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Dynamic analysis of island systems with wind-pumped-storage hybrid power stations
Renewable Energy 74 (2015) 544e554
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Dynamic analysis of island systems with wind-pumped-storage hybrid power stations Stefanos V. Papaefthymiou*, Vasileios G. Lakiotis, Ioannis D. Margaris, Stavros A. Papathanassiou School of Electrical and Computer Engineering, National Technical University of Athens (NTUA), 9 Iroon Polytechniou st., 15780 Athens, Greece
a r t i c l e i n f o
a b s t r a c t
Article history: Received 26 April 2014 Accepted 22 August 2014 Available online
Combined wind and pumped-storage virtual power plants, called hybrid power stations (HPS), constitute a realistic and feasible option to achieve high renewable energy source (RES) penetration levels in power systems and particularly in autonomous island grids. Technical issues arising from the integration of HPS in islands have not been sufficiently investigated yet. In this paper, the dynamic behaviour of an island system with an HPS is analysed, the effects of the various HPS operating modes on the transient behaviour and stability of the system are investigated, constraints regarding the operation of the HPS are identified and potential solutions are proposed. © 2014 Elsevier Ltd. All rights reserved.
Keywords: Hybrid power station Pumped storage Wind power Island system Transient behaviour Dynamic analysis
1. Introduction Energy storage is considered as the most effective means to significantly increase wind penetration levels in power systems [1,2], particularly in the case of isolated island grids where technical limitations are imposed by conventional generating units and the limited size of the systems, [3,4]. For power system sizes beyond a few MW, pumped storage is the most technically mature and economically viable centralized storage technology, particularly suited for facilitating large scale RES integration in medium and large power systems, due to its high power and energy capacity, [1,2,5e9]. A favourable and realistic way to introduce pumped storage in island systems is based on the concept of hybrid power stations (HPS), which are virtual power plants, comprising wind farms (WFs) and storage facilities, operating in a coordinated manner, [10e12]. The basic concept is that wind energy, which would otherwise be discarded, due to the penetration limits imposed (e.g. during periods of low load and high wind), can be stored by pumping water to the upper reservoir. This energy is subsequently recovered in a controllable manner via the hydro turbines, permitting thus the substitution of thermal energy and capacity.
* Corresponding author. Tel.: þ30 210 7724014. E-mail addresses: [email protected], [email protected] (S.V. Papaefthymiou). http://dx.doi.org/10.1016/j.renene.2014.08.062 0960-1481/© 2014 Elsevier Ltd. All rights reserved.
Concerning the exploitation of available wind energy, besides pumping, there exists also the possibility of partially substituting dispatched hydro generation (Hydro-Wind mode of operation). As shown in Refs. [10,12e14], HPS projects can constitute attractive investments, while from a system perspective, the integration of a properly sized HPS may lead to the reduction of the island system levelized cost of energy (LCOE), [14]. The introduction of wind-pumped-storage HPS for increasing wind energy penetration levels has been the subject of several publications, where operating concepts, expected benefits and sizing issues are discussed, [10e20]. However, the published research on HPS dynamics and their effect on the transient response of power systems they are integrated into, is clearly insufficient, focussing actually on the dynamics of individual HPS components. Specifically, extensive work has been performed on hydro power stations, e.g. Refs. [21e26], as well as on wind turbines (WTs), e.g. Refs. [27e30], covering all aspects of modelling, control and system integration. On the other hand, limited material has been published on pumped storage plant dynamic analysis and system integration aspects. A simplified and a more accurate model of the hydraulic part of a pump are presented in Refs. [24,25] respectively, while in Ref. [26] the transient behaviour of reversible pump-turbine units is investigated. The potential contribution of pumped storage in alleviating frequency regulation problems in systems with high wind penetration is discussed in Refs. [31,32]. An investigation of the dynamic response of autonomous power systems incorporating wind-pumped-storage HPS is presented in
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Ref. [33]. Although this paper addresses the issue in an consistent manner, it does not investigate the effect of all HPS operating modes, while the analysis is performed for large island systems, employing conventional generating units with a slower response compared to hydro turbines (like steam turbines and combined cycle plants), therefore the substitution of conventional units by hydro turbines is expected to have a positive effect on system dynamics. In this paper the effect from the integration of wind-pumpedstorage HPS on the dynamic behaviour and stability of autonomous power systems, as those existing on small and medium sized non-interconnected islands, is systematically investigated. Technical issues associated with the various HPS operating modes are discussed, including the substitution of conventional diesel units by hydro turbines, the combined wind-hydro generating mode and the coordination of wind and pumping facilities. In all cases the focus is on the dynamic response of the HPS components and the system in total, rather than on energy efficiency and economic viability issues, which have been the subject of other publications (e.g. Refs. [10e14]). The objective is to assess the effect from the introduction of pumped storage facilities on the dynamics of small isolated power systems, identify possible constraints regarding the operation of the HPS and investigate and propose solutions. A realistic non-interconnected island system and an indicative HPS are used as study case in the paper. All simulations have been performed using DigSilent/PowerFactory, [34]. The paper is organized as follows. In Section 2, the study case island system and HPS are described. The dynamic models used for the components of the system are outlined in Section 3. Simulation results from the analysis of the system response with and without the HPS, at the different possible operating modes, are presented in Section 4. The main conclusions are summarized in Section 5. 2. Description of the study-case system A representative medium-sized-island system, shown in Fig. 1, is used as study case. The island generation system consists of
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conventional thermal units (diesel units) and renewable power stations (WFs and an HPS). A small 150 kV transmission network feeds two 150/21 kV substations (S/S) and their 20 kV distribution network. Analytically, the island system relies on a conventional Autonomous Power Station (APS), comprising 7 15 MW internal combustion diesel engines, which supply the two main S/S via three overhead high-voltage (HV) 150 kV lines. The total installed WF capacity is 14.5 MW. The five WFs of the island are all connected to the medium voltage (MV) 20 kV distribution network and comprise several WT types. A single HPS is integrated in the island system, whose components have been sized based on [14,18,19]. It includes a 9 2 MW WF (WTs with synchronous generators and full-power converters), a pump station with 12 1.47 MW variable speed pump units and a hydroelectric plant with 3 5 MW turbines. The HPS is connected to the 150 kV system via a dedicated MV/HV substation and a radial HV line. The integration of a relatively large HPS in an isolated island system raises several technical issues, including the following, to be further investigated in this paper: Hydro turbines are dispatched by the Island System Operator on a daily basis, typically at medium and high load hours, substituting expensive conventional units (in this paper, diesel generators). An important issue is whether the hydro turbines match the dynamic response characteristics of the substituted thermal units. During operation of hydro turbines, part of their dispatched output power may be substituted by the power generated by the HPS WF (Hydro-Wind mode). In such a case, the hydro turbines need to compensate for the high variability or potential loss of wind power. In a saturated island system, wind power generated by the HPS WF is primarily stored by pumping action (Wind-Pumping mode), rather than fed directly to the load [10e12]. In this mode, the pumps need to effectively track wind power variations. The island system will operate at substantially higher wind penetration levels, placing an increased frequency regulation
Fig. 1. Simplified single line diagram of the examined island power system.
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Fig. 2. IEEE Type 1 model of the AVR [34]. ‘usetp’ is the set-point reference, ‘u’ is the terminal voltage and ‘Vf’ is the stabilizing feedback.
burden. All system components, including those of the HPS, need to contribute to this task.
The hydro turbine is modelled by:
q¼G
pffiffiffi h
(1)
3. Modelling of the system 3.1. Synchronous generators and automatic voltage regulators
P m ¼ At $h$ðq qnl Þ D$G$Du
(2)
where: All synchronous generators (thermal and hydro units) are simulated using the standard 6th order model [35], available in the library of DigSilent/PowerFactory. For the automatic voltage regulators (AVR), the standard IEEE Type 1 model is used [36,37], shown in Fig. 2. Typical values are used for the parameters of the AVR, based on the IEEE Std. 421.5, [37]. 3.2. Diesel engine and speed governor For the diesel engines of the APS, the standard electronic Woodward governor is assumed, shown in Fig. 3 (DEGOV1 model in PowerFactory). Besides the speed deviation (Du) input, the governor model includes a further input (PAGC set-point) from the automatic generation control (AGC) system of the island, to implement secondary and tertiary frequency regulation. The governor droop can be realized via feedback either from the throttle or from the generator output power (Pe). The diesel engine is simulated by a first order time lag, representing the delay in mechanical torque response. The parameter values selected for the model of the diesel engine and its governor are given in the Appendix, based on data from existing diesel engines, [38]. 3.3. Hydroelectric station A variety of linear and non-linear models have been developed so far for the turbine-water column system, [21,22]. Linear models are more useful for control system studies and small signal stability analysis, while time-domain simulations rely on non-linear models, assuming either a non-elastic or an elastic water column (travelling wave model). The latter is more suitable in long penstock applications, where wave travel times are significant, as well as when severe disturbances are simulated. In this work, the travelling wave model of [21] is used 1. The equations of the model are expressed in per unit (p.u.), assuming the nominal quantities of the hydroelectric station as base values.
1
Unlike [33] where the non-elastic water column model is utilized.
q: water flow to the hydro turbine G: gate opening h: head at the turbine admission equal to h ¼ h0 hloss hw , where h0 is the static head, hloss ¼ k$q2 the head loss due to friction in conduit (k being the linear losses coefficient) and hw the head change due to pressure wave caused by a gate movement P m : output power of hydro turbine Аt: turbine gain, in order G ¼ 1 p.u. to result in P m ¼ 1 p.u., given 1 by At ¼ , hr and qr being the head and flow at turbine hr $ðqr qnl Þ
admission under nominal loading qnl : no load flow, accounting for turbine fixed power losses Du: speed deviation D: damping coefficient, representing the speed deviation damping effect, which is a function of gate opening To model hydraulic effects caused by a gate movement due to penstock steel elasticity and water compressibility, the wave transfer function (3) between pressure and flow at turbine admission is used:
hw ðsÞ 1 e2Te s ¼ z0 $tanhðTe $sÞ ¼ z0 qw ðsÞ 1 þ e2Te s
(3)
In (3), z0 ¼ Tw/Te is the surge impedance of the penstock and Tw ¼ ðL$Q0 Þ=ðg$A$H0 Þ is the water starting time in the penstock, where L is the penstock length, Q0 the nominal flow of each hydro turbine, g the gravity acceleration, A the penstock cross section and H0 the static head. Te ¼ L/a is the wave travel time, where a is the wave velocity. Notably, the dynamic performance of hydro turbines degrades with increasing values of Tw and Te, as delay is added in the turbine power response to gate movements, [22,39]. Since the examined hydroelectric station consists of three hydro turbines with individual final penstock sections, supplied by a common tunnel, the coupling effects should be taken into account. The effect of the tunnel is introduced by using the same form of transfer function (3) between downstream head and flow, where the flow is assumed equal to the sum of flows at the turbine
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Fig. 3. Woodward governor and diesel engine model [34].
admissions, (which is accurate for short penstock lengths, as in this application). The block diagram of the turbine-water column system is shown in Fig. 4. Parameter values are given in the Appendix. The selection of governor model (Fig. 5) is based on [39]. It consists of a proportional-integral-derivative (PID) controller with permanent droop, which feeds the actuator system that controls the gate position. The permanent droop is realized via feedback from the output of the PID controller. Governor inputs are the speed deviation, the AGC set-point and the HPS WF output power (PHW), which is subtracted from PAGC, to implement the Hydro-Wind mode of operation. The actuator system is modelled by a first order lag and a rate limiter. Parameter values are given in the Appendix. Due to the water hammer effect and for ensuring stable frequency regulation, the hydro turbine governors are tuned to present relatively large transient droops, with long resetting times, exhibiting low gain for fast frequency deviations. The tuning depends on the values of Tw and Te, [39]. 3.4. Wind farms WFs on the island employ the three basic WT types: active stall induction generator (ASIG), doubly fed induction generator
(DFIG) and permanent magnet synchronous generator (PMSG). Standard models [27e29], are used for the simulation of the WTs. While WFs external to the HPS do not have fault-ride-through (FRT) capability, the HPS WTs are assumed to exhibit full compliance to grid-code requirements [40,41], including frequency response capabilities to contribute to the primary frequency control of the system, if this is deemed necessary. The PD-type frequency controller proposed in [42], is implemented for this purpose (Fig. 6), incorporating both droop and inertial response. The output of the controller is added to the WT power reference signal, as described in Ref. [42]. In Fig. 6, the droop block provides an output proportional to frequency deviation: WT DPdroop ¼ Kdroop $ðf f0 Þ
(4)
where the gain Kdroop is the inverse of the droop parameter R, here selected equal to the permanent droop of the conventional generators, i.e. R ¼ 5%. In order for the droop function to be active in under-frequency events, sufficient power reserve should be maintained in the WTs. The D-type inertial controller provides an output proportional to the rate of change of the frequency: WT DPinertia ¼ Kinertia $
df dt
(5)
where the inertia gain Kinertia corresponds to the equivalent (“synthetic”) inertia constant of the WT, as seen from its terminals. Inertial response does not require a power reserve margin and its upper limit in under-frequency events is determined by the WT maximum power. Here, Kinertia ¼ 20 was chosen to ensure stable operation of the WTs. A more extended discussion on WT inertial response is given in Ref. [43]. 3.5. Pump station
Fig. 4. Model of the hydro turbine-water column system.
Variable speed pumps are necessary in order for the pump station to track effectively wind power variations when operating in Wind-Pumping mode. This configuration is also shown in Ref. [18] to be more efficient from an energy and economic perspective, compared to constant speed pumps. In this paper, all pumps are assumed to be of the variable speed type.
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Fig. 5. Model of the hydro turbine governor.
hp qp ; u ¼ 1:162$u 0:214$q3p
qp np qp ; u ¼ 0:0107 þ 2:293$ u
Fig. 6. Frequency controller for HPS WTs [42].
The dynamic model of the hydraulic part of the pump station is similar as for the hydroelectric station and its block diagram is shown in Fig. 7. The pump model is described by:
P p;i ¼
hp;i $qp;i $Ap np;i
(6)
where P p;i is the mechanical power of the pump, hp;i is the pump head, qp;i the pump flow, np,i the pump efficiency and Ap a gain in order P p;i ¼ 1 p.u. to correspond to rated speed. Quantities hp;i and np,i are given by the pump characteristics, here described by equations (7) and (8). These have been derived from the (H, Q) and (n, Q) curves of a commercial centrifugal pump, defined at the synchronous motor speed, after application of the affinity law equations [44,45], to recalculate pump performance curves for variable speed operation. The resulting (H, Q) and (n, Q) curve equations are normalized on the static head, nominal pump flow and synchronous speed.
(7)
2 qp 1:613$ u
(8)
Water column dynamics are modelled using the travelling wave model, as for the hydro turbines, with the following differentiations: The pressure waves in the penstock are caused by pump speed variations (due to input power changes) and not by gate movement. The pump head given by (7) constitutes the prime mover for the water, not the static head. Further, due to the very short length of the individual pump penstock, the non-elastic water column model [22], is used, instead of the travelling wave model, without loss of accuracy 2. According to this model, the flow in the individual penstock is given by:
qp;i ¼
hp;i hc h0;i h0;c ki $q2p;i Tw;i $s
(9)
where hc is the admission head, h0;i the static head at the pump, h0;c the admission static head and Tw,i the water starting time of each penstock. Parameters are given in the Appendix. Variable speed pumps here use doubly fed asynchronous motors, a choice quite common in such applications for the benefit of reduced converter ratings and losses that it offers [32]. The model used for this scheme is the DFIG WT model, operating with reverse power flow. To determine the set-point for the pump station input power, a load following controller and a frequency controller are combined, [32]. The load following controller tracks the output power of the HPS WF, while a frequency control term is added to exploit potential frequency response capabilities of the pumps. The frequency controller is based on (10) and it is similar as for the WTs (same gains have been used in p.u.):
df Dpf ¼ Kdroop $ðf f0 Þ þ KD $ dt
(10)
For the pumps used here, input power may vary between 0.6 and 1.0 p.u., corresponding to a speed range of 92e108% of synchronous. 4. Results 4.1. Substitution of diesel units by hydro turbines To examine what effect the substitution of diesel units by hydro turbines may have on the dynamic behaviour of the system, both
Fig. 7. Model of the hydraulic part of the pump station.
2
In case of long individual penstock, the model of [25] can be used.
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Fig. 8. Wind speed time series used in the simulation of normal operation.
normal system operation and severe disturbances have been simulated. All cases correspond to medium load conditions, with a total load demand of 40 MW. 4.1.1. Normal operation In this case, wind power variations are the only disturbance in the system. The wind speed time series of Fig. 8 has been used [38], assumed to be the same for all WFs on the island (worst case scenario). The resulting frequency variations are presented in Fig. 9 for two cases: a) Without the HPS: The load is served by 4 diesel units. b) With the HPS: One diesel unit is substituted by the three HPS hydro turbines. The frequency is affected mainly during high wind speed periods (over 8 m/s), where wind power variations are more intense. The magnitude of the fluctuations increases slightly when a diesel unit is replaced by hydro turbines of the same rating, indicating a reduced primary frequency regulation capability of hydro turbines 3 compared to fast diesel units. 4.1.2. Severe disturbance: outage of a diesel unit The frequency excursion following the outage of a 15 MW diesel unit, operating at 10 MW, is presented in Fig. 10 for the same two cases (with and without the hydro turbines in operation). The outage of one unit results in a step load increase of 23% for the remaining units, which is a quite severe disturbance. In both cases, the system survives without any additional loss of generation. However, the minimum frequency is worse by about 0.5 Hz, when the hydro turbines are in operation, marginally exceeding the 48 Hz limit, which is a typical threshold for the activation of underfrequency relays in non-interconnected island systems. Hence, in this case load shedding might have been triggered. 4.1.3. Severe disturbance e 3-phase fault The most severe disturbance for the system occurs in case of a bolted 3-phase fault on the transmission system under high wind conditions, when all WFs operate at nominal power. The fault occurs on the 150 kV line from the APS to S/S 1 and it is cleared by the circuit breakers at each end of the line in 150 ms. The resulting voltage dip leads to the loss of all wind power in 100 ms, as the WTs external to the HPS do not have FRT capability. According to the standard operating practice on small islands, sufficient spinning reserve is maintained to cater for the loss of the entire wind production.
3 Improvement in the frequency response of a hydroelectric plant may be achieved with increase of hydro turbine inertia (e.g. via flywheels) or with decrease of Tw and Te (e.g. increasing the cross section of the penstock or constructing a surge tank near the turbines), albeit at a substantial cost.
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Fig. 9. Frequency fluctuations in normal operation due to wind power variations, with and without the hydro turbines of the HPS.
The transient response of the system, with and without the hydro turbines in operation, is depicted in Fig. 11. Besides the frequency variations, the output power of all regulating units (diesel and hydro) is shown, as well as several internal quantities of the hydro turbines that may be of interest. The main disturbance causing the large frequency drop is the loss of about 15 MW of wind power. Since the minimum frequency is lower than 48 Hz, load shedding would take place by the underfrequency protection relays of the system. When hydro turbines are dispatched instead of a diesel unit, the frequency experiences a more severe drop (even below 47 Hz), which is a real threat to system integrity and would require more drastic load disconnection. If such a situation is to be avoided, the acceptable wind penetration levels should be constrained by the Island System Operator, in order to mitigate a severe loss of wind power. In the case of hydro turbine operation, a strict constraint would have to be enforced (e.g. maximum penetration ~15e20% of the load demand), probably with an adverse effect on the capacity factor of WFs external to HPS. Furthermore, an electro-mechanical mode of oscillations is observed when the hydro turbines are in operation, attributed to the interaction between the APS and HPS units. Although these oscillations do not constitute a threat for the system, they could be damped by foreseeing a suitable PSS functionality in the specification of the hydro turbines. 4.2. Effect of hydro-wind mode of operation In the Hydro-Wind operating mode the scheduled HPS output is partially provided by its WF, i.e. when the HPS has been dispatched by the Island System Operator for a specific power and there is sufficient wind, the hydro turbines might generate as little as their
Fig. 10. Frequency excursion following the forced outage of a 15 MW diesel unit, loaded at 10 MW, with and without the hydro turbines of the HPS.
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Fig. 11. Response following a 3-phase fault on the transmission system. (a) System frequency, (b) Diesel unit output power, (c) Hydro turbine power and internal variables.
technical minimum (here equal to 10% of their rated power), the rest being provided by the HPS WF. Still, the hydro turbines in operation need to provide balancing power to compensate for all wind power variability (including its sudden loss). To achieve this, a set-point equal to PAGC-PHW is delivered to the governors of the hydro turbines (see Fig. 5), while the WF power is also limited in order to avoid under-loading of hydro turbines below their technical minimum. To evaluate the implications of this mode, normal system operation and the severe 3-phase fault disturbance have been simulated, for exactly the same conditions as in the previous
section. The results obtained are to be compared with those in the previous section, where the HPS WF was not operating. 4.2.1. Normal operation Comparing the variation of system frequency in Fig. 12(a) (blue line (in web version)) with that of Fig. 9, the differences are not essential, indicating that Hydro-Wind coordination within an HPS is not an issue in normal operating conditions. The improvement achieved when the WTs of the HPS participate in frequency regulation of the system (red line (in web version) curves) is clear in Fig. 12. Frequency excursions are more contained
Fig. 12. Normal system operation, when the Hydro-Wind mode is applied. Results with and without frequency response by the HPS WTs. (a) System frequency, (b) Diesel unit output power, (c), (d) HPS output powers without/with WT frequency response.
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and the diesel and hydro turbine output powers are smoother. On the other hand, the HPS WF power (and also the total HPS power) fluctuates much more, due to the superimposed frequency response term. Notably, the HPS WTs now respond to wind power variations on the entire island, i.e. they tend to counter the effect of the external WF variability, providing thus ancillary services to the system. Comparing with Fig. 9, it is clear that the Hydro-Wind mode with frequency regulation from the HPS WTs makes the system more robust, as the combined operation of hydro and wind units of the HPS presents superior frequency control capabilities than the existing diesel units. 4.2.2. Severe disturbances The most unfavourable disturbance when the Hydro-Wind mode is applied is a permanent 3-phase fault on the MV interconnecting line of the HPS, rather than on the transmission system. Such a fault would result in the disconnection of all WFs external to the HPS (as they do not have FRT capability), much as in the previous section, but also to the loss of the entire HPS wind power, which was complementing the hydro turbine output. Under high wind conditions, this compounded wind power loss would lead to unacceptable frequency deviations, severe load shedding and possibly loss of synchronism for the system. The probability of such a contingency is not negligible and it should be taken into account in HPS integration studies. One possible remedy to this problem could be the separation of the HPS WTs into two (or more) groups, interconnected via independent lines, reducing thus the amount of wind power loss that may occur due to single fault/failure events. In this analysis it has been assumed that the HPS WTs are separated into two groups of 5x2 ¼ 10 MW and 4x2 ¼ 8 MW each. Should the loss of one group occur, the WTs of the other group (which need to have FRT and frequency regulation capabilities) will mitigate the effect via the provision of primary frequency response. Simulation results for this scenario are given in Fig. 13, where the worst case is first examined, with the dispatched HPS power being equal to the nominal hydro power (PAGC ¼ 15 MW) and the
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HPS WF operating at maximum hydro power substitution mode, producing PAGC-PHmin ¼ 15-3 ¼ 12 MW. It is observed that the grid frequency drops at 46 Hz (blue line (in web version) in Fig. 13(a)), i.e. it is quite lower than in Fig. 11, where the HPS WFs are out of operation and the dispatched HPS power is provided only by the hydro turbines. The variation of the hydro and HPS WF powers for this case is shown in diagram Fig. 13(b). The increase of the output power of the remaining HPS WF up to its nominal capacity (by ~2.7 MW, green line (in web version)) does not suffice to counterbalance the loss of the other WF which was generating around 6.7 MW before the fault. The response to this disturbance would be improved if the prefault wind power generation was reduced, by imposing a suitable set-point limitation to the HPS WF (limiting thus the permitted extent of Hydro-Wind coordination). Several set-points were tested, trying to achieve a response which is not inferior to that of Fig. 11, while sacrificing as little as possible the extent of HydroWind coordination. Best results were achieved when the setpoint to the entire HPS WF is equal to the nominal capacity of the smaller of the two WT groups, i.e. 8 MW. This is shown in Fig. 13 (red line (in web version)), where it is observed that the maximum frequency deviation is similar as in Fig. 11, hence the Hydro-Wind mode does not aggravate the situation. The rationale behind this selection is to ensure that the pre-fault total wind generation of the HPS is lower than the capacity of the smallest WT group. Thus, even if the largest WT group is lost, the remaining WTs will have the capacity to provide the pre-fault power levels for a short time via their inertial response, until the slower-reacting hydro turbines increase their output to compensate for the lost power. If more than two WT groups exist, the set-point should be adjusted to the remaining WT capacity after the worst single failure event. In conclusion, Hydro-Wind coordination is an acceptable operating mode if the HPS WTs have FRT and frequency response capability and they are electrically separated into two or more groups that operate with the appropriate power limitation to ensure the necessary level of inertial power reserve. Under these
Fig. 13. Results for a 3-phase fault on the interconnecting MV line of the one (out of two) HPS WT groups. Different set-points for the HPS wind production (12 and 8 MW) are tested.
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4.3. Effect of wind-pumping mode of operation Whenever there is wind power available that cannot be supplied directly to the load (e.g. via Hydro-Wind operation, when the HPS is not dispatched for generation), it will be stored via WindPumping operation. Wind-Pumping may also occur when hydro turbines are in operation, even in parallel to the Hydro-Wind mode. In principle, the objective of pump control in this mode of operation is to track wind power as closely as possible, so that the windepump combination appears as “neutral” to the system as possible.
Fig. 14. Wind speed time series considered for the HPS WF.
conditions, the Hydro-Wind mode is beneficial for the system under normal operating conditions, as well as for all fault incidents outside the HPS, while the response in worst case (loss of HPS wind power) is not prohibitive. What needs to be stressed is that in order to reap the substantial benefits of WT frequency regulation, the WTs need to have inertial response capabilities, which extend to high levels of power (up to their rated) and can be delivered without any delay following a disturbance (typical delays of a few seconds may be acceptable in large interconnected systems, but not in island systems with very small total inertia). It is further stressed that what matters is the inertial capability, as the droop-type proportional response is of little significance for fast phenomena, [42].
4.3.1. Normal operation The same scenario is examined as in Fig. 9, the only difference being that Wind-Pumping takes place at the same time. The wind time series of Fig. 14 is used for the HPS WF, consisting of high speeds (9.5e12 m/s), where wind power variations are large (worst case). From the results presented in Fig. 15 (a) (blue line (in web version)) and 15(b) it is clear that Wind-Pumping constitutes an operating mode neutral for the system, as the variable speed pumps track effectively the variations of the HPS wind power. In Fig. 15(d) internal quantities of the pumps are also plotted, whose range of variation and overall variability appear to be acceptable. Pumping efficiency is not affected to a great extent, either, due to the variable power operation. In this mode of operation it does not make sense for the HPS WTs to contribute to frequency regulation, because the frequency
Fig. 15. Normal system operation with Wind-Pumping Mode applied. Operation without and with frequency regulation by the HPS pumps.
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dependent wind power term would be cancelled by the pumps. Hence, the only effect would be to increase the wear of the pumps and possibly reduce wind farm efficiency. However, the provision of frequency regulation by the HPS WTs is necessary if the HydroWind mode takes place, according to the conclusions of Section 4.2. The corresponding results when the HPS pumps provide frequency response, are also shown in Fig. 15(a) (red line (in web version)), 15(c) and 15(e). Frequency fluctuations and output power variations of the regulating units decrease significantly in this case, even compared to Fig. 9 with no HPS in operation, with a very slight impact on the internal operation of the pumps. Therefore, the Wind-Pumping Mode may have a noticeable positive effect on system operation, if the pump units can provide frequency response. This can be also important when the Hydro-Wind and Wind-Pumping modes occur at the same time, as the pumps can then effectively substitute the missing contribution of the HPS WTs to the frequency regulation. 4.3.2. Severe disturbances Wind-Pumping Mode is not expected to create any adverse effect on system stability during severe system faults, since the pumps will most probably not have FRT capability and therefore would be disconnected upon the occurrence of a fault. In such a case, the immediate disconnection of the HPS WF can be enforced, to avoid the creation of a high active power surplus in the system. The Wind-Pumping mode might have a positive effect on the dynamic behaviour of the system during faults, if the pumps had FRT and frequency control capabilities. In case of disturbances which do not result in voltage dips (e.g. loss of generation), the effect of the pumps will be positive regardless of their FRT capabilities, provided that they participate in frequency control. 5. Conclusions In this paper, the effect of wind-pumped storage HPS on the dynamic behaviour of autonomous island systems has been investigated. Because hydro turbines present a relatively slower dynamic response compared to diesel engines, a wide scale substitution of the latter should in principle be contemplated with caution. On the other hand, it should be emphasized that existing diesel units in non-interconnected islands deviate significantly from the ideal, as considered in the simulations, while in large island systems other conventional units may operate (e.g. steam turbines), whose response is slower compared to hydro turbines, [33]. The coordinated operation of the HPS WF either with the hydro turbines or with the pump station (denoted as Hydro-Wind and Wind-Pumping modes of operation) are both acceptable from a technical point of view, under specific preconditions, related with the technical characteristics and control of the HPS WTs and pumps, as explained in Section 4 of the paper. As a general conclusion, if the HPS employs WTs and variable speed pumps with FRT capability and frequency response, then the HPS operating in the Hydro-Wind and Wind-Pumping modes may demonstrate superior dynamic response compared even to fast diesel units. Appendix. Parameter values for the models The Tables 1e4 cite the parameter values used in the various models. The static head of the HPS hydraulic part is H0 ¼ 400 m. The hydro turbine penstock consists of a main steel pipe with Lc ¼ 1700 m, dc ¼ 1.3 m and ec ¼ 19 mm and three individual steel pipes with Li ¼ 10 m, di ¼ 0.8 m and ei ¼ 15 mm. For the pump station, a steel pipe with Lc ¼ 1700 m, dc ¼ 1.2 m and ec ¼ 19 mm is used, along with twelve steel pipes with Li ¼ 20 m, di ¼ 0.5 m and
553
ei ¼ 15 mm. The nominal flow of each hydro turbine is qi ¼ 1.5 m3/s and for the common penstock qc ¼ 4.5 m3/s. The nominal flow of each pump is qi ¼ 0.281 m3/s and for the common pipe qc ¼ 3.376 m3/s. Table 1 Parameter values for the model of diesel engine and governor. Parameters
Value
Symbol
Elucidation
Unit
K T4 T5 T6 TD R TE T1 T2 T3 Const Droop_Cntrl
Actuator gain Time constant Time constant Time constant Combustion delay Droop Time constant power feedback Time constant Time constant Time constant ¼ 0/ Throttle feedback, ¼ 1/ Electric power feedback Minimum throttle Maximum throttle Inertia constant
p.u. s s s s p.u. s s s s e
TMIN TMAX Н
p.u. p.u. s
3 0.1 0.1 0.01 0.043 0.05 0.2 0.01 0 2 1 0.08 1.14 2.45
Table 2 Parameter values for the model of hydro turbine -water column. Parameters
Value
Symbol
Elucidation
Unit
TeT Tei TwT Twi kc ki qnl D At Н
Wave time constant of common tunnel Wave time constant of individual penstock Water starting time of common tunnel Water starting time of individual penstock Friction losses factor of common tunnel Friction losses factor of individual penstock No load flow Damping coefficient Turbine gain Inertia constant
s s s s p.u. p.u. p.u. p.u. e s
1.5173 0.0085 0.4824 0.0075 0.0068 0.00045 0.08 0.5 1.165 4
Table 3 Parameter values for the model of hydro turbine governor. Parameter
Value
Symbol
Elucidation
Unit
KP KI KD R TG Ratemax Ratemin Gmax Gmin
Proportional gain of PID Integral gain of PID Derivative gain of PID Permanent droop Main servo time constant Maximum gate opening rate Maximum gate closing rate Upper limit of governor output Minimum limit of governor output
p.u. p.u. p.u. p.u. s p.u./s p.u./s p.u. p.u.
4 0.8 1 0.05 0.2 0.15 0.15 1.1 0
Table 4 Parameter values for the model of pumps-water column. Parameters
Value
Symbol
Elucidation
Unit
Te,c Te,i Tw,c Tw,i kc ki Ap Н
Wave time constant of common tunnel Wave time constant of individual penstock Water starting time of common tunnel Water starting time of individual penstock Friction losses factor of common tunnel Friction losses factor of individual penstock Pump gain Inertia constant
s s s s p.u. p.u. e s
1.4167 0.0167 0.1078 0.0073 0.00036 0.00034 0.7516 2
554
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References [1] Denholm P, Ela E, Kirby B, Milligan M. The role of energy storage with renewable electricity generation. National Renewable Energy Laboratory; January 2010. Tech. Rep., NREL/TP-6A2e47187. [2] Electrical energy storage. IEC White Paper; December 2011. [3] Papathanassiou S, Boulaxis N. Power limitations and energy yield calculation for wind farms operating in island systems. Renew Energy April 2006;31(4): 457e79. [4] Katsaprakakis DA, Papadakis N, Christakis DG, Zervos A. On the wind power rejection in the islands of Crete and Rhodes. Wind Energy 2007;10:415e34. [5] Caralis G, Papantonis D, Zervos A. The role of pumped storage systems towards the large scale wind integration in the Greek power supply system. Renew Sustain Energy Rev June 2012;16(5):2558e65. [6] Electricity storage, technology brief. IEA-ETSAP, IRENA; April 2012. [7] Outlook of energy storage technologies. Policy Department, Economic and Scientific Policy, European Parliament; February 2008. [8] Electricity energy storage: technology options. A white paper primer on applications, costs and benefits. Electric Power Research Institute (EPRI); 2010. [9] Zach K, Auer H, Lettner G. Report summarizing the current status, role and costs of energy storage technologies. StoRE Project, Deliverable 2.1. March 2012. [10] Papaefthimiou S, Karamanou E, Papathanassiou S, Papadopoulos M. Operating policies for wind-pumped storage hybrid power stations in island grids. IET Renew Power Gener Sept. 2009;3(3):293e307. [11] Papaefthymiou SV, Karamanou EG, Papathanassiou SA, Papadopoulos MP. A wind-hydro-pumped storage station leading to high RES penetration in the autonomous island system of Ikaria. IEEE Trans. Sustain Energy Oct. 2010;1(3):163e72. [12] Papaefthymiou SV, Papathanassiou SA, Karamanou EG. Application of pumped storage to increase renewable energy penetration in autonomous island systems. In: Wind energy conversion systems: technology and trends. London: Springer-Verlag; 2012. p. 295e335. [13] Kapsali M, Anagnostopoulos JS, Kaldellis JK. Wind powered pumped-hydro storage systems for remote islands: a complete sensitivity analysis based on economic perspectives. Appl Energy 2012;99:430e44. [14] S. V. Papaefthymiou, S. A. Papathanassiou, “Optimum sizing of wind-pumpedstorage hybrid power stations in island systems,” Renew Energy, 64, pp. 187e196. [15] Hatziargyriou N, Karapidakis E, Georgiadis D, Stefanakis J, Alexandridis S. Safe increase of wind energy penetration in island systems by pumped storage units - the Crete case. In: Proc. RENES; 2001 [Athens, Greece]. [16] Protopapas K, Papathanasiou S. Application of pumped storage to increase wind penetration in isolated island grids. In: Proc. EWEC 2006, Athens; February 2006. [17] Caralis G, Zervos A. Analysis of the combined use of wind and pumped storage systems in autonomous Greek islands. IET Renew Power Gener March 2007;1(1):49e60. [18] Anagnostopoulos J, Papantonis D. Pumping station design for a pumpedstorage wind-hydro power plant. Energy Convers Manag November 2007;48(11):3009e17. [19] Anagnostopoulos J, Papantonis D. Simulation and size optimization of a pumped-storage power plant for the recovery of wind-farms rejected energy. Renew Energy July 2008;33(7):1685e94. [20] Brown PD, Lopes JAP, Matos MA. Optimization of pumped storage capacity in an isolated power system with large renewable penetration. IEEE Trans. Power Syst May 2008;23(2):523e31. [21] Working Group on Prime Mover and Energy Supply Models for System Dynamic Perfomance Studies. Hydraulic turbine and turbine control models for system dynamic studies. IEEE Trans. Power Syst 1992;7:167e79.
[22] Kundur P. Power system stability and control. EPRI power system engineering series. McGraw-Hill; 1994. [23] Mansoor SP. Behaviour and operation of pumped storage hydro plants. Ph.D. Thesis. Bangor: University of Wales; July 2000. School of Informatics. [24] Hannett LN, Baldwin PL, Prabhakara FS, Guofu Q, Mincheng D, Beilei B. “Modeling of a pumped storage hydro plant for power system stability studies,” in Proc. International Conference on Power System Technology 1998:1300e4. [25] Liang J, Harley RG. Pumped storage hydro-plant models for system transients and long-term dynamic studies. In: Proc. 2010 IEEE power and energy society general meeting, Minneapolis, USA; June 2010. [26] Pannatier Y, Nicolet C, Kawkabani B, Deniau J-L, Schwery A, Avellan F, et al. Transient behavior of variable speed pump-turbine units. In: IAHR 2008, 24th Symposium on hydraulic Machinery and systems, Foz do Iguassu, Brasil, October 27-31; 2008. [27] Jauch C, Hansen AD, Sørensen P, Blaabjerg F. Simulation model of an activestall fixed-speed wind turbine controller. Wind Eng 2004;28(2):177e95. [28] Hansen AD, Michalke G. Fault ride-through capability of DFIG wind turbines. Renew Energy 2007;32:1594e610. [29] Hansen AD, Michalke G. Modeling and control of variable speed multi-pole permanent magnet synchronous generator wind turbine. Wind Energy 2008;11(5):537e54. [30] Papaefthimiou S, Papathanassiou S. Modeling of a variable speed wind turbine with synchronous generator. In: Proc. EWEC; 2009 [Marseille, France]. [31] Brown PD. Evaluation of integration pumped storage units in an isolated network. MSc Thesis. University of Porto Department of Electrical and Computer Engineering; May 2006. [32] Suul JA, Uhlen K, Undeland T. Variable speed pumped storage hydropower for integration of wind energy in isolated grids e case description and control strategies. In: NORPIE/2008, Nordic workshop on power and industrial electronics; June 9-11, 2008. [33] Sakellaridis N, Mantzaris J, Papathanassiou S, Vitellas I, Vournas C. Security assessment of an autonomous system with increased wind penetration and pumped storage hybrid plants. In: IEEE PES 2012 general Meeting, San Diego; July 2012. [34] [Online]. Available: http://www.digsilent.de. [35] Krause PC. Analysis of electric machinery. McGraw-Hill; 1986. Section 12.5. [36] IEEE Committee Report. Excitation system models for power system stability studies. IEEE Trans Feb. 1981;PAS-100:494e509. [37] IEEE recommended practice for excitation system models for power system stability studies, IEEE Standard 421.5.-1992. [38] Margaris ID, Hansen AD, Cutululis NA, Sørensen P, Hatziargyriou ND. Impact of wind power in autonomous power systems e power fluctuations e modeling and control issues. Wind Energy January 2011;14(1):133e53. [39] IEEE guide for the application of turbine governing systems for hydroelectric generating units, IEEE power Engineering Society, Standard 1207-2004. [40] Tsili M, Papathanassiou S. A review of grid code technical requirements for wind farms. IET Renew Power Gener Sept. 2009;3(3):308e32. [41] ENTSO-E network code for requirements for grid connection applicable to all generators. 26 June 2012. [42] Margaris ID, Papathanassiou SА, Hatziargyriou ND, Hansen AD, Sørensen P. Frequency control in autonomous power systems with high wind power penetration. IEEE Trans. Sustain Energy 2012;3(2):189e99. [43] L. Zeni, A. Rudolph, J. M. Swendsen, I.D. Margaris, A.D. Hansen, P. Sørensen, “Virtual inertia for variable speed wind turbines,” accepted for publication in Wind Energy, published online: DOI: 10.1002/we.1549. [44] Volk M. Pump characteristics and applications. 2nd ed. Boca Raton: CRC Press; 2005. 13: 978e0824727550. [45] Girdhar P. Practical centrifugal pumps: design, operation and maintenance. Oxford: Newnes; 2005. 13: 978e0750662734.
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Renewable Energy journal homepage: www.elsevier.com/locate/renene
Dynamic analysis of island systems with wind-pumped-storage hybrid power stations Stefanos V. Papaefthymiou*, Vasileios G. Lakiotis, Ioannis D. Margaris, Stavros A. Papathanassiou School of Electrical and Computer Engineering, National Technical University of Athens (NTUA), 9 Iroon Polytechniou st., 15780 Athens, Greece
a r t i c l e i n f o
a b s t r a c t
Article history: Received 26 April 2014 Accepted 22 August 2014 Available online
Combined wind and pumped-storage virtual power plants, called hybrid power stations (HPS), constitute a realistic and feasible option to achieve high renewable energy source (RES) penetration levels in power systems and particularly in autonomous island grids. Technical issues arising from the integration of HPS in islands have not been sufficiently investigated yet. In this paper, the dynamic behaviour of an island system with an HPS is analysed, the effects of the various HPS operating modes on the transient behaviour and stability of the system are investigated, constraints regarding the operation of the HPS are identified and potential solutions are proposed. © 2014 Elsevier Ltd. All rights reserved.
Keywords: Hybrid power station Pumped storage Wind power Island system Transient behaviour Dynamic analysis
1. Introduction Energy storage is considered as the most effective means to significantly increase wind penetration levels in power systems [1,2], particularly in the case of isolated island grids where technical limitations are imposed by conventional generating units and the limited size of the systems, [3,4]. For power system sizes beyond a few MW, pumped storage is the most technically mature and economically viable centralized storage technology, particularly suited for facilitating large scale RES integration in medium and large power systems, due to its high power and energy capacity, [1,2,5e9]. A favourable and realistic way to introduce pumped storage in island systems is based on the concept of hybrid power stations (HPS), which are virtual power plants, comprising wind farms (WFs) and storage facilities, operating in a coordinated manner, [10e12]. The basic concept is that wind energy, which would otherwise be discarded, due to the penetration limits imposed (e.g. during periods of low load and high wind), can be stored by pumping water to the upper reservoir. This energy is subsequently recovered in a controllable manner via the hydro turbines, permitting thus the substitution of thermal energy and capacity.
* Corresponding author. Tel.: þ30 210 7724014. E-mail addresses: [email protected], [email protected] (S.V. Papaefthymiou). http://dx.doi.org/10.1016/j.renene.2014.08.062 0960-1481/© 2014 Elsevier Ltd. All rights reserved.
Concerning the exploitation of available wind energy, besides pumping, there exists also the possibility of partially substituting dispatched hydro generation (Hydro-Wind mode of operation). As shown in Refs. [10,12e14], HPS projects can constitute attractive investments, while from a system perspective, the integration of a properly sized HPS may lead to the reduction of the island system levelized cost of energy (LCOE), [14]. The introduction of wind-pumped-storage HPS for increasing wind energy penetration levels has been the subject of several publications, where operating concepts, expected benefits and sizing issues are discussed, [10e20]. However, the published research on HPS dynamics and their effect on the transient response of power systems they are integrated into, is clearly insufficient, focussing actually on the dynamics of individual HPS components. Specifically, extensive work has been performed on hydro power stations, e.g. Refs. [21e26], as well as on wind turbines (WTs), e.g. Refs. [27e30], covering all aspects of modelling, control and system integration. On the other hand, limited material has been published on pumped storage plant dynamic analysis and system integration aspects. A simplified and a more accurate model of the hydraulic part of a pump are presented in Refs. [24,25] respectively, while in Ref. [26] the transient behaviour of reversible pump-turbine units is investigated. The potential contribution of pumped storage in alleviating frequency regulation problems in systems with high wind penetration is discussed in Refs. [31,32]. An investigation of the dynamic response of autonomous power systems incorporating wind-pumped-storage HPS is presented in
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Ref. [33]. Although this paper addresses the issue in an consistent manner, it does not investigate the effect of all HPS operating modes, while the analysis is performed for large island systems, employing conventional generating units with a slower response compared to hydro turbines (like steam turbines and combined cycle plants), therefore the substitution of conventional units by hydro turbines is expected to have a positive effect on system dynamics. In this paper the effect from the integration of wind-pumpedstorage HPS on the dynamic behaviour and stability of autonomous power systems, as those existing on small and medium sized non-interconnected islands, is systematically investigated. Technical issues associated with the various HPS operating modes are discussed, including the substitution of conventional diesel units by hydro turbines, the combined wind-hydro generating mode and the coordination of wind and pumping facilities. In all cases the focus is on the dynamic response of the HPS components and the system in total, rather than on energy efficiency and economic viability issues, which have been the subject of other publications (e.g. Refs. [10e14]). The objective is to assess the effect from the introduction of pumped storage facilities on the dynamics of small isolated power systems, identify possible constraints regarding the operation of the HPS and investigate and propose solutions. A realistic non-interconnected island system and an indicative HPS are used as study case in the paper. All simulations have been performed using DigSilent/PowerFactory, [34]. The paper is organized as follows. In Section 2, the study case island system and HPS are described. The dynamic models used for the components of the system are outlined in Section 3. Simulation results from the analysis of the system response with and without the HPS, at the different possible operating modes, are presented in Section 4. The main conclusions are summarized in Section 5. 2. Description of the study-case system A representative medium-sized-island system, shown in Fig. 1, is used as study case. The island generation system consists of
545
conventional thermal units (diesel units) and renewable power stations (WFs and an HPS). A small 150 kV transmission network feeds two 150/21 kV substations (S/S) and their 20 kV distribution network. Analytically, the island system relies on a conventional Autonomous Power Station (APS), comprising 7 15 MW internal combustion diesel engines, which supply the two main S/S via three overhead high-voltage (HV) 150 kV lines. The total installed WF capacity is 14.5 MW. The five WFs of the island are all connected to the medium voltage (MV) 20 kV distribution network and comprise several WT types. A single HPS is integrated in the island system, whose components have been sized based on [14,18,19]. It includes a 9 2 MW WF (WTs with synchronous generators and full-power converters), a pump station with 12 1.47 MW variable speed pump units and a hydroelectric plant with 3 5 MW turbines. The HPS is connected to the 150 kV system via a dedicated MV/HV substation and a radial HV line. The integration of a relatively large HPS in an isolated island system raises several technical issues, including the following, to be further investigated in this paper: Hydro turbines are dispatched by the Island System Operator on a daily basis, typically at medium and high load hours, substituting expensive conventional units (in this paper, diesel generators). An important issue is whether the hydro turbines match the dynamic response characteristics of the substituted thermal units. During operation of hydro turbines, part of their dispatched output power may be substituted by the power generated by the HPS WF (Hydro-Wind mode). In such a case, the hydro turbines need to compensate for the high variability or potential loss of wind power. In a saturated island system, wind power generated by the HPS WF is primarily stored by pumping action (Wind-Pumping mode), rather than fed directly to the load [10e12]. In this mode, the pumps need to effectively track wind power variations. The island system will operate at substantially higher wind penetration levels, placing an increased frequency regulation
Fig. 1. Simplified single line diagram of the examined island power system.
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Fig. 2. IEEE Type 1 model of the AVR [34]. ‘usetp’ is the set-point reference, ‘u’ is the terminal voltage and ‘Vf’ is the stabilizing feedback.
burden. All system components, including those of the HPS, need to contribute to this task.
The hydro turbine is modelled by:
q¼G
pffiffiffi h
(1)
3. Modelling of the system 3.1. Synchronous generators and automatic voltage regulators
P m ¼ At $h$ðq qnl Þ D$G$Du
(2)
where: All synchronous generators (thermal and hydro units) are simulated using the standard 6th order model [35], available in the library of DigSilent/PowerFactory. For the automatic voltage regulators (AVR), the standard IEEE Type 1 model is used [36,37], shown in Fig. 2. Typical values are used for the parameters of the AVR, based on the IEEE Std. 421.5, [37]. 3.2. Diesel engine and speed governor For the diesel engines of the APS, the standard electronic Woodward governor is assumed, shown in Fig. 3 (DEGOV1 model in PowerFactory). Besides the speed deviation (Du) input, the governor model includes a further input (PAGC set-point) from the automatic generation control (AGC) system of the island, to implement secondary and tertiary frequency regulation. The governor droop can be realized via feedback either from the throttle or from the generator output power (Pe). The diesel engine is simulated by a first order time lag, representing the delay in mechanical torque response. The parameter values selected for the model of the diesel engine and its governor are given in the Appendix, based on data from existing diesel engines, [38]. 3.3. Hydroelectric station A variety of linear and non-linear models have been developed so far for the turbine-water column system, [21,22]. Linear models are more useful for control system studies and small signal stability analysis, while time-domain simulations rely on non-linear models, assuming either a non-elastic or an elastic water column (travelling wave model). The latter is more suitable in long penstock applications, where wave travel times are significant, as well as when severe disturbances are simulated. In this work, the travelling wave model of [21] is used 1. The equations of the model are expressed in per unit (p.u.), assuming the nominal quantities of the hydroelectric station as base values.
1
Unlike [33] where the non-elastic water column model is utilized.
q: water flow to the hydro turbine G: gate opening h: head at the turbine admission equal to h ¼ h0 hloss hw , where h0 is the static head, hloss ¼ k$q2 the head loss due to friction in conduit (k being the linear losses coefficient) and hw the head change due to pressure wave caused by a gate movement P m : output power of hydro turbine Аt: turbine gain, in order G ¼ 1 p.u. to result in P m ¼ 1 p.u., given 1 by At ¼ , hr and qr being the head and flow at turbine hr $ðqr qnl Þ
admission under nominal loading qnl : no load flow, accounting for turbine fixed power losses Du: speed deviation D: damping coefficient, representing the speed deviation damping effect, which is a function of gate opening To model hydraulic effects caused by a gate movement due to penstock steel elasticity and water compressibility, the wave transfer function (3) between pressure and flow at turbine admission is used:
hw ðsÞ 1 e2Te s ¼ z0 $tanhðTe $sÞ ¼ z0 qw ðsÞ 1 þ e2Te s
(3)
In (3), z0 ¼ Tw/Te is the surge impedance of the penstock and Tw ¼ ðL$Q0 Þ=ðg$A$H0 Þ is the water starting time in the penstock, where L is the penstock length, Q0 the nominal flow of each hydro turbine, g the gravity acceleration, A the penstock cross section and H0 the static head. Te ¼ L/a is the wave travel time, where a is the wave velocity. Notably, the dynamic performance of hydro turbines degrades with increasing values of Tw and Te, as delay is added in the turbine power response to gate movements, [22,39]. Since the examined hydroelectric station consists of three hydro turbines with individual final penstock sections, supplied by a common tunnel, the coupling effects should be taken into account. The effect of the tunnel is introduced by using the same form of transfer function (3) between downstream head and flow, where the flow is assumed equal to the sum of flows at the turbine
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547
Fig. 3. Woodward governor and diesel engine model [34].
admissions, (which is accurate for short penstock lengths, as in this application). The block diagram of the turbine-water column system is shown in Fig. 4. Parameter values are given in the Appendix. The selection of governor model (Fig. 5) is based on [39]. It consists of a proportional-integral-derivative (PID) controller with permanent droop, which feeds the actuator system that controls the gate position. The permanent droop is realized via feedback from the output of the PID controller. Governor inputs are the speed deviation, the AGC set-point and the HPS WF output power (PHW), which is subtracted from PAGC, to implement the Hydro-Wind mode of operation. The actuator system is modelled by a first order lag and a rate limiter. Parameter values are given in the Appendix. Due to the water hammer effect and for ensuring stable frequency regulation, the hydro turbine governors are tuned to present relatively large transient droops, with long resetting times, exhibiting low gain for fast frequency deviations. The tuning depends on the values of Tw and Te, [39]. 3.4. Wind farms WFs on the island employ the three basic WT types: active stall induction generator (ASIG), doubly fed induction generator
(DFIG) and permanent magnet synchronous generator (PMSG). Standard models [27e29], are used for the simulation of the WTs. While WFs external to the HPS do not have fault-ride-through (FRT) capability, the HPS WTs are assumed to exhibit full compliance to grid-code requirements [40,41], including frequency response capabilities to contribute to the primary frequency control of the system, if this is deemed necessary. The PD-type frequency controller proposed in [42], is implemented for this purpose (Fig. 6), incorporating both droop and inertial response. The output of the controller is added to the WT power reference signal, as described in Ref. [42]. In Fig. 6, the droop block provides an output proportional to frequency deviation: WT DPdroop ¼ Kdroop $ðf f0 Þ
(4)
where the gain Kdroop is the inverse of the droop parameter R, here selected equal to the permanent droop of the conventional generators, i.e. R ¼ 5%. In order for the droop function to be active in under-frequency events, sufficient power reserve should be maintained in the WTs. The D-type inertial controller provides an output proportional to the rate of change of the frequency: WT DPinertia ¼ Kinertia $
df dt
(5)
where the inertia gain Kinertia corresponds to the equivalent (“synthetic”) inertia constant of the WT, as seen from its terminals. Inertial response does not require a power reserve margin and its upper limit in under-frequency events is determined by the WT maximum power. Here, Kinertia ¼ 20 was chosen to ensure stable operation of the WTs. A more extended discussion on WT inertial response is given in Ref. [43]. 3.5. Pump station
Fig. 4. Model of the hydro turbine-water column system.
Variable speed pumps are necessary in order for the pump station to track effectively wind power variations when operating in Wind-Pumping mode. This configuration is also shown in Ref. [18] to be more efficient from an energy and economic perspective, compared to constant speed pumps. In this paper, all pumps are assumed to be of the variable speed type.
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Fig. 5. Model of the hydro turbine governor.
hp qp ; u ¼ 1:162$u 0:214$q3p
qp np qp ; u ¼ 0:0107 þ 2:293$ u
Fig. 6. Frequency controller for HPS WTs [42].
The dynamic model of the hydraulic part of the pump station is similar as for the hydroelectric station and its block diagram is shown in Fig. 7. The pump model is described by:
P p;i ¼
hp;i $qp;i $Ap np;i
(6)
where P p;i is the mechanical power of the pump, hp;i is the pump head, qp;i the pump flow, np,i the pump efficiency and Ap a gain in order P p;i ¼ 1 p.u. to correspond to rated speed. Quantities hp;i and np,i are given by the pump characteristics, here described by equations (7) and (8). These have been derived from the (H, Q) and (n, Q) curves of a commercial centrifugal pump, defined at the synchronous motor speed, after application of the affinity law equations [44,45], to recalculate pump performance curves for variable speed operation. The resulting (H, Q) and (n, Q) curve equations are normalized on the static head, nominal pump flow and synchronous speed.
(7)
2 qp 1:613$ u
(8)
Water column dynamics are modelled using the travelling wave model, as for the hydro turbines, with the following differentiations: The pressure waves in the penstock are caused by pump speed variations (due to input power changes) and not by gate movement. The pump head given by (7) constitutes the prime mover for the water, not the static head. Further, due to the very short length of the individual pump penstock, the non-elastic water column model [22], is used, instead of the travelling wave model, without loss of accuracy 2. According to this model, the flow in the individual penstock is given by:
qp;i ¼
hp;i hc h0;i h0;c ki $q2p;i Tw;i $s
(9)
where hc is the admission head, h0;i the static head at the pump, h0;c the admission static head and Tw,i the water starting time of each penstock. Parameters are given in the Appendix. Variable speed pumps here use doubly fed asynchronous motors, a choice quite common in such applications for the benefit of reduced converter ratings and losses that it offers [32]. The model used for this scheme is the DFIG WT model, operating with reverse power flow. To determine the set-point for the pump station input power, a load following controller and a frequency controller are combined, [32]. The load following controller tracks the output power of the HPS WF, while a frequency control term is added to exploit potential frequency response capabilities of the pumps. The frequency controller is based on (10) and it is similar as for the WTs (same gains have been used in p.u.):
df Dpf ¼ Kdroop $ðf f0 Þ þ KD $ dt
(10)
For the pumps used here, input power may vary between 0.6 and 1.0 p.u., corresponding to a speed range of 92e108% of synchronous. 4. Results 4.1. Substitution of diesel units by hydro turbines To examine what effect the substitution of diesel units by hydro turbines may have on the dynamic behaviour of the system, both
Fig. 7. Model of the hydraulic part of the pump station.
2
In case of long individual penstock, the model of [25] can be used.
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Fig. 8. Wind speed time series used in the simulation of normal operation.
normal system operation and severe disturbances have been simulated. All cases correspond to medium load conditions, with a total load demand of 40 MW. 4.1.1. Normal operation In this case, wind power variations are the only disturbance in the system. The wind speed time series of Fig. 8 has been used [38], assumed to be the same for all WFs on the island (worst case scenario). The resulting frequency variations are presented in Fig. 9 for two cases: a) Without the HPS: The load is served by 4 diesel units. b) With the HPS: One diesel unit is substituted by the three HPS hydro turbines. The frequency is affected mainly during high wind speed periods (over 8 m/s), where wind power variations are more intense. The magnitude of the fluctuations increases slightly when a diesel unit is replaced by hydro turbines of the same rating, indicating a reduced primary frequency regulation capability of hydro turbines 3 compared to fast diesel units. 4.1.2. Severe disturbance: outage of a diesel unit The frequency excursion following the outage of a 15 MW diesel unit, operating at 10 MW, is presented in Fig. 10 for the same two cases (with and without the hydro turbines in operation). The outage of one unit results in a step load increase of 23% for the remaining units, which is a quite severe disturbance. In both cases, the system survives without any additional loss of generation. However, the minimum frequency is worse by about 0.5 Hz, when the hydro turbines are in operation, marginally exceeding the 48 Hz limit, which is a typical threshold for the activation of underfrequency relays in non-interconnected island systems. Hence, in this case load shedding might have been triggered. 4.1.3. Severe disturbance e 3-phase fault The most severe disturbance for the system occurs in case of a bolted 3-phase fault on the transmission system under high wind conditions, when all WFs operate at nominal power. The fault occurs on the 150 kV line from the APS to S/S 1 and it is cleared by the circuit breakers at each end of the line in 150 ms. The resulting voltage dip leads to the loss of all wind power in 100 ms, as the WTs external to the HPS do not have FRT capability. According to the standard operating practice on small islands, sufficient spinning reserve is maintained to cater for the loss of the entire wind production.
3 Improvement in the frequency response of a hydroelectric plant may be achieved with increase of hydro turbine inertia (e.g. via flywheels) or with decrease of Tw and Te (e.g. increasing the cross section of the penstock or constructing a surge tank near the turbines), albeit at a substantial cost.
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Fig. 9. Frequency fluctuations in normal operation due to wind power variations, with and without the hydro turbines of the HPS.
The transient response of the system, with and without the hydro turbines in operation, is depicted in Fig. 11. Besides the frequency variations, the output power of all regulating units (diesel and hydro) is shown, as well as several internal quantities of the hydro turbines that may be of interest. The main disturbance causing the large frequency drop is the loss of about 15 MW of wind power. Since the minimum frequency is lower than 48 Hz, load shedding would take place by the underfrequency protection relays of the system. When hydro turbines are dispatched instead of a diesel unit, the frequency experiences a more severe drop (even below 47 Hz), which is a real threat to system integrity and would require more drastic load disconnection. If such a situation is to be avoided, the acceptable wind penetration levels should be constrained by the Island System Operator, in order to mitigate a severe loss of wind power. In the case of hydro turbine operation, a strict constraint would have to be enforced (e.g. maximum penetration ~15e20% of the load demand), probably with an adverse effect on the capacity factor of WFs external to HPS. Furthermore, an electro-mechanical mode of oscillations is observed when the hydro turbines are in operation, attributed to the interaction between the APS and HPS units. Although these oscillations do not constitute a threat for the system, they could be damped by foreseeing a suitable PSS functionality in the specification of the hydro turbines. 4.2. Effect of hydro-wind mode of operation In the Hydro-Wind operating mode the scheduled HPS output is partially provided by its WF, i.e. when the HPS has been dispatched by the Island System Operator for a specific power and there is sufficient wind, the hydro turbines might generate as little as their
Fig. 10. Frequency excursion following the forced outage of a 15 MW diesel unit, loaded at 10 MW, with and without the hydro turbines of the HPS.
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Fig. 11. Response following a 3-phase fault on the transmission system. (a) System frequency, (b) Diesel unit output power, (c) Hydro turbine power and internal variables.
technical minimum (here equal to 10% of their rated power), the rest being provided by the HPS WF. Still, the hydro turbines in operation need to provide balancing power to compensate for all wind power variability (including its sudden loss). To achieve this, a set-point equal to PAGC-PHW is delivered to the governors of the hydro turbines (see Fig. 5), while the WF power is also limited in order to avoid under-loading of hydro turbines below their technical minimum. To evaluate the implications of this mode, normal system operation and the severe 3-phase fault disturbance have been simulated, for exactly the same conditions as in the previous
section. The results obtained are to be compared with those in the previous section, where the HPS WF was not operating. 4.2.1. Normal operation Comparing the variation of system frequency in Fig. 12(a) (blue line (in web version)) with that of Fig. 9, the differences are not essential, indicating that Hydro-Wind coordination within an HPS is not an issue in normal operating conditions. The improvement achieved when the WTs of the HPS participate in frequency regulation of the system (red line (in web version) curves) is clear in Fig. 12. Frequency excursions are more contained
Fig. 12. Normal system operation, when the Hydro-Wind mode is applied. Results with and without frequency response by the HPS WTs. (a) System frequency, (b) Diesel unit output power, (c), (d) HPS output powers without/with WT frequency response.
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and the diesel and hydro turbine output powers are smoother. On the other hand, the HPS WF power (and also the total HPS power) fluctuates much more, due to the superimposed frequency response term. Notably, the HPS WTs now respond to wind power variations on the entire island, i.e. they tend to counter the effect of the external WF variability, providing thus ancillary services to the system. Comparing with Fig. 9, it is clear that the Hydro-Wind mode with frequency regulation from the HPS WTs makes the system more robust, as the combined operation of hydro and wind units of the HPS presents superior frequency control capabilities than the existing diesel units. 4.2.2. Severe disturbances The most unfavourable disturbance when the Hydro-Wind mode is applied is a permanent 3-phase fault on the MV interconnecting line of the HPS, rather than on the transmission system. Such a fault would result in the disconnection of all WFs external to the HPS (as they do not have FRT capability), much as in the previous section, but also to the loss of the entire HPS wind power, which was complementing the hydro turbine output. Under high wind conditions, this compounded wind power loss would lead to unacceptable frequency deviations, severe load shedding and possibly loss of synchronism for the system. The probability of such a contingency is not negligible and it should be taken into account in HPS integration studies. One possible remedy to this problem could be the separation of the HPS WTs into two (or more) groups, interconnected via independent lines, reducing thus the amount of wind power loss that may occur due to single fault/failure events. In this analysis it has been assumed that the HPS WTs are separated into two groups of 5x2 ¼ 10 MW and 4x2 ¼ 8 MW each. Should the loss of one group occur, the WTs of the other group (which need to have FRT and frequency regulation capabilities) will mitigate the effect via the provision of primary frequency response. Simulation results for this scenario are given in Fig. 13, where the worst case is first examined, with the dispatched HPS power being equal to the nominal hydro power (PAGC ¼ 15 MW) and the
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HPS WF operating at maximum hydro power substitution mode, producing PAGC-PHmin ¼ 15-3 ¼ 12 MW. It is observed that the grid frequency drops at 46 Hz (blue line (in web version) in Fig. 13(a)), i.e. it is quite lower than in Fig. 11, where the HPS WFs are out of operation and the dispatched HPS power is provided only by the hydro turbines. The variation of the hydro and HPS WF powers for this case is shown in diagram Fig. 13(b). The increase of the output power of the remaining HPS WF up to its nominal capacity (by ~2.7 MW, green line (in web version)) does not suffice to counterbalance the loss of the other WF which was generating around 6.7 MW before the fault. The response to this disturbance would be improved if the prefault wind power generation was reduced, by imposing a suitable set-point limitation to the HPS WF (limiting thus the permitted extent of Hydro-Wind coordination). Several set-points were tested, trying to achieve a response which is not inferior to that of Fig. 11, while sacrificing as little as possible the extent of HydroWind coordination. Best results were achieved when the setpoint to the entire HPS WF is equal to the nominal capacity of the smaller of the two WT groups, i.e. 8 MW. This is shown in Fig. 13 (red line (in web version)), where it is observed that the maximum frequency deviation is similar as in Fig. 11, hence the Hydro-Wind mode does not aggravate the situation. The rationale behind this selection is to ensure that the pre-fault total wind generation of the HPS is lower than the capacity of the smallest WT group. Thus, even if the largest WT group is lost, the remaining WTs will have the capacity to provide the pre-fault power levels for a short time via their inertial response, until the slower-reacting hydro turbines increase their output to compensate for the lost power. If more than two WT groups exist, the set-point should be adjusted to the remaining WT capacity after the worst single failure event. In conclusion, Hydro-Wind coordination is an acceptable operating mode if the HPS WTs have FRT and frequency response capability and they are electrically separated into two or more groups that operate with the appropriate power limitation to ensure the necessary level of inertial power reserve. Under these
Fig. 13. Results for a 3-phase fault on the interconnecting MV line of the one (out of two) HPS WT groups. Different set-points for the HPS wind production (12 and 8 MW) are tested.
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4.3. Effect of wind-pumping mode of operation Whenever there is wind power available that cannot be supplied directly to the load (e.g. via Hydro-Wind operation, when the HPS is not dispatched for generation), it will be stored via WindPumping operation. Wind-Pumping may also occur when hydro turbines are in operation, even in parallel to the Hydro-Wind mode. In principle, the objective of pump control in this mode of operation is to track wind power as closely as possible, so that the windepump combination appears as “neutral” to the system as possible.
Fig. 14. Wind speed time series considered for the HPS WF.
conditions, the Hydro-Wind mode is beneficial for the system under normal operating conditions, as well as for all fault incidents outside the HPS, while the response in worst case (loss of HPS wind power) is not prohibitive. What needs to be stressed is that in order to reap the substantial benefits of WT frequency regulation, the WTs need to have inertial response capabilities, which extend to high levels of power (up to their rated) and can be delivered without any delay following a disturbance (typical delays of a few seconds may be acceptable in large interconnected systems, but not in island systems with very small total inertia). It is further stressed that what matters is the inertial capability, as the droop-type proportional response is of little significance for fast phenomena, [42].
4.3.1. Normal operation The same scenario is examined as in Fig. 9, the only difference being that Wind-Pumping takes place at the same time. The wind time series of Fig. 14 is used for the HPS WF, consisting of high speeds (9.5e12 m/s), where wind power variations are large (worst case). From the results presented in Fig. 15 (a) (blue line (in web version)) and 15(b) it is clear that Wind-Pumping constitutes an operating mode neutral for the system, as the variable speed pumps track effectively the variations of the HPS wind power. In Fig. 15(d) internal quantities of the pumps are also plotted, whose range of variation and overall variability appear to be acceptable. Pumping efficiency is not affected to a great extent, either, due to the variable power operation. In this mode of operation it does not make sense for the HPS WTs to contribute to frequency regulation, because the frequency
Fig. 15. Normal system operation with Wind-Pumping Mode applied. Operation without and with frequency regulation by the HPS pumps.
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dependent wind power term would be cancelled by the pumps. Hence, the only effect would be to increase the wear of the pumps and possibly reduce wind farm efficiency. However, the provision of frequency regulation by the HPS WTs is necessary if the HydroWind mode takes place, according to the conclusions of Section 4.2. The corresponding results when the HPS pumps provide frequency response, are also shown in Fig. 15(a) (red line (in web version)), 15(c) and 15(e). Frequency fluctuations and output power variations of the regulating units decrease significantly in this case, even compared to Fig. 9 with no HPS in operation, with a very slight impact on the internal operation of the pumps. Therefore, the Wind-Pumping Mode may have a noticeable positive effect on system operation, if the pump units can provide frequency response. This can be also important when the Hydro-Wind and Wind-Pumping modes occur at the same time, as the pumps can then effectively substitute the missing contribution of the HPS WTs to the frequency regulation. 4.3.2. Severe disturbances Wind-Pumping Mode is not expected to create any adverse effect on system stability during severe system faults, since the pumps will most probably not have FRT capability and therefore would be disconnected upon the occurrence of a fault. In such a case, the immediate disconnection of the HPS WF can be enforced, to avoid the creation of a high active power surplus in the system. The Wind-Pumping mode might have a positive effect on the dynamic behaviour of the system during faults, if the pumps had FRT and frequency control capabilities. In case of disturbances which do not result in voltage dips (e.g. loss of generation), the effect of the pumps will be positive regardless of their FRT capabilities, provided that they participate in frequency control. 5. Conclusions In this paper, the effect of wind-pumped storage HPS on the dynamic behaviour of autonomous island systems has been investigated. Because hydro turbines present a relatively slower dynamic response compared to diesel engines, a wide scale substitution of the latter should in principle be contemplated with caution. On the other hand, it should be emphasized that existing diesel units in non-interconnected islands deviate significantly from the ideal, as considered in the simulations, while in large island systems other conventional units may operate (e.g. steam turbines), whose response is slower compared to hydro turbines, [33]. The coordinated operation of the HPS WF either with the hydro turbines or with the pump station (denoted as Hydro-Wind and Wind-Pumping modes of operation) are both acceptable from a technical point of view, under specific preconditions, related with the technical characteristics and control of the HPS WTs and pumps, as explained in Section 4 of the paper. As a general conclusion, if the HPS employs WTs and variable speed pumps with FRT capability and frequency response, then the HPS operating in the Hydro-Wind and Wind-Pumping modes may demonstrate superior dynamic response compared even to fast diesel units. Appendix. Parameter values for the models The Tables 1e4 cite the parameter values used in the various models. The static head of the HPS hydraulic part is H0 ¼ 400 m. The hydro turbine penstock consists of a main steel pipe with Lc ¼ 1700 m, dc ¼ 1.3 m and ec ¼ 19 mm and three individual steel pipes with Li ¼ 10 m, di ¼ 0.8 m and ei ¼ 15 mm. For the pump station, a steel pipe with Lc ¼ 1700 m, dc ¼ 1.2 m and ec ¼ 19 mm is used, along with twelve steel pipes with Li ¼ 20 m, di ¼ 0.5 m and
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ei ¼ 15 mm. The nominal flow of each hydro turbine is qi ¼ 1.5 m3/s and for the common penstock qc ¼ 4.5 m3/s. The nominal flow of each pump is qi ¼ 0.281 m3/s and for the common pipe qc ¼ 3.376 m3/s. Table 1 Parameter values for the model of diesel engine and governor. Parameters
Value
Symbol
Elucidation
Unit
K T4 T5 T6 TD R TE T1 T2 T3 Const Droop_Cntrl
Actuator gain Time constant Time constant Time constant Combustion delay Droop Time constant power feedback Time constant Time constant Time constant ¼ 0/ Throttle feedback, ¼ 1/ Electric power feedback Minimum throttle Maximum throttle Inertia constant
p.u. s s s s p.u. s s s s e
TMIN TMAX Н
p.u. p.u. s
3 0.1 0.1 0.01 0.043 0.05 0.2 0.01 0 2 1 0.08 1.14 2.45
Table 2 Parameter values for the model of hydro turbine -water column. Parameters
Value
Symbol
Elucidation
Unit
TeT Tei TwT Twi kc ki qnl D At Н
Wave time constant of common tunnel Wave time constant of individual penstock Water starting time of common tunnel Water starting time of individual penstock Friction losses factor of common tunnel Friction losses factor of individual penstock No load flow Damping coefficient Turbine gain Inertia constant
s s s s p.u. p.u. p.u. p.u. e s
1.5173 0.0085 0.4824 0.0075 0.0068 0.00045 0.08 0.5 1.165 4
Table 3 Parameter values for the model of hydro turbine governor. Parameter
Value
Symbol
Elucidation
Unit
KP KI KD R TG Ratemax Ratemin Gmax Gmin
Proportional gain of PID Integral gain of PID Derivative gain of PID Permanent droop Main servo time constant Maximum gate opening rate Maximum gate closing rate Upper limit of governor output Minimum limit of governor output
p.u. p.u. p.u. p.u. s p.u./s p.u./s p.u. p.u.
4 0.8 1 0.05 0.2 0.15 0.15 1.1 0
Table 4 Parameter values for the model of pumps-water column. Parameters
Value
Symbol
Elucidation
Unit
Te,c Te,i Tw,c Tw,i kc ki Ap Н
Wave time constant of common tunnel Wave time constant of individual penstock Water starting time of common tunnel Water starting time of individual penstock Friction losses factor of common tunnel Friction losses factor of individual penstock Pump gain Inertia constant
s s s s p.u. p.u. e s
1.4167 0.0167 0.1078 0.0073 0.00036 0.00034 0.7516 2
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