Decarbonisation Technology - February 2025 Issue

Recycle gas

Town gas

T.H.T. Ordorant addition

Superheated steam Steam

To grid

Steam super- heater

Naphtha storage tank

Gas dr ye r

Boiler feed water

Steam reboiler

Tubular reformer

Town gas composition Carbon dioxide

16.3% – 19.9%

Natural gas from pipeline

Town gas energy value Caloric value

Carbon monoxide

1.0% – 3.1%

17.27 MJ/m

Methane Hydrogen

28.2% – 30.7% 46.3% – 51.8%

Specic gravity Wobbe index

0.52

Nitrogen and oxygen 0% – 3.3%

Figure 2 Hong Kong Town Gas – Tai Po catalytic rich gas naphtha/methane reformer and CO₂ capture process

reformer must be removed to enable the catalytic Haber-Bosch ammonia synthesis reaction to take place (see Figure 1 ). Every natural gas- fed ammonia plant already has a CO₂ capture facility. The Capex is spent, and the energy costs for CO₂ capture are committed. This CO₂ must be sequestered to reduce the CO₂ intensity of this ammonia. Large-scale projects for green hydrogen for ammonia production should not be prioritised until we have decarbonised existing natural gas-fed ammonia plants massively. Coal-to-chemicals is another area of low- hanging fruit. Immediately after coal gasification, the raw syngas is fed to a Rectisol unit, where CO₂ and sulphurous gases are removed. At present, this CO₂ is blown to atmosphere, just like the CO₂ from ammonia production is vented on most ammonia plants today. This captured CO₂ must be a priority for sequestration since the capital and operating costs of the Rectisol plant are absorbed into the overall costs of the coal-to-chemicals production. To reduce the CO₂ intensity of coal- to-chemicals, the only incremental costs are CO₂ transmission and sequestration. In Hong Kong, Town Gas production already involves CO₂ capture to control the heating value of the product (see Figure 2 ). This CO₂ is vented to atmosphere. It should be sequestered. Production of ethylene oxide on many petrochemical plants also requires CO₂ removal within the process to purge CO₂ (a byproduct of ethylene oxidation) from the process recycle.

Also, natural gas processing removes CO₂ in midstream operations to ensure dry, acid- free gas enters the pipeline transmission infrastructure. These are tier 1 priorities for sequestration of captured CO₂. Decarbonising refinery hydrogen In many oil refineries, grey hydrogen produced from natural gas on steam methane reformers (SMRs) is used to produce marketable liquid fuels. The CO₂ from these SMRs is not captured at present. However, 60 to 70% of the CO₂ produced on the SMR is available at a very high partial pressure prior to the reformate gas mixture entering the hydrogen separation pressure swing adsorption (PSA) unit. The unit cost of CO₂ capture in this location is low. New equipment and new energy would be required. But the incremental costs of capturing this CO₂ would be less than the incremental cost of implementing carbon capture and storage (CCS) to processes with more dilute CO₂ streams, such as power generation, cement, or steel making (see Figure 3 ). Despite the ideal process conditions, there is not an overwhelming wave of SMR CO₂ capture projects being implemented because the business case is not strong enough. The costs of CO₂ emissions do not cover the costs of new equipment and the energy penalty. CCS of CO₂ from SMRs would be ‘good value for money’ and help with the rapid decarbonisation of hydrogen production