Generator Protection: Protection: The Value of Periodic Settings Review
Robert D. Pettigrew, PE SGS Witter Inc.
Presented to the 59th Annual Conference For Protective Relay Engineers
Texas A&M University April 4-6, 2006
1-4244-0043-0/06/$20.00 ©2006 IEEE
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59th Ann Annual Conference for Protective ive Relay lay Engineers
Abstract: This paper reviews several reasons that generator protection relays should have periodic settings reviews. There are a variety of things that can precipitate a need to change the relay settings. Several examples are presented that indicate the types of situations that have been uncovered during settings reviews. Often problems are uncovered that were a part of the original installation. Introduction: The protective relays at generating plants should not be considered as “Set & Forget” devices. In today’s deregulated environment the generating plants may not have the support from the system protection groups t hat has been traditionally available. Unless there is a problem, spending money on the protection equipment is not considered a high priority. Typically the relays are scheduled for periodic testing and recalibration to ensure they are operating within their specifications. However, these periodic tests do not verify settings calculations or review applicability of the settings. Things can change in the system that effect the settings of generator protection relays. Mistakes from the past, documentation errors, bad design practices may not be caught in these periodic testing programs. This paper reviews some problems that might be lurking in the protection equipment based on actual cases. Periodic settings review can be used as a tool to uncover these problems. This process is also a good training exercise for protection engineers that are not routinely involved in generator protection. Items That May Effect Relay Settings o o o o o
Transmission System Impedance/Configuration Reliability Standards Equipment Changes New Information (i.e. ref. #1) Unrecognized Past Errors
A.
Transmission system changes, new lines or removal of lines, in the vicinity of a power plant may require adjustment of settings on system backup protection, out of step protection and loss of field protection. The effect of in-feed on distance relay reach can be changed significantly if a source is added or removed. Changes in system impedance also affect the transient stability of the unit which will affect the settings of out of step relays.
B.
Changes to reliability standards, for example “WECC Must Operate Frequency Limits”, can require new o ver/under frequency relay settings to ensure the units hang on to the system long enough for the system load shedding relays to operate. The proposed NERC PRC-025 “Generation Protection Requirements during abnormal system voltage and frequency” may also affect the settings of system backup relays.
C.
Replacement of the excitation equipment should prompt a review of the settings of the Minimum Excitation Limiter (MEL), the Over Excitation Limiter, versus the generator capability curve (GCC) and the steady state stability limit (SSSL). Replacement of the protective relays with the latest technology would be another
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obvious reason to review the settings and also calculate settings for the various relay elements that will be included in the digital multifunction relays. Protective relay elements that were missing from the original protection can now be applied. D.
New published reports, such as reference 1, ‘Performance of Generator Protection During major System Disturbances’, may stimulate a change in setting philosophy that would be implemented during a periodic review program.
E.
In some cases a review of the relay setting calculations will uncover problems that are left over from the past.
Effects on Specific Relays
1. Loss of Field Relay: The Loss of Field relay, when set using the method typically associated with the KLF relay recommendations, will be offset into the +X direction by the reactance of the generator step-up transformer (GSU) and system equivalent impedance. Figure 1 shows the relay characteristics in the R-X plane while Figure 2 represents the same relay characteristics plotted in the P-Q plane. The relay characteristic should be coordinated with the GCC, the MEL and the SSSL of the unit. Changes in the system impedance will affect the forward reach setting. The system impedance used for this setting will be established as a maximum expected impedance, with the strongest source removed.
Loss of Field Coordination R-X Plane 15
10
5
R(Ohms) 0 -25
-20
-15
-10
-5
0
5
10
15
20
25
-5
-10
-15
-20
-25
Gen CC Dir El
-30
LOF SSSL
X(Ohms)
-35
MEL
-40
3
Figure 1
Loss of Field Coordination P-Q Plane P (MW) 0 -50
-30
-10
10
30
50
70
90
110
130
150
-20
GCC 30
-40
SSSL LOF1
Q (MVAR)
LOF11 MEL
-60
Figure 2
The condition of steady state stability is determined by the steady state stability limits (SSSL) of the machine when delivering power into the system with the above stated maximum system impedance condition. With proper coordination the unit is can deliver the rated unit power into the system and remain stable on a steady state basis. The Loss of Field relay will not interfere with this power flow. In addition the MEL, a part of the excitation system, should limit the voltage regulators ability to reduce the excitation current in order to prevent the unit from operating beyond the underexcited GCC limits. This protects the machine and prevents the Loss of Field relay operation during periods of high system voltage. Changes to the system impedance will affect the coordination of the SSSL and the loss of field relay. The review process will determine if any changes to the relay settings are warranted. 2. System Backup Protection: Impedance relays are used on large units to provide backup to relays on the generator, GSU and on the transmission system outside the plant. Modifications to the transmission system should be reviewed for the impact on the plant’s backup protection. Figure 3 shows the phase distance relay and the connected transmission system. Depending on the system configuration the relay is set to detect uncleared phase faults in the transmission system. In order to see faults at the end of the longest line the reach may interfere with the machines loadability. Due to in feed effects the reach of the distance relay is often unable to reach the end of the longest line. Changes in the system will directly effect the settings calculations for these relays.
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Longest Line
Generator
m e t s y S r e w o P
Other Sources 21
Short Line
Unit Connected Generator System Backup Relay Figure 3
To ensure the distance relay does not affect normal machine operation, the distance relay’s characteristic is compared to 150 – 200% of the unit’s capability at the rated power factor. This comparison can be done graphically as shown in Figure 4.
Phase Dist. Coordination vs. (200% GCC) 20
15
10
5
R(Ohms)
0 -10
-5
0
5
-5
Gen CC MSA P Dist
X(Ohms)
Gen CC+0.9 PF -0.9 pf
-10
Figure 4
5
10
15
20
Reliability Standards: The WECC has published “must operate” frequency ranges for generating plants in its jurisdiction. The requirements are shown in Table 1. The over and under frequency relay settings for all affected units should be compared to these limits for compliance. In addition turbines also have operational frequency limits that specify ranges of frequency where they should not be operated for extended periods of time. The IEEE has published IEEE Standard C37.106 Guide for Abnormal Frequency Protection of Power Generating Plants (ref. 3) that reviews this subject in detail. The relay engineer needs to set the over and under frequency protection to allow the unit to operate for the minimum times specified in Table 1 but not to exceed the limits of the turbine. An example of this is shown in Figure 5.
Table 1 – WECC Must Operate Frequency Requirements Recommended Abnormal Frequency Protection 4 Step 81O/U 10000
Prohibited Operation
Prohibited Operation 1000
WSCC Low WSCC High Nominal F
) c 100 e s ( e m i T
NN+ LS1
Continuous Operation
LS2 LS3 LS4 LS5 ST High
10
WECC Must Operate
WECC Must Operate
ST Low Tie Trip Trip High Trip Low
Tie Trip 1
WECC Load Shedding 0.1 56
57
58
59
60
Frequency(Hz)
Figure 5
6
61
62
63
With a two step over and two step under frequency relay the settings are at best a compromise between the WECC requirements and the machine capability.
Unrecognized Past Errors : How often do we hear “If it ain’t broke don’t fix it!” As well meaning as this old saying may be, one might counter with, “If you never look, how do you know it ain’t broke?” Relays that trip will get lots of attention, those that never trip are usually considered good. This may not always be the case.
Documentation Error: The following is an example found of a documentation error that resulted in a Loss of Field relay that was incorrectly set. Two identical gas turbine units in a CCCT facility were protected with the KLF single zone Loss of Field relays. The KLF requires six screw tap set tings in order to be set for the desired mho diameter and offset (SA, TA, MA, SC, TC, MC). With identical generating units, transformers, and connections to the system, the relays should be set with identical settings. However, due to a documentation error the SA tap value in Unit 1 was set at 1 and on Unit 2 tap SA was set to 2. The resulting mho characteristics were as shown in Figures 6 and 7. With the incorrect SA=1 Tap Setting on GT1, the LOF relay is not set as recommended for a single zone LOF application. The unit will go out of step prior to the LOF relay tripping, as indicated by the SSSL. During this review, another issue was found with a companion unit at the same facility. This unit’s MEL characteristic is slightly outside the GCC and would allow the unit to operate in the under excited mode beyond the capability of the machine. The operators confirmed that at night the excitation would go “in the tank” trying to keep the system voltage from rising to high. Therefore a brief review of the LOF relay settings has uncovered two potential issues. A simple tap change will solve the LOF relay setting problem at the gas turbine. An adjustment of the MEL will resolve the issue at the companion unit and result in a machine with properly coordinated LOF, MEL, GCC and SSSL.
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Loss of Field Coordination GT#1 R-X Plane (Existing ) 15
10
5
R(Ohms) 0 -25
-20
-15
-10
-5
0
5
10
15
20
25
-5
-10
-15
-20
-25 Gen CC Dir El
-30
LOF SSSL
X(Ohms)-35
MEL
-40
Figure 6
Loss of Field Coordination GT#2 R-X Plane (Existing ) 10
5
0 -25
-20
-15
-10
-5
0
5
10
15
20
-5
-10
-15
-20
-25
-30
Gen CC Dir El LOF
X(Ohms)
25
R(Ohms)
-35 SSSL MEL
-40
Figure 7
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The other issue with these units is the proximity of the SSSL with the GCC. These curves need to be reviewed over the years as system configurations change. Changes in the transmission system or new generating units can modify the system impedance significantly and make things better or worse. Retrofit Gone Bad: An aging plant had been recently updated with modern digital multifunction generator pro tection relays. During a settings review the following design issue was uncovered. The protection for the entire plant, primary and backup was being powered on one set of DC fuses as shown in Figure 8. A simple blown fuse will disable all of the protection for the generator and GSU. The Loss of DC alarm will alert operators. However, the plant is unprotected until the fuse problem is resolved.
Figure 8 A second issue with the retrofit involved the Output contact programming. As is common in digital relays the various protection functions are connected to outputs via a software map. The facility used 3 lockout relays as follows: o o o
86G – generator protection relays 86BU – loss of field, negative sequence overcurrent 86U – Unit differential, phase distance backup (transformer backup)
In the contact programming for the generator protection relays the outputs for tripping 86BU and 86U are reversed. Therefore a negative sequence trip and loss of field trip will completely shut down the unit. However, a phase distance trip, which could be due to a fault in the GSU, will only open the unit breaker and not remove the fault. This clearly is not the intended result.
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CT Polarity Mix-up: Unit differential relays often encompass switchgear CTs on the secondary of the unit auxiliary transformer. Figure 9 shows the problem.
2IS CB
87U
I1 UAT
IS
GS
I1 IS
Figure 9 The differential connection no rmally used utilizes CTs with polarity dots facing away from the protected zone. However, the switchgear load CTs have polarity dots opposite of this convention. The relay doesn’t trip due to the small MVA rating of the UAT vs. the generator. At full load on the UAT the differential current contribution is only 0.25 amps. However, if there is a fault in the plant auxiliaries there will be enough current to operate the 87U relay. Tripping the plant due to a plant feeder fault is not what is intended. Delta Wye Distance Compensation Settings: Phase distance backup relays use generator terminal voltages and currents to sense faults in the transmission system. Unit connected plants have a Delta/Wye GSU. Setting a phase distance function that needs to look through the Delta/Wye GSU requires some phasor manipulation. When Open-Delta VTs are used on the generato r terminals another phase shift is introduced. Digital relays have algorithms that compensate for this configuration. However, not all manufacturers use the same algorithm. This can lead to confusion in setting calculations. The following table shows how two different manufacturers handle the impedance calculations for an AB fault on the system.
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MFG A
MFG B
L-L VTs Z = VBC-VAB/3*IB
L-L VTs Z = VBC-VAB/IB
Using MFG B’s relay, a setting of 3 times the expected setting will need to be put into the unit. This difference in methodology is an obvious source of settings errors that was found in a recent review. A relay with a desired reach of 1.5 ohms was actually set to reach 0.5 ohms. (It was set for 1.5 ohms but the factor of three was overlooked). The requirement for the factor of three is illustrated in Figures 10 and 11. In order to properly measure the impedance to the phase t o phase fault in the transmission system the relay, measuring voltage and current on the generator terminals, must compensate for the effects of the transformer. The relays use IB and VBC-VAB to find the proper phase relationship. The Delta connected VTs introduce a second square root of 3 magnitude factor that results in the factor of 3 in the impedance scaling.
21 Relay Scaling Phase - Phase Fault in System ZL+ZT
A
A' I
IA'
Fault IB'
B
ZL+ZT
2*I
IB = 2*IA
C
B'
C' IC' = 0
I Open Delta VT's
V AB
VBC VCA
Normal Reach Setting Z= V A/I A Delta VT's Give V AB, VBC, VCA Relay Uses V BC - V AB to shift phase Results in Z relay = 3*Z Z = 2(ZL + ZT)
Figure 10
11
GSU Phasing Delta VT's
A
A'
A
A'
B
B'
C
C'
C'-G
C-A
C-G
(B-C)-(A-B) B-G
B-C
A-G
B'-G
A-B
13.8kV
A'-G
69kV
Figure 11 Application consideration: The Zone 1 Loss of Field relay (refer to Figure 7) is applied with a time delay of approximately 0.5 seconds to ensure the relay does not trip due to stable swings. A large plant was recently found to have the KLF loss of field relay applied without the time delay. The relay would trip within 0.06 seconds for any swing that entered the characteristic. Stability studies modeled several potential swings. These studies did not indicate the swings would enter the characteristic. However, the stability studies do not test every possible case. Therefore, the suggested time delay was recommended for reasons o f security.
Conclusion: Periodic reviews of relay settings at generating plants have many benefits. The primary benefit may be the training that is derived from reviewing the relay applications and setting calculations. A thorough review process will require the engineer to research basic machine and system parameters and redo the relay calculations from these basic parameters. Protection engineers in today’s utility companies may not have experience in setting generator protection relays and this process can maintain the expertise that will be needed when one of these relays operates
System modifications will have some effect on the performance of the relays in generating plants. A periodic review process can be used to evaluate the effect of these changes on the operation of generating plant relays.
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The discovery of existing problems may be a very beneficial part of this review process. There are often unexpected surprises waiting to be uncovered There are also regulatory organizations, such as NERC, that may periodically require changes in the setting philosophy of the generating plant relays in order to reduce the chance of tripping unnecessarily during system emergencies.
References: 1. IEEE PSRC WG Report “Performance of Generator Protection During Major System Disturbances”, available from the IEEE PSRC Web Site: www.pes psrc.org 2. IEEE C37.102, Guide for AC Generator Protection 3. IEEE C37.106, Guide for Abnormal Frequency Protection of Generating Plants
Bob Pettigrew is a Senior Consulting Engineer for SGS Witter, Inc. working out of the Albuquerque
office, but domiciled in Asheville, North Carolina. He received his BSEE degree with honors in 1969 from the University of Florida and his MSEE degree in 1980 from the University of South Florida. He spent eight years at Honeywell Inc. working in the Aerospace Industry. He also has spent 22 years as an Engineer and Executive at the Beckwith Electric Company working in the fields of Generation Control and Protection, Load Tapchanger controls and Capacitor controls. He has written and presented several papers on protection and motor bus transfer in power plants. He is presently active in the IEEE Power Systems Relaying Committee and is a past Chairman of the Rotating Machinery Protection Subcommittee. Bob is a licensed pro fessional engineer in Florida, Wisconsin, Washington, and North Carolina.
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