From idea to reality: five years since the first subsea compression system

Five years after the kick off, the subsea compression system covering an area the size of a football field, at Equinor-operated Åsgard development in the Norwegian Sea, still runs like clockwork.

The entire Åsgard field is one of the largest developments on the Norwegian continental shelf, embracing a total of 63 production and injection wells drilled through 19 subsea templates.

In September 2015, Åsgard became the world’s first subsea gas compression operating facility.

Now, five years later, the technology from this project has become one of the most important measures for delivering volumes from existing fields on the NCS.

The Midgard and Mikkel gas reservoirs in the Åsgard field have been developed as subsea field installations. The wellstreams from both fields are sent in the same pipeline to the Åsgard B platform.

Analyses showed that by the end of 2015 the pressure in the reservoirs would have been too low to ensure stable flows and satisfactory production on the Åsgard B platform.

Therefore, compression was necessary to ensure high gas flows and recovery rates.

Specifically, the recovery rate has increased from 67 to 87 per cent for Midgard, and from 59 to 84 per cent for Mikkel.

This represents a combined total of 306 million barrels of oil equivalents, or an average Norwegian oil field.

The development of Åsgard subsea gas compression is one of the most demanding technology projects aimed at improving recovery.

The project started in 2005, and the plan for development and operation (PDO) was approved in 2012.

Many small and big suppliers have helped to develop the sophisticated underwater compressor system.

An estimated eleven million man-hours have been spent from the start until completion. More than 40 new technologies have been developed and employed after prior testing and verification.

Overall, project cost were just above NOK 19 billion, or $2.1 billion at today’s exchange rate.

Generally, compression plants are set up on platforms or onshore, however this one is located in 300 metres of water.

Also, a factory like this would normally require a lot of maintenance, and regularly be stopped for cleaning, but this was not an option for Åsgard.

Here everything had to run without stopping or the possibility of routine replacement of parts.

https://www.youtube.com/watch?v=Ew1h9aU4odo&feature=youtu.be

The Åsgard system consists of modules for two identical sets of compressors, pumps, scrubbers and coolers fitted together in an 1,800-metric ton steel frame, placed on the seabed close to the Midgard wellheads.

A dry gas compressor system is used on Åsgard. Gas and liquids are separated before boosting. The liquid is boosted by a pump and the gas by a compressor. After boosting, gas and liquids are mixed into the same pipeline before transport to Åsgard B.

The closer the compression is to the well, the higher the efficiency and production rates become.

By carrying out compression on the seabed, Equinor also achieved benefits in the form of improved energy efficiency.

Companies developing this technology claim that energy consumption of the subsea compression system is approximately 20 per cent lower over the lifecycle when looking only at compressor work, and up to 38 per cent lower when looking at overall energy consumption.

CO2 emissions from the subsea compression system is approximately 38 per cent lower over the lifecycle when looking only at compressor work, and up to 53 per cent lower when looking at overall CO2 emissions.

Norwegian engineering firm Aker Solutions delivered the world’s first subsea compression system for the Åsgard field.

The company won a contract in December 2010 to deliver the system. It took five years from the project’s start to first gas on September 17, 2015.

In addition to Aker Solutions, MAN, ABB and Technip (now TechnipFMC) played major roles in executing the project.

Aker Solutions continues to further improve future versions, to deliver slimmer and more cost-efficient solutions.

To that end, the company formed an alliance with MAN Energy Solutions in October 2015.

Aker Solutions is also exploring subsea compression in developing offshore CO2 enhanced oil recovery (EOR).

Using CO2 injection to increase recovery rates in offshore oil and gas fields can significantly improve its economics.

So far, the separation of ‘back-produced’ CO2 from the wellstream took place on an existing platform, adding cost and making the concept economically unattractive.

However, in November 2019, Aker Solutions together with energy companies Total, Pertamina, Equinor and industry group the CO2 Capture Project (CCP), initiated a Joint Industry Project (JIP) to identify required membrane qualities for a subsea gas and CO2 separation process, to minimize pre-treatment needs and avoid large processing modules.

Aker Solutions has developed new concepts for subsea processing of wellstreams from CO2-flooded oil fields, in which CO2-rich gas is separated, compressed and reinjected back into the reservoir.

According to the company, the subsea gas separation technology in combination with the subsea gas compression technology could make offshore handling of CO2 for EOR technically and economically attractive.

Going back to 2015, but one month after the Åsgard project, Equinor with partners Petoro and OMV, launched the world’s first wet gas compression on the seabed of the North Sea Gullfaks field.​

The technology should increase recovery by 22 million barrels of oil equivalent and extend plateau production by around two years from the Gullfaks South Brent reservoir.

Åsgard and Gullfaks projects represent two different technologies for maintaining production when the reservoir pressure drops after a certain time.

The advantage of a wet gas compressor is that it does not need gas and liquid separation before compression, thereby simplifying the system and requiring smaller modules and a simpler structure on the seabed.

https://www.youtube.com/watch?time_continue=2&v=vUOgK7xyqQ4&feature=emb_logo

The system, delivered by OneSubsea, consists of a 420-tonne protective structure, a compressor station with two five-megawatt compressors totalling 650 tonnes, and all equipment needed for power supply and system control on the platform.

Gullfaks C went through extensive preparations before the subsea compressor launch, including modifications and preparation of areas as well as installation of equipment.

In addition to Equinor, Shell also decided to go with subsea compression in the Norwegian Sea as a concept for the Ormen Lange Phase 3 to increase the recovery rate from the reservoir.

In November last year, OneSubsea, a division of Schlumberger, secured an engineering, procurement, construction and installation (EPCI) deal to supply a subsea multiphase compression system for the Ormen Lange field.

Through the EPCI contract, OneSubsea and its Subsea Integration Alliance partner Subsea 7 will supply and install the system.

The first phase of the project, will see the engineering and design of the complete system.

The complete EPCI scope should take place following the final investment decision by the license group.

The compression system will get power and control from the Nyhamna onshore gas processing plant, 120 kilometres from the subsea location.

This tieback distance is also a world record for transmitting variable speed power from an onshore facility to equipment on the seabed, the company said.

The system will sit 850 metres bellow water comprising two 16MW subsea compression stations tied into existing manifolds and pipelines.

Last year we also saw another subsea compression plan, but this time in Australia.

Aker Solutions landed a master contract to support subsea compression system delivery for the Chevron Australia-operated Jansz-Io field.

The first service order under the master contract will be for front-end engineering and design (FEED) of a subsea compression station that will boost the recovery of gas from the field.

The FEED scope will also cover an unmanned power and control floater, as well as overall field system engineering services. The field control station will distribute onshore power to the subsea compression station.

Compression will help maintain plateau gas production rates as reservoir pressure drops over time.

The Jansz-Io field is around 200 kilometres offshore the north-west coast of Western Australia at approximately 1,350 metres water depth. It is a part of the Chevron’s Gorgon Project, one of the world’s largest natural gas developments.

Australia will be the first place outside of Norway to use the subsea compression technology.