With a focus on emissions, this article looks at decarbonising the UK’s energy sector and the use of hydrogen as an energy vector in the UK.
The UK urgently needs to find cost-effective and scalable ways to decarbonise our energy sector. Domestic policy, such as the Climate Change Act (2008), commits the UK to reduce its 2050 greenhouse gas emissions by at least 80% compared to 1990 levels. On an international scale, the Paris Agreement also requires significant decarbonisation to keep global temperature increase ‘well below’ 2°C.
The energy sector is pivotal in this and hydrogen as an energy vector can play a significant role in the transition to a low-carbon economy. Hydrogen is abundant in nature, however to be able to generate pure hydrogen for energy consumption, energy is required. Dependent on the method of production, and possible use of carbon capture and storage (CCS) technology, hydrogen has the potential to be a climate- friendly replacement for fossil fuels at the point-of-use.
The main driver for using hydrogen as an energy vector is to decarbonise the UK’s energy sector. The lifecycle emissions of the fuel are therefore critical. Lifecycle pollutants associated with the use of hydrogen as an energy vector are determined by a) the primary energy source and b) the process used for hydrogen production.
There are a number of ways that hydrogen can be produced, including:
- Steam reforming of natural gas (or other hydrocarbons)
- Electrolysis of water
- Extraction of ‘bio-hydrogen’ from biogas produced by fermentation of organics or cyanobacteria
- As a by-product of larger industrial chemical processes, such as chlor-alkali production
Measurement challenges for all types of hydrogen production
Measuring the purity of the hydrogen produced is imperative to define quality control specifications, as each method may introduce its own impurities. We need to understand which impurities are introduced, in what quantities and how producers will collect this information. Each method may require specific validated purification or filtration methods to protect consumers and ensure the durability of the end-use application without compromising performance. A new international standard (ISO 19880-8) for hydrogen quality control is currently under development by ISO TC 197 which aims to explore this challenge further.
Currently, there is no understanding of the level of silicon that would be deemed acceptable in hydrogen, nor any techniques available to measure it. Hydrogen produced from biogas is not covered in current quality standards. If it were to become a conventional production method, then new impurities including silicon would need to be addressed.
Steam methane reforming (SMR)
Almost all of global hydrogen production (96%) comes from hydrocarbon sources and SMR currently accounts for around half of this. During the SMR reaction, natural gas is mixed with steam, heated to over 815°C and reacted in the presence of a nickel catalyst to produce hydrogen (H2) and carbon monoxide (CO), which is then converted to CO2 via a water gas shift reaction. As a result of the chemical mix, there is a risk with SMR that impurities may be present within the hydrogen gas produced. If this gas were to be fed directly for use in a fuel cell, for example, treatment to remove all impurities to meet purity specifications (explained further in section 6.2) may be required. In addition, to meet the UK’s decarbonisation targets, it is important that the carbon-based emissions that are produced via SMR are captured and stored (through CCS).
The development of CCS technologies will be essential should SMR be pursued as a carbon-neutral method for hydrogen production. If the captured carbon is to be stored for example above ground or under the sea, a robust understanding of how the gas is transported and stored in terms of methods and materials would be needed to reduce any potential environmental impacts. If, for example, the CO2 is injected into aquifers or transmitted along oil pipelines, ‘local, regional or transboundary assessment of potential significant environmental impacts on the natural areas’ may be required.
Electrolysers are used to split water (H2O) into hydrogen (H2) and oxygen (O2) gas with energy input. If the energy input used to power the electrolyser comes from a renewable source and the hydrogen produced is used in a fuel cell or combusted, then the entire energy process would create no net emissions.
Electrolysers have the ability to be scaled up or down to meet demand. When scaled down, they could be used at a local level and fed by small-scale renewable systems such as solar photovoltaic (PV) panels on rooftops and solar farms. This provides a viable option should a decentralised approach to decarbonisation be adopted in the UK. When scaled up, electrolysers would use central energy generation facilities and the hydrogen would then need to be transported to the point of use.
Only 4% of global hydrogen production is currently from electrolysis and although it is pre-emptive to assume that electrolysis will become the primary method for producing hydrogen in the UK, this method currently dominates the hydrogen transport sector. Most of the hydrogen refuelling stations in the UK utilise electrolyser technology to produce hydrogen fuel for FCEVs.
Emerging technologies are under development which could provide either lower cost or more efficient processes for the production of hydrogen.
These devices use semiconducting electrode materials that combine two process steps for hydrogen production into one device (solar PV and electrolysis). Development of such devices is being undertaken at Imperial College London as well as other research institutes globally.
Methane is converted to hydrogen and carbon monoxide through cyclic reduction and oxidation reactions of fuel with an oxygen carrier. This produces two separate pure streams of hydrogen and carbon dioxide (from methane and water), without the need for a separation process. Development is ongoing at Newcastle University and the University of Cambridge.
Thermochemical processes include, for example, ‘cracking’ water at elevated temperatures aided by chemical reactions. As these technologies and methods potentially become more established, measurement challenges could arise which will need to be addressed. Presently, challenges here are emergent and less urgent, and therefore lower priority.
Once produced, hydrogen can act as both a short and long-term energy store to balance supply and demand of renewable energy at different scales, geographies and weather conditions. It can therefore meet the need for a low-cost, ‘on-demand’ power supply that only fossil-fuelled power plants can currently satisfy. Options include storing hydrogen in the following.
As a gas in salt caverns (purpose-built geological features or ‘natural aquifers’) or in depleted natural gas fields
Salt caverns are man-made underground holes created by washing salt out of large geological structures that are composed of almost pure sodium chloride. These could be used to store hydrogen gas at large volumes to address seasonal fluctuations in demand. The UK currently stores around 10,000 GWh of natural gas in salt caverns, which means there is a large resource of storage available for hydrogen to replace. There are substantial caverns in Teesside that have been operational since the 1960s, and are proposed for hydrogen storage by the H21 Leeds City Gate project, as well as in East Yorkshire, the Cheshire Basin and the Weald Basin. Some hydrogen is currently stored in salt caverns, predominantly for use in chemical plants and oil refineries.
Compressed within specialised on-site tanks at high pressure
This is the primary method for storing hydrogen at refuelling stations within the UK. There is ongoing development of these tanks – the University of Ulster, for instance, has completed projects on explosion- resistant composite tanks for storage of high-pressure gases.
In a solid state (for example, within a powder form)
When using FCEVs, the hydrogen fuel can be stored within a powdered material, such as a hydride. Research is still being undertaken to establish materials that can store hydrogen efficiently without impacting the performance of the gas as an energy vector.
Cryogenically (in liquid form)
Liquefaction can increase the energy density of the hydrogen; however, this process requires energy. For example, the energy density of gaseous hydrogen would increase ‘from 1.4 kWh/litre at 700 bar to 2.3 kWh/litre as a liquid’; however, the liquefaction process could require as much as 30% of its energy content.
Ammonia (NH3) has the potential to provide an on-demand and in situ vector of hydrogen fuel and has many advantages compared to the direct storage of compressed or cryogenic hydrogen. Ammonia is already produced on an industrial scale, can be easily liquefied and has a volumetric density of hydrogen around 45% higher than that of liquid hydrogen. Generating power from ammonia is possible either as a direct fuel or by ‘cracking’ the ammonia to isolate the hydrogen for use in a fuel cell. However, there are a number of technical challenges in scaling both methods that need to be addressed to give the public confidence in the potential use of ammonia.
Measurement challenges for hydrogen storage
Measuring the efficiency of each storage mechanism for potential use on a national scale, as well as understanding the efficiency of the intraday storage mechanisms (fluctuations in demand during a single day as opposed to seasonally) as these will be important in establishing which is the most appropriate storage solution.
Measurement of the potential leakage from salt caverns or depleted gas fields will be fundamental in addressing safety concerns as well as the efficiency of these storage solutions. Further live field trials for large-scale hydrogen storage mechanisms such as salt caverns and depleted gas fields need to be carried out to not only demonstrate the suitability and capacity available, but to understand any implications of contaminating the hydrogen from remnant gas and establishing the purity of the gas once removed from the storage mechanism.
“measurement of the potential leakage from salt caverns or depleted gas fields will be fundamental in addressing safety concerns as well as the efficiency of these storage solutions”
Measuring the capacity, efficiency, rates of charge and discharge for cryogenic storage mechanisms, as storing hydrogen as a liquid at low temperature means a substantial amount of energy is consumed in the liquefaction process. Difficulties are also faced during handling of the liquid, as well as losses due to boil-off – these issues need to be explored further to understand how they can be addressed.
Establishing the type of material best suited to storing hydrogen within a tank, to avoid leakage and embrittlement, will be important as liquid hydrogen tanks can store more hydrogen in a given volume than compressed gas tanks.
There are a number of measurement challenges surrounding the use of hydride storage in FCEVs, including the ability to measure the amount of stored hydrogen so it can accurately inform the driver when to fill up again. Additionally, car manufacturers will need to understand whether the purity of the hydrogen changes as a result of storage within the hydride for instance.
The hydrogen extracted from ammonia when used as a storage mechanism must be compliant with the ISO standard for use in a fuel cell, and therefore cannot contain more than 0.1 parts-per-million of ammonia (explored in section 6.2). It will also be vital to be able to make accurate leakage measurements to provide safety assurance and establish the efficiency of this process.
Once produced, hydrogen can be fed into storage mechanisms or directly into the distribution network. It is currently unclear whether the existing energy infrastructure can support the introduction of hydrogen gas and hydrogen technologies. Some of the current reports and roadmaps predict hydrogen will most likely be produced at central locations upstream, similarly to conventional gas, which would take advantage of the existing gas infrastructure when it comes to its distribution.
However, generating hydrogen at the point of use would save on transport costs and reduce emissions related to transporting the gas. Currently, 95% of hydrogen produced globally is created and used in the same location. Having the appropriate infrastructure for its production and use in situ may not always be feasible, so robust and efficient distribution and transportation methods will be required in some cases.
Hydrogen in the grid and integration within the existing energy infrastructure
Industry experts have noted that the most practical method for the deployment of hydrogen into the grid would be by initially converting sections of the distribution network and then later linking those together with the transmission network. If several ‘hub’ areas were to invest in this model, this may make a business case for them to ‘share the load’ when demand is high.
In terms of the existing infrastructure in the UK, the NTS (National Transmission System) and LTS (Local Transmission System) are both designed and built to the same technical standards and specifications with regards to the materials that are used. As the NTS and LTS are constructed using a hard steel, they are not optimised for the transportation of hydrogen at high pressures due to hydrogen embrittlement issues and potential leakage. These issues are likely to occur at weak points such as at welded joints, but have the potential to arise almost anywhere within this high-pressure system.
At present, polyethylene (PE) pipes are considered a suitable material for carrying hydrogen up to 100% concentration. PE pipelines have also been seen to be more appropriate for distributing natural gas safely and efficiently, which has led to the current national Iron Mains Replacement Programme in the UK, due to be completed in the early 2030s.
Nevertheless, it is vital to establish a regulatory framework for the blending of hydrogen into the natural gas grid, as it is likely that the integration of hydrogen will involve a gradual mix, where the ratio of hydrogen to natural gas is increased incrementally over time. Should the UK wish to introduce blends of hydrogen and natural gas, or a 100% hydrogen concentration into the existing grid before the completion of the Iron Mains Replacement Programme, then further research would be required on the impact that the injected hydrogen would have on grid infrastructure and vice versa.
These are some projects that aim to demonstrate how hydrogen could be integrated into the grid:
- Hydrogen is known to cause embrittlement issues for many metals and is also extremely light, so can more easily leak than methane. The National Grid aims to better understand this through the ‘HyDeploy’ project, which will introduce hydrogen onto a live gas network and test hydrogen blends with natural gas to assess how it behaves within the grid, without needing to replace appliances or equipment within the existing network
- The ‘H21 Leeds City Gate’ project (for which an extensive feasibility study has already been published) aims to assess the viability of transforming to a hydrogen economy both from a technical and commercial viewpoint, by converting Leeds’s existing natural gas infrastructure incrementally to 100% hydrogen dependency
Measurement challenges for hydrogen distribution
Impact analysis of odorants on end use applications. Similarly to natural gas, hydrogen is odourless. The likely solution to ensure hydrogen gas leaks are detected is to add an odorant. Once a suitable odorant has been identified to make it detectable and to give hydrogen a recognisable smell, it will be important to understand how this odorant would be added, by whom, and at what stage of distribution, as well as how the odorant behaves with the hydrogen within the pipes or in appliances. If the grid hydrogen is required for transport applications, effective methods of removing the odorant would be required.
Purity and gas blend concentration analysis across the gas network. If several different companies are injecting hydrogen at different places, then this may cause issues when establishing what the concentration is at a certain point or time. Therefore, providing traceability with regards to where the gas supply has come from if hydrogen were to be injected into the natural gas grid, as well as measuring what the purity and concentration are at the time of injection, and what these are at each exit point, are vital issues to address. It has been proposed by several industry experts that each energy unit containing hydrogen could have metadata attached to it, which specifies its origins, whether or not it came from a carbon- intensive source, whether it was imported and other such factors, which would give it not only ‘traceability’ but ‘value’. Measurement of the blend ratio if hydrogen were to be mixed with natural gas would be important for a scenario where it is incrementally added into the existing gas network because it would affect the cost that consumers are charged for it per unit volume.
“measurement of material performance and lifetime within the distribution pipeline is essential to ensure the material selection is adequate”
Recalibration of gas detectors for hydrogen distribution pipelines, at substations and at refuelling stations will be important to ensure they are suitable for sensing hydrogen in the air in terms of adequate leak detection for health and safety standards and emergency response. Measurement of material performance and lifetime within the distribution pipeline is essential to ensure the material selection is adequate and to mitigate against potential leakage should hydrogen be introduced at varying concentrations and blends.
Measuring which impurities are currently present within the grid distribution network, and subsequently testing the effect of these impurities on fuel cells, as this will be vital for end-user reassurance of the quality of hydrogen they are receiving and the potential impact of the odorant on lifetime and durability of the end-use appliance.