This story was originally published in The Australian Pipeliner, October 2020.
For investors to approve the vast expenditure to build Australia's LNG projects fed by offshore gas, they needed confidence there would be enough gas for decades.
They then logically planned to develop the cheapest gas first.
Before the last project in the great LNG boom went into production – Shell’s Prelude floating LNG – the industry was busy moving to the next, more difficult, sources of gas.
In April 2018 Chevron committed about $5 billion to Gorgon Stage 2: the drilling of 11 new wells in the Gorgon and Jansz-Io fields.
Inpex is planning to install a 4000-tonne compression module on the Ichthys central processing platform to maintain flow as reservoir pressure declines.
Shell wants to bring gas from the Crux field to Prelude with an unmanned platform and a 165km pipeline, although the pandemic has put that development on hold.
Woodside is drilling the Julimar reservoir that will be tied back to existing subsea infrastructure that feeds the Wheatstone LNG plant.
In early 2019 Chevron engaged Aker to perform front end engineering to add subsea compression to the Jansz-Io field that feeds the Gorgon LNG project.
Aker had designed the first such system, for Equinor’s Asgard field offshore Norway in 2017.
Raw gas from the Asgard reservoir is cooled and separated into gas and liquid streams by machinery on the seabed. The two streams are compressed separately, recombined, and then has enough pressure to flow 40km to shore.
Chevron wants to avoid the expense of an offshore compression platform at its $US54 billion Gorgon project. Instead compressors on the seabed would be powered through subsea electrical cables from Barrow Island 130km away. A normally unmanned control station floating above the location of the compressors.
Such novelty and complexity is not only costly, it increases risk.
WA research to keep gas flowing
With so much money and technology being deployed to maintain the gas supply to LNG plants it makes sense that the west coast’s biggest operators are looking for cheaper, simpler solutions.
Dr Zachary Aman is the Chevron-Woodside chair in long subsea tiebacks at the University of Western Australia.
“Putting in massive subsea compression structures and sinking all of it to the seafloor…the cost of doing that is not necessarily going to be viable,” Aman said, particularly in the current oil and gas market.
The Centre he leads has the goal to enable gas to travel 250km using the natural energy of the reservoir.
It sounds simple, and it would be if not for a problem rarely encountered in onshore pipelines: gas hydrates.
When high pressure flow from a well in deep water is cooled by the surrounding seawater, that can be as cold as 4℃, the well fluids have the perfect condition for hydrates to form.
The water forms thin layers of ice that surround gas molecules but behaves somewhat like regular ice.
Aman said these molecular cages of water with gas inside start binding together to form particles that can range in size from the thickness of a human hair to a dice.
The hydrates build up in the wall of the pipeline and start to restrict flow.
The problem of hydrates is normally solved with the addition of antifreeze, usually methanol or mono ethylene glycol.
Unfortunately, while the additives stop hydrates forming they also drive up the pressure required to move the fluid in the pipeline and so reduce the distance gas can travel just driven by the pressure of the reservoir.
“Companies are up against a constraint where we can't put enough antifreeze in because in doing so, we burn the natural momentum energy of that reservoir," Aman said.
“Our group specifically studies the physics of where these hydrates form, how quickly they build-up, and what is their location on the pipe wall as a function of time, pressure and temperature."
And operators need the understand hydrates very well, as their behaviour can be unexpected.
Hydrate can completely block a pipeline for lengths up to 500m.
Aman said it is natural to think that is one side of the hydrate plug was depressurised the hydrates, that require high pressure and low temperatures, would gradually melt starting at the end with low pressure.
In fact, the whole plug melts from the wall inward, due to the thermal conductivity of the pipeline. Eventually the half kilometre long block of hydrate is no longer stuck to the pipeline wall and become a giant crystal bullet.
“These are the very infamous examples in North America where you've seen loss of life occur because these projectiles can accelerate up to 270 feet per second,” Aman said.
In late 2019 the Centre opened a laboratory where less dangerous scenarios, such as the effect that sand in the gas has on hydrate formation, can be investigated by the Centre’s staff and post-graduate students.
With Australian LNG facing fierce competition, such as huge low-cost developments in Qatar, technology will be key to keeping the LNG plants in WA and the Northern Territory supplied with gas and economically viable.
Main image: Wheatstone platform. Source: Chevron Australia Pty Ltd.