Waterpower '97. Upgrading Hydroelectric Generator Protection Using Digital Technology

Transcription

1 Waterpower '97 August 5 8, 1997 Atlanta, GA Upgrading Hydroelectric Generator Protection Using Digital Technology Charles J. Beckwith Electric Company th Avenue North Largo, FL U.S.A. 11

2 Upgrading Hydroelectric Generator Protection Using Digital Technology Charles J. 1 Abstract This proposed paper presents the reasons/rationale why hydroelectric generator owners should consider upgrading the electrical protection of their generators to meet today s IEEE/ANSI standards. It specifically outlines the risks assumed by the owners in several functional protection areas where 20+ year old generator protection is inadequate. Introduction Contrary to popular belief, generators do experience short circuits and abnormal electrical conditions. In many cases, equipment damage due to these events can be reduced or prevented by proper generator protection. Generators, unlike most other power system components, need to be protected not only from short circuits, but from abnormal electrical conditions. Examples of such abnormal conditions are: overexcitation, overvoltage, loss-of-field, unbalanced currents, reverse power, and abnormal frequency. When subjected to these conditions, damage or complete failure can occur within seconds; thus, automatic detection and tripping are required. In the early 1990 s, the IEEE Power System Relaying Committee conducted a survey to determine how major synchronous generators in North America were protected from short circuits and abnormal electrical conditions. Survey findings indicated that despite the clear need to upgrade older generator protection schemes to meet current standards, utilities seemed reluctant to make needed modifications to existing power plants. This reluctance may be due to several factors: a lack of expertise, a misunderstood belief that generators do not fail often enough to warrant proper protection, or a belief that operating procedures will cover protection design deficiencies. Areas of Protection Upgrade on Older Generators The areas of upgrading of 20+ year old generator protection fall into three broad categories: 1) Improved Sensitivity in protection areas where older relaying does not provide the level of detection required to prevent damages. Examples of protection in this area are: negative sequence (unbalanced current) protection 100% stator ground fault protection 2) New or Additional Protection Areas that 20 years ago were not perceived to be a problem, but operating experiences have proved otherwise. These areas are: 1 Manager Application Engineering, Protection and Protection Systems, Beckwith Electric Company, th Avenue North, Largo, FL , U.S.A. 1

3 inadvertent generator energizing vt fuse loss oscillographic monitoring 3) Special Protection Application Considerations that are unique to generators. These areas include: generator breaker failure The IEEE/American National Standards Institute (ANSI) develop protection guides (see references 1, 2 and 3) reflecting the need to provide the protection, which is outlined in this paper, in the major upgrade areas cited. These guides express the views of both users (utilities/generator owners) as well as the generator manufacturers and are reflective of in-service experience viewed at a national level. The guides are updated on a five year basis to keep them current with both inservice experience as well as changes in technology. Improved Sensitivity Protection Areas Negative Sequence (unbalanced current) Protection There are a number of system conditions that can cause unbalanced three-phase currents in a generator. These system conditions produce negative sequence components of current which induce a double-frequency current in the surface of the rotor. The skin effect of the doublefrequency rotor current causes it to be forced into the surface elements of the rotor. These rotor currents can cause excessive temperatures in a very short time. The current flows across the metal-to-metal contact of the retaining rings to the rotor forging wedges. Because of the skin effect, only a very small portion of this high frequency current flows in the field windings. Excessive negative sequence heating beyond rotor thermal limits results in failure. These limits are based on the following equation, for a given generator: K=I2 2 t Where: K = constant depending on generator design and size t = time in seconds I 2 = RMS value of negative sequence current in p.u. The continuous unbalanced current capability of a generator is defined in ANSI C.13 (references 4 and 5). This standard states that "generator shall be capable of withstanding, without injury, the effects of a continuous current unbalance corresponding to a negative-phase-sequence current I 2 of the following values, providing the rated kva is not exceeded and the maximum current does not exceed 105 percent of rated current in any phase." Type of Generator Permissible I 2 (percent of stator rating) Salient Pole With connected amortisseur windings 10 With non-connected amortisseur windings 5 These values also express the negative-phase-sequence current capability at reduced generator KVA capabilities. It is common practice to provide protection for the generator for external unbalanced current conditions that might damage the machine. This protection consists of a time overcurrent relay which is responsive to negative sequence current. Two types of relays are available for this protection: an electromechanical time overcurrent relay with an extremely inverse characteristic, and a static or digital relay with a time overcurrent characteristic which matches the negative sequence current capabilities of the generator. For open conductor or open breaker pole condi- 2

4 tions, the negative sequence relay is usually the only protection. The low magnitude of negative sequence currents created by this type of event (typically 10-20% of stator rating) prevents other fault relays from providing protection. For electromechanical negative sequence relays, the minimum pickup can be set to provide only 60% of stator rated current sensitivity. Thus, these relays will provide no protection for open phase or open generator breaker pole conditions which are frequent negative sequence events within the industry. The sensitivity of negative sequence static or digital relays is required. Almost all 20+ year old generators are protected with electromechanical negative sequence relays which make this an important upgrade area. 100% Stator Ground Fault Protection High-impedance generator neutral grounding utilizes a distribution transformer and a secondary resistor. The secondary resistor is usually selected so that for a single line to ground fault at the terminals of the generator, the power dissipated in the resistor is approximately equal to the reactive volt-amperes in the zero sequence capacitive reactance of the generator windings, its leads, and the windings of any transformers connected to the generator terminals. Using this grounding method, a single line to ground fault is generally limited to 3-25 primary amperes. R 59 N Figure 1 High Impedance-Grounded Generator The most widely used stator ground fault protective scheme in high impedance-grounded systems is a time- delayed overvoltage relay (59N) connected across the grounding resistor to sense zero-sequence voltage as shown in Figure 1. The relay used for this function is designed to be sensitive to fundamental frequency voltage and insensitive to third harmonic and other zero sequence harmonic voltages that are present at the generator neutral. Typically, the overvoltage relay has a minimum pickup setting of approximately 5 V. The 59N protective scheme is straight forward and dependable, however, this relay will provide protection for only about 95% of the stator winding. This is because a fault in the remaining 5% of the winding, near the neutral, does not produce a sufficient 60 Hz residual voltage. It is important to protect major generators with an additional ground fault protection system so that fault coverage for 100% of the winding is obtained. Twenty plus year old generators typically have only 95% of the stator winding protected for ground faults. Many utilities have upgraded protection to provide 100% stator winding ground fault protection. One method is the use of a third-harmonics undervoltage relay. Third-harmonic voltage components are present at the neutral of nearly every machine to varying degrees; they arise and vary due to differences in design, manufacture and machine load. If present in a sufficient amount, this voltage can be used to detect ground faults near the neutral. 3

5 One method uses the fact that for a fault near the neutral, the level of third-harmonic voltage at the neutral decreases. Therefore, an undervoltage relay operating from third-harmonic voltage measured at the neutral end could be used to detect faults near the neutral. The ground faults in the remaining portion of the windings can be detected by conventional ground fault protection, e.g., the overvoltage relay (59N) which operates on the 60 Hz neutral voltage. The combination of both relays provide 100% stator winding protection. A simplified protection scheme using this technique is shown in Figure (+) 59 59N N Th Th 95% 100% Instantaneous Overvoltage Supervisory Relay 59N Overvoltage Relay Tuned to the Fundamental (60 Hz) Frequency Th Undervoltage Relay Tuned to the Third Harmonic (180 Hz) Frequency 2-1, 2-2 Timers Figure 2 (-) COMPLETE SHUTDOWN Third Harmonic Undervoltage Ground Fault Protection Scheme New or Additional Protection Areas Inadvertent Accidental Generator Energizing Inadvertent or accidental energizing of synchronous generators has been a particular problem within the industry in recent years. A number of machines have been damaged or, in some cases, completely destroyed when they were accidentally energized while off-line. The frequency of these occurrences has prompted generator manufacturers to recommend that the problem be addressed through dedicated protective relay schemes. Due to the severe limitation of conventional generator relaying to detect inadvertent energizing, dedicated protection schemes have been developed and installed. Unlike conventional protection schemes, which provide protection when equipment is in-service, these schemes provide protection when equipment is out of service. One method widely used to detect inadvertent energizing is the voltage-supervised overcurrent scheme shown in Figure 3. An undervoltage element with adjustable pickup and dropout time delays supervise an instantaneous overcurrent relay. The undervoltage detectors automatically arm the overcurrent tripping when the generator is taken off-line. This undervoltage detector will disable or disarm the overcurrent relay when the machine is returned to service. Great care should be taken when implementing this protection so that the dc tripping power and relay input quantities to the scheme are not removed when the generator is off-line. 4

6 CT VT Overcurrent I>P.U. GEN Undervoltage* V<P.U. Pickup Delay Dropout Delay AND Output Contact * On All Three Phases Simultaneously R a) Relay Inputs b) Relay Logic Diagram Figure 3 Inadvertent Energizing Scheme When an off-line generator is energized while on turning gear, or coasting to a stop, it behaves as an induction motor and can be damaged within a few seconds. During three-phase energization at a standstill, a rotating flux at synchronous frequency is induced in the generator rotor. The resulting rotor current is forced into sub-transient paths in the rotor body, similar to those rotor current paths for negative-sequence stator currents during generator single-phasing. Rapid rotor heating occurs, which can quickly damage the rotor. The machine impedance during this highslip interval is equivalent to the generator negative-sequence reactance. Figure 4 shows a simplified equivalent circuit that can be used to calculate the current and voltage associated with threephase inadvertent energizing. Equivalent System Reactance X 1S I Where: X 1S = System Positive Sequence Reactance GEN X 2G E G Equivalent System Voltage E S X 2G = Generator Negative Sequence Reactance E S = System Voltage E G = Generator Terminal Voltage I = Current Figure 4 Inadvertent Energizing Equivalent Circuit Operating errors, breaker-head flashovers, control circuit malfunctions, or a combination of these causes, have resulted in generators becoming accidentally energized while off-line. In industrial applications, the major cause of inadvertent energization of generators has been by closing the generator breaker through the mechanical close/trip control at the breaker itself, thereby defeating the electrical interlocks. VT Fuse Loss Protection Loss of the vt signal can occur due to a number of causes, the most common cause being fuse failure. Other causes may be an actual vt or wiring failure, an open in the draw-out assemblies, a contact opening due to corrosion, or a blown fuse due to screwdriver shorts during on-line main- 5

7 tenance. Such loss of vt signal can cause protective relays misoperations or generator voltage regulator runaway leading to an overexcitation condition. Some method of detection is required so that the effected relay tripping can be blocked and the voltage regulator transferred to manual operation. Typically, protective functions such as 21, 32, 40 and 51V are impacted and are normally blocked when a loss of potential is detected. On larger generators, it is common practice to use two sets of voltage transformers (vts) in the generator zone of protection. As shown in Figure 5a, the vts that are usually connected grounded wye-grounded wye, normally have secondary and possibly primary fuses. These vts are used to provide potential to a number of protective relays and the voltage regulator. If a fuse blows in the vt circuits, the secondary voltages applied to the relays and voltage regulator will be reduced in magnitude. This change in voltage signal can cause the misoperation of the relays and the regulator to overexcite the generator. GEN GEN VT 60 VOLTAGE BALANCE RELAY TO PROTECTIVE RELAY TO VOLTAGE REGULATOR 60 FL TO PROTECTIVE RELAY AND VOLTAGE REGULATOR a) Application of Voltage Balance Relay Protection b) Modern VT Fuse Loss Detection Figure 5 VT Fuse Loss Detection On many older, hydro generators, only one set of vts is provided. It is not possible to use a voltage balance relay unless a second set of vts is added. Thus, many generators do not have vt fuse loss protection. A modern digital method used in vt failure detection makes use of the relationships of negative sequence voltages and currents during a loss of potential. When one vt signal is lost, the three phase voltages become unbalanced. Due to this unbalance, a negative sequence voltage is produced. To distinguish this condition from a fault, negative sequence currents are checked. The presence of negative sequence voltage in the absence of negative sequence current indicates a fuse failure rather than a fault. Oscillographic Generator Monitoring The monitoring of a utility's transmission system with oscillographs which record relay currents and voltages has long been accepted within the industry as providing the basic data to analyze the performance of the transmission protective system. Because of the greater number of transmission line faults versus generator faults and abnormal conditions, it was felt by many that similar monitoring of generators could not be economically justified with stand alone oscillographs. However, with the advent of digital protective relays for generators, oscillographs are built into the protective relay. Figure 6 is an example of an oscillographic recording from such a relay. 6

8 Figure 6 Digital Relay Oscillograph Record With the remote communication capabilities of these relays, oscillograph and target information can be quickly accessed from a remote location, after a generator tripping, to determine if relay and circuit breaker operations were proper. Oscillographic information can also identify the type of testing needed to find the cause of a tripping and speed the return of the generator to service. It gives the relay engineer the necessary data to keep machines off-line for testing and inspection, when necessary, after an electrical tripping or to return the unit to service with a minimum delay. Those utilities that have implemented a program of oscillographic monitoring of generators have found the information invaluable. Special Protection Application Considerations Generator Breaker Failure A breaker failure scheme needs to be initiated when the protective relay system operates to trip the generator circuit breaker but the breaker fails to operate. Because of the sensitivities required, there are major differences in how local breaker failure is applied on a generator breaker versus a transmission line breaker. Figure 7 shows the functional diagram of a typical breaker failure scheme used on a transmission line breaker. When the protective relays detect a fault, they will attempt to trip the primary transmission line breaker and at the same time initiate breaker failure. If the line breaker does not clear the fault in a specified time, the timer will trip the necessary backup breakers to remove the failed circuit breaker from service. The successful tripping of the primary breaker is determined by the drop out of its current detector (CD) which stops the breaker failure timer (62). When breaker failure is applied on a generator breaker, however, its tripping may not be initiated by a short circuit but by an abnormal operating condition for which there maybe little or no short circuit current. Abnormal operating conditions such as overvoltage, overexcitation, excessive underfrequency, reverse power and stator ground faults will not produce sufficient current to operate the current detectors (CD). The breaker 52a switch must be used in parallel with the fault detectors to provide additional indication in a breaker failure scheme for generator breakers. This logic is shown in Figure 8. CD Protective Relays Figure 7 62 CD - Current Detector Timer Trips AND A Backup 62 - Breaker Failure Timer With ø Adjustable Pickup & Zero Dropout Delays Breakers and BFI - Breaker Failure Initiate BFI Trip Unit Generator Breaker Typical Transmission Line Breaker Failure Functional Diagram 7

9 52a 62 CD OR AND Timer Trips A Backup ø Breaker BFI and Unit Protective Relays Trip Generator Breaker 52a - Circuit Breaker Auxiliary Contacts CD - Current Detector 62 - Breaker Failure Timer With Adjustable Pickup & Zero Dropout Delays BFI - Breaker Failure Initiate Figure 8 Functional Diagram of a Generator Breaker Failure Scheme Using Digital Technology to Implement an Upgrade Program Just as it has been in the transmission line upgrade area, multifunction digital relaying is an ideal and cost effective way to upgrade generator protection to current industry standards. Figure 9a shows a functional diagram of such a relay. Utility System Utility System TYPICAL MULTIFUNCTION RELAY C B A 52 Unit 52 I A, B, C BF-N B C A Denotes Upgrade Functions TYPICAL MULTIFUNCTION RELAY BF 3 I A, B, C 87 GD 87 5 BF FL 40 51V I a, b, c 4 60FL I a, b, c 2 TN 59N High-Impedance Grounding 51N N R Denotes Upgrade Functions Low-Impedance Grounding a) High-Impedance Grounded Generator b) Low-Impedance Grounded Generator Figure 9 One-Line Diagrams Common upgrade functions (shaded) are shown in Figures 9a and 9b: 1 Negative Sequence (unbalanced current) Protection 2 100% Stator Ground Fault Protection 3 Inadvertent (accidental) Generator Energizing 4 VT Fuse Loss Protection 5 Generator Breaker Failure 8

10 These functions, plus nine (9) additional protection functions, are included in a single compact package. Space considerations are an important concern when doing upgrade work and can have a significant impact on project cost, making multifunction digital relays ideal for upgrade projects. Additional features, which make these types of relays extremely flexible for upgrade applications, include: Programmable outputs and six programmable inputs Oscillographic recording Target storage Metering of all measured parameters RS-232 and RS-485 communication ports Continuous self-checking diagnostics For low impedance-grounded generators (resistor-or reactive-grounded), overcurrent (51N) stator ground relaying is required. Figure 9b illustrates a one-line diagram of this application. Many protection upgrade projects are part of larger life extension or automation efforts within a power plant. One of the important features of digital relays is their communication capability. Rear-panel communication ports, RS-232 or RS-485, can be used to remotely set and interrogate the relay via a modem. Communication with multiple relays can be accomplished using a simple low cost communication signal splitter and modems (Figure 10). Telephone Line IBM-Compatible PC Modem Modem Communications-Line Splitter Address 5 Address 6 Address 1 Address 3 Address 4 Address 2 a) RS-232 Port Address 1 Address 2 Address 5 RX TX RX TX RX TX PC Master T- T+ R- R+ RS-232 to RS wire converter Twisted Pair b) RS-485 Port Figure 10 Multiple System Addressing Using Communications-Line Splitter 9

11 Relay 1 Relay 2 Relay 3 Relay PLANT DCS System Data link to EMS Center Local Operator CRT Display EMS Center Figure 11 System Integration Metering quantities (MW, MVAR, Volts, Amps, P.F., etc.) within these relays can be accessed by a DCS (Distributed Control System) within the plant through the relay communication ports. This saves in the costs and wiring required for dedicated transducers for each metering quantity. Figure 11 shows a system which uses the digital relay as an Intelligent Electronic Device (IED) to gather data for a DCS system. Conclusion There are a number of functional protection areas on 20+ year old generators which have significant shortcomings. This paper identifies those protection areas and the risks of not addressing them. In addition, a cost-effective strategy to upgrade protection to current industry standards is outlined using multifunction digital relaying. Generation is the single most expensive capital investment of a utility. Protecting this investment to prevent failure should be a priority item with utilties as well as non-utility generator owners. References [1] ANSI/IEEE C , "IEEE Guide for AC Generator Protection." [2] ANSI/IEEE C , "IEEE Guide for AC Generator Ground Protection." [3] ANSI/IEEE C , "IEEE Guide for Abnormal Frequency Protection for Power Generating Plants." [4] ANSI C , "American National Standard for Cylindrical Rotor Synchronous Generators." [5] ANSI/IEEE C , "American National Standard Requirements for Salient Pole Synchronous Generators and Generator/Motors for Hydraulic Turbine Applications." [6] IEEE Power Engineering Society Tutorial 95TP102, "IEEE Tutorial on the Protection of Synchronous Generators." About the Author Chuck is currently Manager of Application Engineering for Protection and Protection Systems for Beckwith Electric Co. He is responsible for the application of Beckwith products and systems used in generator protection and intertie protection, synchronizing and bus transfer schemes. Chuck is an active member of the IEEE Power System Relay Committee and is the past chairman of the Rotating Machinery Subcommittee. He is the U.S. representative to the CIGRE Study Committee 34 on System Protection and chairs a CIGRE working group on generator protection. He also chaired the IEEE task force which produced the tutorial The Protection of Synchronous Generators. Chuck has a bachelor of science in electrical engineering from Purdue University and has authored a number of papers and magazine articles on protective relaying. He has over 25 years of experience as a protective engineer at Centerior Energy, a major investor-owned utility in Cleveland, Ohio. He is also a former instructor in the Graduate School of Electrical Engineering at Cleveland State University. 10