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Decarbonising hydrocarbons: emission impossible?

Image credit: Equinor/Statoil

All eyes are on oil and gas companies to cut down on emissions. Will they rise to the occasion?

Decarbonising hydrocarbon production might sound like a contradiction, but we still rely on a significant amount of it: 45 per cent of the UK’s energy needs came from North Sea oil and gas in 2019 and then there’s petrochemical use. Major efforts are under way to reduce that reliance, but also to reduce the carbon intensity of the stuff we still use. It’s a big task, especially for an industry where 40 per cent of its offshore facilities and a quarter of its pipelines were installed more than 30 years ago.

The numbers are large. Of the estimated 18 million tonnes of CO2 equivalent (MtCO2e) emitted by industry in 2018, 14.6MtCO2e (79 per cent) were emitted at these offshore installations, mostly from gas turbines used for local power and heat generation, but also from flaring, venting and leaks. A further 14 per cent came from onshore terminals, 5 per cent from logistics (e.g. shipping) and 2 per cent from aviation – the way offshore workers get to work.

Collectively, the industry has agreed, via trade body Oil & Gas UK, to halve these numbers by 2030 and reach net zero by 2050, to align with UK government targets. Many also have individual targets or ambitions – although they differ in their ‘Scope’. Some companies are going for Scope 1, direct emissions from operations, others Scope 2 as well, i.e. indirect emissions, and a few also Scope 3, which is those from the product when it’s used.

They have a number of options, some more realistic than others, ranging from relatively simple process upgrades and optimisation to electrification, integration with offshore wind farms, carbon capture and storage (CCS) and hydrogen production.

The quickest Scope 1 win is reducing emissions from existing operations, through operational improvement, says Vysus Group principal consultant Ian Thomas. “On older assets, quick wins include changing out pumps for new more efficient pumps, but also better calibration, better measurement and monitoring, management, maintenance and optimisation,” he says. “It’s looking at the system, going for the biggest items first then working down the list, using something like the ISO 50001 energy management system.”

That’s only going to do so much, which is why many are looking at electrifying offshore facilities, so that they no longer have to run those highly emissive gas turbines for their heat and power.

Industry regulator the Oil & Gas Authority (OGA) has been promoting collaboration in this space and it’s attracting interest. Major operators Shell, Total and BP have been looking at electrifying a cluster of existing platforms in the central North Sea. BP is also looking at the potential for a new facility at its Clair field, west of Shetland, to be electrified.

Electrification could be done a number of ways: by installing a cable from land (UK or Norway, which can be closer to some UK North Sea fields) out to platforms; by tapping into an interconnector; by tapping a nearby wind farm, if there is one; or by building a new offshore wind farm. It’s not unprecedented. Norway has been electrifying platforms for a number of years. There, CO2 prices are high, hydropower from onshore is cheap and abundant, and policy has pushed electrification.

Electrification isn’t cheap. It would cost about £1.1bn to electrify a cluster of fields with a 200MW power demand, says the Closing the Gap report, published in 2020 by OGTC. The further offshore a platform is, the higher the cost will be, as subsea power cables cost £1-2m/km. Retail electricity prices in the UK are also high, at £117/MWh, and a large chunk of it is still produced by burning gas.

Electrifying an existing platform would also be akin to “performing open-heart surgery”, Shell’s UK upstream vice president has said. That’s in part due to how platform design has integrated the use of gas turbines and heat recovery, which is required for many processes.

Low carbon

Subsea factory

Subsea factories, where all-electric process equipment is on the seabed and remotely operated, could help produce low-carbon oil and gas. It’s not that far-fetched – many of the building blocks exist and are operating subsea today, from electric actuators to fully electric compressors. Subsea power-distribution equipment has also been qualified by ABB and Siemens. “If we can do everything (hydrocarbon extraction related) subsea and it’s all electrified that would allow oil and gas to continue operating in a sustainable way,” says Kristina Beadle, research analyst at Wood Mackenzie.

Connecting platforms with an offshore wind farm could be a neat solution. Norwegian operator Equinor is installing a floating offshore wind farm near its Gullfaks and Snorre platforms to reduce gas turbine reliance. With £40/MWh wholesale prices, you could cut emissions and help reduce costs, says Martin Tulloch, head of energy system integration at the Oil & Gas Technology Centre, a tech accelerator.

To do this in the UK will require co-operation between industries and quite a bit of policy and regulation to be resolved, says Will Webster, energy policy manager at trade body Oil & Gas UK. There are already challenges around getting offshore wind power ashore, let alone to other users and then enabling the frameworks to allow that need to be resolved.

The OGA says it is working on these areas with other regulators as well as those who consent wind farms, Ofgem, etc., to understand just how joint wind power-oil and gas schemes could work, and not least how they could be consented in a timeframe that can have a meaningful impact.

While electrification deals with the CO2 emitted offshore, it doesn’t deal with the emissions created when oil and gas come onshore. “You can reduce your Scope 1 and Scope 2 emissions, but you are unlikely to get net negative by doing that and ultimately net negative is what they need to do to offset the Scope 3 emissions,” says Kristina Beadle, research analyst, carbon research, at Wood Mackenzie. “So, for Scope 3 you are looking at bigger carbon capture and storage initiatives and removing CO2 from the atmosphere.” It could also mean having more renewable energy in a portfolio or investing in direct air capture technology.

Another option is to produce hydrogen with the natural gas and burn that instead, producing only water as a by-product. Some 95 per cent of today’s commercially produced hydrogen is made by steam-methane reforming, using natural gas feedstock (known as grey hydrogen). This process emits CO2, at about 8-10kg per kilogram of hydrogen, says the Closing the Gap report. With carbon capture that can be reduced by up to 95 per cent, making it a cleaner option, known as blue hydrogen, compared with burning natural gas. These options also do not come cheap.

Nevertheless, industry interest in hydrogen and CCS projects has increased vastly in the past year and the government’s recent ‘Ten Point Plan for a Green Industrial Revolution’ has also given some high-level support to these ideas. The plan includes 5GW of low-carbon hydrogen production by 2030 and the UK becoming a leader in CCS technology.

The Acorn project in Scotland aims to address both challenges. Its main goal is commercialising CCS, but it’s also working on blue hydrogen production. Some 30 per cent of the gas produced in the UK North Sea comes onshore at St Fergus, north of Aberdeen, points out Alan Booth, a director at Pale Blue Dot, which is leading the Acorn project. Some of it is burned in a power station, where the project partners hope to capture the CO2 emitted and then send it offshore to be stored underground. But some could also be converted to hydrogen and put into the national gas grid.

“None of that is particularly difficult from a technology perspective,” says Booth. At the moment, up to 2 per cent of hydrogen can be put into the national gas grid and up to 20 per cent is possible without major modifications, he says. More than that would require a wholescale change-out of boilers among other things.

The bigger goal is CCS and Acorn hopes to have the first CO2 going offshore late 2024/early 2025, says Booth. The project, supported by oil firms Shell, Chrysaor and Total, is one of a number that hope to gather CO2 from industrial areas for transport offshore and storage underground offshore. Another project, announced in October and backed by BP, ENI, Equinor, the National Grid, Shell and Total, is looking to provide CO2 transport and storage infrastructure off north-east England.

There is an estimated 78,000MtCO2 storage potential in the UK, of which 8,000MtCO2 is in depleted oil and gas fields, according to the Global CCS Institute. This could store UK CO2 but also be a store for emissions from neighbouring European countries. Webster says the oil and gas industry has the expertise for CCS. “It’s managing big projects, pipelines, valves, compressors, moving gases around, management of the subsurface,” he says.

“The main challenges of CCS are cost and how do we get ourselves to a place where it’s an economic proposition to capture CO2, transport it to St Fergus and send it offshore,” says Booth. “At the moment it’s not economic with a carbon price of €20 (£18) per tonne when it costs potentially €60-70/t to dispose of it.” A scheme in Norway, Northern Lights, is under way, but has been heavily government-subsidised.

At Acorn, CO2 could be delivered via the existing Feeder 10 pipeline, which stretches from the industrial Grangemouth area, which contains 90 per cent of Scotland’s large site emissions, to St Fergus. The nearby Peterhead port could also act as a transport and temporary storage site, says Booth.  

There are significant challenges to these initiatives, but an OGA spokesperson notes that both platform electrification and CCS pilots can offer important quick wins to introduce the technologies by the mid-2020s and scale up the oil and gas response by the end of this decade. “In the long term, developing hydrogen (onshore demand and blue vs green hydrogen supply) will be critical to achieve net zero by 2050.”

There are many other ideas circling, such as making ‘green hydrogen’ via electrolysis using offshore wind power, on converted platforms and using existing pipelines to pipe it to shore. Others want to do the electrolysis on the turbine structures. Another nascent idea includes tapping old oil wells for geothermal energy.

There’s no single solution and it’s a complex picture involving policy, regulation and economics. A strategic vision is for a more connected North Sea energy industry, where all forms interconnect. That would require something of a system overhaul, says Webster, and the creation of an offshore grid.

“We are in a period right now where people are trying to work out how the decarbonisation is going to work, dig in to it, realise how much it’s interconnected and then how much public policy is going to need to change,” says Booth.

“There are many technical options; it’s hard to second-guess at the moment,” adds Webster. “We’ve got to give them a try and get to scale to work out what is the most efficient.”

With the COP26 climate conference coming this year in Glasgow, the UK government wants to be seen as leading CO2 reduction initiatives through its policies, but can the industry meet its goals?

“Corporate culture is changing fast; lowering operations’ carbon footprint is understood by many as critical to maintain social licence to operate,” says the OGA. “However, the industry needs to move faster in demonstrating change.”

The Greater Buchan Area project

Scotland

Jersey Oil & Gas, a small independent operator, has been taking a serious look at the options for its greenfield Greater Buchan Area (GBA) project, 120km north-east of Aberdeen. The project hopes to redevelop, with new facilities, the Buchan field, from which an estimated 80 million barrels of oil could still be produced, as well as some nearby discoveries

“Early on we commissioned a study with KBR and looked at a number of ways to power GBA,” says CEO Andrew Benitz, “looking at gas turbines and alternatives including wind and power from shore.” The latter is feasible and the most preferential way to power a project to ensure low carbon emissions, he says. It would also help create simpler facilities with no rotating equipment, so less maintenance, fewer staff needed and so lower running costs, adds project manager Stephen Kirby.

A challenge with using offshore wind, he says, is the consenting process, which can mean it takes up to 10 years to get a wind farm built, which is a challenge when you’re targeting first oil in 2025. You’d also have to have a back-up power supply, for when there’s not enough wind, or build 80MW if you need 20MW so that you can feed batteries to enable an uninterruptible power supply, adding cost.

Evaluations are ongoing, but key will be if the project could be an AC power distribution hub for others within a 150km radius, which would help spread the costs. But “time is of the essence”. As fields – and facilities – age, producing less oil and so less cash, the economics of investing in electrification get harder. “If you can share the capital cost of the cable, then you can start to improve the economics. But there are challenges; power prices in the UK are high and that’s a big challenge,” says Benitz.

 

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