deepwater E&P is expensive. Operators working in this environment are always looking for ways to minimize costs and accelerate production, and Statoil is no different from its peers. Where the company differentiates itself is in its willingness to invest heavily in technologies that will increase its ability to achieve these goals. One of its primary areas of interest is subsea systems, which according to Per Gerhard Grini, chief researcher — upstream process and flow assurance, has enormous potential.

From NCS to GoM

Statoil is looking into ways to transfer experience gained on the Norwegian Continental Shelf (NCS) to the deepwater Gulf of Mexico (GoM), where the company has a large portfolio of assets. “The Norwegian Shelf has been a very challenging area that has demanded technology advances step by step in order to develop the resources,” Grini said. “We pioneered the use of subsea wells, and today, only Petrobras has more subsea wells than us.”

The MAN compressor has been run at a test facility on Norway’s western coast for more than six months, and the technology is soon to be qualified to a level where it could be put into full field implementation. (Images courtesy of Statoil)

Statoil set the world record for subsea production directly from subsea to shore on Snøhvit where production travels 89 miles (143 km) through a 28-in. pipeline. Multiphase transport is routed directly into the LNG plant, which is the worlds’ northernmost and Europe’s only LNG plant.

Ormen Lange also has subsea wells produced directly to shore at Nyhamna 74.6 miles (120 km) away. “This field is special because the water depth is 850 m to 1,100 m (2,789 ft to 3,609 ft), and seafloor temperatures are below zero degrees C (32ºF),” he said.

Contending with freezing water that led to hydrates forming in the lines was a huge challenge. The result was to construct two 30-in. pipelines to shore so hydrate inhibitor could be added efficiently.

“One of our competitive advantages is that we have proprietary operational data from a large variety of multiphase lines,” Grini said. “We now operate more than 1,000 km (610 miles) of these flowlines. And we don’t intend to stop there. Our goal is to go to 200 km (122 miles) for oil-dominated multiphase flow and up to 500 km (305 miles) for gas condensate flow. Gas condensate flow is what we have on Snøhvit and Ormen Lange.”

Statoil set another world record at Tyrihans recently, where the company extended transport of oil-dominated multiphase flow to 26.7 miles (43 km).

“At Tyrihans, we also stretched the limits of direct electrical heating (DEH) on subsea pipelines,” Grini said. The oil is warm enough that DEH is not needed under regular operating conditions, but following a shutdown or at the end of field life, when flow decreases and the likelihood of hydrates increases, the technology will be critical.

Statoil believes there is huge potential for DEH. “We believe it can be extended to 100 km (61 miles),” which means the technology could be used in deepwater GoM applications to move production directly to shore.

Looking at the GoM, Grini sees enormous potential for subsea technology. Potential solutions would be to take subsea separation, liquid boosting, or possibly reinjection of produced water subsea. “This is something Statoil has done in the North Sea,” he said, “and these are ways we believe we could increase production from Gulf of Mexico deepwater fields. We need to search for technology to develop those assets cost-effectively.”

Statoil (and former Hydro) has spent more than a decade working with subsea separation and boosting systems offshore Norway.

In 1999, Hydro installed the Troll pilot, which was the world’s first subsea separation project. “On Tordis, this became a commercial application,” Grini said, with a capacity of 30,000 cm/d. What Statoil intended to do (and what worked for a month or so) was to reinject produced water into an aquifer.

“Unfortunately, the aquifer was not suited for reinjection of produced water,” Grini said, “but we proved the technology worked.” Today the Tordis unit is used to boost the wellstream. “We get operational time on it, and we qualified the technology, although we had to take the produced water back to the host platform, Gullfaks C, where the oil was to go.”

Statoil set the world record for subsea production directly from subsea to shore on Snøhvit, where production travels 89 miles (143 km) through a 28-in. pipeline to the LNG plant at Melkøya near Hammerfest in northern Norway.

The advantage of applying subsea separation technology is that it increases the recovery factor from 49% to 55%, Grini said, which is equal to 36 MMbbl of oil.

From an offshore GoM standpoint, 49% is an acceptable recovery factor, he said, “And this technology allows us to increase it substantially.”

This approach requires placement of a standard gravity separator on the seafloor. Though the technology is somewhat limited in its application, Grini said, it is perfectly applicable to 1,400 m (4,593 ft) water depth, which means there is significant opportunity in the GoM. The limitation, Grini explained, is the installation process, which becomes problematic at greater depth because of the weight of the system.

“We have two other technologies we’re working with at present,” Grini said. One is a pipe separator and the other is a compact separation unit.

According to Grini, the pipe separator technology, which Statoil has licensed to FMC, probably will be installed by Petrobras on the Marlim field. This installation will qualify the technology for future deepwater use.

Meanwhile, Statoil also is working via a joint industry project (JIP) with Chevron and Petrobras on a compact separation unit, which works on the principle of circulating the wellstream so the gases gather in the middle of the pipe and liquids on the outside. The unit being tested is from FMC subsidiary CDS, located in Holland. “Our goal is to qualify that complete system for gas-liquid separation in deep water,” Grini said.

The project currently is at medium-scale testing. “We’ve built it and installed it in a test facility, and we are hoping to have a medium-scale system qualified in 2012,” Grini said. “In pursuing our objectives jointly, we are likely to see success more quickly.

“Chevron operates quite a few Gulf of Mexico installations where we believe we could transplant a number of technologies from Norway,” he said. Statoil also recognized that some of its technology objectives coincided with those of Petrobras. “This particular JIP is operated by Statoil, but it is a very open environment where we share information with our two partners.”

Subsea compression

Statoil also is conducting research on subsea compression technology. This has huge potential, Grini said, but it is enormously challenging. No system of this type has been installed to date, but Statoil is working to change that.

“We have several developments for the subsea compression technology for application on the NCS,” Grini said, explaining that the technology qualification program began when Hydro was operator on Ormen Lange. The objective was to see if it would be possible to develop a huge subsea compressor that would replace a floating compression platform. This would be deployed at 2,789 ft (850 m) water depth, which represents a very challenging seafloor environment, with wind speed and wave heights compounding the challenge. Technology qualification is ongoing.

One of the potential solutions is a 12.5 MW compressor that is being supplied by GE Oil & Gas subsidiary Nuovo Pignone, with Aker Solutions acting as contractor for the rest of the system.

In principle, there are two types of compressors that can be used in this application, Grini said. “The most advanced system is to separate most of the liquid (that is pumped separately) from the gas and use a marinized version of a traditional compressor like we use on the platform. This allows high efficiency of compression but requires a complex system.”

The alternative, which is appropriate for smaller fields, is to use a smaller, slightly less efficient compressor that can take the full wellstream. “We are working with Framo on this one to apply a more simplified system,” he said.

There are several NCS fields that would benefit from subsea compression, but the varying field conditions prohibit application of the same technology across the board, Grini explained. For that reason, Statoil is investigating application of the Framo technology that uses a 4 MW compressor on the Gullfaks field, a 6-8 MW compressor from MAN or from Siemens for the Åsgard field, and a solution from Nuovo Pignone, a 13 MW unit, on Ormen Lange.

The Åsgard program is furthest along, Grini said. The MAN compressor has been run at a test facility on Norway’s western coast for more than six months, and the technology is soon to be qualified to a level where it could be put into full field implementation.

“We are working on a broad range of subsea processing and flow assurance technologies,” he said, “including subsea processing, subsea separation, subsea produced water injection, subsea pumping (which we have used for several years and consider qualified), subsea compression, and raw seawater injection.”

At Tyrihans this year, Statoil will install a very large system for raw seawater injection. Seawater is used on many locations on the NCS for pressure support. “Normally we take the oxygen out of the seawater before injection,” Grini explained. “Here we only have a coarse filter before the water is blown from the seafloor directly into the bottom of the reservoir. Two 2.7 MW liquid booster machines supplied by Aker Solutions will inject 14,000 cm/d of seawater a day to increase field recovery by 10%. I think we can claim that we will bring subsea processing technology a step further when we implement this solution.

“From a cost perspective and from an environmental perspective, it would be desirable to avoid hydraulically operated valves that require an umbilical to transport the fluid to the site. A better option would be to use electric valves instead of hydraulic valves, and that is a technology we’ve worked with FMC Kongsberg on. The all-electric tree design is planned for installation on Tyrihans, although the time frame is a bit uncertain. All of the systems are approved for safety at the same level as the hydraulic components,” Grini said. What remains is to carry out a field acceptance test.

Visions

Statoil will continue to invest in subsea development. “By 2030, we want to be able to use subsea systems to produce oil and gas in areas that are covered with ice either permanently or seasonally,” Grini said. “We would like to have flow assurance and multiphase flow technology qualified to a level that will allow fluids to be transported to shore from that subsea environment.”

The company also is working on technologies that will allow fluids to be transported in areas where hydrates form — called cold flow — in the export lines but remain transportable. “This is definitely not something we’ll do next year,” Grini said, “but we have a vision to find a way to allow hydrates to form but not stick to each other so they can be transported in the wellstream.”

Another far-off goal is to improve operations on typical subsea platforms. R&D will investigate ways to remove water from gas so the gas is not saturated and to remove water from oil to a level of less than 0.5% water in oil so sales-quality oil can be produced subsea.

“We have many dreams,” Grini said, “and we are investing and collaborating to realize them.”