EnergyVille Joint Venture of VITO NV and KU Leuven

Genk, Belgium

EnergyVille Joint Venture of VITO NV and KU Leuven

Genk, Belgium
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Belderbos A.,Catholic University of Leuven | Belderbos A.,EnergyVille Joint Venture of VITO NV and KU Leuven | Virag A.,EnergyVille Joint Venture of VITO NV and KU Leuven | Virag A.,Flemish Institute for Technological Research | And 4 more authors.
Energy Conversion and Management | Year: 2017

Different storage technologies enable an increasing share of variable renewable generation in the electricity system by reducing the temporal mismatch between generation and demand. Two storage ratings are essential to time-shift delivery of electricity to loads: electric power, or instantaneous electricity flow [W], and electric energy, or power integrated over time [Wh]. An optimal storage portfolio is likely composed of multiple technologies, each having specific power and energy ratings. This paper derives and explains the link between the shape of the time-varying demand and generation profiles and the amount of desirably installed storage capacity, both energy and power. An analysis is performed for individual storage technologies first, showing a link between the necessary power and energy capacity and the demand and generation profile. Then combinations of storage technologies are analyzed to reveal their mutual interaction in a storage portfolio. Results show an increase in desirability for storage technologies with low cost power ratings when the mismatch between generation and demand occurs in daily to weekly cycles. Storage technologies with low cost energy ratings are preferred when this mismatch occurs in monthly to seasonal cycles. The findings of this work can help energy system planners and policy makers to explain results from generation expansion planning studies and to isolate the storage benefits accountable to temporal arbitrage in broader electricity storage studies. © 2017 Elsevier Ltd


Gasia J.,University of Lleida | Diriken J.,Flemish Institute for Technological Research | Bourke M.,Glen Dimplex Renewables GDC | Van Bael J.,Flemish Institute for Technological Research | And 2 more authors.
Renewable Energy | Year: 2017

In this paper, the influence of the addition of fins and the use of two different heat transfer fluids (water and a commercial silicone) have been experimentally tested and compared in four latent heat thermal energy storage systems, based on the shell-and-tube heat exchanger concept, using paraffin RT58 as phase change material. Three European institutions were involved under the framework of the MERITS project. A common approach (temperature and power profiles), and five different key performance indicators have been defined and used for the comparison: energy charged, average power, 5-min peak power, peak power to energy ratio, and time. For the same heat transfer fluid, results showed that finned designs (4.7–9.4 times more heat transfer surface) showed an improvement of up to 40%. On the contrary, for the same design, water (which has a specific heat 3 times higher and a thermal conductivity 4.9 times higher than silicone Syltherm 800), yielded results up to 44% higher. © 2017 The Authors


Vandewalle J.,EnergyVille Joint Venture of VITO NV and KU Leuven | D'Haeseleer W.,Catholic University of Leuven
Energy Conversion and Management | Year: 2014

Smart grids are often regarded as an important step towards the future energy system. Combined heat and power (CHP) or cogeneration has several advantages in the context of the smart grid, which include the efficient use of primary energy and the reduction of electrical losses through transmission. However, the role of the gas network is often overlooked in this context. Therefore, this work presents an analysis of the impact of a massive implementation of small scale (micro) cogeneration units on the gas demand at distribution level. This work shows that using generic information in the simulations overestimates the impact of CHP. Furthermore, the importance of the thermal storage tank capacity on the impact on the gas demand is shown. Larger storage tanks lead to lower gas demand peaks and hence a lower impact on the gas distribution network. It is also shown that the use of an economically led controller leads to similar results compared to classical heat led control. Finally, it results that a low sell back tariff for electricity increases the impact of cogeneration on the gas demand peak. © 2013 Elsevier Ltd. All rights reserved.


Patteeuw D.,Catholic University of Leuven | Patteeuw D.,EnergyVille Joint Venture of VITO NV and KU Leuven | Bruninx K.,Catholic University of Leuven | Bruninx K.,EnergyVille Joint Venture of VITO NV and KU Leuven | And 7 more authors.
Applied Energy | Year: 2015

Active Demand Response (ADR) can contribute to a more cost-efficient operation of, and investment in, the electric power system as it may provide the needed flexibility to cope with the intermittent character of some forms of renewables, such as wind. One possibly promising group of demand side technologies in terms of ADR are electric heating systems. These systems could allow to modify their electrical load pattern without affecting the final, thermal energy service they deliver, thanks to the thermal inertia in the system. One of the major remaining obstacles for a large scale roll-out of ADR schemes is the lack of a thorough understanding of interactions between the demand and supply side of the electric power system and the related possible benefits for consumers and producers. Therefore, in this paper, an integrated system model of the electric power system, including electric heating systems (heat pumps and auxiliary resistance heaters) subjected to an ADR scheme, is developed, taking into account the dynamics and constraints on both the supply and demand side of the electric power system. This paper shows that only these integrated system models are able to simultaneously consider all technical and comfort constraints present in the overall system. This allows to accurately assess the benefits for, and interactions of, demand and supply under ADR schemes. Furthermore, we illustrate the effects not captured by traditional, simplified approaches used to represent the demand side (e.g., price elasticity models and virtual generator models) and the supply side (e.g., electricity price profiles and merit order models). Based on these results, we formulate some conclusions which may help modelers in selecting the approach most suited for the problem they would like to study, weighing the complexity and detail of the model. © 2015 Elsevier Ltd.


Nuytten T.,Energyville Joint Venture of VITO NV and KU Leuven | Nuytten T.,Flemish Institute for Technological Research | Moreno P.,University of Lleida | Vanhoudt D.,Energyville Joint Venture of VITO NV and KU Leuven | And 5 more authors.
Applied Thermal Engineering | Year: 2013

The efficiency of micro-combined heat and power (micro-CHP) systems can be increased by decoupling the production of electricity and heat by means of thermal energy storage (TES) systems where heat that is not needed during the production period can be stored for later use. The aim of this article is to evaluate the use of different TES units when coupled to micro-CHP systems. An experimental study was carried out to evaluate the thermal behavior of different TES units for coupling with a micro-CHP system. A cylindrical TES tank was used to compare the performance of two phase change materials (PCMs) with different melting temperature and encapsulation method, while using a water-filled unit as a reference scenario. The first concept consists of cylindrical PCM tubes while the second uses small spherical PCM capsules, both commercially available products. The analysis involves three different tests: constant inlet temperature, constant power, and partial capacity loading. The results are evaluated on the basis of a comparison between inlet and outlet temperatures, charging time and thermal energy stored by the TES units. The PCM tubes are characterized by a higher capacity when a low thermal power is applied while the PCM capsules are able to store more energy at higher power. The operating temperatures in partial loading tests indicate that the incorporation of PCM storage units in a smart grid environment may be beneficial from a thermal systems point of view. © 2013 Elsevier Ltd. All rights reserved.


Zapata Riveros J.,Catholic University of Leuven | Zapata Riveros J.,Energyville Joint Venture of VITO NV and KU Leuven | Donceel R.,Catholic University of Leuven | Van Engeland J.,Catholic University of Leuven | And 2 more authors.
Energy Conversion and Management | Year: 2015

In order to ensure reliable operation of the electric grid, it is required to keep the balance between total generation and consumption of power in real-time. This task is performed by the transmission system operator. Nowadays, with the large penetration of intermittent generation on the electric grid there is a need to increase the flexibility of the system in order to ensure the balance. The present study develops a methodology to provide near real-time balancing services making use of an aggregation of micro-CHP devices. The controller of the aggregator bids electricity into the day-ahead market using the expected heat demand and spot market prices. The main focus of this work is on the near real-time optimization which is performed during the actual day. This optimization provides the opportunity to obtain extra profits by rescheduling the operation of the aggregator. The rescheduling is done in order to compensate the total system imbalance. To achieve this, every time step, the aggregator evaluates the system demand for up or down regulation and decides if it is profitable to adjust its position to provide balancing services to the power system. The methodology is applied to a case study that resembles the actual situation of the energy market and CHP installations in Belgium. The results show that using the near real-time balancing optimization a total cost decrease of 5% can be achieved depending on the season. This conclusion is valid even if there is an increase of the gas prices and if the actual governmental support on CHPs is not taken into account. © 2014 Elsevier Ltd. All rights reserved.


Nuytten T.,Energyville joint venture of VITO NV and KU Leuven | Nuytten T.,Flemish Institute for Technological Research | Claessens B.,Energyville joint venture of VITO NV and KU Leuven | Claessens B.,Flemish Institute for Technological Research | And 5 more authors.
Applied Energy | Year: 2013

The trend towards an increased importance of distributed (renewable) energy resources characterized by intermittent operation redefines the energy landscape. The stochastic nature of the energy systems on the supply side requires increased flexibility at the demand side. We present a model that determines the theoretical maximum of flexibility of a combined heat and power system coupled to a thermal energy storage solution that can be either centralized or decentralized. Conventional central heating, to meet the heat demand at peak moments, is also available. The implications of both storage concepts are evaluated in a reference district. The amount of flexibility created in the district heating system is determined by the approach of the system through delayed or forced operation mode. It is found that the distinction between the implementation of the thermal energy storage as a central unit or as a collection of local units, has a dramatic effect on the amount of available flexibility. © 2012 Elsevier Ltd.


Zapata J.,Catholic University of Leuven | Zapata J.,Energyville Joint Venture of VITO NV and KU Leuven | Vandewalle J.,Catholic University of Leuven | Vandewalle J.,Energyville Joint Venture of VITO NV and KU Leuven | And 2 more authors.
Applied Thermal Engineering | Year: 2014

The penetration of a large amount of distributed generation (DG) technologies with intermittent output, such as photovoltaic installations and wind turbines, yields an important challenge to the electric grid. It is believed that aggregating them with controllable technologies such as cogeneration devices (CHP) can help to balance fluctuations of renewable energy. This work evaluates the ability of a virtual power plant (VPP) to reduce the imbalance error of renewable generators. The study is undertaken in a VPP that consists of several cogeneration devices and photovoltaic (PV) installations. The virtual power plant operator bids electricity into the day-ahead market using the forecast for solar irradiation and for the thermal demand. During the actual day, the imbalance due to deviations between the forecasted electricity delivered and the real output has to be settled in the balancing market. Thus, in order to compensate these errors and possible economic drawbacks, the operation of the CHP is adjusted periodically in a so called reschedule. Two different rescheduling strategies are compared against a 'reference scenario' in which the imbalance error is settled in the market. The first one ('forced strategy') aims at reducing the imbalance error every time step regardless of the imbalance prices. The second ('economic strategy') considers the imbalance prices and takes only action if it is economically appropriate and thus intends to reduce the total operational cost. The results show that the rescheduling technique is able to reduce the imbalance error (up to 90% depending on the season and the strategy). Additionally, the total operational cost is estimated. However, the nowadays imbalance prices only lead to a minor financial advantage that is unlikely to motivate real life operators to perform a rescheduling strategy. © 2013 Elsevier Ltd.


Arteconi A.,University eCampus | Patteeuw D.,Catholic University of Leuven | Patteeuw D.,EnergyVille Joint Venture of VITO NV and KU Leuven | Bruninx K.,Catholic University of Leuven | And 7 more authors.
Applied Energy | Year: 2016

Active demand response (ADR) is a powerful instrument among electric demand side management strategies to influence the customers' load shape. Assessing the real potential of ADR programmes in improving the performance of the electric power system is a complex task, due to the strict interaction between supply and demand for electricity, which requires integrated modelling tools. In this paper an analysis is performed aimed at evaluating the benefits of ADR programmes in terms of electricity consumption and operational costs, both from the final user's and the overall system's perspective. The demand side technologies considered are electric heating systems (i.e. heat pumps and electric resistance heaters) coupled with thermal energy storage (i.e. the thermal mass of the building envelope and the domestic hot water tank). In particular, the effect of the penetration rate of ADR programmes among consumers with electric heating systems is studied. Results clearly show that increasing the number of participating consumers increases the flexibility of the system and, therefore, reduces the overall operational costs. On the other hand, the benefit per individual participant decreases in the presence of more ADR-adherent consumers since a reduced effort from each consumer is needed. Total cost saving ranges at most between about 400 € and 200 € per participant per year for a 5% and 100% ADR penetration rate respectively. © 2016 Elsevier Ltd.


Zapata Riveros J.,Catholic University of Leuven | Zapata Riveros J.,Energyville joint venture of VITO NV and KU Leuven | Bruninx K.,Catholic University of Leuven | Bruninx K.,Energyville joint venture of VITO NV and KU Leuven | And 4 more authors.
Energy Conversion and Management | Year: 2015

Energy efficiency and renewable-energy sources (RES) are fundamental parts of the European energy policy. For this reason, efficient distributed generation technologies such as combined heat and power coupled to district heating (CHP-DH) and RES based electricity are largely promoted. Additionally, the flexibility that CHP-DH offers to the power system is seen as an option to balance the intermittent output of RES-based generation. This could be done by aggregating RES based electricity generation and CHP DH in a virtual power plant (VPP). In this framework, the present work presents a methodology to evaluate the optimal bidding strategy of a VPP composed of a CHP-DH and RES based generators. The objective is to investigate the optimal bidding strategy for a VPP that uses CHP DH to compensate for the uncertainties regarding RES-based electricity generation and market prices. The VPP operator nominates its energy to the day ahead market the day before the actual delivery (D-1). In real time, any deviation from the day-ahead schedule is settled in the imbalance market. The uncertainties are modeled using a two stage stochastic programming approach. Three different bidding strategies are studied: 'static', 'flexible DA' and 'flexible RT'. The major difference between the studied strategies lies in the dispatch decisions. The 'static' strategy does not adjust the scheduled output of the CHP. Whereas, the 'flexible DA' and 'flexible RT' strategies differ from each other in terms of the information available at the moment of performing the reschedule (second stage decision). The 'flexible DA' reschedules the CHP output for the whole day assuming full knowledge of the RES scenario, but under uncertainty regarding the imbalance price. The 'flexible RT' strategy allows the VPP to adjust its position at each time step depending on the RES generation and imbalance price scenarios. The results show that in comparison with the 'static' strategy, the 'flexible DA' operation results in a profit increase during summer (5900 /week), the intermediate season (2800 /week) and winter (2700 /week). This increase is moderate when compared against the total fuel cost in these seasons. Better results are obtained when the 'flexible RT' strategy is applied. Using this strategy larger profits are achieved for all seasons. For instance, during winter the difference between the 'flexible RT' operation and the 'static' case amounts to 22,600 /week, approximately 5% of the fuel cost. © 2015 Published by Elsevier Ltd.

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