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Jun-2018

Gas: the low-carbon fuel?

The natural gas industry has some way to go to make its full contribution to climate change targets.

Chris Cunningham
PTQ
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Article Summary
An end to methane emissions from the production, transmission and distribution of gas is essential to the fuel’s future in a low-carbon economy. In its current World Energy Outlook (WEO) report, the International Energy Agency foresees that methane emissions along the chain from production to consumption need to be 70% lower by 2040 compared with current levels of release. If the gas industry does not manage to eliminate a large percentage of its emissions comprehensively, gas’s advantage over other fuels in a low-carbon economy would be severely diminished and would make the global task of meeting the requirements of the Paris Agreement on Climate Change that much more difficult.
If natural gas is to become a zero-carbon fuel, carbon capture and storage at the production stage has to be an essential component of the matrix of emissions reduction. That said, there are viable and alternative options to tackle the issue of emissions from delivered gas which, if the WEO’s guidelines apply, would change the shape of gas processing. These alternatives include biomethane (biogas) and hydrogen. Biogas is a mixture of methane, carbon dioxide and traces of other gases produced either through the gasification of biomass or by the anaerobic digestion of organic matter by bacteria and enzymes in an oxygen-free environment.

Biogas blending
Biogas can either be used directly, close to where it is produced, or be upgraded to remove CO2 and other contaminants to yield a near total stream of biomethane which can be transported as natural gas. Production of biogas in 2015 was 60 billion cu m, most of it consumed in the production of power and heat. If biogas were to be blended with conventional natural gas, this would help to reduce the CO2 intensity of the gas stream and could help prolong the utilisation of existing natural gas infrastructure while reducing emissions globally. Several countries currently allow the introduction of biogas into their local distribution networks. Production of biogas for a meaningful contribution to emissions control of course depends on the availability of sufficient raw materials of production, including municipal waste and agricultural byproducts. It also depends on the economics of production. The cost of producing biogas is estimated to range between $6/MBtu and $17/MBtu when waste is used as a feedstock, and between $20/MBtu and $50/MBtu if the source is biologically processed energy crops. This means that the lowest cost source of biogas can be produced and supplied in competition with conventional natural gas, but scale of production from available resources is hardly likely to contribute substantially to overall consumption.

Costs would need to reduce substantially for biogas to be an accountable component of a low-carbon energy system. However, hydrogen could play a role in the low-carbon transition. At present, the largest user of hydrogen in the energy sector is petroleum refining and chemicals production, where hydrogen synthesised by steam reforming natural gas is consumed on-site for hydroprocessing applications for clean fuels production, and in the manufacture of ammonia and methanol.

To be useful as an energy source, hydrogen would have to be produced from low-carbon energy sources and in many instances would have to be transported over distances much longer than the route from a steam reformer to a same-site hydrocracker. However, the so-called power to gas route based on renewable power sources such as wind generation offers an interesting opportunity. As the capacity of variable renewables grows, so does the risk of mismatches between electricity generation and demand. If more electricity is generated than the system needs then, unless it can be stored or used, some capacity has to be curtailed and generation capacity is effectively lost. In the IEA’s long-term view, a third of the world’s electricity will be supplied by wind and solar sources in 2040. Some 8% of this variable electricity generation could be lost because of imbalance between generation and demand unless there is the opportunity to store it or to put it to practical use. The ‘lost’ electricity in the US, Europe and India together could alternatively provide an estimated 20 million tonnes of oil equivalent of hydrogen, about 2% of these regions’ natural gas demand in 2040. While the cost of producing the electricity would be low, the capital costs of hydrogen production facilities are high and facilities are unlikely to be economic if they can only operate intermittently. It may well be that it makes more sense to produce hydrogen using dedicated generation sites.

Hydrogen supply
How to transport hydrogen to consumers is also an important factor. One possibility is to inject hydrogen into the natural gas stream within existing pipelines. The low pressure distribution network could cope with relatively high injection levels since the networks in many parts of the world were installed to transport town gas, some 30-50% of which was hydrogen. A trunk gas network might present more of a problem since this was designed to carry natural gas, not town’s gas, and would be more prone to corrosion issues. However, current estimates are that hydrogen blended into the natural gas stream at a level no higher than 10% would overcome corrosion problems. The next question, once hydrogen has been delivered, is how do you burn it? Few consumers are currently equipped to handle a blend of hydrogen and natural gas. Many existing natural gas turbines could handle only around 1% hydrogen injection without compromising performance and safety. However, hydrogen injection could displace around 100 billion cu m of the world’s natural gas consumption by 2040, which could at least help to reduce CO2 emissions.

Carbon capture and storage
For natural gas to play a major role in a fully decarbonised global energy system, it will be essential in the long term for its consumption to result in almost no CO2 emissions. The only clear route to achieving this is carbon capture and storage. Like hydrogen production, carbon capture and storage requires additional capital expenditure. Unlike hydrogen, storing CO2 does not generate any direct revenue, or indeed any form of revenue unless a storage site can be put to use for application to enhanced oil recovery, for instance. Nonetheless, if carbon capture and storage and networked hydrogen production and distribution were to reach the point where they could be commercially deployed, there are various routes to CO2 emissions curtailment. Most obviously, gas-fired power plants equipped with carbon capture and storage would result in near-zero CO2 emissions during production of electricity. Additionally, a dedicated supply of pure hydrogen could be used in chemical synthesis or to help decarbonise freight or maritime transport, where the potential for electricity may be constrained by the need for very large batteries. Some estimates suggest that the cost of using hydrogen in trucks, including the cost of dedicated hydrogen infrastructure, could become comparable to that of plug-in hybrid trucks.

However, while the distribution network may be able to handle a pure stream of hydrogen, an entirely new transmission network and a great deal of new burner equipment would be required at high cost.

Fugitive methane
Annual methane emissions from the energy sector have been estimated at 100-200 million tonnes. Sources include the extraction of oil, natural gas and coal, and natural gas movement. Of these, coal mining is a significant contributor through the release of methane from coal seams. The largest source of emissions of coal bed methane is China. It is, after all, the world’s biggest producer of coal. The most recent local estimate puts releases of Chinese coal bed methane at 15 million t/y. Chinese coal production has increased by around 50% since 2005, and so current emissions may be much higher. Globally, it is estimated that coal bed methane emissions could be 30-60 million t/y.

That said, recent studies estimate that oil and gas operations combined are the largest source of methane emissions from the energy sector and that the potential for abatement (both in absolute and relative terms) for methane emissions from oil and gas is greater than that for coal or bioenergy. Methane emissions captured during oil and gas production or transport can often be monetised directly and so emissions reductions could result in economic savings or be carried out at low cost. According to the WEO’s long-term outlook, coal consumption falls rapidly, consequently reducing methane emissions from coal beds.
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