Over the past decade, the research community has demonstrated increasing interest in advancing geothermal heating and cooling (GHC) systems through the integration of phase change materials (PCMs), tripling the number of scientific publications between 2021 and 2024. Within this context, this review evaluates two main application forms: PCM-based thermal energy storage (PCM-TES) units and PCM in ground heat exchangers (PCM-GHEs), the latter used with PCM-enhanced heat transfer fluids, PCM in heat transfer pipes, PCM in backfills, or PCMs deployed in ground vicinity. This review yields that on average, PCM integration improves heat transfer between the ground and the thermal load by 27 %, increases the coefficient of performance of heat pumps by 15 %, stabilizes heat transfer fluid temperature by 1–3 °C, and reduces GHE length by 10 - 90 %. For PCM-TES units, cost savings of up to 55 % are achieved with tariff-based operation. However, system performance is sensitive to both ground and phase change temperatures. Especially for PCM-GHEs, which require favorable operating conditions in both short- and long-term, and thermal conductivity enhancement of PCMs is often a necessity. Current technologies demonstrate a technology readiness level of 4–8, yet require validation through long-term, full-scale testing and comprehensive evaluations of cost effectiveness, as under-investigated aspects today.

In pursuit of the 2050 decarbonisation goals outlined in the Paris Agreement, the European Union aims to integrate renewable energy sources into electricity generation. However, the intermittent nature of solar and wind energy presents challenges for grid stability and reliability. Hydrogen (H2), particularly "green H2" produced through renewable electrolysis, has emerged as a promising energy carrier to complement variable renewable energy. This study investigates the technical and economic feasibility of utilising excess heat generated during Proton Exchange Membrane (PEM) electrolysis, a by-product typically underutilised, to improve the overall efficiency and cost-effectiveness of green hydrogen production. Using Aspen Plus, the study models five heat recovery scenarios: electricity generation via an ammonia Organic Rankine Cycle (ORC), direct heat supply to a District Heating (DH) network, steam generation using hydrogen and electric boilers, and a combined DH and steam generation configuration. The base case assumes no heat recovery and relies solely on cooling towers for heat rejection. Among the alternatives, the DH scenario proved to be the most economically viable, achieving a Net Present Value (NPV) of <euro>9.5 million, an Internal Rate of Return (IRR) of 0.23, and a Payback Period (PB) of 7 years, at a hydrogen price of <euro>9.5/kg. In contrast, the ORC scenario yielded a negative NPV and a payback period exceeding 30 years, indicating limited viability under current conditions. The results highlight the importance of integrating low-grade heat recovery into green hydrogen systems. Redirecting PEM excess heat to existing DH infrastructure offers the most immediate economic and technical benefits, contributing to more efficient, circular, and financially attractive hydrogen production systems.

Reliable and cost-effective energy storage is essential to accelerate the adoption of renewable energy systems such as concentrated solar power (CSP) technologies. Single-tank Packed Bed Thermal Energy Storage (PBTES) offers a promising, lower-cost alternative to traditional two-tank systems for high-temperature storage. This study explores a hybrid sensible-latent PBTES system that integrates two types of Phase Change Materials (PCMs), strategically placed at opposite ends of a sensible-based PBTES, to enhance performance in terms of storage density and outlet fluid temperature stability. This is the first study to systematically evaluate metallic PCMs in multi-layered hybrid PBTES. A comprehensive numerical investigation, spanning PCM volume fractions from 0 to 30 % for each PCM, is conducted using a validated concentric dispersion model. The results show that PCM integration significantly boosts storage capacity, improves thermal stability, extends temperature plateaus during charging and discharging cycles and increases the energy density by up to 250 %. These hybrid configurations also extend the useful operation time by up to 220 % during charging and 300 % during discharging cycles with up to 250 % of useful energy capacity increase. Economic analysis showed a payback period of 4.8–5.5 years, with reductions in PCM layer at the top of the TES unit and encapsulation fabrication costs providing the most significant improvements in overall cost. While the hybrid system enhances temperature stability and energy utilization, it introduces trade-offs in terms of cost and efficiency, underscoring the importance of optimized PCM selection and its operating conditions. This work demonstrates the transformative potential of hybrid PBTES systems in delivering efficient, stable, and tailored energy storage solutions for future energy systems.

Integrating District Heating (DH) with the Electric Power Sector (EPS) offers a key strategy for addressing climate challenges by improving resource efficiency and enabling low-carbon transitions. Through Flexible Sector Coupling (FSC) mechanisms, DH systems can mitigate greenhouse gas emissions and enhance system flexibility by absorbing intermittent renewable electricity surpluses. This study evaluates the potential of FSC enabled through Thermal Energy Storage (TES) in DH applications, using the energy system of Oskarshamn, Sweden, as a case study. A soft-linked modelling framework is developed by combining a long-term investment optimisation model based on the Open-Source energy Modelling System (OSeMOSYS) with a high-resolution hourly dispatch model. These models are iteratively linked to align strategic investment decisions with operational feasibility. The analysis evaluates scenarios based on variations in electricity prices, TES capital costs, and the availability of self-consumption via heat pumps and excess heat. Key performance indicators, including Levelised Cost Of Energy (LCOE) and CO<inf>2</inf> emissions, are used to compare outcomes. Results show that the feasibility of FSC is strongly influenced by electricity price trends and TES investment costs. High electricity prices favour cogeneration of electricity and heat, while lower prices lead to increased investment in TES and heat pumps, prioritising heat production. Scenarios with low electricity prices achieve lower LCOEs (37.5–42.7 €/MWh) compared to those with high prices (46.6 €/MWh). The approach demonstrates that soft linking the capacity expansion model and dispatch models strengthens energy system planning by integrating long-term and short-term perspectives. Overall, the study highlights the potential of FSC with TES for cost-effective and resilient DH planning under different future energy conditions. Future work could explore the wider deployment of FSC by assessing its integration with electricity market services, expanding to multi-city or regional DH networks, and evaluating enabling policies, business models, and digital control strategies for large-scale implementation.

This paper proposes a generic, extensible, and scalable definition of hybrid energy storage systems (HESS) and provides a corresponding information model applicable for energy management system (EMS) implementation. Given the need for flexibility in both energy supply and demand due to the energy transition, multiple energy carriers have been coupled, energy storage mediums have been leveraged, and their characteristics have been optimized. EMS are adapting to these developments, which can be facilitated by having common definitions and information models. There are at least two prevailing descriptions of HESS: one based on complementary characteristics, and another based on the constituent energy storage mediums. The proposed definition is an extension and specific application of the concept of "energy hubs" and a clarification of the multiple descriptions of HESS. On a larger scale, this work aims to facilitate the interoperability of various EMS that involve HESS and to provide a foundational resource for projects related to HESS architectures, control, and optimization. This work is a contribution to the development of an open ontology tailored for EMS applications in the context of energy communities with HESS.

This study proposes a life cycle assessment (LCA) framework to support the design of a building heating and cooling system with a ground source heat pump (GSHP) and phase change material thermal energy storage (PCM-TES) considering three key performance indicators (KPIs) in long-term performance, life cycle cost, and life cycle impact. It provides a method to map interlinkages of KPIs and identify key influence factors.   

This study reviews advancements in the use of phase change materials (PCMs) in underground thermal energy storage(UTES) systems. The primary application forms include vertical and horizontal ground heat exchangers (GHEs) and PCM underground storage units. The paper emphasizes the diverse potential of PCMs in UTES by selecting representative research that investigates various types of PCMs and their integration concepts. It highlights the role of PCMs in enhancing storage density and improving system efficiency.

Refrigerants today include blends of e.g. hydrofluorocarbons (HFCs) and hydrofluoroolefins (HFOs). HFOs have low global warming potential however are also less stable, risking compositional variations, with not much known yet. To add new knowledge, R452B (with R32, R125 and R1234yf) is analysed here, in used (7790 h in a heat pump) and pristine conditions, in a gas chromatograph with a thermal conductivity detector (TCD) and a flame ionization detector (FID). R452B was compared with moisture, N2 and a calibration blend containing CO2, R32, R125, R134a and R1234yf. The results yielded, besides the intended three components in R452B, also traces of R134a, moisture, possibly CO2 and several unknown compounds eluting before (thus lighter than) CO2. Some unknowns appeared only in TCD are thus non-combustible (including possibly O-2), while some appeared in both TCD and FID. The identification of these unknowns, calibrations for those and a comprehensive compositional analysis will follow.

District cooling (DC) is an important sector within today’s energy systems, with a renewed interest in cooling as an energy service, owing to global warming. Cold storages (CSs) are an important element in DC systems, to alleviate unnecessary capacity investment costs while accommodating peak shaving and load shifting, and to lower the cold production costs as well. Through a current status mapping of DC and CS in Sweden, it is found that the DC supply is about 1 TWh/year as opposed to the estimated 2-5 TWh annual cooling demand. This also revealed that the existing CSs are almost exclusively cold water storages, and which are most likely centralized units located adjacent to cold production plants. This brings us to the question: how can expanded integration of CS allow for DC to meet an even larger share of the cooling demand, in a robust, cost effective and environmentally sound way?

To answer this, it is important to first recognize the available CS alternatives and their potential. Sundsvall seasonal snow storage system is an attractive Swedish exception to cold water CS. Cold water thermal energy storage (TES), in tanks and natural rock caverns (CTES) operate more for short-term CS whereas e.g. aquifer TES (ATES) and borehole TES (BTES) are utilized for seasonal storage (yet in building-scale). Hornsberg CTES and Arlanda ATES are Swedish UTES CS examples. Their relatively high technology readiness levels (TRLs) encourage their exploitation. CSs with snow and ice as phase change materials (PCMs) are gaining interest for being compact storages (up to 60 kWh/m3 unlike 7 kWh/m3~with water) with rather competitive costs for daily storage in buildings or small districts. Examples are Chitose airport, Hokkaido, and Nagoya JR station in Japan and Paris La Défense in France. CS with other PCMs or thermochemical heat storage materials (TCMs) are scarce in DC. Two PCM examples on building cooling systems are e.g. in Gothenburg, Sweden, and in Bergen, Norway, using salt-hydrates. CS with PCMs and TCS has lower TRLs and hence requires further research before reaching district level applications. 

Within this background, the true benefits of CSs are evaluated herein with a special focus on distributed CS solutions. For that, the existing DC system of Norrenergi AB (catering to Solna and Sundbyberg) was chosen as a case study for a techno-economic performance evaluation and cost benefit analysis. Norrenergi AB’s DC system comprises three production plants in Frösunda, Sundbyberg and Solna Strand, with one CS of 10 MW (75.7 MWh, 6500 m3), altogether allowing a 73.1 MW peak installed capacity. Here, the expanded integration of CS capacity has been explored through the DC system (i.e., production versus demand) optimization as well as DC distribution grid dynamics optimization. Centralized and distributed CSs, considering cold water CSs (due to data limitations on other alternatives) were employed. The DC system analysis was performed as the first step using the software tool BoFit, whereas, the DC distribution grid dynamics were then evaluated using the software tool Netsim. 

With BoFit, three scenarios were analyzed besides today’s system- the base case (BC). In these scenarios, one additional CS of 15 MW or two CSs of 3 MW were considered at different production locations and supply combinations. Hereby, the most cost effective solution was to install one additional central CS of 15 MW in Sundbyberg. As this BoFit analysis was inconclusive on the impacts of these CSs on the distribution grid, the investigations were continued to distribution grid dynamics assessment with Netsim. In Netsim, three corresponding scenarios were analyzed using additionally: a 15 MW CS in Sundbyberg (centralized), a 15 MW CS in Frösunda (at a distributed location) and two 3 MW CSs at both Sundbyberg and Frösunda. The distributed location in Frösunda was chosen for displaying low differential pressure bottlenecks as found using Netsim. The results revealed that the optimal CS choice lies in two CSs, one located centrally in Sundbyberg and one at the distributed location in Frösunda, with a total capacity of 6-15 MW. Therein, six more scenarios (A-F) were analyzed in Netsim with two equisized CSs of 3, 4, 5, 6, 7 and 7.5 MW capacity. Here, scenario F with two CSs of 7.5 MW capacity each is found as the most optimal solution, with the lowest costs (99 SEK/MWh,cold and 589 SEK/MWh,electricicty) than the other scenarios and the BC (105 SEK/MWh,cold and 608 SEK/MWh,electricity). Although the relative difference between the operational costs savings of each consecutive scenario (A-F) is low, scenario F allows the best savings (for cold production cost per used electricity). 

For a 10% demand increase, scenario F and the BC were then compared in Netsim against two other alternatives: a pipe extension (~420 m) at Frösunda low-pressure loop and a new chiller (6 MW) in Sundbyberg. Therein, scenario F followed by the new chiller had the lowest operational costs, while the new pipe extension had the lowest investment cost. Once the annual operating costs and apportioned investment costs were combined, scenario F exhibited the best cost savings, overall. It allows 3% annual cost savings than the BC, while avoids 16% and 4.5% of the costs if instead a new chiller or a new pipe extension was used. Scenario F also facilitates the largest reductions in peak electricity use (4 MW,electricity/peak hour and 35 MWh,electricity/day) and peak cold production (115 MWh,cold/day), successfully adopting power-to-cold. Sensitivity analyses on ground temperature increases and electricity price fluctuations also confirmed that scenario F outperforms the BC. Therefore, scenario F is the most optimal solution for competitively expanding DC.

In summary, this work exemplifies the benefits in implementing CSs in DC, in peak shaving, load shifting, and power-to-cold adaptations, overall leading to cost savings. Also, this work highlights the particular benefits of distributed CSs in better managing the DC distribution grid dynamics. As a whole, the work conveys the importance of DC system-level as well as distribution grid-level optimizations, which are more effective in combination to truly decide the suitability, sizing and positioning of CSs in DC. Important KPIs are also proposed herein for their general utility, i.e., the unit operating cost of cold (e.g. in SEK/MWh,cold) and unit operating cost of electricity to produce that cold (SEK/MWh,electricity), for cost as well as power-to-cold implications. Moving beyond cold water CSs is a potential future work with benefits. In future studies, CS in DC will be developed with a detailed focus on power-to-cold synergies, which emerges as a promising business area in a future electricity system with a large proportion of solar and wind.

District cooling (DC) is gaining interest with global warming and rising demands on indoor comfort. As DC grid expansions are capital intensive, cost effective alternatives to meet these rising cooling demands are desired. Integrating cold storage (CS) into the grids is one attractive choice, allowing peak shaving, load shifting, and renewable electricity recovery via power-to cold. To analyze the impact of new CSs, the DC distribution grid dynamics must be investigated. This work evaluates the implementation of several new CSs into an existing DC system (called the base case-BC), to find the optimal solution. This is performed considering the case study DC system of Norrenergi AB, Sweden, catering to Solna and Sundbyberg via three production plants Solnaverket, Sundbybergsverket and Frosundaverket, and a 10 MW CS (in Solnaverket). The software tool Netsim is used for distribution grid dynamics analysis of the BC and three scenarios with additional cold storages, for the optimization of differential pressure (dP) of the grids to be within 100-800 kPa. These scenarios include: one additional 15 MW CS in Sundbybergsverket (Scenario 1), one additional 15 MW CS in Frosunda (Scenario 2) and two additional 3 MW CSs in Sundbybergsverket and Frosunda (Scenario 3). The CSs in Sundbybergsverket are centrally placed, whereas, those in Frosunda were positioned in a grid loop experiencing low differential pressure, identified in Netsim simulations of BC. The simulations were done for 24 h at 1-hour resolution, on a chosen historically highest demand day (02 August 2018). The results indicate that the optimal solution is implementing two additional CSs in Sundbybergsverket (centralized) and Frosunda (distributed), each with a capacity between 3-7.5 MW (6-15 MW total capacities). Further evaluations to determine the optimal sizing of these CSs is the next step in this study.