ML18101A809

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LER 95-004-00:on 950607,ESFA Rt Occurred During Unit 2 Controlled Shutdown Per TS 3.0.3.Caused by RHR Sys Inoperability.Replaced All SBF-1 Failed Protection Relays on 500 Kv Breakers
ML18101A809
Person / Time
Site: Salem PSEG icon.png
Issue date: 07/07/1995
From: HALL W
PENNSYLVANIA POWER & LIGHT CO.
To:
Shared Package
ML18101A808 List:
References
LER-95-004-02, LER-95-4-2, NUDOCS 9507110212
Download: ML18101A809 (11)
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Text

  • I NRG FORM 366 . U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB NO. 3150-0104
  • ,(5-92) EXPIRES 5/31/95 ESTIMATED BURDEN PER RESPONSE TO COMPLY WITH THIS LICENSEE EVENT REPORT (LER) INFORMATION COLLECTION REQUEST: 50.0 HRS. FORWARD COMMENTS REGARDING BURDEN ESTIMATE TO THE INFORMATION AND RECORDS MANAGEMENT BRANCH (MNBB 7714). U.S. NUCLEAR REGULATORY COMMISSION.

WASHINGTON, DC 20555-0001, AND TO THE PAPERWORK REDUCTION PROJECT (3150-0104), OFFICE OF (See reverse for required number of digits/characters for each block) MANAGEMENT AND BUDGET, WASHINGTON, DC 20503. FACILITY NAME (1) DOCKET NUMBER (2) II PAGE (3) Salem Generating Station 05000 311 1 OFlO TITLE (4) Engineered Safety Features Actuation (Reactor Trip) During Unit 2 Controlled Shutdown Per Technical Soecification 3.0.3. EVENT DATE (5) LEA NUMBER (6 REPORT NUMBER (7) OTHER FACILITIES INVOLVED (8) FACILITY NAME DOCKET NUMBER SEQUENTIAL REVISION MONTH DAY YEAR YEAR NUMBER NUMBER MONTH DAY YEAR 05000 6 07 95 95 004 00 07 07 95 FACILITY NAME DOCKET NUMBER ----05000 OPERATING THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR §: (Check one or more (11) MODE (9) 1 20.402(b) 20.405(c) x 50. 73 (a) (2) (iv) 73.7.1 (b) POWER 100 20.405 (a) (1) (i) 50.36(c) (1) 50. 73 (a) (2) (v) 73.71(c) LEVEL (10) 20.405(a)

(1 )(ii) 50.36(c)(2) 50.73(a) (2) (vii) OTHER : !!llil'll!;il i\'11! Iii, 20.405(a)

(1) (iii) x 50. 73 (a) (2) (i) 50.73(a) (2) (viii) (A) (Specify in Abstract i 20.405 (a)(1 )(iv) 50.73(a) (2) (ii) 50.73(a) (2) (viii) (B) below and in Text, NRC Form 366A) 20.405(a)

(1) (v) 50.73(a) (2) (iii) 50.73(a) (2)(x) :., LICENSEE CONTACT FOR THIS LEA 12) NAME Warren Hall, LER Coordinator T6LEPHONE NUMBER (Include Area Code) 09 339-5165 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT (13) SYSTEM COMPONENT MANUFACTURER REPORTABLE CAUSE SYSTEM COMPONENT MANUFACTURER REPORTABLE CAUSE TO NPRDS TO NPRDS x BP FCV V085 y SUPPLEMENTAL REPORT EXPECTED (14) EXPECTED MONTH I SUBMISSION xj YES (If yes, complete EXPECTED SUBMISSION DATE) NO DATE (15) 09 \ rs 195 ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewritten lines) (16) On 6/7/95, at 1828 hours0.0212 days <br />0.508 hours <br />0.00302 weeks <br />6.95554e-4 months <br />, a Unit 2 controlled shutdown from Mode 1 was initiated in accordance with the requirements of Technical Specification (TS) 3.0.3 due to the inoperability of both Residual Heat Removal (RHR) trains. The inoperability was caused by the failure of the 21RHR pump recirculation valve ( 21RH2 9) to automatically open when the 21RHR pump was started and the inability to ensure operability of the 22RHR pump recirculation valve (22RH29).

With both RHR trains inoperable the Unit was operating in a condition not covered by the TSs and the requirements of TS 3.0.3 were initiated.

The Unit was reducing load with the group buses already transferred to the 21 and 22.Station Power Transformers.

When the Unit load was below 50 MW (14% reactor power), the Nuclear Control Operator manually tripped the turbine. 500KV Bus Section breakers, BS 1-9 and BS 9-10, both opened; however, BS 1-9 breaker failure protection circuitry actuated unexpectedly causing loss of Bus Section 1 which represents the loss of one source of off-site power to both Salem Units. This caused the loss of 4KV group buses 2F and 2G which caused the trip of 23 and 24 reactor coolant pumps, followed by an automatic reactor trip on low flow in two of four reactor coolant loops (> 10 % reactor power) at 2301 hours0.0266 days <br />0.639 hours <br />0.0038 weeks <br />8.755305e-4 months <br /> on 6/7/95. The investigation of the RHR System inoperability event is continuing final results, including apparent provided in NRC FORM 366 (5*92) a supplement to this 9507110212 950707 PDR ADOCK 05000311 -...... r. cause and corrective actions, will LER, anticipated by 9/15/95. and be BLOCK NUMBER 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 *

  • REQUIRED NUMBER OF DIGITS/CHARACTERS FOR EACH BLOCK NUMBER OF DIGITS/CHARACTERS TITLE UP TO 46 FACILITY NAME 8 TOTAL 3 IN ADDITION TO 05000 DOCKET NUMBER VARIES PAGE NUMBER UP TO 76 TITLE 6 TOTAL 2 PER BLOCK EVENT DATE 7 TOTAL 2 FOR YEAR 3 FOR SEQUENTIAL NUMBER LER NUMBER 2 FOR REVISION NUMBER 6 TOTAL 2 PER BLOCK REPORT DATE UP TO 18 FACILITY NAME 8 TOTAL -DOCKET NUMBER OTHER FACILITIES INVOLVED 3 IN ADDITION TO 05000 1 OPERATING MODE 3 POWER LEVEL 1 CHECK BOX THAT APPLIES REQUIREMENTS OF 10 CFR UP TO 50 FOR NAME 14 FOR TELEPHONE LICENSEE CONTACT CAUSE VARIES 2 FOR SYSTEM 4 FOR COMPONENT EACH COMPONENT FAILURE 4 FOR MANUFACTURER NPRDS VARIES 1 CHECK BOX THAT APPLIES SUPPLEMENTAL REPORT EXPECTED 6 TOTAL 2 PER BLOCK EXPECTED SUBMISSION DATE
  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 2 of 10 Unit # 2 50-311 95-004-00 Plant and System Identification:

Westinghouse

-Pressurized Water Reactor Energy Industry Identification System (EIIS) codes appear in the text as {xx} Identification of Occurrence:

Engineered Safety Features (ESF) Actuation (Reactor Trip) During Unit 2 Controlled Shutdown Per Technical Specification 3.0.3, Due To Inoperability Of Both RHR Trains. Event Date: June 7, 1995 Report Date: July 7, 1995 Conditions Prior to Occurrence:

Mode: 1 Reactor Power: 100% Unit Load: 1120 MWe Description/Analysis of Occurrence:

On June 7, 1995, Operations requested that both RHR pump recirculation valves (21RH29 & 22RH29) be tested to assure that they would open when called upon when the pump started. At 0150 the 22RHR pump was started and 22RH29 opened automatically as required.

The pump was then stopped and 22RH29 closed automatically as required.

AT 0155 the 21RHR pump was started but 21RH29 did not open automatically as required.

The operator took manual control of 21RH29 and opened the valve. The 21RHR pump was then stopped and 21RH29 was placed in automatic and the valve closed. The operator then entered Technical Specification 3.5.2c, Action Statement a, which requires that the inoperable ECCS subsystem be returned to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the unit must be shutdown.

Continuing evaluation of both RHR pump recirculation valves confirmed that 21RH29 was inoperable and that 22RH29 was operable but may be in a degraded condition.

A follow up operability assessment of 22RH29 was requested to be completed in a timely manner.

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 3 of 10 Unit# 2 50-311 95-004-00 Description/Analysis of Occurrence (cont'd):

Trouble shooting of 21RH29 was initiated and as a result of failure analysis, three relays in the control circuitry were replaced.

Because the follow up assessment for operability of the 22RH29 valve could not be completed in a timely manner commensurate with the safety significance of the RHR System {BP}, 22RH29 was declared inoperable.

At 1827 hours0.0211 days <br />0.508 hours <br />0.00302 weeks <br />6.951735e-4 months <br /> on June 7, 1995, Unit operators entered Technical Specification 3.0.3 and commenced a controlled shutdown of the Unit from Mode 1 due to both trains of the RHR System being inoperable.

At 1907 on June 7, 1995, Public Service Electric & Gas made a one-hour notification to the NRC in accordance with 10CFR50.72(b)

(1) (i) (A). An orderly shutdown was in progress and the Unit was reducing load at a rate of 30% per hour. As the load reached 20% power the group buses were transferred from the Auxiliary Power Transformer to the 21 and 22 Station Power Transformers (SPTs) . As the load was reduced below 50MW (14% reactor power) the operator manually tripped the turbine in accordance with normal operating procedures.

This action in conjunction with the actuation of the back-up reverse power relay caused the Generator Overload and Out of Step HEA Multi-Trip (MT) to operate. The Generator Overload MT subsequently initiated several signals to circuitry which included BS 1-9 (32X) breaker trip coil, BS 9-10 (30X) breaker trip coil, BS 1-9 breaker failure relay, BS 9-10 breaker failure relay, Exciter Field Breaker, and Overhead Alarms. As expected, this action resulted in the opening of both BS 1-9 and BS breakers.

However, BS 1-9 breaker failure protection circuitry actuated unexpectedly causing loss of Bus Section 1 which represents the loss of one source of off-site power to both Salem units. The operation of BS 1-9 breaker failure protection circuitry resulted in tripping 500KV BS 1-5, BS 1-8, 13KV BS 3-4, BS 4-5, BS C-D, BS D-E, and Gas Turbine breakers.

This caused a loss of power to 2SPT, 4SPT, 12SPT, 14SPT, 22SPT, 23SPT, and 4KV group buses lF, lG, 2F, and 2G. The loss of 4KV group buses 2F and 2G caused 23 and 24 reactor coolant pumps to trip and consequently resulted in an automatic reactor trip on low flow conditions in two of four reactor coolant loops. The BS 1-9 breaker failure relay actuated after the breaker trip signal was received.

The Generator Overload MT

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 4 of 10 Unit# 2 50-311 95-004-00 Description/Analysis of Occurrence (cont'd):

initiated the breaker trip signals and breaker failure timing to both BS 1-9 and BS 9-10 simultaneously, but the breaker failure time delay relay unexpectedly actuated for BS 1-9. There was no problem in opening the BS 1-9 breaker within the required time, however, the BS 1-9 breaker failure relay time delay requirement did not reset during the event thereby causing the breaker failure circuitry to actuate without the proper time delay. The purpose of the breaker failure relay time delay is to allow adequate time for the breaker to open prior to actuating the breaker failure relay. The BS 1-9 breaker and the breaker failure relay actuation occurred at approximately the same time. This points to a deficiency or malfunction in the breaker failure relay (SBF-1) circuitry.

Tests performed under the troubleshooting plan extensively checked the breaker main contacts, auxiliary contacts, associated control circuitry, SBF-1 circuitry, and the time delay circuitry.

Results of the.preliminary on-site testing found no anomaly or problems with any of the circuitry.

However, laboratory analysis of the breaker failure circuitry is being conducted and the results, if available, will be provided in the Supplement to this LER. At 0152 on June 8, 1995, Public Service Electric & Gas made a four hour notification to the NRC in accordance with 10 C FR5 0 . 7 2 ( b) ( 2 ) ( ii ) . Apparent Cause of Occurrence:

The apparent cause of the occurrence related to the RHR system inoperability is still under investigation and will be provided in a supplement to this LER, anticipated by 9/15/95. The cause of this occurrence related to the BS 1-9 breaker failure and the subsequent reactor trip is attributed to the malfunction of the SBF-1 breaker failure relay. The manufacturer of the SBF-1 relay (Westinghouse/ABB) had notified users of SBF-1 relays manufactured prior to 1992 that they are susceptible to misoperation under transient voltage conditions.

The malfunction has been attributed to surge voltage conditions on the 125V DC system. The energization and de-energization of the relays in the

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 5 of 10 . Unit# 2 50-311 95-004-00 Apparent Cause of Occurrence (cont'd) control circuitry creates a very rapid switching transient of greater than 2.5KV on the 125V DC system. The opening of the main breaker contacts also impresses additional noise signal transients on the 125V DC system. These transients have the potential to momentarily short circuit the time delay device in the SBF-1 relay circuitry resulting in the premature operation of the relay. This misoperation of the relay was preliminarily determined to be the reason for the breaker failure and the subsequent reactor trip. In August 1993, a notice from the manufacturer (Westinghouse/ABB) of the possible SBF-1 relay malfunction for relays manufactured prior to 1992 was received by the Nuclear Business Unit. This notification provided information on the use of certain types of cables with the relay and also stated that a surge suppresser kit had been developed to upgrade the surge withstand capability of the relay to prevent future relay malfunction.

Relays manufactured after 1992 have the surge protection feature upgrade built in. The corrective action recommended in the vendor notice was not acted upon until May 16,1995, when a Design Change Request (DCR) was issued by Nuclear Engineering to replace the current relays with the upgraded model. This modification had not taken place at the time of the breaker failure. Prior Similar Occurrence:

A review of the Salem records determined that there has been no similar occurrences at the Salem Station related to either the RHR inoperability or the breaker failure. Safety Significance:

The RHR System inoperability is reportable pursuant to 10CFR50. 73 (a) (2) (i) (A) and the reactor trip is reportable pursuant to 10CFR50. 73 (a) (2) (iv). RHR Pump Recirculation Valves (21RH29 & 22RH29) Testing of the 21RH29 recirculation valve determined that the valve would fail to open after placing the 21RHR pump in service. Testing of the 22RH29 recirculation valve determined that the valve would open upon receiving a start signal thereby assuring that the 22RHR pump would not be

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 6 of I 0
  • Unit # 2 50-311 95-004-00 Safety Significance (cont'd) placed in a shut off head condition.

Testing did not confirm that the 22RH29 valve would close when RHR flow to the core was required for various sized LOCAs. If this valve were to remain open, flow delivered to the core would be reduced under some conditions.

No safety injection (SI) signal occurred during this event therefore no automatic signal to start the RHR pumps was generated.

Consequently, no operation of the RHR pumps in either normal or shut off head conditions was required.

The fact that one recirculation valve was inoperable and the operability of the other was of concern did not contribute in any way to the Unit trip. If a SI signal had been generated and the valves responded consistently with the test results, the 22RHR pump would have had recirculation.

Assuming no other single failure, 22RHR pump would have been available to perform its intended safety function, while the 21RHR pump would have been in a shut off head condition.

After operating for an extended period of time in this configuration, the 21RHR pump could eventually fail sometime after 45 minutes, while the 22RHR pump would be available to deliver flow to the core. In the Salem safety analysis, the single failure assumed for the minimum safeguards analysis is the loss of one RHR pump. This is consistent with the conditions that existed at the time the testing was conducted with the exception that it could not be assured that the 22RH29 valve would close when flow to the core was required.

If the 22RH29 valve did not close, the flow to the core would be reduced by the amount of the recirculation flow. However, ample margin is provided between various conservatisms and in newer, generically approved analyses.

Credit is available for Large Break LOCAs since they assume the broken line spills to 10 psig rather than 0 psig (this artificially increases the peak cladding temperature (PCT)). Additional margin would also exist by crediting the second IHSI pump which would not be compromised by failure of the RH29 valve to close. Further margin is also available in the Large Break LOCA PCT. The PCT difference between maximum and minimum safeguards flow is 102°F. The change in flow caused by an open RH29 valve would be substantially less than the difference between maximum and minimum safeguards.

Hence, the increase to PCT would be expected to be less than 102°F. This would be acceptable since there is 186°F of margin. On

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 7 of 10 Unit# 2 50-311 95-004-00 Safety Significance (cont'd) the basis of these considerations, it is judged that the penalty on an RHR pump associated with an open RH29 valve would not have caused the Unit to exceed 10CFR50.46 criteria for Large Break LOCA. Small Break LOCA and LOCA hydraulic forces are not affected by RHR flows because they are not credited in the analyses.

Furthermore, long term core cooling and hot leg switchover are not impacted by this issue because the recirculation valve is manually closed by the operator when recirculation begins. Short term LOCA subcompartment analysis and pump runout concerns have also been considered.

It was concluded that there would be no adverse effect on these issues due to an open RH29 valve. Consequently, if the recirculation valves behave consistently with the test results and no other failures occurred to compromise the 22RHR pump, it can be concluded that the inoperable status of the recirculation valves did not pose any undue risk to public health and safety. With the existing condition on 21RH29, a single failure could cause 22RH29 to fail closed and the both RHR pumps would be in a shut off head condition.

The current Large Break LOCA analysis uses RHR pump flows that assume the recirculation valves are closed. The reactor rapidly depressurizes to approximately 30 psia in about 30 seconds. With a loss of off site power and maximum safety injection delay time, the RHR pumps will still deliver flow following a large break LOCA since the valves would already be closed. No operator action would be required to open the recirculation valves following a large break LOCA since system pressure would be low and pump flow would be adequate to keep the valves closed. Therefore, the failure of both recirculation valves to open would have no impact on the safety analysis or the ability of the RHR system to perform its safety function during a large break LOCA. For the limiting Small Break LOCA PCT analysis, operation of the RHR pumps is not credited since system pressure does not fall below the cut in pressure during the transient.

Therefore, failure of the recirculation valves to open does not impact the analysis.

If the operator were to secure the pumps or open the recirculation valves there would also be no impact on the analysis.

All other Chapter 15 analyses do not recognize start up or operation of the RHR pumps at RCS pressures above the shut off head of the pumps. Therefore,

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 8of10 Unit # 2 50-311 95-004-00 Safety Significance
  • (cont'd) plant safety would not have been compromised and the results and conclusions of the safety analysis remain valid for the period in which the recirculation valves would not have opened. Operation of the pumps in a shut off head condition for an extended period of time has also been reviewed.

The Salem Emergency Operating Procedures (EOPs) direct the operators to secure the RHR pumps. This activity is normally performed in approximately 30 minutes. Westinghouse predicts that the Salem RHR pumps could operate at shut off head conditions for 45 minutes and still perform their required safety function after restoration of normal flows. PSE&G has reviewed the EOPs and has confirmed that 45 minutes provides the operators with adequate time to perform these actions. Therefore, the RHR pumps would have been secured before damage could occur and would remain capable of performing their intended safety function when needed. Effects of the Transient on the Primary Plant The transient that resulted following the reactor trip is bounded by the loss of offsite power and loss of flow analyses in Chapter 15 of the UFSAR that assumes the coast down of all four loops. Clearly the loss of flow in four loops is more severe and therefore bounds the loss of flow in two loops. The analysis is unaffected by the inoperability of 21RH29 and 22RH29. With the Unit at 14% power at the time of the reactor trip, additional margin to Departure From Nucleate Boiling (DNB) and reactor vessel pressure limits is provided.

The loss of 23 and 24 reactor coolant pumps coupled with the isolation of letdown, reduced normal pressurizer spray flow. This has no impact on the Chapter 15 analysis since spray is only assumed in the analysis if it is detrimental to the accident.

In this transient, pressurizer spray was not detrimental since it would have mitigated the pressure increase.

Further margin for the analysis was provided when auxiliary pressurizer spray was initiated to stop increasing pressurizer pressure.

Reactor coolant system pressure was maintained below 2350 psia throughout the transient.

Based on the above discussion, this transient is bounded by the Chapter 15 accident analysis and had no impact on the reactor core or the reactor coolant system.

  • LICENSEE EVENT REPORT (LER) TEXT CONTINO A TION Salem Generating Station Docket Number LER Number Page 9 of 10 Unit# 2 50-311 95-004-00 Safety Significance (cont'd) 500KV Bus Section 1-9 Breaker Failure/Reactor Trip As a result of the failure of the breaker failure protection relay of the BS 1-9 breaker Bus Section 1 of the 500KV ring bus was de-energized.

This resulted in the loss of power to the Number 2 and Number 4 Station Power Transformers (SPT) . The Number 2 SPT normally feeds the 4KV 2F and 2G group buses through the Number 22 SPT and the Number 4 SPT normally feeds the 4KV 2B and 2C vital buses and one half of the circulating water bus through the Number 23 SPT. When power was lost to the Number 2 SPT, all equipment fed from the 2F and 2G group buses was de-energized.

All of this equipment is classified as non-safety related and safe shut down of the Unit without this equipment is within the design basis analysis of the plant. When power was lost to the Number 4 SPT, the vital buses transferred to their alternate power source, as designed.

This transfer took place as required and all effected equipment functioned as designed.

If the transfer to the alternate source failed, the diesel generators were available and would have started and sequenced on the appropriate shutdown loads. This would have allowed the operators to continue the safe and orderly shut down of the Unit. Therefore, the loss of the Number 4 SPT is within the design basis analysis of the plant. The partial loss of off site power/reactor trip is within the design basis analysis of the plant and therefore did not pose any additional risk to public health and safety. Corrective Action: Corrective actions related to the RHR system inoperability will be established as a result of completing the cause investigation and will be provided in a Supplement to this LER, anticipated by 9/15/95. All SBF-1 breaker failure protection relays on the 500KV breakers will be replaced with upgraded relays that have higher surge withstand capabilities.

The SBF-1 relays on the generator output breakers (BS 1-9, BS 9-10, BS 1-5, and BS 5-6) will be replaced first followed by other 500KV breakers.

  • LICENSEE EVENT REPORT (LER) TEXT CONTINUATION Salem Generating Station Docket Number LER Number Page 10 of 1 O Unit# 2 50-311 95-004-00 Corrective Action (cont'd):

All SBF-1 breaker failure relays on the new 13KV BS A-B, BS B-C, BS C-D, and BS D-E will be replaced with relays. Similar circuitry for other breaker failure relays at both Salem and Hope Creek will be reviewed to determine transient susceptibility and replaced with upgraded relays as necessary.

The process used to evaluate and implement vendor recommendations in a prompt and effective manner will be reviewed and changes made where necessary.

The status of these corrective actions will be provided in the supplement to this LER. MJPJ:vs REF: SORC Mtg.95-072 je{;'-57--

J. C. Summers General Manager -Salem Operations

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