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Active demand side response (DSR) will provide a significant opportunity to enhance the power system flexibility in the Great Britain (GB). Although electricity peak shaving has a clear reduction on required investments in the power system, the benefits on the gas supply network have not been examined. Using a Combined Gas and Electricity Networks expansion model (CGEN+), the impact of DSR on the electricity and gas supply systems in GB was investigated for the time horizon from 2010 to 2050s. The results showed a significant reduction in the capacity of new gas-fired power plants, caused by electricity peak shaving. The reduction of gas-fired power plants achieved through DSR consequently reduced the requirements for gas import capacity up to 90 million cubic meter per day by 2050. The cost savings resulted from the deployment of DSR over a 50-year time horizon from 2010 was estimated to be around £60 billion for the GB power system. Although, the cost saving achieved in the gas network was not significant, it was shown that the DSR will have a crucial role to play in the improvement of security of gas supply. [ABSTRACT FROM AUTHOR]

Integration of a large capacity of wind generation in the Great Britain (GB) electricity network is expected to pose a number of operational challenges. The variable nature of wind generation necessitates introduction of technologies that can provide flexibility to generation portfolios and therefore compensate for intermittency of wind generation. In this paper, the efficacy of three options to address electricity balancing challenges was evaluated: flexible gas-fired plants, electricity storage and Power-to-Gas system. The combined gas and electricity network model (CGEN) was enhanced and through adopting a rolling optimisation approach the model aims at minimising the operational cost of an integrated gas and electricity networks that represents a GB system in 2030. The potential impacts of employing each of the flexibility options on the operation of the integrated electricity and gas networks were investigated. The analysis showed that amongst all the flexibility options, the deployment of grid-scale electricity storage will achieve the highest reduction in the operational cost of the integrated system (£12 million reduction in a typical winter week, and £3 million reduction in a typical summer week). The results of this study provide insights on the system-wide benefits offered by each of the flexibility options and role of the gas network in the energy system with large capacity of wind generation. [ABSTRACT FROM AUTHOR]

The reliance of Great Britain power generation on the gas network makes it critical to consider the future availability and cost of gas in planning the expansion of the power system. A combined gas and electricity network planning model was used to investigate impacts of various low carbon strategies on regional expansion of the Great Britain gas network out to the 2050s. A number of long term energy supply and demand strategies covering a range of plausible investment policies for Great Britain gas and electricity systems were explored. Reliance of Great Britain on gas imports was projected to vary from 84%, in an energy system with significant electrification of heat and transport sectors and large capacity of nuclear generation, to 94% in a business as usual case. Extensive investment in Liquefied Natural Gas import facilities at Milford Haven and the Isle of Grain was shown to compensate for reduction of indigenous gas supplies. Exploitation of shale gas in north England was shown to reduce the gas dependency of Great Britain in the business as usual case to 74%. Electrification of the heat and transport sectors combined with exploitation of shale gas in Great Britain could reduce import dependency to below 10% by 2050. [ABSTRACT FROM AUTHOR]

Abstract: A combined gas and electricity network expansion planning model was developed. Gas-fired generation plants were considered as linkages between the two networks. The model simultaneously minimises gas and electricity operational and network expansion costs. Additionally it optimally places planned power generation plants around the electricity network. Network expansion was implemented by adding new assets such as pipes, compressors, and storage facilities in the gas network and increasing transmission line capacity in the electricity network. The developed model was used to analyse the GB gas and electricity infrastructure expansion requirements to achieve a low carbon energy system. Two scenarios were implemented, a reference and a low carbon scenario. For both scenarios, CGEN defined a network at lowest cost capable of meeting varying demand and power generation capacity profiles. Greater peak gas demand of approximately 25mcm/d by 2030 in the reference scenario resulted in CGEN adding an additional 1Bcm of gas storage capacity compared with the low carbon scenario. LNG gas supplies were shown to account for over 70% of total gas supplies by the end of the time horizon for both scenarios. The combined gas and electricity network planning approach allows analysis into the interactions between these two networks. This interaction allows variables such as total gas supply (gas used for electricity production is an endogenous variable), which 13% higher in the reference scenario and geographic location of gas fired generation to explicitly take account of the impact on both gas and electricity infrastructures. [Copyright &y& Elsevier]

Compressor stations play a crucial role in natural gas networks to maintain required pressure levels for transporting gas. Centrifugal compressors commonly used in high pressure gas transmission networks could be driven by gas turbines or electric motors. Including compressor units powered via different fuels in a compressor station allows switching between fuels required by compressors to achieve a set outlet pressure and flow throughput. In this paper, an optimisation model of gas network was developed considering reasonably detailed representation of a compressor station to investigate flexibility provision from the compressor station to the power system. The model was formulated as a mixed integer linear programming (MILP) problem by linearising the nonlinear equations governing gas flow along pipes and compressor power consumption. The model was tested on the gas transmission system in South Wales, UK. The operation of compressors was optimised in response to gas and electricity price subject to meeting operational limits of the gas network. The results showed that the compressors can provide flexibility to the power system through shifting their electricity energy consumption in time or switching between gas- and electric-driven compressor units. It was found that the allowable range for variation of linepack plays a key role in the magnitude and duration of flexibility provision from compressor units. • An optimisation model was proposed for operation of compressors in the gas networks. • Flexibility from coordinated operation of gas- and electric-driven compressor units were quantified. • The value of linepack in providing flexibility to power systems was investigated. [ABSTRACT FROM AUTHOR]