05000440/LER-2003-002

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LER-2003-002, Reactor Scram as a Result of a Loss of Off-site Power
Docket Number
Event date: 8-14-2003
Report date: 12-12-2003
Reporting criterion: 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
10 CFR 50.73(a)(2)(iii)
10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident
10 CFR 50.73(a)(2)(iv)(A), System Actuation
10 CFR 50.73(a)(2)(vii), Common Cause Inoperability
4402003002R01 - NRC Website
v • d • e

I. INTRODUCTION

On August 14, 2003, at 1346 hours0.0156 days <br />0.374 hours <br />0.00223 weeks <br />5.12153e-4 months <br />, the Perry Nuclear Power Plant (PNPP) was operating in Mode 1 at approximately 100 percent reactor power when the PNPP control room operators contacted the FirstEnergy Systems Control Center (SCC) to report voltage spikes being observed on the PNPP control room console voltage meters. The SCC subsequently requested that Perry increase its main transformer [XFMR] voltage to maximum. A control room operator, assigned to monitor the generator [EL], observed an upward, saw-tooth trend on the MVAR recorder starting at about 1530 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.82165e-4 months <br />. At about 1536 hours0.0178 days <br />0.427 hours <br />0.00254 weeks <br />5.84448e-4 months <br /> voltage fluctuations were seen on the PNPP main transformer and the generator out of step supervisory relay tripped. The SCC was notified of these conditions. The -PNPP control room "operator lowered the generator voltage'regulator'setpoint to'maintairrge-nerator field voltage"�- less than the trip setpoint (528 volts). At 1541 hours0.0178 days <br />0.428 hours <br />0.00255 weeks <br />5.863505e-4 months <br /> plant operators entered the off-normal instruction for degraded grid and both off-site AC sources were declared inoperable as a result of grid voltage' fluctuations. At about 1610 hours0.0186 days <br />0.447 hours <br />0.00266 weeks <br />6.12605e-4 months <br /> the operator monitoring the generator observed a number of spikes on the generator field voltmeter followed by the meter indication going full upscale. The MVAR and Megawatt (MW) meter also went full upscale. Reactor water cleanup pumps [CE] tripped and the offgas system [WF] isolated. At 1610 hours0.0186 days <br />0.447 hours <br />0.00266 weeks <br />6.12605e-4 months <br />, a main generator trip occurred which caused a turbine trip resulting in an automatic reactor scram due to a turbine control valve fast closure signal. Loss of off-site power to the essential switchgear busses is reportable per 10CFR50.72(b)(3)(v)(D) and 50.73(a)(2)(v)(D), an event or condition that could have prevented fulfillment of a safety function, 10CFR50.73(a)(2)(iii), an external condition that posed an actual threat to the safety of the nuclear power plant as well as 10CFR50.73(a)(2)(vii), common-cause inoperability of independent trains.

The Nuclear Regulatory Commission was notified via the Emergency Notification System (ENS) at 1635 hours0.0189 days <br />0.454 hours <br />0.0027 weeks <br />6.221175e-4 months <br /> on August 14, 2003, (ENF 40063), in accordance with 10CFR50.72(a)(1)(i), declaration of any emergency class (Unusual Event). At 1705 hours0.0197 days <br />0.474 hours <br />0.00282 weeks <br />6.487525e-4 months <br />, a follow-up notification was made for 10CFR50.72(b)(2)(iv)(A), ECCS discharge to the RCS, 10CFR50.72(b)(2)(iv)(B), as an event that resulted in an actuation of the reactor protection system when the reactor is critical, 10CFR50.72(b)(3)(iv)(A), specified system actuation for multiple system containment isolation valves and main steam isolation valves. At 2225 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.466125e-4 months <br />, an additional follow-up notification was made for 10CFR50.72(b)(3)(xiii), any event that results in a major loss of off-site response capability, when it was recognized that there was no power available to the Emergency Operations Facility (EOF) and the Backup EOF (BEOF).

This Licensee Event Report is being submitted in accordance with:

  • 10CFR50.73(a)(2)(iii), any natural phenomenon or other external condition that posed an actual threat to the safety of the nuclear power plant,
  • 10CFR50.73(a)(2)(v)(D), any event or condition that could have prevented the fulfillment of the safety function of structures or systems, (loss of both off-site electrical power sources),
  • 10CFR50.73(a)(2)(vii), any event where a single cause or condition caused at least one independent train or channel to become inoperable in multiple systems or two independent trains or channels to become inoperable in a single system.

This report also satisfies Operational Requirements Manual (ORM) section 7.6.2.1, which requires a special report to be submitted following an Emergency Core Cooling System (ECCS) actuation and injection into the reactor coolant system.

The special report shall include a description of the circumstances of the actuation and the total accumulated actuation cycles to date. Additionally, the current value of the usage factor for each affected safety injection nozzle shall be provided when its value exceeds 0.70. The High Pressure Core Spray (HPCS) [BG] system was used for level control and injected into the Reactor Pressure Vessel [RPV] on 19 occasions during this event. The injections occurred over� I about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> and over a RPV pressure range of 1000 psig to about 110 psig, with not all injections being design cycles.

There had been 14'HPCS injections over the life rif the plant prior to this -event, which results in a total of 33-HPCS� I injections to date. Forty design cycles would result in a nozzle usage factor of 0.164. Since the HPCS injection nozzle usage factor is less than 0.70, an exact value has not been calculated for inclusion in this report. The Low Pressure Core Spray (LPCS) [BM] system was manually operated for RPV level control for about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> after the HPCS system. The RPV pressure was less than 200 psig when LPCS was first used. Use of LPCS for level control is not considered an ECCS injection since the design injections are for a pressure of 520 psig down to 450 psig. However, operation of the system was reviewed for its impact on the injection nozzle. The nozzle usage factor for LPCS is less than 0.70.

II. EVENT DESCRIPTION

On August 14, 2003, at 1610 hours0.0186 days <br />0.447 hours <br />0.00266 weeks <br />6.12605e-4 months <br />, with the plant operating at approximately 100 percent reactor power, a main generator trip occurred which caused a turbine trip resulting in an automatic reactor scram due to a turbine control valve fast closure signal. The reactor scram is reportable per 10CFR50.72(b)(2)(iv) B), reactor protection system actuation while critical, and 50.73(a)(2)(iv), actuation of specified systems. All control rods fully inserted as required.

In addition to the scram, the following system isolations occurred: balance of plant (BOP), reactor water cleanup system (RWCU), residual heat removal (RHR) [BO], reactor sample, main steam line drains and main steam isolation valves (MSIV)[SB]. Automatic start of the division 1, 2, and 3 diesel generators [EK] as well as emergency service water [BI] and emergency closed cooling [CC] occurred as a result of the loss of power. The system isolations and automatic starts are reportable per 10CFR50.72(b)(3)(iv) and 50.73(a)(2)(iv) as valid actuations of specified systems. An initiation of HPCS and the reactor core isolation cooling system (RCIC)[BN], and an automatic trip of the reactor recirculation system pumps [AD] occurred due to a RPV low water level signal (Level 130 inches above the top of active fuel). The HPCS injection is reportable per 10CFR50.72(b)(2)(iv)(A) for ECCS discharge into the reactor coolant system and 50.73(a)(2)(iv) for specified system actuation. Safety Relief Valves highest pressure that occurred was 1112 psig which was within the tolerance of the SRV setpoint. Low-Low set operation provided automatic pressure control following the initial pressure reduction until operators established control to lower the pressure band.

Following the initial scram level transient, injection with HPCS was procedurally over-ridden off and RCIC was automatically terminated at level 8 (219 inches) at about 1616 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.14888e-4 months <br />. RCIC was then used, as required, to makeup for RPV level decrease primarily as a result of SRV manual operation. SRVs were being operated for RPV pressure control. On August 14, 2003, at about 1925 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.324625e-4 months <br />, level control was shifted to HPCS. Continued use of RCIC would have resulted in an automatic isolation of RCIC due to high steam tunnel temperature. The increasing steam tunnel temperature was caused by not having ventilation. The ventilation was de-energized due to the loss of off-site power. HPCS was used for level control until the LPCS fill and vent was completed and it was placed in service at 0230 hours0.00266 days <br />0.0639 hours <br />3.80291e-4 weeks <br />8.7515e-5 months <br /> on August 15. The pressure at that time was being maintained at 100 to 250 psig. RHR A was used for suppression pool cooling from 1425 hours0.0165 days <br />0.396 hours <br />0.00236 weeks <br />5.422125e-4 months <br /> until 1433 hours0.0166 days <br />0.398 hours <br />0.00237 weeks <br />5.452565e-4 months <br /> on August 15, 2003 following fill and venting of that system. Shutdown cooling operation using RHR A was commenced at 1934 hours0.0224 days <br />0.537 hours <br />0.0032 weeks <br />7.35887e-4 months <br /> on August 15, 2003. The plant achieved cold shutdown, Mode 4, at 0120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br /> on August 16, 2003.

Loss of power to the main steam line leak detection system caused the isolation of the main steam line isolation valves. Following the power loss, the feedwater pumps tripped, reactor recirculation pumps tripped, isolation signals were received for residual heat removal, balance of plant, reactor water cleanup and sample system. The emergency diesel generators [EK] received an automatic start signal. Within 10 seconds, the division 1 and 2 diesel generators began to supply power to their respective busses. The SRVs opened in pressure relief mode to control RPV pressure. About 2 seconds later the division 3 diesel generator began supplying power to its electrical bus. HPCS and RCIC started on RPV level 2 (130 inches above top of active fuel) and injected into the RPV to restore level. RPV level and pressure were restored and stabilized. Additional operator actions included operation of the RHR B loop in suppression pool cooling mode to remove the heat added by the SRV operation. The maximum pressure during the event was 1112 psig.-The"maXimurribeilitron flux level reached was 102%-es a result of the — pressure transient. The minimum water level reached was 103.9 inches above the top of active fuel on wide range level instruments. The maximum suppression pool temperature was 129 ° Fahrenheit.

Loss of off-site power to the safety-related emergency power supply busses for greater than 15 minutes required entry into an Unusual Event, the lowest level of the plant's emergency plan. The Unusual Event was entered at 1610 hours0.0186 days <br />0.447 hours <br />0.00266 weeks <br />6.12605e-4 months <br />. The State of Ohio and Lake, Ashtabula and Geauga counties were notified of the Unusual Event at 1625 hours0.0188 days <br />0.451 hours <br />0.00269 weeks <br />6.183125e-4 months <br /> and the NRC was notified at 1635 hours0.0189 days <br />0.454 hours <br />0.0027 weeks <br />6.221175e-4 months <br />. Subsequently, it was recognized that power was not available at the EOF and the .BEOF. Although the activation of the EOF and BEOF was not required for this event, this condition was reported to the NRC via the Emergency Notification line at 2225 hours0.0258 days <br />0.618 hours <br />0.00368 weeks <br />8.466125e-4 months <br />. The Unusual Event was terminated at 1952 hours0.0226 days <br />0.542 hours <br />0.00323 weeks <br />7.42736e-4 months <br /> on August 15, 2003, following restoration of off-site power to the safety-related emergency power supply busses and stabilization of the off-site power supply.

The following equipment deficiencies were noted during the transient and shutdown following the scram:

The LPCS/RHR A water-leg pump was found running but not supplying adequate keep-fill pressure after receipt of low pressure alarms. As a result, the LPCS and the RHR A pumps were placed in secured status at 1847 hours0.0214 days <br />0.513 hours <br />0.00305 weeks <br />7.027835e-4 months <br /> and were made inoperable until verification was performed that they were adequately filled. Additionally, RHR B was inoperable for injection at 1636 hours0.0189 days <br />0.454 hours <br />0.00271 weeks <br />6.22498e-4 months <br /> when it was placed in suppression pool cooling. This combination resulted in 3 ECCS injection pumps being unavailable. Three injection pumps inoperable requires entry into Technical Specification 3.0.3 which requires the plant to be in cold shutdown within the following 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />.

Operation in this condition continued until 2002 hours0.0232 days <br />0.556 hours <br />0.00331 weeks <br />7.61761e-4 months <br /> on August 15, 2003, when the RHR A system was declared operable, a period of about 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> and 15 minutes. LPCS was subsequently declared operable at 0318 hours0.00368 days <br />0.0883 hours <br />5.257936e-4 weeks <br />1.20999e-4 months <br /> on August 16, 2003. Entry into Technical Specification 3.0.3 for greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is reportable per 10CFR50.73(a)(2)(i)(B), as a condition prohibited by Technical Specifications.

Subsequent investigation identified additional reportable conditions related to the water-leg pump air binding. The conditions are described in LER 2003-005.

The combustible gas drywell purge inboard containment isolation valve failed to close. The outboard valve in the containment penetration closed as required to provide the required safety function, which was to isolate the penetration.

The Division 1 diesel generator tripped on reverse power while being removed from service. The diesel was placed in standby and was considered to be operable until 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br /> on August 21, 2003, when it was identified that the voltage regulator was set above the required Technical Specification limit. This condition will be reported in a separate licensee event report (LER 2003-003).

Reactor water samples were not obtained within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> as required by the Operating Requirements Manual and the Off-site Dose Calculation Manual (non-Technical Specification).

The reactor water cleanup pumps (RWCU) tripped about 90 seconds prior to the loss of off-site power.

The offgas treatment system isolated as a result of the loss of power to the offgas post-treatment radiation monitor about 3 seconds prior to the scram.

III. CAUSE OF EVENT

The cause of the generator trip was under-frequency due to grid instabilities that resulted in the loss of off-site power (LOOP). The generator trip caused the actuation of the generator lockout relay and caused the turbine to trip resulting in a turbine control valve fast closure signal. The turbine control valve fast closure signal caused an automatic reactor protection system actuation (reactor scram). As a result of the loss of off-site power, power was -� -lost to the safety-related emergency powi5i� — The cause of the air binding in the water-leg pump was determined to be inadequate design of the division 1 water­ leg pump piping system that resulted in a collection point for air in the FWLCS system. Past venting procedures failed to remove entrapped air from two high point locations in the division 1 LPCS system and LPCS/RHR A water­ leg pump piping. Subsequent venting, on a periodic basis, has resulted in minimal accumulation of air in the affected piping and assures a similar condition will not recur. Subsequent investigation identified additional reportable conditions related to the water-leg pump air binding. The conditions are described in LER 2003-005.

The combustible gas drywell purge inboard containment isolation valve failed to close. Troubleshooting of the condition failed to identify a cause; the circuitry functioned as designed during testing. Review of the design and re­ enactment of the event did not identify any failed or degraded components. The most likely cause was the failure of the K36 or K39 relay to reposition. The K36 relay is an interposing relay that provides isolation between the non­ safety drywell radiation monitor and the safety-related valve control circuit. The K39 relay is in the override open circuit. It prevents the valve closing circuit from being energized when the valve is manually overridden open.

The loss of the EOF and the BEOF was the result of the widespread power outage. Although these facilities were not required to be activated, additional backup facilities were identified. This information was communicated to the NRC at 2345 hours0.0271 days <br />0.651 hours <br />0.00388 weeks <br />8.922725e-4 months <br />. Potential facilities that were identified included the Perry Technical Support Center, the Lake County EOC, the Blaise-Naimeth minimum-security jail and the Job and Family Services Center. Power was available at each of these locations.

The inability to obtain a reactor water sample from the normal sample location was due to the loss of electrical power. The initial attempt to obtain a sample from the Post Accident Sample System (PASS) was also unsuccessful. The PASS system is the current contingency system for post accident samples that was committed to when PASS was removed from Technical Specifications. The PASS system valves were cycled several times resulting in a successful sample. The apparent cause of the.inability to initially obtain a sample was a temporary flow obstruction that was eventually freed by cycling the valves during numerous attempts to line up sample flow.

The RWCU pumps tripped due to low suction flow as a result of loss of power to the suction valve interlock circuit.

The suction valve interlock circuit is powered from non-safety 120 volt AC bus, K-1-N. It was likely that the voltage dropped low enough to cause the system to trip. All equipment operated correctly for the fluctuating power condition.

The offgas isolation was determined to have been caused by voltage fluctuations affecting the offgas post treatment radiation monitor. The radiation monitor provides isolation signals to the off-gas system on both hi radiation and a downscale signal. This condition had no impact since the main steam isolation valves received an isolation signal and closed about 4 seconds later.

IV. SAFETY ANALYSIS

This event, a LOOP, was compared to the loss of all grid connection event that is evaluated in the updated safety analysis report (USAR), section 15.2.6. Note that a LOOP, although a safety significant event, is less severe than the station blackout (SBO) event that is evaluated in USAR Appendix 15H. The loss of all grid connection event is categorized as an incident of moderate frequency, potential to occur about every 20 years. The sequence of actual events followed those as listed in the USAR. An exception was that SRVs opened later as a result of a slower pressure increase (about 9 seconds after MSIV isolation). The conditional core damage probability (CCDP) calculated for the loss of all grid event was 1.25E-04.

Subsequent investigation identified additional reportable conditions related to the water-leg pump air binding. The safety analysis associated with the water-leg conditions are described in LER 2003-005.

V, CORRECTIVE ACTIONS The grid instability that caused the generator trip and resulted in the reactor scram is still being reviewed by FirstEnergy. Lessons learned by the industry that apply to PNPP will be reviewed for incorporation. The operation of the turbine, generator and main transformer were assessed. No damage to this equipment was identified to have occurred as a result of this event.

Subsequent investigation identified additional reportable conditions related to the water-leg pump air binding. The corrective actions associated with the water-leg pump conditions are described in LER 2003-005.

The combustible gas drywell purge inboard containment isolation valve relays, K36 and K39, were cycled and the circuitry functioned as designed. The condition was entered in the corrective action program and the relays were conservatively scheduled for replacement.

Additional backup facilities were identified during the event that could have been used as an EOF during the event.

The inability to obtain a timely reactor water sample was entered into the corrective action process for trending purposes. No additional actions are required.

VI. PREVIOUS SIMILAR EVENTS

No previous loss of off-site power event or pump air binding event was identified to have occurred at the PNPP.

Energy Industry Identification System (EDS) codes are identified in the text in the format [xx].

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