How can gas networks further support the energy transition?

Technical challenges 

Biomethane is a low carbon fuel that can be injected into the gas networks today and combusted in equipment that uses natural gas. In 2023, 6.4 TWh of biomethane was injected into Great Britain’s gas grid from anaerobic digestion plants.1 A peak of around 8 TWh of biomethane injection per annum is forecast by 20302. Similarly, DNV’s UK Energy Transition Outlook forecasts that the share of biomethane in the gas grid will rise to over 7% by mid-century.3 We have found the technical barriers for the gas networks are mainly in the capacity of the pipelines to accept the gas, as during the summer months when gas usage is low there may not be the offtakers available in some areas, which is problematic since the anaerobic digestion process is continuous. Technical solutions to the capacity constraints are already in use, either injecting into higher pressure networks, or using in-grid compression to move gas up the pressure tiers. Where a grid injection connection is not available then centralised hubs and tankering (virtual pipelines) can be employed. Further development of low cost/high pressure connections would be beneficial though. 

Other technical barriers for biomethane producers include the gas quality specification4 that imposes additional costs to clean up biomethane’s trace components, in particular siloxanes, oxygen, sulfur compounds, and corrosives. The high pressure (>38bar) networks and in particular underground storage cannot accommodate higher levels of oxygen without detailed assessment of the risks, but further research could enable the limits to be relaxed in some cases given that pipeline integrity risk is effectively managed by control of the water dew point. 

Lastly, the need to add fossil propane to biomethane to match the calorific value of the natural gas in the local distribution zone requires both regulatory and technical solutions. For example, blending biomethane into natural gas prior to measuring the calorific value can reduce the need for propane, even at offtakes where the flow in the network is low, and this should be employed more across the gas network. 

The technical barriers to the adoption of hydrogen are numerous as the case for safety needs to be developed, and the supply chain built. There are already numerous projects addressing all aspects of a conversion to hydrogen, although there remains much work to do. Enormous technical challenges will need to be overcome to convert the natural gas pipeline network to hydrogen, particularly the distribution networks, if a decision is made to use hydrogen for domestic heat. Consumers cannot be left without a heating source for long and the planning and logistics of sectorising and converting the network should not be underestimated. 

The public also needs to be convinced of hydrogen’s cost and environmental credentials. Hydrogen production requires green electricity for electrolysis or carbon capture technology for reforming, and these need to be scaled significantly.  Hydrogen’s higher flame temperature means it can produce more harmful NOx emissions, although this may be mitigated by improved burner design etc.5 Hydrogen is also an indirect greenhouse gas with a global warming potential for a 100-year time horizon6 is 11 ± 5 and so emissions still need to be minimised. 

Policy challenges 

Gas networks are predicted to have a role to play in the short, medium and long term energy supply, accepting that uncertainty in the pathway to net zero increases with time. Gas networks will increasingly form part of a ‘whole energy system’ that must consider gas and electricity etc together. The UK’s new National Energy System Operator (NESO) is now responsible for planning the whole system. The NESO’s Future Energy Scenarios (now called pathways) need annual updates and the 2024 set better recognise the role of gas in the pathway, and the inertia created by the existing asset base, in part influenced by DNV’s work on the Common Planning Pathway for National Gas Transmission. The investment community also has a key role to play in providing the funding for infrastructure, and stranded assets will need to be avoided and business models developed to make decarbonisation investable. 

Hydrogen is likely to be used in industry and power generation, although its use in the home is less certain. The government will make a decision about hydrogen for domestic heating in 2025 and evidence of hydrogen’s safety is increasing, while the gas networks are also developing procedures and workforce competency. It will take many years to convert end users to hydrogen, although 20% blends are interchangeable with natural gas in domestic boilers, although only contribute 7% of the energy and emissions reductions, but will help kick-start the hydrogen industry. Policy is required to enable this though.  

Policy changes are required at all stages, e.g. mandating hydrogen-ready boilers, rolling out hydrogen blending, finalising the hydrogen purity standard. Security of supply and digitalisation are increasingly important too, and these can be driven by policy.  

Policy changes that could be considered also include setting a carbon intensity target for the gas grid, green gas tariffs, and including hydrogen within the Green Gas Support Scheme (currently only biomethane). 

Regulatory challenges

The gas networks are regulated by Ofgem under the RIIO price control framework, and by the Health and Safety Executive for safety. Both regulatory frameworks need modifications to better enable the gas network’s role in meeting net zero. 

The gas networks will facilitate more biomethane connections to reduce fossil carbon emissions. Challenges for expansion include capacity of the network to accept new biomethane connections, flow-weighted average calorific value (FWACV) billing system under Gas (Calculation of Thermal Energy) Regulations and the impact of changes in gas composition. 

For ‘hydrogen for heat’ to happen the public needs to accept the new fuel. Safety is key to acceptance, and while hydrogen is a flammable gas the same as methane, its wider flammability range, lower ignition energy and higher flame speed mean research is required to understand the risks. The government will need to amend schedule 3 of the Gas Safety (Management) Regulations to allow hydrogen into the network as it is currently limited to 0.1%. 

Finally, gas pipelines may be decommissioned but this leads to possible repurposing (e.g. heat network routes, cable ducting, CO2 transportation). This will affect the regulatory asset value of the infrastructure that will need to be considered by Ofgem, but does offer a future opportunity for the gas networks themselves. 

Conclusion 

Pipelines are a safe and sustainable way of transporting fuel gases around the country and one that the gas consumer has largely already paid for. While electrification is likely to be the primary route to decarbonisation, there will be a need for hydrogen in some industrial sectors at the very least, and so the gas networks should remain relevant as we transition away from fossil fuels well into the future.