The future of the UK gas network

The UK has an extensive natural gas pipeline network supplying 84% of homes. Previous studies of decarbonisation pathways using the UK MARKAL energy system model have concluded that the low-pressure gas networks should be mostly abandoned by 2050, yet most of the iron pipes near buildings are currently being replaced early for safety reasons. Our study suggests that this programme will not lock-in the use of gas in the long-term. We examine potential future uses of the gas network in the UK energy system using an improved version of UK MARKAL that introduces a number of decarbonisation options for the gas network including bio-methane, hydrogen injection to the natural gas and conversion of the network to deliver hydrogen. We conclude that hydrogen conversion is the only gas decarbonisation option that might enable the gas networks to continue supplying energy to most buildings in the long-term, from a cost-optimal perspective. There is an opportunity for the government to adopt a long-term strategy for the gas distribution networks that either curtails the iron mains replacement programme or alters it to prepare the network for hydrogen conversion; both options could substantially reduce the long-term cost of supplying heat to UK buildings

Green Hydrogen Characterisation Initiatives: Definitions, Standards, Guarantees Of Origin, And Challenges

Hydrogen can be produced from many different renewable and non-renewable feedstocks and technological pathways, with widely varying greenhouse gas emissions. For hydrogen to have a role in future low-carbon energy systems, it is necessary to demonstrate that it has sufficiently low carbon emissions. This paper explores how green hydrogen has been defined, reviews nascent green hydrogen characterisation initiatives, and highlights the main challenges that standards and guarantee of origin schemes must overcome to develop a market for green hydrogen. Most existing green hydrogen initiatives are in Europe. In anticipation of a future market for green hydrogen, international standards are starting to be discussed by national and international standardisation organisations and policy makers. A range of approaches have been taken to defining green hydrogen and guarantees of origin. These vary on whether green hydrogen must be produced from renewable energy, on the boundaries of the carbon accounting system, the emission thresholds at which hydrogen is considered green, and on which feedstocks and production technologies are included in the scheme. Decisions on these factors are often influenced by other national and international standards, and the legal framework in which the green hydrogen supply chain operates

Regulatory Challenges to Energy Storage Deployment An Overview of the UK Market

This working paper investigates how the UK is currently integrating energy storage technologies into its electricity markets, the regulatory barriers it is facing, and how it is responding to these challenges. It was prepared by the ‘Realising Energy Storage Technologies in Low-carbon Energy Systems’ (RESTLESS) project, which is funded by the UK Engineering and Physical Sciences Research Council. The project is part of the EPSRC Energy Superstore Hub and is associated with the UK Energy Research Centre (UKERC). The authors are solely responsible for all of the analysis in this paper. Any views expressed in this paper are the authors’ and have not been endorsed by any of the organisations associated with the RESTLESS project

Energy system modelling challenges for synthetic fuels: Towards net zero systems with synthetic jet fuels

Long-distance air travel requires fuel with a high specific energy and a high energy density. There are no viable alternatives to carbon-based fuels. Synthetic jet fuel from the Fischer-Tropsch (FT) process, employing sustainable feedstocks, is a potential low-carbon alternative. A number of synthetic fuel production routes have been developed, using a range of feedstocks including biomass, waste, hydrogen and captured carbon dioxide. We review three energy system models and find that many of these production routes are not represented. We examine the market share of synthetic fuels in each model in a scenario in which the Paris Agreement target is achieved. In 2050, it is cheaper to use conventional jet fuel coupled with a negative emissions technology than to produce sustainable synthetic fuels in the TIAM-UCL and UK TIMES models. However, the JRC-EU-TIMES model, which represents the most production routes, finds a substantial role for synthetic jet fuels, partly because underground CO2 storage is assumed limited. These scenarios demonstrate a strong link between synthetic fuels, carbon capture and storage (CCS) and negative emissions. Future model improvements include better representing blending limits for synthetic jet fuels to meet international fuel standards, reducing the costs of synthetic fuels and ensuring production routes are sustainable

Repurposing of Offshore Oil and Gas Cables for Renewable Generation: Feasibility and Conceptual Qualification

Wind farms are expected to be deployed in the North Sea in increasing numbers and at ever greater distances from land, over the coming decades. Many nearby oil and gas fields have reached or are near the end of their lifespans, and their operators are eager to explore innovative ways to reduce decommissioning costs. One possibility would be to repurpose some of their infrastructures for use by wind farms, which would both delay decommissioning and reduce the wind farm capital costs. This paper investigates the potential for repurposing existing submarine power cores in decommissioned oil and gas fields as transmission cables for offshore renewables. Offshore power cables generally have longer lifetimes than are needed to deplete hydrocarbon reservoirs. Cable transmission capacity could be too low to provide the main connection to wind farms, but there is scope to increase capacity or use cables as auxiliary connections. A qualification methodology is proposed to assess whether existing cables might be usefully repurposed. Repurposing cables has an impact on renewable project capital expenditure (CAPEX) and levelised cost of energy (LCOE), it also positively affects decommissioning cost and the environment. The qualification methodology provides a cost-effective initial appraisal prior to field testing

Can we use hydrogen as a storage vector to reduce the cost of intermittent renewables?

Hydrogen has long been identified as a zero-carbon energy carrier for transport applications. Yet there are other potential roles for hydrogen in low-carbon energy systems that have received relatively little attention. One option is power-to-gas, in which excess intermittent renewable generation is used to produce hydrogen that can be stored for subsequent electricity generation or injected into the natural gas network to avoid supply-demand imbalances. For countries that currently rely on piped high-carbon natural gas for heating buildings, hydrogen is a low-carbon heating fuel that could be delivered using the existing gas networks as an alternative to electrifying heat. The electricity and gas networks, which currently operate independently, could be integrated in the future, with the gas network providing an important short-term energy storage medium to cope with periods of peak energy demand. Larger storage (e.g. salt caverns) could be used for inter-seasonal storage of hydrogen to deal with winter peaks in heat demand. We have examined the potential for hydrogen to be a storage vector in the UK electricity and gas systems. First, using the UK MARKAL energy system model, we have examined the cost-optimal long-term use of hydrogen to decarbonise the gas network, through injection (Dodds and McDowall 2012; Dodds and McDowall submitted) or through conversion to deliver only hydrogen (Dodds and Démoullin in press). This model is not able to represent inter-seasonal hydrogen storage so we have created a new energy system model that is based on the TIMES platform to examine the potential benefits to the UK of these technologies. This new model also includes all greenhouse gas emissions, an improvement from UK MARKAL which represents only CO2 emissions, so it also allows us to assess the benefits of avoiding methane leakages from the gas networks. The representation of power-to-gas technologies is also much improved. In this paper, we discuss the prospects for using hydrogen as an energy carrier in the UK gas networks using UK MARKAL. We then introduce the new UK TIMES model and consider the potential for power-to-gas and inter-seasonal storage to contribute to the planned large-scale deployment of renewables in the UK in the future

Integrating housing stock and energy system models as a strategy to improve heat decarbonisation assessments

The UK government heat strategy is partially based on decarbonisation pathways from the UK MARKAL energy system model. We review how heat provision is represented in UK MARKAL, identifying a number of shortcomings and areas for improvement. We present a completely revised model with improved estimations of future heat demands and a consistent representation of all heat generation technologies. This model represents all heat delivery infrastructure for the first time and uses dynamic growth constraints to improve the modelling of transitions according to innovation theory. Our revised model incorporates a simplified housing stock model, which is used produce highly-refined decarbonisation pathways for residential heat provision. We compare this disaggregated model against an aggregated equivalent, which is similar to the existing approach in UK MARKAL. Disaggregating does not greatly change the total residential fuel consumption in two scenarios, so the benefits of disaggregation will likely be limited if the focus of a study is elsewhere. Yet for studies of residential heat, disaggregation enables us to vary consumer behaviour and government policies on different house types, as well as highlighting different technology trends across the stock, in comparison with previous aggregated versions of the model

Hydrogen and fuel cell technologies for heating: A review

The debate on low-carbon heat in Europe has become focused on a narrow range of technological options and has largely neglected hydrogen and fuel cell technologies, despite these receiving strong support towards commercialisation in Asia. This review examines the potential benefits of these technologies across different markets, particularly the current state of development and performance of fuel cell micro-CHP. Fuel cells offer some important benefits over other low-carbon heating technologies, and steady cost reductions through innovation are bringing fuel cells close to commercialisation in several countries. Moreover, fuel cells offer wider energy system benefits for high-latitude countries with peak electricity demands in winter. Hydrogen is a zero-carbon alternative to natural gas, which could be particularly valuable for those countries with extensive natural gas distribution networks, but many national energy system models examine neither hydrogen nor fuel cells for heating. There is a need to include hydrogen and fuel cell heating technologies in future scenario analyses, and for policymakers to take into account the full value of the potential contribution of hydrogen and fuel cells to low-carbon energy systems