Hydrogen focus for net zero moonshot

Jason Crusan left a role at the US agency tasked with returning humans to the moon to take on a mission in Perth he hoped would solve a big problem here on earth.

At the National Aeronautics and Space Administration (NASA), Mr Crusan had been director of human exploration and operations at the advanced exploration systems division.

In that position, he led the development of the Project Artemis program, which plans to put humans back on the moon by 2025, 56 years after Neil Armstrong set foot on it.

In March 2019, Mr Crusan moved to Perth to become Woodside Petroleum’s vice-president of technology, where he is at the vanguard of efforts to create a green hydrogen industry.

Speaking to Business News, Mr Crusan said he was excited to be working on the energy transition.

“It is rewarding,” he said.

“I have a 16-year-old daughter and 12-year-old son; their dad had worked for NASA their entire lives.

“It’s an interesting perspective when you have children of that age, who question everything their parents do.

“It’s rewarding to explain to them and be pretty proud of what you do.”

Mr Crusan spent 14 years at NASA, after studying physics, electrical engineering, and computer science.

“I’ve been a technical geek most of my life,” Mr Crusan said.

“I’m a very mission-driven kind of person.”

But after working with three different presidential administrations and pushing forward the Artemis program, he wanted to return to his passion in technology and strategy.

The jobs at NASA and at Woodside have more similarities than initially apparent.

“At its heart, what NASA is really good at is systems engineering or systems thinking,” Mr Crusan said.

“NASA does a lot of work where we have a set of technologies we’ve been working on; we have a mission … nobody’s ever done it before.

“You have to design all the pieces and parts, how they’ll work together to get from here to there.

“That’s systems engineering.

“How do we solve [the] energy transition? 

“From an engineer’s point of view, it’s how do we put together renewable energy, electrolysis, transportation systems, storage systems, and liquefaction systems? It’s a systems-engineering problem again.”

An example of this thinking was Woodside’s collaboration with Californian business Heliogen, which is developing solar thermal technology to provide consistent power to the grid.

That technology could eventually be used for hydrogen production in Australia.

Powering ahead

Woodside added to the growing list of proposed hydrogen projects in Western Australia with its October announcement of H2Perth, to be built near Rockingham.

The project will be developed in phases, with stage one to produce 300 tonnes of hydrogen a day.

Two thirds of that will be through steam reformation of natural gas, making blue hydrogen, using about 40 terajoules of gas a day, roughly 4 per cent of WA’s domestic supply.

The remaining third will be green hydrogen produced through electrolysis driven by power from the state’s main South West electricity grid.

Woodside’s plan could be the firmest export scale project proposed in WA so far.

BP undertook a feasibility study on a potential green hydrogen project near Geraldton and declared it technically feasible but warned the economics would not yet stack up. 

A proposal by Intercontinental Energy to build a major renewable powered ammonia project in the Pilbara also hit a wall, with federal regulators concerned by the impact on a protected wetland.

The same business proposed an even larger project near Esperance.

Intercontinental is yet to get a project under way.

The state government has been pushing a renewable hydrogen development at Oakajee, running an expressions of interest program starting in 2020.

Woodside may have the upper hand getting a project across the line because of its experience developing LNG projects such as Pluto and the North West Shelf Venture, a sizable balance sheet, and ongoing cash flow.

“We have an ability for large-scale capital projects, and complex projects, they have long-term payback cycles,” Mr Crusan said.

“Designing and operating facilities and sets of contract arrangements that last 20 to 30 years is the bread and butter of what the LNG industry is.”

He said the company had sought advantaged locations to build the facility to help reduce costs, because it was economically challenging for customers to pay a premium for a lower carbon hydrogen product.

The H2Perth location has some advantages over the Mid West, including existing infrastructure to lower capital costs.

“You start drawing a series of Venn diagrams over each other,” Mr Crusan said.

“Where is existing infrastructure like ports, like a highly qualified skilled workforce, electricity grids and electricity infrastructure in general, roads, gas pipelines, water access?

“If you can lower the number of things you need to build … you lower your barrier to entry and in essence you lower your cost and make that product more affordable for your customer.

“Eventually places like the Mid West and others will also be very good places.

“But if you want to move quickly into the market and start doing something now, do you wait for the time it takes to build the infrastructure, and the cost that goes with that?

“Or do you start doing something now to help build the demand with those customers switching demand?”

A similar process led to Bells Bay in Tasmania being chosen by Woodside for a green ammonia development with IHI Corporation and Marubeni Corporation.

Bells also has port access and is connected to a grid powered largely by renewables, including wind and hydroelectric.

In WA, about 42 per cent of electricity dispatched through the South West Interconnected System in October was generated by coal, with 34 per cent by gas.

There’s also an increasing level of rooftop solar power in the system.

The Australian Energy Market Operator has warned rooftop solar will produce so much electricity by 2024 that demand on the network may fall below safe operational levels.

That has led Synergy to develop plans for construction of a $155 million battery in Kwinana, to help stabilise the grid, and work by utilities such as Western Power to encourage flexible demand sources that switch on when there is excess power supply. 

Woodside’s hydrogen plant will be in a central location in the SWIS grid and will be able to flexibly draw power to balance the grid.

It’s a service the state government has been willing to pay for through programs such as the 100 Megawatt Challenge.

Mr Crusan said grid stability problems were getting worse, particularly as the level of rooftop solar increased.

H2Perth would use electricity to run electrolysers, which split water into oxygen and hydrogen, for the hydrogen to then be exported or piped elsewhere.

Given Woodside’s electrolysers would have a capacity of 250MW in the first stage of the development, H2Perth would be the single biggest load source on the SWIS network, he said.

“We can actually act as that buffer,” Mr Crusan said.

“Although it is not technically a battery, it provides the same role in stabilisation; it helps smooth the variability in the network.

“We’re that variable load, we can deal with that intermittency.

“Our electrolysis can go up and down, that’s how it’s designed.”

The flexibility to absorb excess electricity would help support more renewables on the network.

Here, Woodside has big plans.

Construction of phase one could get under way in 2024, pending a final investment decision.

H2Perth will be designed to be modular, like a data centre, with capacity expansions added gradually, in contrast to the very large upfront investment commitments of LNG projects.

Ultimately, the facility is intended to produce 1,500 tonnes of hydrogen a day.

There will be options every three years to increase the size of the plant over a 10-to-12-year period, with the final scale to be about 3.25 gigawatts.

To draw that much power, Woodside would need to enable more than 6GW of renewable capacity, Mr Crusan said, which could be done through power purchasing agreements or through the company originating its own.

That would roughly double the capacity of the SWIS network.

There has been criticism about H2Perth’s environmental impact, however, because steam reformation of methane produces carbon, and coal contributes substantially to the SWIS grid.

Mr Crusan said 100 per cent of carbon dioxide emissions created by the project would be offset or would displace industrial CO2 use by others in the Kwinana precinct.

Blue hydrogen capacity would not expand after stage one.

“We add no more gas beyond the 40 terajoules we start with; all future growth is electrolysis based,” he said.

“The reason we do that at the beginning is, how do you get the material scale that a customer needs, say, in Japan?

“They need a large-scale ammonia offtake or liquid hydrogen offtake to justify the building of the ships to ship it.

“You can’t take months and months and months to fill a ship.

“You need to get a big enough size so you can fill a ship in a reasonable amount of time [and] that you can supply a reasonable enough volume for them to consume, say at a power plant.”

Right now, green hydrogen is about three to four times more expensive than gas-based hydrogen production, he said, so using blue hydrogen helped bring down costs while the market evolved.

The other environmental consideration is that export-scale hydrogen production could also displace coal use in trading partners.

Japanese customers were slowly increasing ammonia use to reduce coal at their power stations.

In May, JERA, which is jointly owned by Tokyo Electric Power Company and Chubu Electric Power, said it would work with IHI Corporation to demonstrate ammonia co-firing at a major power station in Japan.

“Notably, this is the world’s first demonstration project in which a large amount of ammonia will be co-fired in a large-scale commercial coal-fired power plant,” the companies said in an announcement.

The demonstration project will run four years to 2025.

Mr Crusan said Japanese customers were active in converting coal boilers, some of which had a long lifespan ahead.

Global momentum

The Economist recently reported that more than 350 large-scale hydrogen projects had been announced globally, which are expected to receive $500 billion in public and private funding through 2030.

Perth-based Fortescue Metals Group chair Andrew Forrest has been playing a major role in this development.

In the past 18 months, Mr Forrest has signed deals to explore the development of hydrogen projects including in Jordan, Papua New Guinea, New Zealand, and India.

The biggest was with the Democratic Republic of Congo, where the Grand Inga Dam development could cost as much as $100 billion. 

In Australia, he has proposed an electrolyser manufacturing centre in Gladstone, Queensland, and a green ammonia plant with Incitec Pivot.

The federal government has also sought to support hydrogen uptake, with $1.2 billion promised for programs including seven hydrogen hubs.

Research by Wood Mackenzie estimated green hydrogen costs for delivery into Northeast Asia from Australia would almost halve to about $US3 a kilogram by 2030.

“While current costs of green hydrogen production are typically more than three times higher than those of blue hydrogen, green hydrogen costs are expected to fall as electrolyser manufacturing technology improves and renewable electricity costs decline,” the research house said. 

The research note said nearly 60 per cent of proposed green hydrogen export projects were in the Middle East and Australia, and that there had been a 50-fold increase in announced projects globally over 12 months.

Wood Mackenzie forecast global demand for hydrogen to increase between two and sixfold by 2050, depending on carbon policies.

It could reach as much as 530 million tonnes annually by 2050, with about 150mtpa traded on the seaborne market.

WA will be competing with other Australian states, the Middle East, and South America for that market.

The research suggested Australia would be slightly cheaper than Middle Eastern exporters shipping to Northeast Asia, and close in cost to South American producers.