Getting to the bottom of it

Groundbreaking technology is boosting recovery from the Åsgard area of the Norwegian Sea by 306 million barrels of oil equivalent (boe). It also opens new opportunities for other fields.

| Arnt Even Bøe

Illustration: Aker Solutions

Illustration: Aker Solutions


Injecting water and/or gas can improve recovery from an oil reservoir along with drilling a lot of production wells, but has little to offer when draining gas fields.

The challenge with these is usually found in the seabed pipelines. When reservoir pressure sinks, multiphase flow problems rise as gas and liquids are piped to a processing facility.

That could also have been the case with the wellstreams from the Midgard and Mikkel deposits, which lie 40 and 60 kilometres respectively from the Åsgard gas process platform.

The longer the pipeline, the greater the friction to be overcome. More and more of the liquid fractions separated out and accumulated in the lowest sections as natural pressure declined.

As space in the flowlines contracted, the gas increased its speed and drove slugs of liquid ahead of it. These arrived at the Åsgard B process floater as a series of sharp jolts.

The platform had not been designed to handle such loads. Unless the problem was overcome, gas production would have had to be reduced and eventually discontinued.

This was why operator Statoil decided, with the other licensees, to initiate what would prove its most demanding-ever technology project for improved recovery. The outcome is the world’s first subsea wet gas compression facility.


Not new

The challenges of piping wellstreams over long distances are not new. An old and widely used solution has been to boost such multiphase flow with the aid of compressors.

That is done by building a separate platform to support traditional compressors or to install such machinery on an existing topside.

Statoil decided that compression was also the answer for boosting recovery from Midgard and Mikkel, and began planning this around 2004.

“The natural starting point would have been another traditional compressor platform,” acknowledges project director Torstein Vinterstø at the operator company.

“But the more we thought about subsea compression, the more fascinated we became. A compressor is also more effective the closer it is to the reservoir.

“That means the seabed is basically a perfect site for it. Once the challenge of keeping out the seawater has been solved, the machine can work in a stable and protected environment.”



“When we began thinking along these lines, we adopted a completely innovative approach,” says Vinterstø, who has worked on Åsgard subsea compression since planning began in the early 1990s.

“To ensure maximum uptime for the seabed equipment, it had to be as simple as possible. We wanted to avoid traditional solutions with motor cooling and separate lubrication for the bearings.

“The first of these was eliminated by using the gas to cool the electric motors, while we wanted to replace ordinary ball bearings with magnets which allowed the shaft to turn freely. Nothing like that had been done before in this setting.”

After four years on the drawing board, a full-scale model of the new compressor system began undergoing tests in the K-Lab at the Kårstø process plant north of Stavanger during 2008.

The gas mix, the water temperature and the other parameters were as close as possible to real conditions on the bed of the Norwegian Sea.

A key question was whether gas from the reservoir had the right temperature to cool the motors adequately. Another was to see if the lubrication-free magnet technology – which gave the crankshaft a clearance of one millimetre – would work.

The licensees for the Ormen Lange field, also in the Norwegian Sea, launched their own pilot project for subsea compression with Aker around 2006.

Development of these two systems then progressed more or less in parallel. After Statoil and Hydro merged in 2007, closer collaboration was established between the projects.


Big savings. “The price of a similar installation as new can be driven sharply down,” says project director Torstein Vinterstø in Statoil.

Big savings.
“The price of a similar installation as new can be driven sharply down,” says project director Torstein Vinterstø in Statoil.



Test results for the Åsgard system were very encouraging. After 3 500 hours, the world’s first subsea gas compression facility was ready to be compared with a conventional platform concept.

The conclusion was that it would be the most profitable and climate-friendly solution, and an amended plan for operation and development (PDO) of Åsgard subsea compression was prepared.

This was submitted to the Ministry of Petroleum and Energy in August 2011. By then, more than 40 new technological inventions had been implemented during the course of the project.

When the Storting (parliament) finally gave a green light for the pilot project in March 2012, time was at a premium if a shutdown of Midgard and Mikkel was to be avoided.

Such a halt would have been very unfavourable, not only because of delayed revenues and possible restart problems but also with regard to the quality of Åsgard B’s deliveries.

This platform pipes a blend of various gas types from all the reservoirs in the area for optimisation at Kårstø plant before being transported on to Europe.

A key consideration in this context is that the relatively high carbon content in gas from the other fields can be offset by mixing with the low-carbon output from Midgard and Mikkel.

Without their production, a separator like the ones on Sleipner and Snøhvit might be needed to strip CO2 from Åsgard gas. So getting the compression unit on stream was a matter of urgency.

An engineering, procurement and construction (EPC) contract was awarded to Aker Solutions, while MAN supplied compressors with the new cooling technology and magnetic bearings.

Nexans delivered a total of 160 kilometres of power cables and Technip was responsible for most of the marine installation work, including all the modules for the compressor station.

This facility was completed in time to prevent any halt to production from Åsgard, and the world’s first subsea wet gas compression unit could come on line on 16 October 2015.



“We were obviously on tenterhooks,” admits Vinterstø. “We as operator, the other licensees and the suppliers naturally wondered whether this would work after all the time, all the millions, all the energy and not least all the prestige we’d put into it.”

Today, after a year of operation, the facility is running like clockwork and has had almost 100 per cent uptime. Energy consumption – and thereby carbon emissions – has been halved compared with the platform concept.

This innovative technology has improved recovery from 67 to 87 per cent for Midgard and 59 to 84 per cent for Mikkel. That adds up to 306 million boe – or a mediumsized Norwegian oil field.

When director general Bente Nyland presented the Åsgard licence with the NPD’s IOR prize at this year’s ONS oil show, she praised its willingness to accept risk and think innovatively at every level.

Vinterstø highlights collaboration between the licensees. The technical committee held monthly meetings, achieving a very good dialogue, while the project team received full backing.

He also commends the suppliers for the purposeful way they worked, for their willingness to take new approaches and for their ability to execute the work.



“The sense of urgency and the technological challenges meant we were four-five months late and roughly NOK 2 billion above the PDO cost estimate of NOK 16.9 billion,” reports Vinterstø.

“That was because we costed the project in the depths of the financial crisis around 2009, when prices were low, and started procurement when oil prices had shot up – and costs with them.

“The good news, though, is that the installation itself is profitable even today when the price of crude has slumped.”

This is confirmed by Halvor Engebretsen, operations vice president for Åsgard, who notes that production rose by just over 16 million boe in the first year after the facility came on line.

At current prices, that represents an added value of well over NOK 5 billion for these 12 months.



Subsea wet gas compression is one of the most radical innovation projects in Statoil’s history. The technology represents a quantum leap, bringing the company a step closer to a “seabed factory”.

This concept involves establishing processing facilities which make it possible to conduct hydrocarbon transport by remote control.

The compression template stands on Midgard, about 40 kilometres from Åsgard B, so the Mikkel wellstream must travel some 20 kilometres before getting a new boost.

This means that installing another template on the latter field could improve recovery even further.



Vinterstø also explains that the experience gained by Statoil through the Åsgard project can be used to simplify and standardise future installations. This could substantially reduce investment for new fields.

He adds that the first user of new technology incurs costs which the next can avoid, such as spending on technology development, testing, installation tools and maintenance on land.

That creates new opportunities for major fields on the NCS, such as Troll, Ormen Lange and Snøhvit.

“Åsgard also taught us that it’s very important to make provision for future compression in new field developments if a possible future IOR solution exists.

“A modest facilitation of this kind could significantly reduce the cost of implementing future subsea compression projects.”


"The Åsgard subsea compressor is the result of enthusiastic engineers, ambitious leadership, a long-term strategic approach and the stamina needed to follow through."


Proud prizewinners. From left: Fredrik Sønstabø (ExxonMobil), Halvor Engebretsen (Statoil), Gunnar Einang (Total), director general Bente Nyland, Erling Bergerød (Petoro) and Vidar Kråkenes (Eni). Photo: ONS.

Proud prizewinners.
From left: Fredrik Sønstabø (ExxonMobil), Halvor Engebretsen (Statoil), Gunnar Einang (Total), director general Bente Nyland, Erling Bergerød (Petoro) and Vidar Kråkenes (Eni).
Photo: ONS.


This conclusion was drawn by director general Bente Nyland when she awarded the NPD’s prize for improved oil recovery (IOR) in 2016. The ceremony took place at the ONS oil show in August.

She emphasised that the interaction demonstrated by the licensees in this project was perhaps especially important in today’s demanding position for the industry.

“So is keeping world-class, dynamic engineering clusters. My message is: make sure you don’t cut so much that it becomes impossible for Norway’s oil and gas industry to continue making world-class technology advances.”

Nyland said the NPD would challenge more players to achieve such a collaboration.

The Åsgard subsea compression technology not only represents an important contribution to improving recovery from that field, but also provides opportunities to recover more oil and gas from other reservoirs on the NCS.

Subsea processing – and wet gas compression in particular – could make it easier to develop discoveries in deep water and in areas far from existing infrastructure.

In a comment on the prize, Nyland pointed out that recovering all commercial resources is part of the each licensee’s work commitment.

“That naturally involves risk, and we therefore acclaim technology development and pilot projects.

“When we see that these succeed, as has been the case with Åsgard, we must recognise the inventiveness and boldness displayed by the companies. They have taken an investment risk, and can now reap the reward.”

She said that such a project would have been more difficult to launch with today’s cost and oil price regime. “At the same time, this shows that the profitability of a field is determined when it ceases production, and not by current oil and gas prices.”

The government has also contributed through its support for basic research and the backing provided in the early 2000s for testing subsea compression by the Demo 2000 programme.

This scheme is intended to help reduce costs and risk for the petroleum industry in achieving the commercialisation of new technology.


Answers on the hoof
Aker Solutions had to accept binding contracts for the Åsgard compressor project despite a string of unanswered questions. “We were clearly on tenterhooks,” says project director Øystein Haukvik.

Øystein Haukvik, project director, Aker Solutions. (Photo: Aker Solutions)

Øystein Haukvik,
project director,
Aker Solutions.
(Photo: Aker Solutions)

The company was given responsibility in December 2010 for all engineering, procurement and construction (EPC) covering the subsea manifold and compressor station.

Everything in this groundbreaking job was bigger than usual, and new technology had to be developed on the hoof to implement it.

Keeping the number of operational shutdowns to a minimum was crucial for making the concept – a world first – competitive with platform-based compression.

“Operator Statoil set extremely tough requirements for this installation, with an uptime of almost 100 per cent,” reports Haukvik.

“It also had to have a high flow capacity and be efficient and flexible. That called for extensive use of advanced pipe connections, high-voltage connectors and fibre optics.”

In his view, developing new control system units which could give the earliest possible warning that something was wrong represented the most demanding single part of the project.

Magnetic bearings and gas cooling had never been tried on the seabed before, either. “Things could quickly pile up here if we made a misstep.”

Haukvik adds that this project was unquestionably one of the most challenging assignments the people in his team had worked on.

“Subsea compression also undoubtedly represented one of the most demanding assignments our company has pursued in the field of technological development.

“It was a relief along the way to see how good and effective the collaboration became between us, Statoil, other contractors and suppliers large and small.”

He is particularly complimentary about MAN, which had the job of qualifying a new type of compressor capable of working effectively on the seabed.

Although Statoil had done a lot of good preliminary work, an installation of this size had never been built before – and it was also required to stand in several hundred metres of water.

“But MAN did a great job, and must get its share of the acclaim for Åsgard’s success,” affirms Haukvik, who also highlights the collaboration with installer Technip.

This aimed to ensure that the individual modules could be positioned without damage and efficiently hooked up during the complex offshore installation process.

Immediately after the completion of the Åsgard project, Aker Solutions formed an alliance with MAN Diesel & Turbo to develop the next generation of subsea compressor systems.

The aim is to cut the size and weight of such facilities by 50 per cent, thereby sharply reducing their price and enhancing the competitiveness of this technology in stormy waters far from land.



Squeezed for time
Subsea compression on Åsgard became a struggle against the clock and for the future, with quality as the input factor. The results exceeded all expectations for partner Total Norge.

Gunnar Einang, asset manager, partneroperated assets and development studies, Total Norge.

Gunnar Einang,
asset manager,
partneroperated assets and development studies,
Total Norge.

The position of the Midgard and Mikkel gas fields in 2005 was quite simply that production would cease in May 2011 unless something was done.

One problem was that a well on Midgard had been shut down after water intrusion. At the same time, problems would arise as natural reservoir pressure fell.

Simulations showed that water, condensate and antifreeze in the wellstreams would then separate out and form powerful slugs which the process system on Åsgard B could not handle.

A permanent shutdown of these two fields in 2011 would leave recoverable reserves exceeding 300 million barrels of oil equivalent (boe) behind.

None of the licensees were interested in such an outcome. So these companies had less than six years to come up with a solution.

“Statoil was operator for both fields and very technology-oriented,” says Gunnar Einang, asset manager for partner- operated assets and development studies at Total Norge.

“It wanted to challenge a new compressor platform for Åsgard by developing the world’s first subsea gas compression facility. The other partners liked this aggressive approach and agreed.”

“As we saw it, the challenge was to secure the time needed to develop and test the new technology,” explains petroleum architect Johnny Kolnes at the French oil company.

“One move was testing with reduced production on Åsgard to see when  the problems would arise. After several trials, we could postpone the start of unstable production until around 2014.”

Another step to buy time was to bring the small nearby Yttergryta field on stream. This supplemented flow in the pipeline system, and pushed the deadline further forward.

But development time was still short, and the investment was heavy. Total Norge devoted a lot of time and effort to entrenching the project properly at its Paris head office.

“Our bosses were well aware that this was groundbreaking work and involved great technological and economic risk,” says Einang. “Our contribution wasn’t small change.

“On the other hand, top management also saw the opportunities such a technological breakthrough could bring, both on the NCS and in our other international offshore projects.

“We can say now that Åsgard subsea compression is established as an important step towards the goal all oil companies dream of – moving offshore activity from the surface to the seabed.”

Both he and Kolnes praise Statoil for being technology-driven in its search for new solutions, and give the company most of the honour for the innovation on Åsgard.

They also highlight a good and open collaboration in the licences, and suppliers who were positive and willing to make a commitment.

“With the new compression facility in place, wellstreams have increased sharply and made a big contribution to producing the volumes we risked losing,” says Kolnes.

“Costs ended up a good deal higher than the original estimates, but it’s not unusual for the bill to be fairly high in this type of pilot project,” adds Einang.

“Given the experience and knowledge which have been gained in this phase, the price tag can undoubtedly be driven down in subsequent projects.

“Following up this success isn’t so easy right now, with today’s low oil prices. But it’ll come. The best guarantee of this is that the facility has been operational for more than a year, virtually without a stop.

“That’s payback for the decision taken by the project to make a commitment to quality at all levels from day one. Statoil again deserves praise here for its role as a driving force.”



Lifting with success
French group Technip developed new technology through its involvement in Åsgard subsea compression. “That strengthens our position in the market,” affirms project director Sven Guderud.

Sven Guderud, project director, Technip.

Sven Guderud,
project director,

One job pursued on Åsgard by this company, which does field development and marine installation work worldwide, was to convert the existing seabed infrastructure.

That would allow the new compressor system to be connected without interrupting production – normally a standard operation. But complexity and volumes were much greater than usual.

“The assignment was very dynamic, with a great many people involved,” says Guderud. “Thanks to good collaboration with Statoil, however, we managed to avoid shutting down Åsgard.”

Lifting the equipment into place from the North Sea Giant subsea construction vessel and assembling the modules on the seabed presented the biggest challenge.

This operation was very delicate, with demanding tolerances, sensitive equipment and limited space in the module frame. Careful planning and close cooperation were essential.

The most demanding aspect of such work is eliminating vertical motion by the modules during their installation in the seabed template. Too much movement can damage expensive equipment.

“Given Statoil’s demanding requirements for uptime, we’ve had to develop a new lifting concept which allows us to replace modules in greater wave heights than normal,” explains Guderud.

That was accomplished in collaboration with Norway’s Axtech company in Molde, which has a reputation as a world leader for this type of lifting and modulehandling system.

The result was a new crane type able to work in significant wave heights up to 4.5 metres. In practice, modules on the subsea installation can thereby be replaced in virtually any weather.

This means in turn that the vessel can lift out and remove a defective module before replacing it without affecting the target of virtually 100-per-cent regularity.

“Personally, I found it both fun and exciting to be part of such successful teamwork,” says Guderud. “However, this pioneering project has not been entirely without challenges.

“These demanded both more time and greater resources, but that’s forgotten now. The equipment plays an important part in Statoil’s vision of a subsea factory, which we hope will materialise in the future.”



Big dimensions. The subsea compressor station on Åsgard is the size of a football pitch. (Photo: Statoil/Øyvind Hagen)

Big dimensions.
The subsea compressor station on Åsgard is the size of a football pitch.
(Photo: Statoil/Øyvind Hagen)


Technologically demanding

A number of oil companies have long been seeking to establish new remote-controlled subsea solutions in order to improve recovery from oil and gas fields.

In the mid-1990s, Shell and Statoil installed multiphase pumping and metering stations on Draugen in the Norwegian Sea and Lufeng on the Chinese continental shelf respectively.

And Norsk Hydro initiated a pilot project on Troll in the Norwegian North Sea in 2001 for seabed separation of gas and water, with the latter injected into the Utsira aquifer.

The world’s first full-scale facility for separating water and sand from a wellstream was installed on Norway’s Tordis field in the North Sea around 2007.

Two years later, a seabed pump for injecting seawater into the subsurface became operational on the Tyrihans field in the Norwegian Sea.

A subsea compression station started up on Gullfaks in the North Sea about the same time as the Åsgard facility, but has failed to function as intended and is currently off line.

Parallel with the Åsgard project, development began for subsea wet gas compression on the Ormen Lange gas field in the Norwegian Sea. However, this work has been suspended since 2014.



Statoil (operator) 34.57 per cent, Petoro 35.69, Eni Norge 14.28, Total 7.68 and ExxonMobil 7.24. Åsgard lies on the Halten Bank in the Norwegian Sea, about 200 kilometres off Trøndelag and 50 kilometres south of Heidrun.

Surface facilities comprise the Åsgard A oil production ship, the Åsgard B gas production floater and the Åsgard C storage ship for condensate.

In addition to Mikkel, two fields in other licences – Yttergryta and Morvin – are tied back to Åsgard’s infrastructure. Both are Statoil-operated.

The subsea compression facility on Åsgard is the size of a football pitch and handles gas produced from 2 500 metres beneath the seabed.

Measuring 74 x 45 x 26 metres, the template weighs 1 800 tonnes and comprises two parallel process trains. It was installed in 300 metres of water during the summer of 2013.

Each compressor train consists of 11 modules containing pumps, scrubber and cooler, weighs 1 500 tonnes and was installed in the spring of 2015.

The compressors are powered by submarine cables from Åsgard A and have an output of 11.5 MW. A third train is held in reserve on land.


The saga of Åsgard


The story of one of the biggest and most complex field developments on the NCS began when Saga Petroleum discovered Midgard in 1981. Statoil found Smørbukk in 1984 and Smørbukk South a year later in the same area. That initiated a lengthy process to get the three discoveries on stream.


Precision: A module is moved with Åsgard A in the background. (Photo: Statoil/Øyvind Hagen)

A module is moved with Åsgard A in the background.
(Photo: Statoil/Øyvind Hagen)


By 1994, the two Norwegian oil companies had each spent hundreds of millions of kroner in seeking to realise these proven assets on the Halten Bank in the Norwegian Sea.

Saga’s dilemma was that it could not progress with Midgard until a market for its gas was found. But buyers would not commit themselves without serious development plans, including a transport infrastructure.

That was easier said than done at a time when Statoil and Norsk Hydro had fields with much spare gas in the North Sea, where a pipeline network to continental Europe already existed.

Statoil’s starting point was that Smørbukk and Smørbukk South, which contained oil, condensate and gas, could be developed as a single unit.

Its problem was simply that these reservoirs were among the most complex on the NCS, with unusually high pressure and temperature. The challenge was to find a development concept which was both safe and sufficiently profitable.



The solution was found at the traditional garden party thrown by Statoil at its head office during the 1994 ONS oil show in Stavanger. After working for a long time on the Smørbukk challenges, the state-owned oil company had detected signs that private-sector Saga could be interested in a collaboration.

Following introductory drinks at the party, Statoil vice president Kyrre Nese invited Lars Bjerke, Saga’s head of exploration and development, up to his office.

Nese’s starting point was that Midgard lacked sufficient gas for a stand-alone development, and had a hand-written outline proposal with him.

He and Bjerke draw up two new outlines, and suddenly saw a solution. Two months later, a collaboration deal on developing the three fields was ready and the Åsgard project was born.

The big challenge was naturally the division of roles. Statoil became the formal operator for Åsgard, with Saga in a new role as deputy operator.

To get the collaboration accepted, moreover Saga had to be compensated with the operatorship for the Varg field in the North Sea.



Åsgard has represented very special challenges right from the start for its licensees and the supplies sector, with the unitisation process one of the most complex on the NCS.

The next step was to plan an offshore development which still ranked among the most complicated projects of its kind in the world.

After 16 months, it became clear that this would embrace the world’s largest oil production ship (Åsgard A), its biggest floating gas process platform (Åsgard B), and the Åsgard C storage ship.

These facilities supported the world’s largest and most complex subsea development, with 17 seabed templates and 59 wells over a radius of 50 kilometres.

Other elements included the Åsgard Transport gas pipeline to Kårstø north of Stavanger, an expansion of the latter and the Europipe II gas pipeline from there to Dornum in Germany.

Costed at NOK 47 billion, this development on the Halten Bank set new standards for subsea technology and was characterised by records and technological breakthroughs.

Another key element was the spirit created by Norsok, a collaboration between government, oil companies and suppliers to cut time taken and costs on the NCS by about 50 per cent.

This giant project was the first of its size in deep water off Norway, and marked in practice the end of the Norwegian Contractors concrete platform saga at Hinnavågen in Stavanger.

The Heidrun floater was Norway’s 18th and last concrete and steel structure when it was towed to the field in 1995. Subsea solutions combined with ships or semi-submersibles then took over.



In April 1999, it became clear that the Åsgard project would overrun the original cost estimate by NOK 17 billion. Acting petroleum minister Anne Enger Lahnstein was not amused.

When she carpeted Statoil chair Kjell O Kran to explain, he was unapologetic beyond admitting at a pinch that the enhanced bill was “unfortunate”.

He and the rest of the board were dismissed and chief executive Harald Norvik saw no other option but to resign as well along with his deputy, Terje Vareberg.

Norvik had replaced Statoil’s first CEO, Arve Johnsen, after the Mongstad scandal in 1988, but – unlike his predecessor – was careful to keep the directors informed about the rising costs.

Before his resignation, Norvik had unexpectedly called for the part-privatisation of the state oil company. This proposal came in January 1999 at a prestigious annual oil conference outside Oslo.

The Ministry of Petroleum and Energy was not pleased, and its relations with the Statoil management were still icy when the Åsgard overrun emerged.

Oil production from Åsgard A began shortly after the dramatic events in Statoil, on 19 May 1999. Processing of gas and condensate on Åsgard B started on 1 October 2000.


Gods and humans

In Norse mythology, Åsgard (or Asgard) was the home of the Æsir or gods. Bounded by thick walls, it lay in the centre of Midgard – Middle Earth – so that humans would not feel alone or abandoned.

Midgard was surrounded in turn by massive defences against the wild, unknown and fearsome giants and trolls outside. Beyond that again lay the world ocean, home of the Midgard serpent.

Clearly, these myths are readily transferrable to the Halten Bank in such terms as dimensions and the concern with safety. Heads undoubtedly rolled in Norse mythology too.

But the comparison between the Åsgard legends and today’s world breaks down over creativity and the ability to think along new lines. That is a human attribute.