Day-ahead allocation of operation reserve in composite power systems with large-scale centralized wind farms

This paper focuses on the day-ahead allocation of operation reserve considering wind power prediction error and network transmission constraints in a composite power system. A two-level model that solves the allocation problem is presented. The upper model allocates operation reserve among subsystems from the economic point of view. In the upper model, transmission constraints of tielines are formulated to represent limited reserve support from the neighboring system due to wind power fluctuation. The lower model evaluates the system on the reserve schedule from the reliability point of view. In the lower model, the reliability evaluation of composite power system is performed by using Monte Carlo simulation in a multi-area system. Wind power prediction errors and tieline constraints are incorporated. The reserve requirements in the upper model are iteratively adjusted by the resulting reliability indices from the lower model. Thus, the reserve allocation is gradually optimized until the system achieves the balance between reliability and economy. A modified two-area reliability test system (RTS) is analyzed to demonstrate the validity of the method.This work was supported by National Natural Science Foundation of China (No. 51277141) and National High Technology Research and Development Program of China (863 Program) (No. 2011AA05A103)

Impact of emissions cost on the mid-term generation scheduling in the Greek Electricity Market

The EU Emissions Trading Scheme, Europe's main mechanism for implementing EU climate policy, is driving thermal electricity generation units to incorporate their emissions cost into their variable costs. In this paper, we investigate the impact of this incorporation on the mid-term (yearly) performance of the Greek Electricity Market. To carry out our investigation, we iteratively solve the day-ahead market problem for 365 days, assuming that the generation units internalize the emissions cost in their bids. In order to provide a realistic estimate for the market performance, we use a set of input data that is based on a projection of the current data onto the year 2013. We examine three different scenarios for the prices of gas and oil, which are used to fuel some of the thermal generation units, and seven scenarios for the CO2 prices. To enhance the confidence in our results, we perform a sensitivity analysis of the market performance with respect to outages. We conclude by discussing the major insights and potential extensions of this work

An overview of Greece's wholesale electricity market with emphasis on ancillary services

Greece's wholesale electricity market is a mandatory pool in which the commodities of energy and ancillary services are simultaneously traded and dispatched on the generation units. In this paper, we provide an overview of the Greek wholesale electricity market with emphasis on ancillary services. Considering the wide range of ancillary services, our goal is to contribute to the growing literature on individual case studies and comparisons of different ancillary services markets worldwide, pointing out similarities and differences with other market models. In addition, we discuss several aspects, and report on some of the strengths and weaknesses of the Greek wholesale electricity market model. (C) 2011 Elsevier B.V. All rights reserved

Evaluating the cost of emissions in a pool-based electricity market

This paper proposes a methodology that quantifies the impact of emissions cost on the electricity price, the generation scheduling outcome, and the overall emissions in a pool-based electricity market. It employs a mid-term (yearly) generation scheduling model, by sequentially solving a Day-Ahead Scheduling problem, in which power plants internalize their emissions cost in the energy offers that they submit to the day-ahead market. It further explores several scenarios with respect to gas and carbon prices, as well as the realization of random outages that affect the availability of the generation units. An illustration on an instance of the Greek electricity market during the European Union Emissions Trading Scheme Phase III indicates that: (i) A carbon price equal to 30 €/tCO2e combined with low gas prices results in a 18.7% reduction of CO2 emissions, due to the substitution of lignite units by gas units in the energy generation mix. (ii) An increase in the carbon price by 1 €/tCO2e results in an increase of the weighted average electricity price ranging from 0.52 to 0.61 €/MWh. (iii) The average pass-through rate of the carbon costs onto the demand-side payments for carbon prices up to 15 €/tCO2e is close to 60%. © 2021 Elsevier Lt

Medium-Term Unit Commitment in a pool market

We consider a mandatory pool, based to the one established in the Greek electricity market, in which the unit commitment and the scheduling of energy and reserves are the solution of Day-Ahead Scheduling (DAS), an optimization problem that is solved daily and aims to minimize the system cost for the next day. The single-day horizon of DAS may be rather short for capturing the effects of the long start-up times and large commitment costs of slow-start lignite units; hence, the DAS solution may be myopic, resulting in higher total costs in the long-run. To tackle this problem, the Greek market uses a heuristic approach, in which the units' shut-down costs are replaced by their start-up costs and the start-up costs are suppressed; this facilitates the start-up and discourages the shutdown of slow-start units. To address and evaluate the myopic solution issue of DAS more rigorously, we extend the unit commitment problem to a longer horizon of several days, and keep only the solution for the next day as binding (rolling horizon). We call the resulting approach Medium-Term Unit Commitment (MTUC). We compare the long-run average performance of the MTUC output for different horizon lengths (2, 4 and 7 days) to that of the heuristic DAS approach used in the Greek market. The results show that MTUC brings in a small reduction in the total system cost. © 2011 IEEE

Optimal generation scheduling of interconnected wind-coal intensive power systems

Large scale wind power generation complicated with restrictions on the tie line plans may lead to significant wind power curtailment and deep cycling of coal units during the valley load periods. This study proposes a dispatch strategy for interconnected wind-coal intensive power systems (WCISs). Wind power curtailment and cycling of coal units are included in the economic dispatch analysis of regional systems. Based on the day-ahead dispatch results, a tie line power plan adjustment strategy is implemented in the event of wind power curtailment or deep cycling occurring in the economic dispatch model, with the objective of reducing such effects. The dispatch strategy is designed based on the distinctive operation characteristics of interconnected WCISs, and dispatch results for regional systems in China show that the proposed strategy is feasible and can improve the overall system operation performance