1. Introduction
One of the known methods of increasing renewable energy integration in power systems is by means of pumped-storage hydropower plants (PSHPs) [
1]. In case of large interconnected power systems, their role mainly involves leveling the daily or weekly power demand curve [
2,
3,
4]. Traditionally, fixed-speed PSHPs contribute continuously to frequency regulation in turbine operation mode and to starting and stopping units in pump operation mode [
5]. However, due to advances in power electronics, variable-speed PSHPs can nowadays contribute continuously to frequency regulation in both modes [
5,
6,
7].
Frequency regulation is the most expensive ancillary service [
8]. For island power systems, this is more challenging than in large interconnected power systems due to the lower inertia inherent to island power systems [
9]. For this reason, specific grid codes for island power systems have been developed [
10]. In these systems, there are several contributions that enhance turbine mode operation of PSHPs [
11,
12,
13,
14].
Variable-speed pumping can get remarkable energy savings [
15]. In fact, there are several studies on the economic gains attainable through variable-speed operation of PSHPs [
16,
17]. In addition, the contribution of variable-speed PSHPs to frequency regulation has been explored. In Reference [
18], a PSHP equipped with doubly fed adjustable-speed units was modeled in both operation modes—generating and pumping—connected to a high-inertia power system. Simulations were compared with real data from Okawachi Pumped-Storage Power Plant. Results showed that the converter response was virtually instantaneous compared to rotor speed deviations or wicket gate movements so that the response to the power command signal was improved. These results were confirmed in Reference [
19], where the dynamic response of a PSHP providing primary regulation in pumping mode was simulated. In Reference [
20], an isolated power system that included a wind farm, a thermal power plant, and a variable-speed PSHP was modeled. Simulation results confirmed that variable-speed units operating in pumping mode reduced frequency deviations caused by wind speed fluctuations. However, frequency converters supplying the rotor of variable-speed machines induced harmonics on active power. In Reference [
21], the main part of the power system on Faroe Islands was modeled, including a diesel group, a conventional hydropower plant, a wind farm and a PSHP. Several control strategies for the pumped-storage power plant in pumping mode were studied to include their contribution to primary regulation. Simulation results demonstrated that variable-speed units in pumping mode in this isolated power system could compensate fluctuations in the power generated by the wind farm.
El Hierro is an island in the Canary island archipelago. Historically, electric generation has been based on diesel generators. However, the island aims to become entirely free from carbon dioxide emissions [
22]. In order to contribute to the achievement of this objective, a hybrid wind pumped-storage hydropower plant (W-PSHP) was committed in June 2014 to minimize utilization of fossil fuels [
23]. The PSHP is divided into a hydropower plant equipped with four Pelton turbines and a pump station. As mentioned above, in the case of small autonomous power systems with reduced short-circuit power, using variable-speed pumps (VSPs)—and consequently frequency converters—may cause severe power quality problems due to converter-caused harmonics. As fixed-speed pumps (FSPs) do not produce harmonics, the pump station is equipped with both FSPs and VSPs.
The most challenging situation for this system takes place when there is high wind power production and not enough power demand to absorb the total amount of wind energy. Therefore, the pump station must consume the difference between the wind power supplied and the power consumed. Usually in this scenario, some diesel units are connected so they can provide primary reserve and inertia, both enough for maintaining frequency under safe values. This paper presents a new PSHP control strategy that combines variable-speed-driven pumps and fixed-speed-driven pumps in the described scenario. Here, frequency regulation is only provided by a dual controller: a continuous speed regulator for the VSPs and a discrete controller for the FSPs. The inertia is supplied by Pelton units, which operate as synchronous condensers [
24]. In this manner, diesel units may be disconnected, decreasing generation costs and greenhouse gas emissions. Owing to the combination of both controllers and the inertia of the Pelton units, an acceptable frequency regulation can be achieved. This technique has been validated through computer simulations.
The remaining paper is organized as follows:
Section 2 presents the main characteristics of the power system.
Section 3 describes the simulation model used.
Section 4 describes the proposed control of the pump station.
Section 5 presents and discusses the simulations made. Finally,
Section 6 draws the conclusions.
2. Wind–Hydro Power Plant and Power System Description
El Hierro is an island belonging to the Canary Islands archipelago, which was declared as a biosphere reserve by the UNESCO. The island aims to become 100% free of greenhouse gas emissions [
22]. The maximum peak demand in 2016 was 7.7 MW, whereas the minimum was approximately 4 MW [
25]. The electrical capacity of the island is 37.8 MW, mainly distributed by diesel generators of 15 MW and a W-PSHP of 22.8 MW.
Table 1 lists the energy supplied by the different technologies during 2016.
In
Figure 1, the simplified scheme of the W-PSHP is shown, describing the water and energy flow according to the operation mode of the turbine and the pump. The wind farm, at a power rate of 11.5 MW, is equipped with five variable-speed wind turbines (VSWTs) ENERCON-E70, while the four Pelton turbines provide the remaining power of 4 × 2.8 MW [
23]. The PSHP includes a pump station that is able to consume 6 MW. The pump station is equipped with 6 × 0.5 MW FSPs and 2 × 1.5 MW VSPs.
As stated above, in this paper, a new dual frequency control provided only by the pumping station is proposed when there is high wind power production. Diesel units are not connected to the grid. The four generators driven by the Pelton turbines, as shown in
Figure 2, operate as synchronous condensers and not in no-flow mode [
24]. Therefore, they provide voltage regulation and inertia.
Figure 2 shows a simplified one-line diagram of El Hierro power system in this scenario.
4. Pump Station Control System
In the scenario considered, VSWTs do not provide frequency regulation, Pelton units operate as synchronous condensers, and diesel units are disabled. Therefore, frequency regulation is only provided by the pump station. The power consumed by the two VSPs (Pumps 1 and 8) should be modified as well as the number of FSPs in operation (Pumps 2, 3, 4, 5, 6, and 7) to maintain the power system frequency,
Figure 6.
4.1. Variable-Speed Pump Control
Frequency disturbances will initially be mitigated by means of a frequency controller that modifies the power consumed by the pumps. Frequency deviations are corrected through an adjustment of the power reference tracked by the converter (see
Figure 6) according to the PI control, Equation (14):
Power converters, according to the modification in power reference, change electric power demanded by VSPs, thus reducing frequency deviation. Consequently, according to Equation (11), rotor speed, np, and mechanical power from the hydraulic machines, pp, will adapt to the new electrical power.
The normal operation power range of each VSP is delimited by the maximum (1.5 MW) and minimum allowable power (900 kW). Therefore, the regulating capacity is limited to 2 × (1.5 − 0.9) = 1.2 MW. For this reason, an anti-windup scheme has been introduced in the controller. These power limits are related to the maximum rotational speed
Nbmax (2970 rpm) and minimum rotational speed
Nbmin (2775 rpm), as recommended by the manufacturer. Operating points out of these limits produce pressure and torque pulsations that may be propagated, both along the power plant conduits and to the electrical grid [
33]. Therefore, the regulating capacity provided by the VSPs is not enough to control possible variances in the power consumed in the system or in the power supplied by the wind turbines. Thus, a second level control for the FSPs is also needed.
4.2. Fixed-Speed Pump Control
A FSP comprises an asynchronous motor and a pump. The rated power of each pump is 500 kW, and the consumed power cannot be regulated. Therefore, the power consumed by the six FSPs can only be modified by changing the number of FSPs in operation.
As shown in
Figure 7, the “Discrete Controller Fixed-Speed Pumps” determine the number of FSPs in operation. The input of this controller is the rotational speed of both VSPs.
If the rotational speed signal of one VSP is larger than the maximum rotational speed
Nbmax threshold during a certain time, an additional FSP will start. In this situation, the VSPs are at maximum load; however, after the connection of a new pump, the VSPs will decrease its power into the normal operation power range. Therefore, the VSPs would have a band of power available for new variations in generation. This process is performed by Part 1 of the “Discrete Controller Fixed-Speed Pumps” presented in
Figure 7 and, for this purpose, a relay, a delay, a pulse generator, and a counter are used. The relay block evaluates if the VSPs rotational speed is outside the operating range. In this case, the relay block introduces a unitary positive signal. To transmit the ON order, it is necessary that this positive signal is maintained during a few seconds, which is evaluated by the ON delay blocks. These continuous signals will be converted into discrete signals by the edge detectors blocks in order to be counted in the counter block.
On the other hand, if the rotational speed of one VSP is below the minimum rotational speed, Nbmin, threshold during a certain time, a FSP should be disconnected. In this situation, the VSPs are at minimum load; however, after the disconnection of one FSP, the VSPs will increase its power into the normal operation range. The control process is analogous to the ON detection case.
Part 2 of “Discrete Controller Fixed-Speed Pumps” represents the ON-OFF activation logic. This part takes into account the number of FSPs, which are operating to activate the FSP that are disabled (i.e., to start up the FSP 4, it is necessary that FSP 2 and FSP 3 are operating. Analogously, to shutdown FSP 4, it is necessary that FSP 7, FSP 6, and FSP 5 are disabled).
6. Conclusions
This paper has studied the frequency control in an isolated system consisting of diesel units and a hybrid wind pumped-storage hydropower plant. The PSHP is divided into a hydropower plant equipped with four Pelton turbines and a pump station equipped with both fixed- and variable-speed pumps. The implementation of a new, dual frequency controller when the intensity of wind power is higher than the power demand has been analyzed so that the frequency regulation could be provided only by VSPs and FSPs. The lack of inertia in the system is solved by Pelton turbines, which operate as synchronous condensers. In this way, diesel units may be disconnected, decreasing generation costs and greenhouse gas emissions.
A dynamic model of the power system has been developed in Matlab Simulink to obtain the system dynamic response and check the effectiveness of the new controller. The main elements of this model are the power system, the pump station, and the VSWTs. The frequency deviation of the power system has been modeled by means of an aggregate inertial model. The pump station model includes—apart from the controller—hydraulic components (penstock, manifold, pipes, etc.), and different mechanical and electrical parts of the pumps. Finally, data from manufactures and a transfer function has been used to obtain the power provided by VSWTs from the wind speed.
The proposed controller has two different levels: variable-speed and fixed-speed control. Frequency deviations are initially corrected by means of a PI controller, which modifies the power consumed by the VSPs. Therefore, frequency fluctuations are corrected through an adjustment of the power reference tracked by the converter of the VSPs. VSPs regulating capacity is restricted because of their rotational speed limits. Thus, when the rotational speed of any VSP is near its limit, the FSPs controller acts by ordering to start up or switch off the necessary number of FSPs. In this manner, the VSPs will decrease or increase their power into the normal operation power range.
Two different simulations have been carried out in order to analyze the dynamic response of the system when the dual pump controller is introduced, paying special attention to the frequency. On the one hand, an event that may occur frequently has been modeled (normal operating conditions), i.e., fluctuations in the power supplied by wind turbines due to variations in wind speed. On the other hand, an unlikely event has been simulated (abnormal operating conditions), i.e., a sudden and unexpected disconnection of one of the five wind generators.
Simulation results have shown that in both cases, the frequency never exceeds the regulation limits and that all the hydraulic and mechanical variables present normal values. It is noticeable that the hierarchical sequence used to start or disconnect the FSPs by the controller should be changed properly so that wear of the six machines are the same. Therefore, as a general conclusion, the proposed controller could reduce the necessity of diesel units when there is high wind power production. It would be interesting, as a future line of work, to economically and environmentally measure the implications of introducing the proposed controller in El Hierro Island.
It is important to highlight that nowadays, according to the current Spanish legislation, this control strategy cannot be implemented because consumers, such as pump stations, are not allowed to provide ancillary regulation services.