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Abstract The upgrade of a pumped-storage power plant (PSPP) to allow variable speed operation offer several advantages in pumping and generating modes. However, in pumping mode at part load, both pressure and torque pulsations develop in the pump turbine runner. This paper evaluates the risk of fatigue damage in the penstock of a variable-speed PSPP due to the propagation of the pressure pulsations developing in the pump turbine runner at partial load in pumping mode. For that purpose, a simulation model of a variable-speed PSPP has been developed. The pressure and torque pulsations are generated each from a different set of sinusoidal functions calibrated from the results of a Computational Fluid Dynamic model, which was in turn validated from experimental data. A Monte Carlo simulation has been performed considering different temporal gaps between the sinusoidal functions reproducing the pressure pulsations in one and another pump turbine. The number of stress cycles that may cause fatigue damage in the penstock has been obtained from the results of the simulations and the fatigue curves defined in the Eurocode, and then transformed into the maximum number of hours per year the PSPP can operate at partial load in pumping mode to avoid fatigue damages. Highlights • Modelling a variable speed pump turbine considering pressure pulsations in pumping mode. • Analysing the pressure pulsations along the conduits using characteristic method. • A fatigue analysis in penstock has been done by using Rainflow method and Montecarlo simulations. • An estimation of the maximum hours in pumping mode according to the plant lifetime has been proposed. [ABSTRACT FROM AUTHOR]

This paper analyses the economic viability of twelve pumped-storage hydropower plants equipped with different fixed-speed and variable-speed units and with and without considering hydraulic short-circuit operation. The analysed plants are assumed to participate in the day-ahead energy market and in the secondary regulation service of the Iberian power system. A deterministic day-ahead energy and reserve scheduling model is used to estimate the maximum theoretical income of the plants assuming perfect information of the next day prices, the residual demand curves of the secondary regulation reserve market and the percentages of the real-time use of the committed reserves. An estimate of the minimum theoretical pay-back period is obtained from the maximum theoretical income as a result of the scheduling model. Results indicate that the economic viability with and without variable speed units and operating or not in hydraulic short-circuit mode is not discarded if the plants also participate in the secondary regulation service, and that the minimum theoretical pay-back periods can be reduced significantly when the plant is equipped with variable speed units and/or operates in hydraulic short-circuit mode. In addition, the maximum theoretical income obtained with the used optimization model and the proposed pumped-storage hydropower plants are significantly higher than the real income obtained by plants that are currently operating in the Iberian system. [ABSTRACT FROM AUTHOR]

The establishment of more severe hydrological environmental constraints , usually minimum flows and maximum ramping rates , on hydropower operation is a growing trend in the world. This paper presents the results of an attempt to assess the long-term economic impact of the above-mentioned constraints by three approximate formulae which quantify their effects, both separately and jointly, on a hydropower plant characterised by two parameters. The formulae are the result of three regression models developed from the solutions of 476 deterministic long-term hydro-scheduling problems corresponding to ten hydropower plants located in Spain. They were tested with 98 additional problems corresponding to two other Spanish hydropower plants. The formulae have a final average relative error of 8.2% and a final relative error of 19% with a confidence interval of 95%. This paper also offers some insight about the difficulties for tracking the energy prices when these constraints are present. Finally, the analysis of the hourly results indicates some additional effects of these constraints on hydropower operation related to the energy generated by the plant, the amount of water spilled from the reservoir, and the number of operating hours and of start-ups and shut-downs of the hydro units. [ABSTRACT FROM AUTHOR]

The paper aims at demonstrating that the consideration of constant start-up costs and ramps of the thermal generating units for assessing the contribution of pumped-hydro energy storage to reduce the scheduling costs of hydrothermal power systems with high wind penetration, may yield unrealistic results. For this purpose, an isolated power system is used as a case study. The contribution of a pumped-storage hydropower plant to reduce the system scheduling costs is assessed in the paper by using a hydrothermal weekly unit commitment model. The model considers different start-up costs and ramps of the thermal generating units as a function of the start-up type. The effects of including pumped hydro energy storage in the system on the integration of wind energy, and on the start-ups and capacity factors of the thermal generating units are also evaluated. The results of the paper demonstrate that the consideration of constant start-up costs and ramps of the thermal generating units yields unrealistic results, and that the pumped-storage hydropower plant may help reduce the system scheduling costs by 2.5–11% and integrate wind power and may allow dispensing with some inflexible thermal generating units. [ABSTRACT FROM AUTHOR]

This paper studies the impact that different approaches of modeling the real-time use of the secondary regulation reserves have in the joint energy and reserve hourly scheduling of a price-taker pumped-storage hydropower plant. The unexpected imbalance costs due to the error between the forecasted real-time use of the reserves and the actual value are also studied and evaluated for the different approaches. The proposed methodology is applied to a daily-cycle and closed-loop pumped-storage hydropower plant. Preliminary results show that the deviations in the water volume at the end of the day are important when the percentage of the real-time use of reserves is unknown in advance, and also that the total income in all approaches after correcting these deviations is significantly lower than the maximum theoretical income. [ABSTRACT FROM AUTHOR]

The increasing penetration of renewable energy sources (RESs) in the power system has highlighted the benefits of being able to store energy in a more efficient manner, and the need of holding additional operating reserves to manage the system under more demanding conditions due to the inherent uncertainty and variability of wind and solar power. Pumped hydroelectric energy storage (PHES) is by far the most established technology for energy storage at a large-scale. PHES units have also participated in the active power-frequency control for years, and last technical developments in PHES have been oriented to improve their capability of providing regulation reserves by means of variable speed design or by hydraulic short-circuit configurations. This fact, together with the impact of RES on spot-market energy and ancillary services prices, is changing the operation and market conditions faced by PHES plants. The aim of this paper is to review the current trends in the PHES operation, to discuss why current practices should be re-examined, and to present the main challenges faced by PHES operators who will need to adapt their scheduling and bidding models to optimize jointly the operation in the energy and in the ancillary services markets. [ABSTRACT FROM AUTHOR]

In this paper, the contribution of a hydraulic short-circuit pumped-storage power plant (HSCPSPP) to the load-frequency regulation (LFR) of an isolated power system has been further analyzed by means of simulations. For this purpose, a simulation model has been developed that considers the AGC system and both the synchronized thermal units' and the HSCPSPP's response to frequency deviations and power set-point signals sent by the AGC system. The frequency deviation of the power system and the electromechanical behavior of the HSCPSPP have been modeled by using commonly accepted approaches for studies on long-term dynamics of power systems. The behavior of the penstock has been considered through an elastic water column model. The simulations results demonstrate that the HSCPSPP has a large flexibility and that can contribute to a great extent to the LFR of the system, while fulfilling the requirements established by the TSO and preserving the plant safety. [ABSTRACT FROM AUTHOR]

Abstract: This paper presents a dynamic programming model to solve the short-term scheduling problem of a hydropower plant that sells energy in a pool-based electricity market with the objective of maximizing the revenue. This is a nonlinear and non-concave problem subject to strong technical and strategic constraints, and in which discrete and continuous variables take part. The model described in this paper determines, in each hour of the planning horizon (typically from one day to one week), both the optimal number of units in operation (unit commitment) and the power to be generated by the committed units (generation dispatch). The power generated by each unit is considered as a nonlinear function of the actual water discharge and volume of the associated reservoir. The dependence of the units’ efficiency and operating limits with the available gross head is also accounted for in this model. The application of this model to a real hydropower plant demonstrates its capabilities in providing the operation schedule that maximizes the revenue of the hydro plant while satisfying several constraints of different classes. In addition, the use of this model as a supporting tool to estimate the economic feasibility of a hydropower plant development project is also analyzed in the paper. [ABSTRACT FROM AUTHOR]

This paper aims to investigate the influence of the water hammer effect on low-frequency oscillations (LFO) in power systems, mainly quantifying and revealing the characteristics of hydraulic damping of LFO. The models of the grid-connected hydropower stations considering the water column elasticity (elastic model) and without considering it (rigid model) are respectively established and used as time domain validation models. The corresponding analytical formulas for the mechanical damping torque coefficients (MDTC) are derived to obtain the system's damping frequency characteristics. Finally, a method for quantifying the nonlinear system's damping is proposed. The results show that due to the effect of the water hammer wave, the system's damping frequency characteristics have changed, and damping peaks and valleys appear. The corresponding frequencies are determined by the frequency of the water hammer wave. The system has a critical oscillation frequency. When the frequency of LFO is below the critical frequency, water column elasticity must be considered. When the frequency of LFO is consistent with the frequency of the water hammer wave, the negative damping reaches its maximum. Finally, the proposed quantitative method was used to clarify the influence of the water hammer effect on the system's damping characteristics while considering nonlinear head loss. [ABSTRACT FROM AUTHOR]

• Operating principle and configuration method for energy storage pump are proposed. • Quantified how pump affects renewable energy consumption in a hybrid power system. • The capacity relationship between pump and hydropower plant is investigated. • The configuration that maximizes the investment profit of pump is identified. Coupling energy storage pumps with conventional hydropower plants is one of the most valuable methods to increase the consumption rate of renewable energy. There are few small-scale hybrid power systems configurating energy storage pumps in the world (e.g., Ikaria Island, Greece). However, whether the operating principle and configuration method are feasible and transferable for a large-scale renewable energy base is unclear. This study proposes specific operating principles and configuration method for a large-scale hybrid power system, demonstrating the feasibility by investigating typical scenarios of an engineering case in Qinghai Province, China. Assume the conventional hydropower plants, wind farms, and PV stations in the case are constructed and in operation completely. The configuration relationship between energy storage pump and hydropower is investigated by setting the unit of energy storage pump from 1 to 50, the per-kW investment cost from CNY 5000 /kW to CNY 30000 /kW under the constraint of individual capacity of 100 MW. Furthermore, the economic indicators of internal rate of return and dynamic payback period are introduced to evaluate the performance of the whole hybrid power system. The configuration consequence of 18–21 pumps shows a good relation with renewable energy. This study provides theoretical and technical support for planning relevant hybrid power station projects. [ABSTRACT FROM AUTHOR]

Traditional fixed-speed pumped storage (PS) has been a reliable measure to provide power system flexibility. However, the increasing need for flexibility of power systems due to adverse environmental events and amplified utilization of renewable sources necessitates the need for modernization of PS units. This paper studies the effect of five PS technologies with different operational flexibility in Qinghai Province's energy system. Firstly, PS models considering the difference in minimum stable generation & pumping, unit efficiency, configurations of turbine & pump are established. Then, the energy mixes, planning capacity, inflow, reservoir operation curve and other data are input into the energy system model. Finally, we quantify the effects of different PS forms on the energy system based on technical, economic, and emission indicators, also identify the optimal PS considering cost preference and emission preference. Results show that the investment costs for various pumped storage technologies depend on the motor type and pump capacity. Fixed-speed pump turbine technologies have a lower cumulative power variation of up to 11,225 GWh and the largest number of start-ups in pumping conditions, at 10,857 times. Increasing operational flexibility stabilizes the reservoir water level, and enhancing pump capacity reduces net load fluctuations for ternary PS and variable-speed quaternary PS. Improving wind-solar curtailment is limited by pump capacity, generating flexibility, and reservoir water level. Systems equipped with fixed-speed PS technologies emit more than carbon emissions other PS technologies. Our research outcomes have the potential to provide valuable insights, enabling stakeholders to optimize the deployment of pumped storage flexibility in low-carbon energy systems, taking into account the energy mix and hydrological conditions that are specific to each region. [ABSTRACT FROM AUTHOR]

• A vibration avoidance strategy is proposed for operation stability of hydropower units. • Two multi-objective optimization algorithm distinguish the implementation difficulty of this strategy. • The strategy is verified by twelve scenarios composed of different inflow and weather conditions. • Implementation achieves 99.31% of operation time in non-vibration zones. Hydropower has the advantages of quickly responding to load variability, which overcomes the unpredictable and unstable variabilities of solar and wind power. Therefore, such power generation can be combined into a hydro-wind-photovoltaic complementary plant (HWPCP). However, hydropower units running at partial load are prone to suffer from hydraulic instabilities generated by a cavitating vortex rope, which may lead to power swings and high vibrations. Operation in these vibration zones may affect the operation and ultimately cause structural damage and affect the power plant. The problem of avoiding running hydropower units in the vibration zones is effectively addressed in this study. This is achieved by adopting a vibration avoidance strategy to determine a rational power distribution scheme for hydropower units. Multi-objective optimization is performed to maximize power generation, minimize output power fluctuations, and minimize the deviation between the power generation and the planned output. The power distribution strategies of hydropower units under 12 scenarios, composed of different inflow and weather conditions, are analyzed. The results indicate that the vibration avoidance strategy effectively avoids the operation of hydropower units in the vibration zones and ensures the operation of hydropower units in the non-vibration zone for more than 99.31% of the operation time. This study contributes to the identification of the relationship between conflicting objectives and provides operational strategies for the safe and stable operation of hydropower units. [ABSTRACT FROM AUTHOR]