A Tutorial on the Application and Setting of Collector Feeder Overcurrent Relays at Wind Electric Plants

Transcription

1 A Tutorial on the Application and Setting of Collector Feeder Overcurrent Relays at Wind Electric Plants Martin Best and Stephanie Mercer, UC Synergetic, LLC Abstract Wind generating plants employ several distribution class circuits called collector feeders which enable the combined output of the wind turbine generators connected to them to be supplied to the bulk electric transmission system. The application and coordination of overcurrent protection systems for collector feeders at wind plants depends on several system characteristics, including collector feeder design, available fault currents, and the protective devices applied to the wind turbine generators. This paper provides a brief tutorial on the application and setting of overcurrent relays for collector feeders at wind plants and includes examples of typical calculations and coordination plots. Index Terms Collector Systems, Overcurrent Relays, Wind Farms, Wind Power. I. INTRODUCTION Large wind generating plants have become prevalent as green energy sources on the power system. A typical large wind generating plant may have wind turbine generators (WTGs), each rated at MVA connected to medium voltage distribution lines called collector feeders spread over a large area. Power from the WTGs is collected at medium voltage (typically 34.5 kv) and supplied to the main substation through the main collector feeder breakers. The relays applied to protect the collector feeder circuits must coordinate with the protective devices for faults at the individual WTGs without limiting the ability of the WTGs to provide power and effective voltage control for the system. This paper is intended to introduce novice engineers to the physical and electrical characteristics of collector feeders at wind electric plants and to provide a general method of overcurrent relay setting calculations and coordination for collector feeders at wind electric plants. II. WIND FARM COLLECTOR FEEDER CHARACTERISTICS Collector systems of large wind power plants normally have a radial configuration where the WTGs are connected together in a daisy-chain style, moving from the main feeder breaker at the collector substation to the farthest turbine. Collector feeders can therefore be thought of as radial distribution lines when all the generators are off-line and as multi-terminal subtransmission lines when one or more generators are on line. Figure 1 shows a one-line diagram of a wind electric power plant consisting of two collector feeder sections. As can be observed in this figure, the wind turbine generators on some collector feeders are simply connected one after the other down the length of a single circuit. However, some collector feeders may also have branch strings, which are connected by junction boxes. The junction boxes, in turn, have separable connectors (or elbows) that allow isolation of a feeder string to enable continuous operation of the remaining connected WTGs while maintenance or repair work is being performed. Collector feeder circuit operation exhibits both radial and network (looped) characteristics. When the WTGs are off-line they draw only the relatively low load current required by their station auxiliary equipment (lights, heaters, turbine gear motors, etc.). This station service current for the WTGs flows radially from the Collector Substation to the WTGs on the line, and system fault current flows exclusively from the Collector Substation to the fault location on the line or at a WTG. When the WTGs are on-line, their collective output current flows from the WTGs to the Collector Substation, and with multiple generation sources the collector feeder operates as a network. If a fault occurs on the line or at a WTG, most of the fault current comes from the Collector Substation, but a small component of the total fault current does come from any WTGs that are on line at the time of the fault.

2 sequence overcurrent elements can be also applied to provide additional protection or to satisfy coordination requirements that are unique to the installation. Non-directional overcurrent protection can often be applied for collector feeders because the fault current contribution from the collector substation is usually much greater than the contribution from the WTGs; however, if increased sensitivity is required to coordinate with individual WTG protective devices or to detect a fault on the low-voltage side of the WTG transformer, then directional overcurrent protection may be required at the collector feeder breaker. Fig. 1. Collector Feeder One-Line Diagram at a Wind Electric Power Plant. Therefore, relay protection schemes that are commonly applied for either radial or network distribution circuits may be considered. Non-directional overcurrent protection schemes have traditionally been applied for radial distribution line protection. Directional over-current protection schemes have traditionally been applied for protection of network or looped circuits, as well as directional distance relay protection schemes. Ideally, the protection schemes applied at the main feeder breakers at a wind electric power plant should provide primary protection for the collector feeder and backup protection for the step-up transformer at each WTG location. The inverse time-current characteristic of a time overcurrent relay can be selected to coordinate with the thermal damage curve of a line conductor or transformer as well as with overcurrent protective devices such as transformer fuses. Therefore, non-directional and directional overcurrent schemes are almost exclusively applied for collector feeder protection. 1) Non-Directional Overcurrent Protection Example The collector feeder in Figure 1 consists of eight 3.4 MW wind turbine generators. The full load current I FLA of all 8 Generators at 34.5 kv is: I FLA = 1000(8)(3.4 MVA) = 455 A ( 3)(34.5 kv) Since the relay is non-directional, the trip current setting of phase time overcurrent element 51P must be greater than or equal to 1.3 x I FLA for asynchronous generators and inverters, per NERC Standard PRC-025 (Generator Relay Loadability) [1]. Therefore, the 51P setting must be greater than or equal to: 1.3*(455) = 592 A The CT ratio on Feeder 4 is 1200:5 or 240:1. Therefore, dividing the desired trip setting by the current transformer ratio yields 592/240 = 2.47 A, secondary Therefore, the trip current setting for the 51P can be 2.47 A, secondary, if the relay can be set exactly, or rounded up to the nearest tenth to 2.5 A, secondary = 600 A, primary. Each WTG pad mount transformer in Figure 1 has a 3.35 MVA rating and is protected on the 34.5 kv side by a 100 A current limiting fuse in series with a 71 A expulsion type fuse. A current limiting fuse is typically connected in series with the expulsion fuse in cases where the available fault current exceeds the current interrupting rating of the expulsion fuse. The 51P relay must coordinate with the expulsion fuse at fault currents below the 1200 A interrupting rating of the fuse and with the current limiting fuse at fault currents above the expulsion fuse interrupting rating. A very inverse curve was selected to generally match the slope of the EXP and CLF curves over the range of fault currents. III. PROTECTION SCHEMES FOR WIND FARM COLLECTOR FEEDER CIRCUITS Overcurrent protection schemes for collector feeder circuits typically includes time delay and instantaneous phase and ground overcurrent elements. Definite time and negative An example of the resulting coordination appears in Figure 2. In Figure 2 the expulsion fuse (EXP) curve appears below both the transformer damage curve and the current limiting fuse (CLF) at fault currents lower than about 1200A. At fault currents above about 1200A the current limiting fuse (CLF) curve falls below the expulsion fuse curve and will clear the fault before the expulsion fuse can be damaged, thus protecting

3 the expulsion fuse. A very inverse curve was selected for the 51P to match the slope of the EXP/CLF curve combination. Both the EXP and CLF fuse curves fall below the feeder 4 51P relay curve so the 51P relay curve coordinates with both of the fuse curves. The 51P curve is well below the thermal damage curve of the smallest conductor or the feeder and will therefore trip the breaker for a fault before the conductor is damaged. The 600A trip current setting of the 51P is approximately 10 times the full load current rating of one wind turbine generator. It can be seen from Figure 2 that the high trip current setting provides little protection for individual wind turbine generator transformers. This is because the transformer thermal damage curve ends approximately where the 51P curve starts to operate. Therefore, even at a minimum time dial of 0.5, the relay is providing relatively poor back-up transformer protection for currents under 900 A. The phase instantaneous overcurrent relay 50P is typically set low enough to operate for a three-phase fault at the end of the collector feeder circuit but high enough to avoid operation for the inrush current caused by the eight WTG transformers when the collector feeder breaker is initially closed to energize the circuit. The maximum three-phase fault current available at the end of the collector feeder in Figure 1 is 10,375 A. To ensure that the 50P will operate positively for a fault at the end of the circuit, the relay may be set at 75-80% of the maximum current figure. For example, 0.8(10,375 A) = 8300 A. At the 240/1 CT ratio, the desired setting in secondary Amps would be A. Rounding up to the nearest Amp would yield a 50P setting of 35 = 8400 A, primary. Transformer inrush current upon initial energization is typically estimated to be times the nameplate rating of the transformer. If the combined inrush current of the 8 transformers is 12 x Ic, then the inrush current is 5382 A. This value is below the 8400 A 50P setting, so the 50P should not operate when the main collector feeder breaker is initially closed to energize the circuit. The 50P curve in Figure 2 appears as the vertical line at the end of the 51P curve at 8400 A. In cases where the calculated 50P setting is below the maximum expected GSU transformer inrush current, a dual level 50P scheme can be implemented in which the 50P element can be set to detect a feeder fault at the first WTG transformer on the feeder, based on 75-80% of the maximum fault current available at the high voltage side of the first WTG GSU transformer. A second phase overcurrent element can then be set to detect a fault at the farthest GSU on the circuit. The second 50P element can then be set with a definite time delay (usually in cycles) to ride out the transformer inrush current but avoid thermal damage to the cable at the end of the feeder. The combined nameplate current rating Ic of the 8 WTG transformers is: Ic = 8(3.35 MVA)(1000) = 449 A 1.732(34.5 kv)

4 Fig. 2. Non-Directional Phase Time-Overcurrent Coordination. Since the output current from the WTGs to the substation feeder breaker is essentially balanced, the trip current pickup of the neutral or residual ground time overcurrent (51N or 51G) element can be set relatively low, typically in the range of 10 30% of the phase time overcurrent (51P) setting. When selecting the 51G pickup setting, it is important to ensure that the pickup setting is high enough to coordinate with the expulsion fuse on the high voltage side of the WTG GSU transformers. For example, based on the 600 A 51P pickup current setting calculated previously, the 51G pickup setting could range from 60 A (10%) to 180 A (30%). However, the 71 Amp expulsion fuse on the high voltage side of the GSU transformer won t operate at currents below about 140 A, so the minimum 51G pickup setting should be at least 140 A to ensure proper coordination with the expulsion fuse.

5 Given the 240/1 CT ratio, a 0.6 = 144 A pickup setting for the 51G will be equivalent to 24% of the 51P pickup setting and will coordinate with the expulsion fuse. The curve type and time dial is then selected to coordinate with the expulsion fuse. An example of the resulting coordination between the Feeder F4 51G relay of Figure 1 and the high-side EXP fuses of the WTG 1 GSU transformer appears in Figure 3. In Figure 3 the 51G relay provides very good backup protection for the WTG GSU for single phase-to-ground faults because its setting is equal to just over twice the GSU full load current rating. The 51G coordinates with the EXP fuse at all values of fault current, but it coordinates with the CLF fuse only at current values above about 1200 A. This is acceptable, because the CLF was installed to blow before the EXP fuse for currents above 1200 A. Fig. 3. Non-Directional Ground Time-Overcurrent Coordination. The trip current pickup setting for the residual ground or neutral instantaneous overcurrent (50G or 50N) element is calculated much like that of the 50P. The 50G pickup for a collector feeder is typically set low enough to operate for a single phase to ground phase fault at the end of the feeder circuit but high enough to avoid operation for the combined

6 inrush current of the WTG transformers upon initial energization. The maximum single phase to ground fault current available at the end of the collector feeder in Figure 1 is 7175 Amps. Using the same 50P criterion of 75-80% of maximum fault current figure, an 80% setting for the 50G would be 24 = 5760 A, primary. This figure is just above the estimated 5382 A figure for combined GSU inrush, so the 5760 A 50G pickup setting should suffice. The 50G curve in Figure 3 appears as the vertical line at the end of the 51G curve at 5760 A. In cases where the calculated 50G setting is below the maximum expected GSU transformer inrush current, a dual level 50G protection scheme can be set based on the same criteria as the dual level 50P protection scheme described earlier. 2) Directional Overcurrent Protection Example A directional overcurrent relay can be set to operate for a fault in a particular direction, usually defined as forward or reverse. The forward trip direction for the relay could be defined as being in the direction from the substation bus towards the generators on the line. Conversely, the reverse direction could be defined as being in the direction from the WTG on the line towards the main substation bus. Consequently, the directional phase time overcurrent (67P) trip current pick-up can be set below the maximum output current of all the wind turbine generators when the trip direction is from the substation bus towards the WTG. However, the 67P trip current pick-up setting must be set above the combined wind turbine generator auxiliary load (heater and auxiliary equipment load with the wind turbine generators offline). The combined auxiliary load of all the WTGs on the circuit is typically less than 5% of the generating capacity of one WTG. Therefore, for coordination purposes, the 67P trip current setting can be based on the rating of a single wind turbine GSU transformer. For example, each wind turbine generator transformer in Figure 1 is rated at 3.35 MVA. The maximum nameplate current rating would therefore be: I FLA = 1000(3.35 MVA) = 56A ( 3)(34.5 KV) A typical phase time overcurrent setting for transformer protection would be 1.5 to 2.5 times the transformer nameplate rating, which would be equivalent to 84 to 140A, primary. However, the71 A expulsion fuse does not begin to melt until approximately 140 A; therefore the 67P trip current setting should be set above 140 A in order to coordinate with the EXP fuse. Therefore, the minimum trip current setting of the relay would be 0.6 = 144 A, primary, given the 1200/5 current transformer ratio. A curve type and time dial is then selected to coordinate with the expulsion fuse. Figure 4 shows the coordination between the wind turbine generator fuses and the 67P directional phase overcurrent relay.

7 Fig. 4. Directional Phase Time-Overcurrent Coordination. circuit. From Figure 4 above, it can be inferred that with the lower trip current setting, a more inverse time/current curve characteristic than the 51P could be selected whose slope more closely matches that of the expulsion fuse. The combination of the more inverse curve and the lower trip current setting enables the directional phase time overcurrent relay to provide excellent back-up protection for any of the wind turbine generators on the A 67P relay or the 67P element of an electronic multifunction relay usually determines the trip direction by comparing the line current with the system voltage; therefore, it is important to manage the protection system s response to an inadvertent loss of voltage on one or more phases, such as the loss of a VT secondary fuse. Most electronic relays have loss of potential logic which either blocks the 67P element or allows it to operate non-directionally. Non-directional

8 > REPLACE THIS LINE WITH YOUR PAPER IDENTIFICATION NUMBER (DOUBLE-CLICK HERE TO EDIT) < 8 operation of the 67P during a high generation condition could result in a needless trip of the main collector feeder breaker. Blocking the 67P element for loss of voltage and enabling a backup 51P element with a higher trip current setting would be one solution to the problem. It is also important to consider the effect of variable WTG generator loading conditions when applying directional overcurrent relays for collector feeder protection. Wind turbine generators with classifications of Type 3 and higher can supply or absorb appreciable amounts of reactive power. For example, when the WTGs are being operated in a voltage control mode they may absorb reactive power when they are lightly loaded to counter-act the effects of the capacitance of the collection system. Conversely, when it is necessary to raise the system voltage, the WTGs may be required to supply leading VARs to the system. While this capability enables the wind farm to help control and regulate the system voltage and power factor at the point of interconnection, the main power transformer or collector feeder relays may see a wide range of power factor angles, depending on the system dispatch requirements at the time. Jones and Bennett [2] described two occasions in which the 67P element of a collector feeder protection relay tripped when the VAR output of the Type 3 WTGs connected to the feeder brought the load current angle just inside the trip zone of the forward directional element. This can be seen in Figure 5 for Phase A. Their initial solution was simply to lower the line impedance angle setting used by the directional element from 50 0 to 35 0 to shift the forward trip zone away from the normal and emergency range of generator load current. If the relay is equipped with the load encroachment function, a second solution is to define the desired forward zone of fault protection using both directional control and load encroachment [2]. In this case, the maximum sensitivity angle of the positive sequence forward directional element can be set at the line impedance angle of 50 0 for directional control. Based on the first quadrant of an R-X plot, reverse load encroachment impedance characteristic angles can be set at 90 0 and 270 0, respectively, and the forward load encroachment characteristic angles can be set at 90 0 and 85 0, respectively. The forward and reverse load encroachment impedance settings can be set equivalent to % of the combined WTG capacity of the circuit. Alternatively, the forward and reverse load encroachment impedance settings can also be set on their minimum value [4]. The resulting relay trip zone under both directional control and load encroachment supervision on an R-X plot would therefore go from 85 0 in the first quadrant to in the fourth quadrant. Figure 6 shows the relay trip and non-trip zones as they would appear on the Phase A relay voltage and current axis of Figure 5. The effective relay trip zone under both load encroachment and the positive sequence forward directional element for the Phase A element in Figure 6 goes from 40 0 in the first quadrant through the 50-degrees lagging impedance angle of the line at in the fourth quadrant and ending at in the fourth quadrant. The combined directional and load encroachment settings will make the 67P element insensitive to both leading and lagging VAR flows from the WTGs to the transmission system. Figure 5: Phase A Directional Element Operation with WTGs Supplying Additional VARs for Voltage Support An additional margin of reliability can be provided by setting the line impedance angle as low as 10 0 to ensure proper directional element operation in the presence of large VAR flows (Chen, Shrestha, Ituzaro, and Fischer [2]). Figure 6: Phase A Element Operation with Directional and Load Encroachment Control In some electronic multi-function relays, negative sequence polarization techniques are used to control the operation of the 67P element. The negative sequence element settings used for directional control in typical protection applications may not provide reliable operation for directional protection of

9 > REPLACE THIS LINE WITH YOUR PAPER IDENTIFICATION NUMBER (DOUBLE-CLICK HERE TO EDIT) < 9 collector feeder circuits because the Type 4 turbines that are often installed on collector feeders generally produce very little negative sequence current during faults. Type 3 turbines may also provide little negative sequence current during faults when their response is being controlled by their electronic controls. Chen, Shrestha, Ituzaro, and Fischer [2] described an event in which a collector feeder breaker tripped correctly by 67P for a BCG line fault, but the 67P elements for both unfaulted collector feeders tripped incorrectly because the WTGs on the un-faulted feeders were not able to produce enough negative sequence current to enable the feeder relay to correctly determine the direction of the fault. The authors solution was to change the line impedance angle setting in all the relays to about In the negative sequence domain, lowering the line impedance angle to 10 0 enabled the relay to correctly calculate the fault current direction on both the faulted and un-faulted feeders. Additionally, lowering the line impedance angle to 10 0 moved the boundary angles of the positive sequence forward directional trip zone to and 280 0, respectively on an R-X diagram, or 80 0 and 260 0, respectively on a voltage/current axis such as that shown in Figure 5. The directional phase instantaneous overcurrent relay or element can be given the same pickup setting as the 50P because the collective inrush of the WTG transformers upon energization must still be considered. Some electronic multifunction relays have harmonic current blocking functions. In cases where the transformer inrush current exceeds the instantaneous trip current setting required to detect a fault at the end of the collector feeder circuit, harmonic current blocking can be used to inhibit the directional phase instantaneous overcurrent element from tripping for transformer inrush [4]. Similarly, the considerations discussed above for directional phase instantaneous overcurrent elements apply to directional neutral or ground instantaneous overcurrent element settings. Directional neutral or residual ground time overcurrent relays (67N or 67G) can also be applied for collector feeder protection. However, because the 67G (67N) must coordinate with the high-side fuse of the WTG step-up transformer, its minimum trip current setting will be the same as that of a 51N or 51G, and the resulting coordination would be the same as that shown in Figure 3. combined WTG load, will accommodate any change in generator loading conditions, and will generally provide excellent protection over the length of the collector feeder. However, because their minimum trip current pickup setting can be as much as 8 10 times higher than the rating of a single WTG on the circuit, non-directional phase time overcurrent elements may provide only limited backup overcurrent protection for individual WTG step-up transformers. Directional phase time overcurrent elements can be set below the combined WTG load to provide excellent collector feeder protection and backup overcurrent protection for individual WTG step-up transformers. Additional considerations are required in the selection of directional phase time overcurrent settings to ensure that the relay can accommodate any special generator loading conditions mandated by system voltage support requirements. Both directional and non-directional ground time overcurrent relays or elements in a multi-function relay can be set at a third or less of the combined generator load current but higher than the minimum operating current of the expulsion fuses protecting the WTG step-up transformer. Both directional and non-directional ground time overcurrent elements can provide excellent protection for the entire collector feeder as well as for individual WTG step-up transformers. Non-directional instantaneous overcurrent elements are generally set low enough to detect a fault at the end of the collector feeder but high enough to avoid misoperation for WTG GSU transformer inrush upon energization. Directional instantaneous overcurrent elements can either be set the same as their non-directional counterparts, or harmonic blocking control can be applied to enable them to operate for a fault at the end of a feeder without mis-operating for collective WTG transformer inrush. Additional contributions to the body of knowledge in the field of wind farm protection are made with every advance in wind turbine generator and protective relay technology. It is important for the protection engineer to design protection systems that are optimized to effectively address the specific protection requirements at hand. It is the authors hope that this paper will provide a knowledge base from which to start. IV. CONCLUSION The relay protection schemes applied to collector feeders at a wind electric power plant should provide primary protection for the collector feeder and backup protection for the step-up transformer at each WTG location. Several conclusions can be drawn from the foregoing discussion of overcurrent relay setting calculations and coordination for collector feeders. The first conclusion is that both non-directional and directional overcurrent relays or elements in a multi-function relay can be successfully applied and set to provide primary collector feeder protection and backup WTG transformer protection. Nondirectional phase time overcurrent elements are set above the

10 > REPLACE THIS LINE WITH YOUR PAPER IDENTIFICATION NUMBER (DOUBLE-CLICK HERE TO EDIT) < 10 REFERENCES Professional Engineer in the states of CA, DE, FL, GA, ME, NC, OH, PA, SC, TX, VA, and WA. [1] NERC Reliability Standard PRC-025-1: Generator Relay Loadability, July 17, 2014 [Online] Available: RC pdf [2] D. Jones and K. Bennett, Wind Farm Collector Protection Using Directional Overcurrent Elements, Transmission and Distribution Conference and Exposition (T&D), 2012 IEEE PES [Online] Available: [3] B.Chen, A. Shrestha, F.A. Ituzaro, and N. Fischer, Addressing Protection Challenges Associated With Type 3 and Type 4 Wind Turbine Generators, 40 th Annual Western Protective Relay Conference, October 2013 [Online] Available: /Technical%20Papers/6626_AddressingProtection_AS _ _Web2.pdf?v= [4] R. McDaniel, Phase Directional Overcurrent Settings recommendations for Wind Farm Applications Using the SEL-351S, SEL Application Guide AG Martin F. Best received a BS degree in Electrical Engineering from NC State University in 1976 and an MS degree in Electrical Engineering from the University of North Carolina at Charlotte in He joined Duke Energy in 1976 as a Junior Relay Engineer. He joined Duke Engineering & Services in 1995 as a Senior Engineer and served as the lead engineer on protection and control projects. Mr. Best moved to The Shaw Group in 2003 and then to Pike Electric/UC Synergetic in 2008 as a Consulting Engineer. At UC Synergetic he provides technical assistance and training to others on protective relay, control, and instrumentation issues including relay, control and instrumentation system design, determination of equipment requirements and application criteria, fault and coordination studies, power system disturbance analysis, and calculation of protective relay settings. Mr. Best became a Member (M) of IEEE in 1976 and a Senior Member (SM) in He is a working group chair in the Power System Relay Committee. He is a registered Stephanie Mercer received a BS degree in Electrical Engineering from Florida International University in 2008 and an MS degree in Electrical Engineering from the University of North Carolina at Charlotte in She joined Mitsubishi Heavy Industries in 2008 as a Junior Project Engineer. She worked with Florida Power and Light in 2012 as a Test Engineer for their smart meter grid project and with TYLin as a Project Engineer. Ms. Mora moved to UC Synergetic in 2014 as a Relay and Controls Engineer. At UC Synergetic she works on protective relay, control, and instrumentation issues including relay, control and instrumentation system design, determination of equipment requirements and application criteria, fault and coordination studies, power system disturbance analysis, and calculation of protective relay settings. Ms. Mora became a Member (M) of IEEE in She is an Engineer in Training currently registered for the Professional Engineer exam.