Flexible nuclear co-generation plant combined with district heating and a large-scale heat storage

Journal Pre-proof Flexible nuclear co-generation plant combined with district heating and a large-scale heat storage Miika Rämä, Martin Leurent, Jean-Guy Devezeaux de Lavergne PII:

S0360-5442(19)32423-5

DOI:

https://doi.org/10.1016/j.energy.2019.116728

Reference:

EGY 116728

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Energy

Received Date: 28 May 2019 Revised Date:

23 October 2019

Accepted Date: 7 December 2019

Please cite this article as: Rämä M, Leurent M, Devezeaux de Lavergne J-G, Flexible nuclear cogeneration plant combined with district heating and a large-scale heat storage, Energy (2020), doi: https://doi.org/10.1016/j.energy.2019.116728. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier Ltd.

Flexible nuclear co-generation plant combined with district heating and a large-scale heat storage Miika Rämä* Energy Systems and Climate VTT Technical Research Centre of Finland PL 1000, Espoo, 02044, Finland e-mail: [email protected] Martin Leurent I-tésé, CEA, Université Paris-Saclay F-91191 Gif-sur-Yvette, France; Laboratoire Genie Industriel CentraleSupelec, Université Paris-Saclay, Grande Voie des Vignes, 92290 Chatenay-Malabry, France e-mail: [email protected] Jean-Guy Devezeaux de Lavergne I-tésé, CEA, Université Paris-Saclay, Centre de Saclay F-91191 Gif-sur-Yvette Cedex, France e-mail: [email protected]

ABSTRACT The paper presents a concept of flexible nuclear co-generation. A plant operating according to the concept can vary its production of heat and electricity by utilising steam on different pressure levels. It is also connected to a district heating system and utilises a large-scale heat storage. France has set long-term targets to increase the share of solar and wind power in the power mix, consequently reducing the share of nuclear power. The flexible co-generation can help the nuclear fleet cope with this change while potentially reducing emissions from the heating sector. High utilisation rate, efficiency and more stable reactor output is targeted. The concept is studied with an optimisation model within the French operational environmental in three case studies of Paris, Lyon and Dunkirk. Total efficiencies of 70 %, 54 % and 34 % are reached, respectively. Cases represent systems with different heat loads and distances from nearby DH systems. Result indicate that both operational flexibility and large-scale storages are heavily utilised. However, compared to the flexibility required by a high-renewable power system, the plants can only play a small part. Also, the current district heating systems need development to utilise a large-scale heat source such as nuclear cogeneration.

*

Corresponding author

KEYWORDS district heating; nuclear co-generation; flexibility; energy systems

INTRODUCTION While climate change mitigation has been recognised as a global challenge [1] with the Paris Agreement in 2015 [2] representing a major international response, implementation of its content remains a formidable task due both to its scale and urgency. The global energy supply is still heavily dependent on fossil fuels, and major greenhouse gas (GHG) emission reductions have to be achieved during the next decade, well before 2030 [3]. Electricity production is one of the most significant sectors where actions are needed. Conveniently, renewable energy sources, especially wind and solar energy, have experienced significant technological development in terms of efficiency and costs. This development and global policy support such as support schemes for renewable electricity production have resulted in rapid growth of both installed capacity and produced renewable electricity. Other major renewable energy sources such as hydro power and biomass will have a part to play as well. As dispatchable forms of electricity production, they are both very suitable for balancing the variable renewable energy (VRE) based electricity production by solar and wind power. However, they do have other issues that limit their potential. Biomass utilisation needs to be evaluated based on its effect on the carbon stock through resource consumption and land use. Hydro power has its own local effects on ecosystems and biodiversity, and its potential has already been met in many developed countries. Other potential renewable technologies include wave and tidal energy, but they are also partly intermittent in production. Another option for an emission-free source of electricity is nuclear power. While having substantial investment costs nuclear power does have low operational costs and produces significant amounts of electricity during its lifetime of 40-60 years. While nuclear power plant can contribute to load-following operations, due to its high investment costs it has the best economic performance when operated as baseload. Due to the undoubtedly increasing shares of wind and solar power, it seems clear that the other forms of electricity production in future energy systems need to more flexible to accommodate the increase even if demand response solution would improve the flexibility of the electricity demand itself. The amount of flexibility required by a specific energy system depends on the share of VRE based electricity production, characteristics of other forms of electricity production, electricity demand profile and the energy system as a whole. Paiho et al [4] review the potential solutions for providing flexibility, identify the need to consider different energy sector holistically and present a review of potential solutions for providing flexibility under the context of the Finnish energy system. District heating (DH) has been recognised as an important element for providing flexibility to the electricity system. Kirkerud et al [5] study power to heat (P2H) concept in Nordic countries in 2030 through the use of electric boilers, finding out that P2H would indeed support the VRE integration. Regions with less flexibility on the supply side like the significant hydropower capacity in Nordic countries could benefit from P2H concept even more.

Vandermeulen et al [6] have performed a literature review concerning the practical exploitation of the flexibility provided by DH through the smart use of control. The paper also recognizes the main sources of flexibility; network itself, thermal inertia of connected buildings and dedicated thermal storage units. This paper focuses on a conceptual design of a nuclear co-generation plant that utilises the heat output of a unit in a more flexible way by connecting the plant with a nearby DH system and combining it with a largescale heat storage. The concept is studied in context of the French energy system. Electricity production and heating sector in France Nuclear power has a dominant role in the French electricity supply. In 2017, the output of the nuclear fleet was 379 TWh, 72 % of the total production. Hydro and thermal power accounted for 10 % and 12 %, respectively. The shares of wind and solar energy were 4.5 and 1.7 %, respectively. [7] The heating sector had a share of 45 % in final energy consumption in France in 2015, space heating and domestic hot water demand was evaluated to be 515 TWh in total [8]. The most common heating systems (2014) are gas and electric boilers with shares of 44 % and 33 %, respectively. The other sources of heat are oil boilers (13 %) and wood (3 %) and DH (7 %) [9]. With a market share of 7 %, DH is not very common but the amount of heat supplied is not insignificant; 25.0 TWh in 2017 [10]. However, compared to e.g. Finland with 33.6 TWh district heating supplied and 46 % market share in 2016 [11], France is still developing its DH systems. The share of renewable or excess heat sources in the total DH supply in France increased from 7.9 TWh in 2009 to 13.8 TWh in 2017. This growth can be partly attributed to the public DH support set up by the government in 2009 offering an incentive of about 5 €/MWh. Eligible projects must have a linear heat density of over 1.5 MWh/m and utilise more than 50 % renewable or excess heat sources as heat supply [10]. French policy objective is to reach 31-36 TWh/a in DH supply based on renewables or excess heat sources by 2030. [12] While nuclear energy continues to have a key role within the French energy and electricity sector, there are plans of a significant increase in wind and solar energy. The Act on Energy Transition for Green Growth [13] sets many ambitious objectives such as decreasing the share of nuclear-based electricity down to 50 % by 2025. A recent French Strategy for Energy and Climate [12] postpones this objective by aiming to close 14 reactors by 2035, starting from 2020. The report also presents the option of building new units. The share of VRE based electricity production will undoubtedly increase in the future energy system, but this development will not significantly lower the specific emissions of the French electricity sector. It could actually result in higher emissions if the required balancing power is produced by natural gas in combined cycle gas turbine plants [14]. Similar result has been also concluded by the French national alliance for energy research coordination (ANCRE) [15], or, more recently, by the national transmission system operator RTE [16]. In a study on nuclear and VRE in the French energy transition until 2030 and 2050, Cany et al [14] showed that when VRE based production exceeds 30 % of the total electricity supply, new solutions are needed for

balancing the production. The study also noted the solar power having a more intense impact than wind power. The increased system costs can clearly be seen in the results. Cany et al concluded that the coproduction of electrical and non-electrical products can help in bypassing this economic issue, while also providing flexibility services to the power system. These co-products include hydrogen and heat. Hydrogen production potential, market and GHG emission reductions have been studied [17] by Cany et al. The potential and possible opportunities are created mainly by the mobility sector. Nuclear based H2 production could reduce GHG emissions by 2-4 % by 2030 and can increase up to 16 % by 2050. The nuclear fleet could supply the H2 demand by 2030-2035, according to the scenarios built by RTE for the French Multiannual Energy Planning (Programmation Pluriannuelle de l’Electricité). The RTE’s future system scenarios with high penetration of solar and wind such Ampére [16] also include high capacities (33 GW export, 27 GW import) for interconnectors with neighbouring countries. Thus, import and export remain the main solutions for balancing the electricity supply and demand, although shares of solar and wind power are expected to increase in other countries as well. Leurent et al [18] evaluated the cost and emission reduction potential of nuclear plant based heating systems for fifteen locations across Europe, including metropolitan areas of Paris, Lyon and Dunkirk. Seven of the fifteen locations were found cost-effective if 25 % of the heat demand would be supplied by a nearby site. Leurent et al [19] has also studied the feasibility of supplying 250°C steam to industrial sinks in France, currently mostly using on-site boilers based on fossil fuels. Suitable locations were found for a costeffective implementation. The importance of social, political, institutional and psychological dimensions have also been emphasised [20]. Jasserand & Devezeaux [21] have shown that there is a significant potential for nuclear DH in France. Use of nuclear based heat has been evaluated to peak in 2050 at 22 TWh/a. Industrial heat loads can increase this potential by additional 45 TWh/a [21].

CONCEPT The concept studied in this paper is a nuclear plant operating in flexible co-generation mode with a connection to a city-wide DH system. Common nuclear plant design aims to maximise the electricity production. While significant amounts of excess heat is available, the temperature level (30-40 °C) makes it less useful for heating purposes. In a normal co-generation nuclear plant often found in the literature, the expansion of steam is stopped early at a higher pressure and temperature levels to provide high enough temperatures (around 100 °C) e.g. for a DH system. In a flexible co-generation unit studied in this paper both high and low pressure steam can be used directly as a source of heat. This feature called bleeding is common in CHP plant design, although not normally implemented to the extent proposed here. In both normal nuclear and CHP plant design, the aim is to maximise electricity production. In existing nuclear plant designs, part of the high pressure steam is already used for superheating the steam coming out of the first turbine. The flexible unit is also equipped with a heat storage between the plant and the DH system, enhancing the flexibility of the unit. The reactor load is more stable while the electricity output can vary. A similar principle has been examined by Denholm et al [22]. However, in their work the heat storage is located in a separate circuit between the steam generation and the Rankine cycle. Edwards et al [23] analyse different heat storage technologies in a design like proposed by Denholm et al.

In normal operation, the minimum thermal output of the reactor is 20 % of the given maximum capacity. This minimum output rises up to 100 % during the last third of the fuel cycle due to boron dilution [24]. The same assumption was also used by Cany et al [14]. Fuel cycle length is assumed to be 12 months for the included units with the maintenance break assumed to take place during the summer to minimise the impact on heat supply. The rising minimum thermal output of the reactor at the end of the fuel cycle means that the output is not cannot be reduced below a certain level. If there is no heat demand, the thermal output is either wasted by running the unit in normal condensing mode or the unit is shut-down. If the low pressure steam is used for heat production, the electricity production is cut similarly than in normal nuclear co-generation. The share of electricity production capacity of the high pressure turbine (HPT) and the remaining turbines is assumed to be 25 % and 75 %, respectively. The 75 % is further divided between intermediate pressure turbine (IPT) and low pressure turbine (LPT) according to enthalpy values corresponding to a temperature of 100 °C during low pressure steam expansion in a normal NPP. This approach results in 61.5 % and 38.5 % shares between IPT and LPT based electricity production capacity. The heat loss representing the thermal output of the reactor that is not useful for electricity production or heat production due to the low temperature level is assumed to be 5 %. The concept is visualised in Figure 1 as components and energy flows between them.

Figure 1. Principle of the flexible nuclear co-generation concept.

The DH production capacity is restricted by the capacity of the pipeline supplying heat to a connected DH system. The specific capacity is calculated based on both the DH demand and the investment required for the pipeline. The heat storage capacity is linked to the pipe line capacity enabling 6 hours of production, e.g. 2 200 MW transmission pipeline resulting in a 13 200 MWh storage. Although massive, this scale is still possible to implement as a water-based sensible heat storage; e.g. largest specifically built unit found in a literature review was 100 000 m3, roughly 7 000 MWh [25]. In Helsinki DH system, there are plans for a 260 000 m3 storage in a rock cavern used before as an oil storage [26] although it is likely that similar opportunities are not available within the sites. The aim is not a seasonal heat storage although for smaller DH systems the scale would indicate one. The purpose is to provide short-term flexibility to react to changes in electricity demand. If prices are low, heat is stored. If high, electricity production is prioritised should the heat demand allow this.

MODELLING METHOD The concept is modelled as a mixed integer linear programming (MILP) model. Open Energy System Modelling Framework (oemof) [27], an open-source Python based package for energy system modelling and optimisation is used for defining the model. The optimisation problem is solved by an open-source solver Coin-or branch and cut (CBC) [28]. The model developed consists in a specified number of flexible nuclear co-generation plants (FlexNPPs) connected to a DH system with a specified heat demand. The plants also produce electricity for a price defined as year-long hourly time series. According to the oemof modelling principles, the model is defined as sources, sinks, transformers, storages and connections called buses between these. The sources are the resources like nuclear and combustible fuels. The sinks are the DH demand, produced electricity and losses. Transformers are the conversion processes either within the FlexNPPs or the heat-only production by combustible fuels. Heat-only boilers (HOBs) are included as a peak and a backup heat supply option. Storages represent the heat storages between a FlexNPP and a DH system. Figure 2 illustrates the main elements for a case with a single FlexNPP included. The storage component is in practice within the FlexNPP itself, but highlighted here as it is considered to be part of the heat supply.

Figure 2. DH system supplied by HOBs and a FlexNPP (Figure 1) unit with heat storage.

Each FlexNPP has a specified electricity production capacity, assumed electricity production efficiency, share of unusable excess heat due to low temperature level, minimum and maximum thermal output time series for the reactor, including a shutdown period for refuelling and maintenance. Also pipeline capacity for supplying DH to a connected DH system and the capacity of heat storage units are given.

CASE STUDY: FRANCE Three specific sites have been selected for studying the operation of FlexNPPs due to their proximity to a large city with an existing DH system that could be expanded in the future. The sites are Nogent-sur-Seine (Paris), Bugey (Lyon) and Graveline (Dunkirk). One unit per site is considered. As the current district heating systems other than Paris are relatively small compared to the heat potentially available from a nuclear plant, only future systems are considered.

The heat demand time series are generated by scaling a typical French heat demand time series based on Grenoble DH system to match the estimated future yearly heat demand by Leurent et al [18]. The evaluated Paris heat demand corresponds to the City of Paris. Including the surrounding suburbs could increase this potential up to 50 TWh. Table 1 summarises the main properties of the systems studied. When calculating the maximum thermal output of the units, a 33 % efficiency for electricity generation is assumed. Table 1. Main properties of the systems studied.

Site (location) Nogent-sur-Seine (Paris) Bugey (Lyon) Graveline (Dunkirk)

Unit capacity 1 310 MWe 910 MWe 910 MWe

Distance to city 90 km 30 km 15 km

Future DH demand 19 839 GWh 5 686 GWh 734 GWh

Figure 3 illustrates the full load hours (FLHs) and heat supplied as a function of transmission pipe capacity. In terms of heat supplied, all systems start to become saturated with higher transmission pipe capacities.

Supply (Lyon)

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Transmission pipe capacity (MW) Figure 3. FLHs (dashed line) and heat supplied (solid line) as a function of transmission pipe capacity for Paris, Lyon and Dunkirk cases.

While higher transmission pipe capacity enables more heat to be supplied, it also results in more investment costs. The pipeline investment costs are evaluated according to an equation proposed by Hirsch et al [29], giving the investment costs as a function of pipe diameter. The diameter is calculated according to a set design pressure drop (1 bar/km) for a given transmission pipe capacity. In calculation of the mass flow, a temperature difference of 80 °C (110 °C supply, 30 °C return) is used. Also based on work by Hirsch et al [29], investment costs for pumping stations (3.5 M€/station) are included. Station costs are deducted from Paris case data and calculated separately according a principle of having one station per 10 km pipeline.

A previous case study for Paris [21] used total costs of 9.5 M€/km. A Finnish case study for a heat transmission pipe between city of Helsinki and nuclear site in Loviisa used cost data of 10 M€/km for a 1200 mm diameter pipe [30]. The investment costs according to the Hirsch equation are higher. There is clearly some uncertainty on costs. Finally, the investment is considered as an annuity with a lifetime of 25 years and interest rate of 4 %. The interest rate used is in line with recommendations by European Commission [31]. Other costs arise from pumping electricity consumption, heat losses and maintenance. Pumping electricity consumption (Ep) is calculated with the equation (1). ‫ܧ‬௣ =

௏ሶ ௗ௣ ఓ

(1)

where µ is the average pump efficiency (0.70) and the volumetric flow rate ொ ܸሶ = ୼்௖

(2)

೛ఘ

and pressure drop ொ ଶ

݀‫ = ݌‬൬0.9 ቀொ ቁ + 0.1൰ ݀‫݌‬଴ బ

(3)

Q is the hourly heat demand (W), ΔT the temperature difference (K), cp the specific heat capacity (J/kgK), ρ the density of water (kg/mଷ ) and Q0 design heat demand (W), i.e. transmission pipe capacity, and dp0 the design pressure drop (Pa). The design pressure drop is defined as 1 bar/km. Heat losses are not significant compared to the other cost elements (0.6 % to 1.9 % of total costs) and are evaluated in a simplified method taking only into account the thermal resistance of the insulation layer, assumed to be 20 cm thick. The temperatures (supply and return pipes, ground) are assumed constant. Ground temperature of 10 °C is used. Conductivity for the insulation material is assumed as 0.027 W/mK. Yearly maintenance costs are assumed as 2 % of the total investment. The benefit in revenue for using nuclear based heat instead of other alternative heat sources is assumed to be 30 €/MWh. The average price level of DH in France was around 65 €/MWh in 2013 [32]. Gas price for households in 2018 were around 67 €/MWh [33]. Given the very low operational costs of nuclear heat production (~20 €/MWh), the assumed revenue seems reasonable. When compared to individual gas boilers, the value could be even higher. This assumption is not the profit made, but the value for revenue used in calculating the profitability. The results of the profitability calculation is visualised in Figure 4 with the same ranges for transmission pipe capacities as in Figure 3.

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Transmission pipe capacity (MW) Figure 4. Indicative yearly profit as a function of transmission pipe capacity for Paris, Lyon and Dunkirk.

Based on the results transmission pipe capacities of 2 200 MW, 1 300 MW and 200 MW are chosen for Paris, Lyon and Dunkirk systems, respectively. It must be noted that the profit curves are indicative and remain very sensitive to cost and revenue assumptions. However, the method provides a systematic way to assess a reasonable capacity for the transmission pipe. Due to the size of the DH system and the distance between the city and the site, Paris is the most sensitive to the most important parameters in calculating the cost-optimal transmission pipe capacity; revenue and interest rate. If interest rate would 1 %-unit lower or higher, the transmission pipe capacity would be 2 600 or 1 400 MW, respectively. In Lyon, the higher interest rate would decrease the capacity by 100 MW. In Dunkirk, there would be no change. Revenue assumption of 35 €/MWh would increase the capacity for Paris system by 800 MW while other locations would not change. Decreasing it to 25 €/MWh would make Paris system infeasible as smallest possible system would be the best option, capacity in Lyon would decrease by 100 MW and Dunkirk by 50 MW. The electricity price time series are based on work by RTE and correspond to the scenario Ampére [16] representing a scenario for year 2035 with significant reduction of nuclear capacity (48.5 GW) and high renewable electricity production capacity (149 GW). While numerous time series are used in RTE’s scenario work, the modelling in this paper is based on a single, representative example year. The choice of a year is based on the average price level and average number of sharp peaks and valleys in electricity prices.

RESULTS Shares of the different heat supply in Paris, Lyon and Dunkirk district heating systems are illustrated in Figure 5. The total DH demand is 19 839 GWh, 5 686 GWh and 734 GWh for Paris, Lyon and Dunkirk, respectively. Direct use is district heating used at the time of production at the site.

Figure 5. Yearly DH supply distribution between direct use, storages and HOBs for Paris, Lyon and Dunkirk systems.

Figure 6 presents the heat supply in Paris system in both hourly and monthly time resolution. The heat demand in Lyon and Dunkirk systems follow the same shape, but the shares of storage and HOBs are different. The figures on Lyon and Dunkirk would be of the same shape, but with a larger share of nuclear based heat.

Figure 6. Hourly (left) and monthly heat supply in the Paris system.

Figure 7 shows the monthly electricity and heat (steam in three pressure levels) production and losses for the systems. Overall yearly efficiencies are 70 %, 54 % and 34 % for Paris, Lyon and Dunkirk, respectively. Lyon

Dunkirk 3 000

2 500

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Heat losses

Figure 7. Energy production of flexible nuclear co-generation units in Paris, Lyon and Dunkirk.

Table 2 summarises the heat storage operation in all studied systems. Number of cycles indicates how many times a storage unit is loaded (and unloaded); a common metric on the utilization of storages.

Table 2. Summary of key results concerning heat storage operation in Paris, Lyon and Dunkirk systems. Annual storage cycles

Annual savings

Payback

Capacity

105 109 143

41.5 M€ 25.5 M€ 5.15 M€

3 years 3 years 2 years

13 200 MWh 7 800 MWh 1 200 MWh

Paris Lyon Dunkirk

Annual savings are based on an assumption that the stored heat would replace 30 €/MWh more expensive heat source. The estimation is based on the costs of industrial use of natural gas [33] and production costs of a nuclear plant in France [34]. An alternative evaluation could be the value of the stored heat and price of electricity. This varies throughout the year, but 30 €/MWh is a reasonable estimation for this as well. Payback time does not take into account any interest or discount rate. Investment costs for a sensible thermal storage range from 0.1 to 10 €/kWh [35]. Here, a specific investment costs of 10 €/kWh is assumed. Figure 8 and Figure 9 illustrate the operation of the FlexNPPs and the system during example weeks in winter and summer time, respectively. The left column presents the shares of output for each units, divided between electricity produced by the turbines and heat from different pressure levels. Lost heat is also included. The middle column sums up the electricity and heat production of a unit and presents the reactor utilization rate. The right column shows how the corresponding district heating demand is supplied and also presenting the electricity price. In summer time examples, Paris and Lyon units are partly in shut-down. Paris HP steam

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Figure 8. Energy flows within the FlexNPPs (left column), electricity and heat output with utilisation rate (middle) and heat demand and supply (right) for Paris, Lyon and Dunkirk systems during winter time (week 4).

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LPT elec.

Utilisation rate

IPT elec.

Output (MW)

Shares in output

HPT elec.

140 120 100 80 60 40 20 0 -20

250 200 150 100 50 0 0

12

24

36

48

60

72

84

96 108 120 132 144 156

Hours

Figure 9. Energy flows within the FlexNPPs (left column), electricity and heat output with utilisation rate (middle) and heat demand and supply (right) for Paris, Lyon and Dunkirk systems during summer time (week 31).

DISCUSSION The studied systems represent three different cases in terms of heat demand and distance from the city. The heat demand corresponds to a potential for heat utilisation and distance has a direct impact on the investment costs. This leads to different profits for the three systems (Figure 4). The Paris system potentially has a massive heat demand, but the distance from the site is 90 km and thus the implementation of the transmission pipe would require a substantial investment. The Dunkirk site is very close to the city area (15 km), but the district heating demand is expected to be low compared to the heat output of a nuclear unit. Lyon falls in between these two in both heat demand and site distance. Also the available thermal capacity is different; close to 4 000 MWth in Paris and little less than 3 000 MWth in Lyon and Dunkirk. Figure 7 shows the monthly electricity produced by each turbine and how steam is used as a heat source. Due to a high heat demand and a high capacity transmission pipe, Nogent-sur-Seine unit near Paris can make use of much of the heat. Other two cities less so. This is also reflected in the overall efficiency of the units; 70 %, 54 % and 34 % for Paris, Lyon and Dunkirk, respectively. Compared to the electricity generation efficiency of 33 %, both Paris and Lyon units operate at a high efficiency. Intermediate pressure steam between the high and low pressure turbines is rarely used as a heat source. This might indicate that having this option available is not reasonable. While LP steam is mostly used as a hear source for DH, the use of HP steam is linked directly to the flexibility due to the impact in varying the power output. This makes it a relevant part of the concept despite not being utilised as much. Figure 7 also shows an increase in lost heat during the last three months of the fuel cycle, just before the maintenance break. This is due to the increasing minimum output of the reactor. Paris system is different in this respect due to a 72h shutdown during the last month.

As indicated in the description of the concept in Figure 1, in this paper the heat storage is assumed to be located at the plant site. The heat storages at each site are actively used with 100 or more cycles per year as presented in Table 2. The payback time of 2-3 years based on the assumed benefit of 30 €/MWh and the specific investment of 10 €/kWh seems very reasonable. The storage acting as a buffer clearly improves the operation of a flexible co-generation unit. However, more research is needed to determine whether a storage unit should be located near the city and connected directly to the district heating network or near the nuclear site. From a heat supply point of view, storage located near the city would enable its use as a separate heat source and ease the bottleneck of the transmission pipe capacity. This would also reduce the required investment. On the other hand, finding space for a large scale unit could be a problem. Located near the nuclear plant, space would not be a problem and there would be an opportunity to make use of the high temperature storage solutions. The site location would also enable both transmission pipe and the storage to be used as heat sinks. Having storages in both ends of the transmission pipe is an option as well. Figure 8 and Figure 9 illustrate the operation of the flexible units as two example weeks for all systems during winter and summer, respectively. During the winter week example, all units experience two periods when they ramp down the reactor output due to very low electricity prices and switch to heat-only production. Also especially in Lyon and Dunkirk systems, there are hours of electricity-only production during peaks in electricity prices. Figures also show how the periods of lower electricity prices are used for loading the heat storage. The winter week example also shows the difference between the DH systems; the high Paris heat demand allows higher utilisation of the available heat compared to sites in Lyon and Dunkirk. During the summer week example, similar behaviour than during winter can be observed. However, the use of heat storages in heat supply is more visible as they can supply the entire heat demand for longer periods of time. Like in winter time, storages are loaded during periods of low electricity prices. In the case of Paris, this also prevents ramping down the reactor output. In addition to reacting to low electricity prices, the units can also prepare for expected high electricity prices. Storage can supply the heat needed while unit runs on full electricity production capacity. Both in winter and summer example weeks, the reactor output is ramped down and up again a few times. Although not specifically modelled, the results show that the units operate in any case according to the common safety principle of not having more than one up and down cycle during 24h. One potential advantage of the studied concept and nuclear co-generation in general is the potential for greenhouse gas emission reductions. This depends on which heat source the emission-free nuclear heat is replacing. There also might be reasons why replacement is not feasible such as local waste incineration plant heat supply, depending on heat demand and waste incineration output. However, the scale of potential emission reduction can be calculated. All three studied units produce 18 686 GWh of heat. If the same amount of heat would be produced by natural gas, assuming a constant efficiency of 85 %, the GHG emissions would be 4.4 Mt. Emission calculation for municipal waste is not as straightforward, but for combustion only it would be 6.3 Mt. However, not burning the waste will cause some emissions as well. All DH systems included in the case studies need development both in terms of size and efficiency. This could be a major factor in improving the efficiency and reducing the emissions from the heating sector, regardless of whether nuclear co-generation will be implemented or not. The renovation and extension of

the DH systems and improving the efficiency of the older buildings within the cities is a major task on its own.

CONCLUSIONS The paper presented the concept of flexible nuclear co-generation concept where the steam generated by a nuclear unit could be used in both electricity generation and as a heat source e.g. for DH in the studied cases. The concept also includes a large-scale heat storage. The concept was tested for supplying DH for three cities in France; Paris, Lyon and Dunkirk. The locations were chosen due to their existing district heating systems with potential for expansion, and proximity to a nuclear site. They can be considered as the most promising candidates for nuclear co-generation in France. Distance between the site and the city district heating demand are the main elements for evaluating the economics of nuclear co-generation. However, the flexible nuclear co-generation concept can further improve the economic performance both by enabling balancing services for the power system and by combining cheap heat supply with heat storage capabilities. The results indicate that concept could be of interesting in France for the implementation with large reactors, typically 900 MW or more in electricity production capacity. The findings are also relevant in respect to the decision by the French government in 2021 on whether to launch a new nuclear programme or not. The economic benefits and the emission reduction potential could be worth considering new NPPs as cogeneration units. It is likely that new sites will not be established, making the presented three locations in Paris, Lyon and Dunkirk the most reasonable options for implementing NPPs according to the FlexNPP concept. If a new location would be an option, the vicinity of a large-scale DH system should be an important factor for the decision. However, the maximum instantaneous flexibility provided by three units (3 530 MW) is still small compared to assumptions on e.g. the VRE based electricity production (115 GW) or interconnector capacities (27 GW for import, 33 GW for export) used in scenario studies [16] with high penetration of renewables. There are several aspects of the concept that require further research; details on the technical implementation and economic evaluation of the needed plant-level changes, suitable heat storage solutions, possibly taking advantage of higher temperature steam to reduce the volume and space requirements and a full scale sensitivity analysis of the investment as a whole. Also, due to the large heat output of an existing or a new NPP (e.g. EPR2 design; 1 600 MWe, almost 5 000 MWth) and the costs related to the long distance heat transportation pipeline, an interesting point of comparison for the study would be small modular reactor design (SMR). These type of smaller plants could possibly be built closer to DH demand, decreasing the investment cost of the transportation pipeline. They could also be easier to integrate with existing DH systems due to the lower heat output. This option has been investigated by Lindroos et al [36] in the context Helsinki DH (and cooling) system. The findings identified SMRs as a feasible solution for heat supply. Work is also required to find out technical solutions and economic basis for developing the French district heating systems as a prerequisite for a large scale utilisation of a heat source as massive as nuclear heat. Also, in the case of Paris a section of the distribution network is based on steam as the heat transfer medium. This would most likely require a full renovation of even the existing infrastructure.

NOMENCLATURE DH

District heating

FlexNPP

Flexible nuclear co-generation plant

GHG

Greenhouse gas

HPT

High pressure turbine

IPT

Intermediate pressure turbine

LPT

Low pressure turbine

HOB

Heat-only boiler

NPP

Nuclear power plant

VRE

Variable renewable energy

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Highlights • • • • •

A flexible nuclear co-generation concept with is presented The concept includes a large-scale heat storage and a connection to a DH system Operation of three case systems are studied in context of the French energy system Optimisation results indicate that flexibility is utilised frequently Developing and extending the existing DH systems in Paris is required

Declaration of interests ☒ The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. ☐The authors declare the following financial interests/personal relationships which may be considered as potential competing interests: