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This paper deals with the internal dispatch policy for Hybrid Power Stations (HPS) consisting of renewable energy source (RES) based generation and storage facilities, operating in isolated island power systems in a coordinated manner to provide dispatchable power. Objective of the proposed dispatch method is the maximization of HPS revenues during real time operation, while avoiding deviations from the dispatch orders (DOs) issued by the System Operator (SO). DOs can be met either by RES production directly injected to the grid or by the storage facilities of the station. A Model Predictive Control (MPC) method is implemented to regularly update the internal dispatch decisions for HPS components, relying on an optimization problem built upon the Mixed Integer Linear Programming (MILP). In the proposed formulation the technical and operating constraints of the examined HPS configuration are taken into consideration, while a variable time resolution technique is also adopted to reduce computational complexity and achieve feasible solutions within acceptable time limits. • An internal dispatch method for HPSs contributes to their optimal management. • The variable time resolution approach achieves optimal solutions in reasonable time. • Exploitation of imbalance tolerances may increase revenues for the station. • BESS of high rated power and limited energy capacity improve operation of the HPS. • SoC variability penalization for BESS greatly improves battery life expectancy. [ABSTRACT FROM AUTHOR]

• A new UC method for autonomous power systems is presented, employing dual minimum loading levels for thermal units. • Method enhances systems flexibility by operating inflexible units below their minimum loading level in a structured manner. • Application of the proposed unit commitment approach reduces the generation cost of the system and RES curtailments. This paper investigates the benefits from operating thermal units in isolated grids below their technical minimum loading (TML) levels for short time periods, as a means of providing increased flexibility to the system. Such an operating practice is primarily dictated by the fact that small island systems exhibit very high seasonal variability of their load demand. The base load generating units of island systems are usually internal combustion engines (ICE) running on heavy fuel oil, with relatively large capacity and high TML levels. The inflexibility of these units renders in several occasions necessary the dispatch of flexible but costly peaking units, even in low demand periods, to ensure the feasibility of the unit commitment and economic dispatch (UC-ED) problem. Further, renewable energy penetration is severely hampered by the high TML of the base load units. To address such issues, a two-level TML technique is proposed for ICE units of isolated power systems, incorporated in a UC-ED problem based on the Mixed Integer Linear Programming approach. The benefits from this method are evaluated in terms of conventional generation management and cost, as well as regarding the achieved improvement in the penetration of renewables, examining the operation of two indicative island systems. [ABSTRACT FROM AUTHOR]

The generation management concept for non-interconnected island (NII) systems is traditionally based on simple, semi-empirical operating rules dating back to the era before the massive deployment of renewable energy sources (RES), which do not achieve maximum RES penetration, optimal dispatch of thermal units and satisfaction of system security criteria. Nowadays, more advanced unit commitment (UC) and economic-dispatch (ED) approaches based on optimization techniques are gradually introduced to safeguard system operation against severe disturbances, to prioritize RES participation and to optimize dispatch of the thermal generation fleet. The main objective of this paper is to comparatively assess the traditionally applied priority listing (PL) UC method and a more sophisticated mixed integer linear programming (MILP) UC optimization approach, dedicated to NII power systems. Additionally, to facilitate the comparison of the UC approaches and quantify their impact on systems security, a first attempt is made to relate the primary reserves capability of each unit to the maximum acceptable frequency deviation at steady state conditions after a severe disturbance and the droop characteristic of the unit's speed governor. The fundamental differences between the two approaches are presented and discussed, while daily and annual simulations are performed and the results obtained are further analyzed. [ABSTRACT FROM AUTHOR]

• Alternative BES management concepts are analyzed to support high RES penetrations. • Suitable sizing of BES components benefits system costs and increase RES penetration. • Central dispatch concept is more cost-effective in supporting high RES penetrations. This paper presents a comparative evaluation of central and self-dispatch management concepts for battery energy storage (BES) facilities in island power systems with a high renewable energy source (RES) penetration. BES facilities deployed to support the integration of additional wind capacity can be either centrally dispatched by the island System Operator or they can be self-dispatched within a Virtual Power Plant entity comprising renewables and storage, called a Hybrid Power Station (HPS). To explore the anticipated benefits of each BES management paradigm, annual simulations are performed for an example island system, employing a three-layer mixed integer linear programming (MILP) method to simulate the unit commitment and economic dispatch processes. The levelized cost of energy (LCOE) of combined BES and renewables investments is calculated and the achieved RES penetration levels and island system generation cost are evaluated, allowing the identification of Pareto optimal storage configurations, leading to lowest LCOE for a given RES penetration target. Overall, the centrally dispatched BES systems prove to be substantially more cost-effective, compared to the self-dispatched alternative, for achieving similar RES penetration levels. [ABSTRACT FROM AUTHOR]

The objective of this paper is to evaluate the contribution of energy storage systems to resource adequacy of power systems experiencing increased levels of renewables penetration. To this end, a coherent methodology for the assessment of system capacity adequacy and the calculation of energy storage capacity value is presented, utilizing the Monte Carlo technique. The main focus is on short-duration storage, mainly battery energy storage systems (BESS), whose capacity values are determined for different power and energy configurations. Alternative operating policies (OPs) are implemented, prioritizing system cost or reliability, to demonstrate the significant effect storage management may have on its contribution to system adequacy. A medium-sized island system is used as a study case, applying a mixed integer linear programming (MILP) generation scheduling model to simulate BESS and system operation under each OP, in order to determine capacity contribution and overall performance in terms of renewable energy sources (RES) penetration, system operating cost and BESS lifetime expectancy. This study reveals that BESS contribution to system adequacy can be significant (capacity credit values up to ~85%), with energy capacity proving to be the most significant parameter. Energy storage may at the same time enhance system reliability, reduce generation cost and support RES integration, provided that it is appropriately managed; a combined reliability-oriented and cost-driven management approach is shown to yield optimal results. [ABSTRACT FROM AUTHOR]

• New MILP-based UC model with embedded ac power flow constraints. • Piecewise linear ac power flow equations introduced, compatible with MILP models. • UC model perfectly applicable to small power systems containing tens of system buses. This paper presents a new network-constrained unit commitment (UC) model, which is formulated as a mixed-integer linear programming (MILP) optimization problem with embedded ac power flow (AC-PF) constraints. Piecewise linear AC-PF equations are formulated, which constrain the UC dispatch schedule within permissible transmission capacity and voltage deviation limits, solely by executing the main optimization problem. The proposed model is tested on a six-bus and the IEEE RTS-79 test systems, using GAMS software, whereas the obtained AC-PF results are validated against DIgSILENT/Powerfactory package. The UC schedules are comparatively assessed with detailed results presented in the relevant literature for the same test systems, employing different UC+AC-PF models. [ABSTRACT FROM AUTHOR]