Modelling of integrated local energy systems: low-carbon energy supply strategies for the Oxford-Cambridge arc region

The energy supply system is undergoing enormous change to deliver against cost, security of supply and decarbonisation objectives. Robust decisions on the provision of infrastructure requires integrated models to perform analytics across the entire energy supply chain. A national level combined gas and electricity transmission network model was upgraded to represent local energy systems. Multiple energy vectors including electricity, gas, hydrogen and heat were integrated within the modelling framework. The model was utilised for a study of the Oxford-Cambridge arc region. The study assessed how different energy supply strategies, from electrification of heat to use of ‘green’ gases or local heat networks, could affordably reduce carbon emissions from the Oxford-Cambridge arc region energy system whilst considering constraints from the national system. The modelling process generated a diverse range of options for energy supplies, the choice of supply networks and end use technologies. The analysis illustrated the cost effectiveness and emission reduction potential of electrification of heat despite the requirement for additional network and supply capacity. Additionally, insulation and other energy efficiency solutions were also analysed. Potential barriers to technological change such as upfront costs, lack of awareness and perceived technology shortcomings were discussed in the context of the strategies assessed

Vulnerability assessment of the European natural gas supply

As indigenous natural gas reserves within the European Union (EU) decline, higher gas imports are expected in order to meet future EU gas demand. Natural gas will be transported across considerable distances from regions of gas reserves to European consumers. This raises security of gas supply concerns especially for EU countries that depend heavily on a single supply source or major transit route. A linear programming model of the European gas supplies was developed and used to investigate the impact of loss of the Ukraine transit capacity on gas supply from Russia to Europe. Two demand scenarios – that is a reference case and a high demand case in the winter of 2014/2015 were investigated. The results have shown that gas flows on interconnectors and from storage and liquefied natural gas import terminals compensated for the supply shortfall. Furthermore, to mitigate the effect of the supply shortage, the impact of increasing the capacities of selected pipelines within the EU was compared against increasing the maximum storage withdrawal rates in southeast Europe. Higher storage withdrawal rates achieved lower demand curtailment than the additional interconnector capacity in both scenarios

Electricity systems capacity expansion under cooling water availability constraints

Large and reliable volumes of water are required to cool thermal power plants. Yet across the world growing demands from society, environmental regulation and climate change impacts are reducing the availability of reliable water supplies. This in turn constrains the capacity and locations of thermal power plants that can be developed. The authors present an integrated and spatially explicit energy systems model that explores optimal capacity expansion planning strategies, taking into account electricity and gas transmission infrastructure and cooling water constraints under climate change. In Great Britain, given the current availability of freshwater, it is estimated that around 32 GW of combined cycle gas turbine capacity can be sustainably and reliably supported by freshwater. However, to maintain the same reliability under a medium climate change scenario, this is halved to 16 GW. The authors also reveal that the current benefit of available freshwater to the power sector is ∼£50 billion between 2010 and 2050. Adapting to expected climate change impacts on the reduced reliability of freshwater resources could add an additional £18–19 billion in system costs to the low-carbon energy transition over the time horizon, as more expensive cooling technologies and locations are required

Uncertainties in decarbonising heat in the UK

Heating is arguably one of the most difficult sectors to decarbonise in the UK's energy system. Meeting the 80% greenhouse gas emission reduction target by 2050 is likely to require that heat related emissions of CO2 from buildings are near zero by 2050, and there is a 70% reduction in emissions from industry (from 1990 levels). Though it is clear that the use of the natural gas network will reduce over time, recent modelling suggests a limited residual role for gas by 2050 to help meet peaks in heat demand. High levels of uncertainty about the way in which heat will be decarbonised present a number of challenges to policy makers. This paper will explore the risks and uncertainties associated with the transition to a low carbon heat system in the UK as outlined by the 4th carbon budget review. The potential impact of key uncertainties on the levelised costs of heat technologies and the development of energy networks are explored using a sensitivity analysis approach. Policy changes required to decarbonise the heat sector are also examined

Simulating flexibility, variability and decentralisation with an integrated energy system model for Great Britain

Energy system models allow the development and assessment of ambitious transition pathways towards a sustainable energy system. However, current models lack adequate spatial and temporal resolution to capture the implications of a shift to decentralised energy supply and storage across multiple local energy vectors to meet spatially variable energy demand. There is also a lack of representation of interactions with the transport sector as well as national and local energy system operation. Here, we bridge these gaps with a high-resolution system-of-systems modelling framework which is applied to Great Britain to simulate differences between the performance of decarbonised energy systems in 2050 through two distinct strategies, an electric strategy and a multi-vector strategy prioritising a mix of fuels, including hydrogen. Within these strategies, we simulated the impacts of decentralised operation of the energy system given the variability of wind and across flexibility options including demand side management, battery storage and vehicle to grid services. Decentralised operation was shown to improve operational flexibility and maximise utilisation of renewables, whose electricity supplies can be cost-effectively converted to hydrogen or stored in batteries to meet peak electricity demands, therefore reducing carbon-intensive generation and the requirement for investment in expanding the electricity transmission network capacity

The implications of ambitious decarbonisation of heat and road transport for Britain's net zero carbon energy systems

Decarbonisation of heating and road transport are regarded as necessary but very challenging steps on the pathway to net zero carbon emissions. Assessing the most efficient routes to decarbonise these sectors requires an integrated view of energy and road transport systems. Here we describe how a national gas and electricity transmission network model was extended to represent multiple local energy systems and coupled with a national energy demand and road transport model. The integrated models were applied to assess a range of technologies and policies for heating and transport where the UK’s 2050 net zero carbon emissions target is met. Overall, annual primary energy use is projected to reduce by between 25% and 50% by 2050 compared to 2015, due to ambitious efficiency improvements within homes and vehicles. However, both annual and peak electricity demands in 2050 are more than double compared with 2015. Managed electric vehicle charging could save 14TWh/year in gas-fired power generation at peak times, and associated emissions, whilst vehicle-to-grid services could provide 10GW of electricity supply during peak hours. Together, managed vehicle charging, and vehicle-to-grid supplies could result in a 16% reduction in total annual energy costs. The provision of fast public charging facilities could reduce peak electricity demand by 17GW and save an estimated £650 million annually. Although using hydrogen for heating and transport spreads the hydrogen network costs between homeowners and motorists, it is still estimated to be more costly overall compared to an all-electric scenario. Bio-energy electricity generation plants with carbon capture and storage are required to drive overall energy system emissions to net zero, utilisation of which is lowest when heating is electrified, and road transport consists of a mix of electric and hydrogen fuel-cell vehicles. The analysis demonstrates the need for an integrated systems approach to energy and transport policies and for coordination between national and local governments

Multi-time period combined gas and electricity network optimisation

A multi-time period combined gas and electricity network optimisation model was developed. The optimisation model takes into account the varying nature of gas flows, network support facilities such as gas storage and the power ramping characteristics of electricity generation units. The combined optimisation is performed from an economic viewpoint, minimising the costs associated with gas supplies, linepack management, gas storage operation, electricity generation, and load shedding. It is demonstrated on the GB gas and electricity network

A sequential Monte Carlo model of the combined GB gas and electricity network

A Monte Carlo model of the combined GB gas and electricity network was developed to determine the reliability of the energy infrastructure. The model integrates the gas and electricity network into a single sequential Monte Carlo simulation. The model minimises the combined costs of the gas and electricity network, these include gas supplies, gas storage operation and electricity generation. The Monte Carlo model calculates reliability indices such as loss of load probability and expected energy unserved for the combined gas and electricity network. The intention of this tool is to facilitate reliability analysis of integrated energy systems. Applications of this tool are demonstrated through a case study that quantifies the impact on the reliability of the GB gas and electricity network given uncertainties such as wind variability, gas supply availability and outages to energy infrastructure assets. Analysis is performed over a typical midwinter week on a hypothesised GB gas and electricity network in 2020 that meets European renewable energy targets. The efficacy of doubling GB gas storage capacity on the reliability of the energy system is assessed. The results highlight the value of greater gas storage facilities in enhancing the reliability of the GB energy system given various energy uncertainties