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The sizing of solar district heating (SDH) systems with pit thermal energy storage (PTES) and heat pumps (HP) is conventionally performed using detailed tools (e.g TRNSYS, Modelica etc). While accurate, these simulations are computationally intensive and unsuitable for large parametric studies due to large simulation time. Traditional thumb rules, such as fixed collector-to-storage ratios expressed in m²/m³, are often used as a shortcut but become unreliable when the load profile or integration constraints deviate from standard assumptions. For example, when PTES discharge is limited by the pipe diameter at the integration point, the achievable solar fraction and storage utilization can differ substantially from conventional design guidelines. Such conditions necessitate case-by-case evaluation, for which a fast sensitivity tool can provide valuable guidance. We propose a two-stage methodology. In the first stage, a Python-based model is developed which integrates solar collectors, pit thermal energy storage, and a heat pump, resolving hourly boundary conditions with sub-hourly thermo-hydraulic dynamics. The tool performs random sampling across a million combinations of component’s sizes which enables rapid evaluation of energy balances and techno-economic indicators. In the second stage, only the most promising configuration(s) are re-simulated in TRNSYS, where collector physics, diffuser layouts, hydraulics, and soil–storage coupling are fully represented. This workflow provides a computationally efficient yet physically consistent approach for robust SDH system sizing, offering a faster alternative to direct TRNSYS optimization while maintaining reliability.

Electric vehicles (EVs) and solar photovoltaic (PV) systems pose challenges to existing power grids, which were often not designed to accommodate such large loads or local generation. With growing adoption of these technologies, hosting capacity (HC) studies are essential for understanding their impact and supporting future planning. However, combined HC assessments of EVs and PVs remain limited compared to studies treating the technologies separately, particularly when accounting for spatial uncertainties, temporal correlations, varying implementation levels, and different charging strategies. This study addresses this gap by applying a broadly applicable method for calculating the HC of EVs and PV systems in a Swedish residential grid. A combined time-series and stochastic approach was used across multiple scenarios, supported by geographic information system-based (GIS-based) PV potential analysis. The analysis is based on real-world data and performed as a case study, providing new insights into joint EV-PV integration. Results show that spot price-based charging resulted in the most frequent violations. Evenly distributed charging was the most grid-friendly strategy in winter, while PV generation caused significant violations in summer regardless of charging strategy. Under the even charging strategy, the average number of unique buses with voltage violations during summer was 11–63 times higher than during winter. This is because the strategy uses low power, limiting the impact of EV charging, while high uncontrolled PV production in summer becomes the main driver of voltage problems. The findings highlight the need for strategic charging strategies and additional measures to manage the grid impact of high PV implementation. © 2026 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY license. http://creativecommons.org/licenses/by/4.0/

Energy storage systems for family dwellings such as thermal and battery energy storage systems are of significant interest for several reasons, particularly in the context of increasing renewable energy adoption, ensuring grid resilience, and reducing environmental impact. This study examines the potential life cycle energy savings and environmental impacts related to the addition of the two energy storage technologies namely thermal such as a domestic hot water tank (DHW) and electrical which is a battery bank and attempts to evaluate the contribution of each component to the whole life cycle impacts. Moreover, the use of a second life electric vehicle Li-on NMC battery bank is examined as an optional replacement of a stationary battery bank LiFePO 4 . For a reference case is used a detached single-family house with a roof top photovoltaic system which has a compact exhaust air heat pump system to provide the hot water and space heating annual demand for the Swedish climate conditions. High resolution weather data and historic price data for the same year as well as stochastic occupancy profiles that include the domestic hot water load are used as boundary for a parametric simulation study for the system modelled in detail in TRNSYS 17. Main results show as far as the life cycle cost comparison that thermal storage has the least life-cycle cost among the three examined energy storage options. Examining the global warming potential of the first life of the electrical storage is found to be approximately more than 5 times the impact of the domestic hot water tank comparing the specific products from the two storage types.

District heating (DH) systems in Sweden are facing growing challenges due to rising biomass prices and uncertainty surrounding future supply availability. Integrating solar thermal collectors with pit thermal energy storage (PTES) offers a promising pathway for reducing dependence on biomass and improving system sustainability. However, the optimal integration and techno-economic performance of such systems under real-world limitations (such as spatial and hydraulic constraints) remain largely underexplored. This study develops a two-stage modeling framework to evaluate solar + PTES integration while accounting for practical constraints such as sitting feasibility and discharge power limitations. A Python-based simplified model first generates a sensitivity matrix mapping heat delivery performance across a wide range of collector areas and storage volumes, which guides the selection of PTES sizes for subsequent detailed modelling in TRNSYS. Three system configurations are analysed: a real-world case with waste heat and pipe limitations, a generalized case without waste heat but with pipe constraints, and an ideal case without any integration barriers. Monte Carlo simulations and sensitivity analyses are performed to quantify economic uncertainties and identify key influencing factors. Results show that discharge power limitations and pipe constraints significantly penalise the system performance, leading to higher levelized costs of heat (LCOH) compared with the ideal benchmark. The findings highlight the necessity of simultaneous consideration of spatial and techno-economic constraints to achieve cost-effective solar fractions and optimal storage design in real-world DH systems.

Large-scale solar district heating has increased fast recently and is a commercial industry in Denmark with over 100 systems. Pit stores with high solar fraction exist in several of these systems. Some economic factors in Sweden are not as good as in Denmark. However, recent events have forced up the price of biomass in Sweden and other competing uses for the forest resource point to greater competition and thus higher prices, resulting in better viability for solar. The project has used geographic and geological data from e.g. SGU to identify which areas in Sweden that are potentially suitable for pit stores. The results from the screening process show that the vast majority of district heating areas have potentially suitable areas for pit storage within a reasonable distance from the network. Only 86 district heating areas do not. As there is no reliable data for the whole country for ground water level and flow, both important factors for economic viability, the results are optimistic. As to be expected, the results show large variations over the country, but in general there are more suitable areas in the south than north. The project also estimated how much heat solar and pit storage systems could potentially deliver to the district heating areas with suitable areas. If all of these identified district heating areas installed solar and pit storage systems covering 20% of their demand, 15% of Sweden’s total district heating demand would be supplied by solar. If all networks with potential areas for pit storage installed systems covering 40% of the local demand, the equivalent figure is 36%. Pre-feasibility studies for Råneå, Härnösand and Söderhamn show that the heat cost for solar heating systems is slightly higher than the current production heat cost in these networks, given the current interest rate. As the heat cost for solar is mostly dependent on the investment cost, it varies over time in principle only with the interest rate. A lower interest rate or small annual increases in fuel costs would make the studied solar heating systems economically viable. Costs, as for many other technologies, are lower for larger systems. Integration of a heat pump in the system is cost effective if the site of the pit store is in the periphery of the network and the district heating system has exhaust gas condensation. In practice there are many additional factors that can hinder building a pit store in the sites identified as suitable in the screening. The results of the screening are theoretical and are based on the assumption that none of these negative factors exist. Detailed on-site geological measurements are needed if one wants to take the next step in actually building a pit store.

For Sweden, a country with one of the most developed district heating sectors in the world, the continued decarbonisation of central heat supplies and the contemporary development towards lower heat distribution temperatures is generating increased interest in large-scale seasonal thermal energy storage technologies. By virtue, not only of energy storage, but also of load shifting and peak shaving capabilities, seasonal storages are recognised today as key components in highly integrated and smart energy systems but have so far seen very limited application in Sweden. Given that Denmark, neighbour to Sweden and with a district heating development on par, is a world-leader in the application of pit thermal energy storages (PTES), this paper aims to initiate investigations into the possibilities for a similar application in Sweden. A spatial analysis sequence, akin to indicator modelling, identifies suitable areas for the construction of PTES by elimination of non-suitable areas based on a set of input data parameters and associated selection criteria, all within cost-effective heat transmission distances of aggregated district heating areas. The national potential in terms of available suitable land, expressed and discussed here by two model extremes scenarios, is generally high, but with local variations and with a characteristic latitudinal difference.

District heating (DH) is a key component of Sweden’s heating infrastructure, more than half of which is currently reliant on biofuels. However, recent energy scenarios from the Swedish energy agency (March 2025) project up to an 80 % reduction in biomass use by 2035, creating an urgent need for alternative heat sources for district heating. Solar thermal collectors and heat pumps combined with short- and long-term storage represent a promising solution, yet their optimal integration and performance remain largely underexplored in the Swedish DH context. This study presents a techno-economic analysis of integrating solar thermal collectors, pit thermal energy storage, and a heat pump in the Härnösand DH network. A multi-stage simulation approach combining simplified (in Python) and detailed (in TRNSYS) models was used to optimize system design. Geological assessment and hydraulic constraints identified a DN400 feed-in pipe as optimal. Results show that a 35 % solar fraction minimizes the levelized cost of heat (LCOH), with an optimized system comprising 102 000 m² of collectors, 325 000 m³ PTES, and a 5 MW HP. The LCOH of the evaluated system is 70 €/MWh at 5% discount rate for 20 years. The study highlights the importance of accounting for practical constraints including feed-in pipe size, geological conditions, PTES location, and integration strategy for achieving cost-effective solar district heating integration in Swedish networks.

This paper is the second of three accounts which describes a Swedish study aiming to derive a first order assessment of the national potential for large-scale solar thermal heat production with pit thermal energy storage’s (PTES) connected to existing district heating systems (DHS). Whereas the first paper presented project objectives, outset parameters, and an updated Swedish district heating database – and the third is planned to report on the final project results and conclusions – this paper focuses on the assembled study data and the associated selection criteria applied to these data categories under the objective to distinguish suitable (and non-suitable) land areas within cost-efficient heat transmission distances from the existing DHS. The approach centres around a principal spatial analysis with superposition of study data and elimination of non-suitable land areas according to the used selections criteria but also entails a wide periphery of related activities, such as literature reviews, gathering of technology preferences, meetings with sector experts, data management etc. Apart from technical specifications for solar heat production and seasonal storage, key data categories for the spatial analysis consist of geological data (e.g. soil types, soil depth, bedrock etc.), hydrological data (lakes, rivers, wells, soil moisture, ground water levels etc.), geographical data (elevation, built-up areas, administrative units etc.), and thematic data (energy statistics, building heat demands, district heat deliveries etc.). Selection criteria for the relevant data categories have been definediteratively during e.g. expert consultancy, for example minimum soil depth, preferred soil types, maximum feasible transmission distance to existing DHS etc. By application of the selection criteria, raw input data are converted to processed data extracts to be used in the final analysis. Study data categories are illustrated and summarised (raw and processed) together with a listing and discussion of the used selection criteria.

Sweden was among the first countries to install solar thermal plants for district heating (DH) as early as in 1970s. However, in recent years, the focus on solar DH installations has shifted primarily to Denmark and Germany, with only one recent installation reported in Sweden. Nonetheless, due to changes in the overall heating market, the use of large-scale storage (both with and without solar heat) is becoming increasingly important. Despite significant advancements in adopting DH systems, the combination of solar DH with PTES is not well studied from Swedish context. The economic and geological prerequisites for the deployment of PTES remain largely unexplored. This paper explores the integration of large-scale solar thermal systems into DH networks in Sweden, particularly highlighting the feasibility and potential of pit thermal energy storage (PTES) systems. Through findings from a national project, this paper assesses the techno-economic-geological viability of PTES alongside solar thermal collectors, providing insights into the project’s methodological approach and initial findings.

Most of the district heating systems today use higher operating temperatures than those in new-built systems, possibly limiting compatibility with solar energy. This study evaluates the cost-effectiveness in terms of unit heat cost of integrating solar heating into an existing district heating system compared to not using solar energy, under changing economic boundary conditions such as collector and fuel cost, in addition to discount rate. This is investigated for both a scenario where the solar heating and a boiler replacement is done concurrently, as well as a scenario where solar heating is added to an existing system without replacing the boiler. A theoretical district heating supply of 3 MW is modelled and simulated based on a real system and load profile. The heat supply is varied to include storage with or without solar heating. Results for a 3 % discount rate indicate that; Replacing a 3 MW boiler with a slightly smaller boiler of 2.5 MW and adding a storage is cost effective and yields a unit heat cost of 58.0 EUR/MWh (16.1 EUR/TJ) which is a reduction of about 6 %. Installing solar heating together with the boiler replacement yields a unit heat cost as low as 55.7 EUR/MWh (15.4 EUR/GJ) which is a reduction of about 8 %. When replacing the boiler, all system configurations have similar unit heat costs compared to a boiler-only system, so factors such as emission reductions due to solar heating are relevant when considering alternatives. Furthermore, adding solar flat plate collectors corresponding to a 13 % solar fraction without replacing the boiler can reduce the unit heat cost as low as 34.8 EUR/MWh (9.7 EUR/TJ), which is 32 % lower than without solar. Evacuated tube collectors can increase this solar fraction to 17 % with similar system size, although at a higher cost. At a discount rate of 5 % solar heating is cost-competitive when fuel cost is above 26 EUR/MWh (7.2 EUR/TJ) and at 7 % competitive when fuel cost is above 32 EUR/MWh (8.9 EUR/TJ). Increasing solar heating system size reduces the backup-boiler fuel use during summer maintenance and makes fuel type less relevant for the overall unit heat cost. © 2024 The Authors