In Vilnius city, when there is insufficient heating capacity from independent heat producers, natural gas is utilized to address heat demand peaks. A study has been conducted to evaluate the potential feasibility of employing a thermal energy storage system charged with renewable energy as an alternative to relying on natural gas for managing heat peaks. Peak heat demand occurs during the period from November to April, correlating with outdoor temperatures falling below 0°C.
The idea revolves around the Power-to-Heat (P2H) model, where surplus electricity is transformed into heat. Given the intermittent nature of excess electricity, a thermal energy storage system is typically employed. The type of storage varies based on the application, ranging from seasonal to diurnal setups.
Two scenarios of this system were modelled: one with seasonal thermal energy storage and the other with a diurnal storage configuration.
In the seasonal scenario, a pit thermal energy storage (PTES) solution was chosen, a technology successfully deployed in various projects of comparable scale in Denmark. It is estimated that at least 3 million m³ of PTES capacity would be needed to avoid the combustion of natural gas to cover the heat demand peaks in Vilnius.
Due to limitations in land area at TEC-3 site (Vilnius 3rd CHP plant), the selected storage volume for this study is 200,000 m3. Storage medium is water with temperatures reaching up to 90°C. The PTES addresses 5% to 9% of the total heat demand peaks, varying based on the storage temperatures. When coupled with a MW-scale heat pump, this storage system has the potential to provide up to 22 GWh of heat to the district heating network.
The storage is charged during the period from May to October, leveraging surplus electricity primarily generated by increased solar power production. During this time of the year, surplus electricity is evident during both night-time and mid-day hours. Therefore, the storage is charged during these hours. A MW-scale electric water heater is employed for the charging process. The storage temperature at the end of the charging period varies from 46 to 88°C, depending on the mode, which is based on preferred coefficient of performance (COP) of the heat pump. The average (seasonal) COP ranges from 3 to 5 for different operational modes of the system.
The discharge of heat from PTES takes place through two approaches: one entails direct heat exchange with the district heating network when the storage temperature is sufficiently high, while the other employs a heat pump to raise the water temperature to the necessary level. The discharge process is initiated solely in instances of increased heat demand. The seasonal efficiency of PTES is 70% to 80%.
Another scenario that was contemplated for seasonal thermal energy storage involves utilizing heat from solar thermal collectors. To achieve an equivalent thermal energy output for district heating, a total of 41,500 m2 of solar collectors is required. While more complex with a greater number of system elements and considerably higher capital expenditure, this system is less dependent on electricity market prices. Several solar district heating projects incorporating seasonal thermal energy storage have been implemented in Denmark and Germany. The heating prices ranged from 37 to 88 €/MWh, depending on the interest rates and availability of investment subsidies. In Denmark, each municipality provides loan guarantees for renewable district heat projects, mitigating the risk associated with long-term investments. This makes it possible to secure an exceptionally low interest rate ranging from 0% to 3% for a long duration, like 25 years.
In the scenario of diurnal system operation, two modes were considered: addressing 5% to 17% of total heat demand peaks and 100% of peaks. The diurnal system enables the coverage of 100% of demand peaks as it can recharge daily, eliminating the necessity for a large storage volume. Utilizing tank thermal energy storage (TTES) is cost-effective for volumes of up to 10,000 m3. For this study, a tank with a volume of 3,700 m3 was chosen to address up to 17% of peak heat demand.
The charging and discharging process is analogous to seasonal operation, with the only difference being that the storage facility is charged during the night when electricity prices are typically lower in winter. Simultaneously, it is discharged when there is the highest heat demand in the centralized heating supply system.
To address 100% of peak demand, the previously mentioned PTES technology with a volume of 21,500 m3 has been chosen. The system operates identically, the only distinction lies in the scale of each component, as well as power consumption and output.
Initiatives associated with heating using renewable energy sources receive subsidies from funds like the EU's Innovation Fund and Modernisation Fund. Funding for the projects can cover over half of the capital expenditures.
Considering capital and operational expenditures, a 4% interest rate and a project lifetime of 25 years, levelized cost of heat (LCOH) was calculated. The seasonal thermal energy storage scenario, which relies on surplus electricity in summer for charging, faces limited competitiveness compared to heat supplied by other independent providers, where the LCOH is predominantly influenced by biofuel prices. In 2023, the cost of heat in Vilnius was around 50 €/MWh. The competitiveness of the LCOH is evident only when factoring in a 60% subsidy for capital expenditures (CAPEX) and the average price of electricity in charging and discharging periods is significantly lower than those observed in 2023. In the case of heat generated by solar thermal collectors, the LCOH is more susceptible to subsidies due to higher CAPEX of the system. Hence, the heat cost, without factoring in the subsidy, exceeds a competitive range.
The diurnal systems are more economically feasible, with the CAPEX having a less pronounced impact on the LCOH. The drawback of the diurnal systems is that they produce the most of heat during the winter when electricity price is usually higher, primarily due to increased demand and the absence of solar generation.
The LCOH for the studied systems is significantly more competitive when compared to the cost of heat produced by gas-fired boilers that are currently covering demand peaks.
The potential of providing services such as manual or automatic frequency restoration reserves (mFRR/aFRR), or flexibility services could improve the economic viability of such P2H projects. However, this has not been analysed in the scope of this study.
The appeal of renewable district heat projects can be enhanced by innovative solar thermal, heat pump and energy storage technologies, along with the next generation low-temperature district heating systems with supply temperatures of between 50°C and 70°C. This temperature range is significantly lower than the 70°C to 120°C used in conventional district heating systems, such as here in Lithuania. This reduction of temperatures allows to minimize heat losses and enables the use of low-grade heat renewable sources, such as surplus renewable electricity (P2H) and solar thermal energy.