Chevron looks to new subsea compression technology for Gorgon

Chevron may boost gas production from its Jansz-Io field to Gorogn LNG with subsea compression technology used just once before in Norway.

Chevron looks to new subsea compression technology for Gorgon

This story was originally published in The West Australian on 21 August 2017 with the headline "New subsea tech plan to feed Gorgon LNG plant." © Peter Milne.

Chevron is considering using a radical new technology known as subsea compression to keep gas flowing to the Gorgon LNG project and avoid a multibillion-dollar offshore structure.

Two giant gas fields, Gorgon and Jansz, feed the 15.6 million tonne-a-year Gorgon LNG plant and the domestic gas plant on Barrow Island.

The pressure in the reservoirs drives the gas to the island but ongoing production drops the pressure and eventually the gas must be compressed to keep the operation at full capacity.

The favoured option had been a semi-submersible compression platform. Gas from the Jansz wells would have flowed to a giant floating structure weighing up to 20,000 tonnes anchored in 1km of water. There it would be compressed and returned to the existing subsea pipeline headed to Barrow Island.

Industry sources said that late last month Chevron and its partners switched focus to compressing the gas on the seabed using electrically driven compressors powered from Barrow Island, 130km away. Work on the semi-submersible by WorleyParsons in Perth has been suspended while subsea compression is investigated.

Subsea compression has worked in the Statoil-operated Asgard field off Norway since 2015. Norwegian engineering company Aker Solutions led the development of the technology for the 67 per cent state-owned oil and gas producer.

WestBusiness understands that Gorgon will also use Aker for the study of subsea compression. ExxonMobil, which owns 25 per cent of Gorgon, is familiar with the Aker technology as it also has a 7 per cent interest in Asgard.

The equipment on the seabed, 260m below the surface of the North Sea, is complicated. The raw gas from the wells is cooled, separated into gas and liquid streams that are compressed and pumped respectively, then the gas is cooled, combined with the liquids and flowed through a 40km pipeline.

Poten & Partners upstream and LNG adviser Will Pulsford said reliability was the biggest concern with subsea compression. He said the equipment on a semi-submersible had workers to maintain it, but access to equipment on the seabed was more challenging.

Statoil manager technology management Simon Davies said at the AOG conference in Perth in February that the benefits of subsea compression increased with water depth and distance the gas had to move.

The ability of subsea compression to make extracting gas from deep and distant wells cheaper has applications for Chevron in Australia well beyond the Jansz field.

Chevron subsea factory champion Mark Wagstaff, also speaking at the AOG conference, said the company had launched an initiative that aimed to increase recovery of oil and gas by 20 per cent and reduce capital costs by 25 per cent.

It is believed the Gorgon joint venturers planned to select a Jansz compression solution in the first quarter of next year and commence front-end engineering and design in late 2018.

A Chevron spokesman said ongoing work to maintain gas supply to Gorgon had been anticipated. “This includes additional wells, subsea infrastructure and compression facilities at the existing Gorgon and Jansz-Io fields,” he said.

Main image: Woodside headquarters Mia Yellagonga in Perth. Source: Chevron Australia Pty Ltd