The deregulation of the electric systems requires the definition of market procedures for the effective management of reactive resources. However, the amount of payments for participating to the voltage regulation service is a task characterized by conflicting objectives, from both the technical and the economic viewpoints. The main subjects related with the reactive power management are: maintaining an adequate security level, defining correct economic signals, providing a simple and transparent structure, ensuring market equity, and avoiding additional charges on the final energy price. After a brief review of the hierarchical voltage regulation structure developed in the Italian power system, a practicable scheme, coherent with the above mentioned requirements, is proposed: the final aim is to assign a correct economic value to the reactive resources
Summary form only given. The electricity markets are changing the power system operation. The increasing power exchanges make it necessary to operate the transmission grids closer and closer to security limits. A problem posed to power system engineers is therefore to find a suitable methodology to combine the results of both steady state and dynamic tools: this can reduce the overall computational effort and the difficulty in the interpretation of results. The paper presents a detailed comparison of the computations that can be performed through steady state and dynamic procedures regarding the power system security. In particular, the analysis of the loadability margins available on the corridor between the Italian power system and the UCTE (Union for the Coordination of the Transmission of Electricity) grids is carried out using both steady state and dynamic tools; the results are compared, pointing out also the security enhancement given by a hierarchical voltage control.
For off‐grid microgrids in remote areas (e.g. sea islands), proper configuring the battery energy storage system (BESS) is of great significance to enhance the power‐supply reliability and operational feasibility. This study presents a life cycle planning methodology for BESS in microgrids, where the dynamic factors such as demand growth, battery capacity fading and components’ contingencies are modelled under a multi‐timescale decision framework. Under a yearly timescale, the optimal DER capacity allocation is carried out to meet the demand growth, while the investment decisions of BESS are made periodically to yield the optimal sizing, type selection and replacement plans of BESS during the entire lifetime of the microgrid. Then, under an hourly timescale, the long‐term probabilistic sequential simulation is adopted to comprehensively evaluate the investment decisions and derive detailed operation indicators. Moreover, a decomposition–coordination algorithm is developed to address the presented planning model, which iteratively strengthens the feasible space of investment‐decision model by substituting the operation indicators until an acceptable sub‐optimal solution is obtained. Case studies on a wind–solar–diesel microgrid in Kythnos Island, Greece illustrate the effectiveness of the proposed method. This study provides a practical and meaningful reference for BESS planning in off‐grid microgrids.
The large amounts of power transfers consequent to the liberalization of energy markets has raised, among others, two issues: (i) transmission line congestions and (ii) low-damped inter-area oscillations. The method proposed in this paper simultaneously solves both problems by installing FACTS devices like TCSCs and SVCs in key points of the power system. In particular, TCSCs can eliminate the congestions by modifying the steady-state parameters of the transmission lines while SVCs and also TCSCs can assure a good damping of the inter-area modes through additional modulated signals generated by well designed Power Oscillation Dampers (PODs). As the problem is mathematically quite complex and robustness is highly required, Genetic Algorithm (GA) techniques are employed. To prove the efficiency of the method, simulations were performed on suitable test systems.
Abstract This study aims at introducing a new metric to evaluate the production costs of photovoltaic plants that includes the impacts of adding them in the existing energy system. In other words, the levelized cost of electricity concept is enlarged to incorporate the so‐called integration costs. They consider the costs of reinforcing the grid infrastructure to accept the increase of variable renewable sources production and the effects on the operating conditions of the existing fossil fuel power plants. These costs are applied to the utility‐scale photovoltaic plants to analyse how their market parity and profitability would change in the future if a more systematic approach is used to evaluate their production costs. Moreover, a bottom‐up energy system model performing an operational optimization is introduced and coupled with a genetic algorithm to perform the expansion capacity optimization. This model is used to study the effects on the utility‐scale photovoltaic plants' dispatchability if the integration costs are included. The Italian energy system and photovoltaic market projected to the year 2030 are taken as reference. The results of the market parity highlight that its achievement will not be compromised when the integration costs are considered, mainly thanks to the strong decrease of the investment costs expected in the future years. The results of the optimization underline that the future role of photovoltaic plants in the energy mix with low CO 2 emissions will not be significantly affected, even when these additional costs are applied as annual costs.
In a zonal market, the transmission system operator (TSO) has to compute the transfer limits among areas in advance (weeks or months) with respect to the day-ahead market session. The computation of such limits is usually made starting from some reference scenarios: this choice is arbitrary and has a strong influence on the results of the market. In this paper, a new probabilistic approach is developed to reduce such arbitrariness. A Monte Carlo method is applied to sample many different reference scenarios (in terms of generation patterns) to be adopted for the total transfer capacity (TTC) computation. Eventually, the probability density function of the TTC values is built. The proposed procedure allows the TSO to evaluate, for each possible choice of the TTC limit among areas, the maximum probability of congestion in a market framework, thus selecting the limit corresponding to the acceptable risk level. The new methodology is applied to the Italian system
First optimization models regarding optimal dispatch of generation resources considering static and dynamic security of the network are reviewed. Given the difficulty to solve non-linear optimization problems with discrete variables, the decoupling of the active and reactive powers issues is proposed. The two resulting problems interact iteratively. A Security Verification (SV) problem is solved to identify the generation deployment in terms of real power constraints: branch flow security constraints, primary/secondary frequency control constraints to correctly identify required regulation bands and minimum inertia are here considered. The proposed linearized models are validated against real grid behavior on representative test networks. The SV solution is given to AC OPF, to optimally deploy reactive power resources.
The increasing participation of intermittent renewable energy sources (RES) in modern power systems makes the expansion and operational planning an even more complex task, specially in hydro-based systems. To properly assess the impact that intermittent generation may have on generation expansion planning (GEP) decision, higher temporal resolution methodologies for GEP are required that take into consideration the system operation as well. This paper proposes a soft-linking methodology for the GEP problem of large hydrothermal power systems with increasing expansion of RES. The proposed methodology coordinates power systems models ranging from an expansion planning to an hourly hydrothermal scheduling one. It has been applied to a ten-year expansion planning of the Brazilian power system: the importance of considering the short-term wind generation intermittency is demonstrated by the necessity of changing the original expansion plan both in terms of installed generation and interconnection capacity.
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