4,598 research outputs found
Operational planning and bidding for district heating systems with uncertain renewable energy production
In countries with an extended use of district heating (DH), the integrated
operation of DH and power systems can increase the flexibility of the power
system achieving a higher integration of renewable energy sources (RES). DH
operators can not only provide flexibility to the power system by acting on the
electricity market, but also profit from the situation to lower the overall
system cost. However, the operational planning and bidding includes several
uncertain components at the time of planning: electricity prices as well as
heat and power production from RES. In this publication, we propose a planning
method that supports DH operators by scheduling the production and creating
bids for the day-ahead and balancing electricity markets. The method is based
on stochastic programming and extends bidding strategies for virtual power
plants to the DH application. The uncertain factors are considered explicitly
through scenario generation. We apply our solution approach to a real case
study in Denmark and perform an extensive analysis of the production and
trading behaviour of the DH system. The analysis provides insights on how DH
system can provide regulating power as well as the impact of uncertainties and
renewable sources on the planning. Furthermore, the case study shows the
benefit in terms of cost reductions from considering a portfolio of units and
both markets to adapt to RES production and market states
Review of existing electricity quality label systems in the European Union
Green electricity quality labels have been utilised in the European Union since 1990. Of the seventeen European countries analysed here1, at the time of writing nine had no countryspecific quality label, although all electricity tariffs within Europe were able to apply for accreditation under the EUGENE labelling scheme. Germany had several quality labels, each with slightly different criteria. All of the eighteen labels identified in the report applied to electricity from renewable sources. Of these, seven also allowed co-generation to be a part of the fuel mix and one had a requirement for eligible companies to fulfil some demand side management activities. No existing labelling scheme set an overall requirement for CO2 emissions, although some did set emissions limits for co-generation components. Seven labels required some contribution from new renewable energy plant2. Only three of the labels did not allow publicly funded plant to contribute to a labelled green tariff. A review of labels clearly indicates that: · there are several schemes with varying levels of “greenness”, operating in some countries, which may be confusing for customers; · very few labels are clearly requiring some additionality for the products. It is therefore recommended that the European Union and member states continue to use other support mechanisms to increase the generation of electricity from renewable sources
A novel bidding method for combined heat and power units in district heating systems
We propose a bidding method for the participation of combined heat and power
(CHP) units in the day-ahead electricity market. More specifically, we consider
a district heating system where heat can be produced by CHP units or heat-only
units, e.g., gas or wood chip boilers. We use a mixed-integer linear program to
determine the optimal operation of the portfolio of production units and
storages on a daily basis. Based on the optimal production of subsets of units,
we can derive the bidding prices and amounts of electricity offered by the CHP
units for the day-ahead market. The novelty about our approach is that the
prices are derived by iteratively replacing the production of heat-only units
through CHP production. This results in an algorithm with a robust bidding
strategy that does not increase the system costs even if the bids are not won.
We analyze our method on a small realistic test case to illustrate our method
and compare it with other bidding strategies from literature, which consider
CHP units individually. The analysis shows that considering a portfolio of
units in a district heating system and determining bids based on replacement of
heat production of other units leads to better results
Commitment and Dispatch of Heat and Power Units via Affinely Adjustable Robust Optimization
The joint management of heat and power systems is believed to be key to the
integration of renewables into energy systems with a large penetration of
district heating. Determining the day-ahead unit commitment and production
schedules for these systems is an optimization problem subject to uncertainty
stemming from the unpredictability of demand and prices for heat and
electricity. Furthermore, owing to the dynamic features of production and heat
storage units as well as to the length and granularity of the optimization
horizon (e.g., one whole day with hourly resolution), this problem is in
essence a multi-stage one. We propose a formulation based on robust
optimization where recourse decisions are approximated as linear or
piecewise-linear functions of the uncertain parameters. This approach allows
for a rigorous modeling of the uncertainty in multi-stage decision-making
without compromising computational tractability. We perform an extensive
numerical study based on data from the Copenhagen area in Denmark, which
highlights important features of the proposed model. Firstly, we illustrate
commitment and dispatch choices that increase conservativeness in the robust
optimization approach. Secondly, we appraise the gain obtained by switching
from linear to piecewise-linear decision rules within robust optimization.
Furthermore, we give directions for selecting the parameters defining the
uncertainty set (size, budget) and assess the resulting trade-off between
average profit and conservativeness of the solution. Finally, we perform a
thorough comparison with competing models based on deterministic optimization
and stochastic programming.Comment: 31 page
Short-term Self-Scheduling of Virtual Energy Hub Plant within Thermal Energy Market
Multicarrier energy systems create new challenges as well as opportunities in future energy systems. One of these challenges is the interaction among multiple energy systems and energy hubs in different energy markets. By the advent of the local thermal energy market in many countries, energy hubs' scheduling becomes more prominent. In this article, a new approach to energy hubs' scheduling is offered, called virtual energy hub (VEH). The proposed concept of the energy hub, which is named as the VEH in this article, is referred to as an architecture based on the energy hub concept beside the proposed self-scheduling approach. The VEH is operated based on the different energy carriers and facilities as well as maximizes its revenue by participating in the various local energy markets. The proposed VEH optimizes its revenue from participating in the electrical and thermal energy markets and by examining both local markets. Participation of a player in the energy markets by using the integrated point of view can be reached to a higher benefit and optimal operation of the facilities in comparison with independent energy systems. In a competitive energy market, a VEH optimizes its self-scheduling problem in order to maximize its benefit considering uncertainties related to renewable resources. To handle the problem under uncertainty, a nonprobabilistic information gap method is implemented in this study. The proposed model enables the VEH to pursue two different strategies concerning uncertainties, namely risk-averse strategy and risk-seeker strategy. For effective participation of the renewable-based VEH plant in the local energy market, a compressed air energy storage unit is used as a solution for the volatility of the wind power generation. Finally, the proposed model is applied to a test case, and the numerical results validate the proposed approach
Renewable energy balancing with thermal grid support
Waste heat valorisation in process industry is a common strategy today. The residual heat is converted to electricity by using steam turbines or organic Rankine cycles. As this energy conversion is likely constructed as an integral cooling capacity for the primary process, loss of electricity production will result in reduced process cooling and hence production capacity loss. This restriction prevents these generators to deliver supporting services to the electrical grid. In this paper, it is proven that coupling waste heat recovery with a district heating network provides flexibility to the electricity generation while ensuring cooling capacity to the process. This flexibility can be utilised by a Virtual Power Plant (VPP), e. g., to compensate for the variable output of renewable energy sources. Today, the power fluctuations are only compensated by traditional power plants (gas, coal) due to the scale and flexibility of these power plants. In this paper, a strategy is defined to balance variable (renewable) production with industrial waste heat. As such, some grid support tasks can be transferred from the central power plants to decentralised generation units. The backup of the variable sources is provided by utilising the local available capacity, while maintaining or improving energy efficiency of exothermal industrial processes. Operational boundaries are defined and new challenges identified. In this paper, firstly, the heat sources available for this concept are identified. Secondly, the properties of the different conversion technologies are described. Thirdly, the benefits of a virtual power plant utilising waste heat are determined. Finally, this VPP concept is verified by means of a case study in Belgium, Ostend Energy port. Available heat from biomass, chemical processing and waste incineration is used as primary energy source to balance local renewable production
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