hope creek report; salem turbine trip report 1/06 - 3/06

 

 

 

SUMMARY OF FINDINGS

IR 05000354/2006002; 01/01/2006 - 03/31/2006; Hope Creek Generating Station; Heat Sink

Performance, Maintenance Effectiveness, Other Activities.

The report covered a 13-week period of inspection by resident inspectors and announced

inspections by regional reactor inspectors. Three Green non-cited violations (NCVs) were

identified.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

C Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, “Corrective Action,” for PSEG’s failure to implement

corrective actions for a condition adverse to quality involving inadequate

procedure guidance for service water pump packing replacement. This resulted

in a degraded condition on the 'B' service water pump packing assembly that

was identified by the inspectors on February 13, 2006. PSEG's corrective

actions included tightening the packing and revising maintenance procedures.

The finding was more than minor because it was associated with the equipment

performance attribute of the Mitigating Systems cornerstone and affected the

cornerstone objective of ensuring the availability, reliability, and capability of

systems that respond to initiating events. In accordance with NRC Inspection

Manual Chapter 0609, Appendix A, "Significance Determination of Reactor

Inspection Findings for At-Power Situations," the inspectors conducted a Phase

1 SDP screening and determined the finding to be of very low safety significance

(Green) because the finding was not a design or qualification deficiency, did not

represent a loss of system safety function, and did not screen as risk significant

due to external events. The finding had a cross-cutting aspect in the area of

problem identification and resolution because PSEG did not identify that

corrective actions were not implemented correctly during a corrective action

effectiveness review. (Section 1R07)

C Green. The inspectors identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion XVI, "Corrective Action," when the ‘D’ service water strainer was

rendered unavailable for 49 hours on November 6, 2005. On May 23, 2005,

PSEG technicians reassembled the ‘D’ service water strainer with the backwash

arm off-center and a packing gland machined from its original size to allow

assembly. The resulting non-conforming condition was not entered into PSEG’s

iv Enclosure

corrective action program. The absence of this documentation and evaluation

led to the reuse of the machined gland, which resulted in a packing leak and the

unavailability of the 'D' service water strainer in November 2005. PSEG initiated

actions to address the problem associated with not entering the non-conforming

condition into the corrective action program.

This performance deficiency was more than minor because it was associated

with the equipment performance attribute of the Mitigating Systems and Initiating

Events cornerstone objectives and affected both cornerstone objectives. In

accordance with NRC Inspection Manual Chapter 0609, Appendix A,

"Significance Determination of Reactor Inspection Findings for At-Power

Situations," the inspectors conducted a Phase 1 SDP screening and determined

a more detailed Phase 2 evaluation was required to assess the safety

significance, because the finding affected two cornerstones. The inspectors

determined that the finding was of very low safety significance (Green). The

performance deficiency had a cross-cutting aspect in the area of problem

identification and resolution because PSEG did not identify a condition adverse

to quality by entering the issue into the corrective action program. (Section

1R12)

C Green. A self-revealing, non-cited violation of 10 CFR 50 Appendix B, Criterion

XVI, “Corrective Action," was identified when the guide vane pivot arm on the 'A'

control room chiller was discovered to be operating incorrectly in May 2005,

rendering the chiller unable to perform its design function. PSEG corrective

actions included modifying applicable procedures and providing training to

maintenance technicians.

This finding was more than minor because it was associated with the equipment

performance attribute of the Mitigating Systems cornerstone and affected the

cornerstone objective to ensure the availability, reliability, and capability of

systems that respond to initiating events. The improper use of setscrews on the

'A' control room chiller guide vane arms resulted in the chiller not being able to

perform its design function and unplanned unavailability of the chiller for about

85 hours to implement repairs. The inspectors completed a Phase 1 screening

using Appendix A of Inspection Manual Chapter (IMC) 0609, “Determining the

Significance of Reactor Inspection Findings for At-Power Situations,” and

determined that the performance deficiency was of very low safety significance

(Green) because the finding was not a design or qualification deficiency, did not

represent a loss of system safety function, did not represent an actual loss of

safety function of a single train greater than its technical specification allowed

outage time, and did not screen as risk significant due to external events.

(Section 4OA3)

B. Licensee Identified Violations

Violations of very low safety significance, which were identified by PSEG have been

reviewed by the inspectors. Corrective actions taken or planned by PSEG have been

entered into PSEG's corrective action program. These violations and corrective actions

are listed in Section 4OA7 of this report.

Enclosure

 

 

 

Note that PSEG admits

this event identified the potential vulnerability of the digital EHC system to RFI/EMI. Tests conducted

on the simulator EHC system demonstrated that interference could be induced into the EHC system.

he three turbine overspeed conductors (channels) are routed together in a single cable.

 

 

7 a

PSEG Nuclear LLC

P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236

PSEG Nuclear LLC MAY~ 0 B2006

LR-N06-0208

U. S. Nuclear Regulatory Commission

Document Control Desk

Washington, DC 20555

LER 272106-001-00

SALEM - UNIT I

FACILITY OPERATING LICENSE NO. DPR-70

DOCKET NO. 60-272

This Licensee Event Report, "Salem Unit 1 Turbine Trip - Reactor Trip with Reactor

Power Above P-9," is being submitted pursuant to the requirements of the Code of

Federal Regulations 10CFR50.73(a)(2)(iv)(A).

O YES (If yes, complete 15. EXPECTED SUBMISSION DATE) 10 NO DATE

ABSTRACT (Limit to 1400 spaces, i.e., approximately 15 single-spaced typewdfiten lines)

n March 8, 2006 at 1 109, with Salem Unit 1 at 100 % power, a turbine trip signal was received in the

ain control room with an immediate reactor trip. The reactor trip actions and plant recovery were

erformed without complications. Analysis of computer data indicated that the turbine over speed

rcuit initiated an overspeed signal at 103% and tripped the main turbine as designed. Turbine speed

as a constant 1800-rpm as controlled by the electric grid with the generator synchronized to it.

he most probable cause of the turbine trip reactor trip was Radio Frequency Interference (RFI) or

lectro Magnetic Interference (EMI) by an unknown source. Some of the corrective actions taken were

he following: (1) prohibiting the use of electric tools, radios, cellular phones, portable radios, arc flash

welders and other equipment that could result in EMI or RFI in relay rooms and (2) posting warning

signs in the effected areas.

This report is being made in accordance with 10CFR50.73(a)(2)(iv)(A), "any event or condition that

resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)."

NR IOM38820)PINE

NRCCE AE

NRC FORM 366 (ZM204) PRINTED ON RECYCLED PAPER

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION

(1-2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE

I SEQUENTIAL REVISION

Salem Generating Station Unit 1 05000272 YEAR I NUMBER I NUMBER

12006 -0 0 1- 00 2 OF 4

17. NARRATIVE (if more space s required, use additional copies of NRC Form 366A)

PLANT AND SYSTEM IDENTIFICATION

Westinghouse - Pressurized Water Reactor

Electro-Hydraulic Control System (TG){EHC}

Steam Generator Feed Pump (BF/P) {SGFP}

Control Rod System (AN-)

ndustry Identification System (EIIS) codes and component function identifier codes appear in the text

as {SSICCC}.

DENTIFICATION OF OCCURRENCE

Event Date: March 8, 2006

Discovery Date: March 8, 2006

CONDITIONS PRIOR TO OCCURRENCE

Salem Unit 1 was in Operational Mode 1 at 100% reactor power.

No structures, systems or components were inoperable at the time of the discovery that contributed to

the event

DESCRIPTION OF OCCURRENCE

n March 8, 2006 at 1109, with Salem Unit 1 at 100% power, a "first-our Overhead Alarm (F38) Turbine

rrip & P-9 (Reactor above 49% power) was received in the main control room with an immediate reactor

rip. The reactor trip actions and plant recovery were performed without complications; however, two

Dquipment issues were noted during the trip. The two issues were: (1) one control rod position

ndication for shutdown rod 1SC1 indicated that the rod was at approximately 17 steps, and (2) reports

rm field operators (non-licensed personnel) indicated a leak on the condensate line at the suction of

he 11 Steam Generator Feedwater Pump. Control room operators (Licensed personnel) initiated a

ain Steam Line Isolation to isolate steam flow to the secondary plant and controlled Reactor Coolant

ystem average temperature using the atmospheric dump valves. The leak on the condensate line was

due to the momentary secondary system pressure perturbation that caused a flange gasket to fail. The

failed gasket was replaced.

Later assessments determined that control rod ISCI was fully inserted. The erroneous ISCI position

indication was the result of residual magnetic flux in the individual rod position indicator coil that induced

a voltage on the secondary side of the coil. The secondary coil voltage is used to provide the relative

rod position and as such any error introduced will directly affect the rod position indication. The rod

position indication would have eventually decreased to indicate full insertion through natural decay of the

residual magnetic flux. De-energizing the individual rod position indication system let the residual flux

decay almost immediately. The individual position indicator was calibrated during the outage.

NRC FORM 366A(1-2001)

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION

(1-2001)

I LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER 3. PAGE

I SEQUENTIAL REVISION

Salem Generating Station Unit 1 05000272 YEAR NUBE N

2006 -0 0 1- 00 3 OF 4

1 17. NARRATIVE (If more space Is required, Use additional copies of NRC Form 366A)

DESCRIPTION OF OCCURRENCE (cont'd)

Analysis of computer data indicated that the turbine over speed circuit initiated an overspeed signal at

103% and tripped the main turbine as designed. Turbine speed was a constant 1800-rpm as controlled

by the electric grid with the generator synchronized to it.

The unit was returned to service the following day, March 9, 2006.

The automatic initiation of the reactor trip and the manual initiation of the Main Steam Line Isolation are

reportable in accordance with 10CFR50,73(a)(2)(iv)(A), "any event or condition that resulted in manual

or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)."

PREVIOUS OCCURRENCES

A review of reportable events for Salem Generating Station in the last three years identified five licensee

event reports associated with manual or automatic reactor trips.

311/2004-006 "Salem Unit 2 Reactor Trip Due to a Malfunction of a Main Feedwater Regulating Valve

(21BF19)," dated September 13, 2004.

311/2004-007 "Salem Unit 2 Reactor Trip Due to a Malfunction of a Main Feedwater Regulating Valve

(23BF19)," dated September 13, 2004.

311/2003-001 Salem Unit 2 "Manual Reactor Trip Due to Degradation of Condenser Heat Removal,"

dated May 22, 2003.

11/2003-003 Salem Unit 2 "Manual Reactor Trip Due to Dropped Control Rod," dated January 20, 2004.

72/2003-002 Salem Unit 1 "Reactor Trip due to Turbine Trip Caused by a 500KV Switchyard Breaker Trip,"

ated September 24, 2003.

Ilthough these events involved a reactor trip, the root causes were different than the one described in this

ER; and therefore they could not have been prevented this occurrence.

.,R11W1- ý"NJILA W=Afll -XIM I

NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION

(1-2001)

LICENSEE EVENT REPORT (LER)

1. FACILITY NAME 2. DOCKET 6. LER NUMBER S. PAGE

SEQUENTIAL REVISION

Salem Generating Station Unit 1 05000272 YEAR NUMBER I NUMBER

1 12006 -O 0 1 - 00 4 OF 4

17. NARRATIVE (if more space is required, use additional copies of NRC Form 366A)

CAUSE OF OCCURRENCE

The investigation team explored several possible failure methods which could have resulted in the turbine

overspeed trip and determined that the most probable cause was Radio Frequency Interference (RFI) or

Electro Magnetic Interference (EMI) by an unknown source.

Efforts to pinpoint the source of the interference signals are continuing. Due to the length of cable

associated with the turbine speed circuit and the transient nature of the interference, the investigation

team has not identified the specific device and location that initiated the EMI/RFI.

this event identified the potential vulnerability of the digital EHC system to RFI/EMI. Tests conducted

on the simulator EHC system demonstrated that interference could be induced into the EHC system.

he three turbine overspeed conductors (channels) are routed together in a single cable.

SAFETY CONSEQUENCES AND IMPLICATIONS

There was no actual safety consequences associated with this event.

As stated earlier, later assessments following the reactor trip determined that the control rod indication

was erroneous and that the leak on the condensate line was due to the momentary secondary system

pressure perturbation caused by the trip. The licensing basis of the Salem plant includes the assumption

that the highest worth control rod is stuck completely out of the core; therefore, the current licensing

basis accident analyses bound this event.

A review of this event determined that a Safety System Functional Failure (SSFF) as defined in NEI

99-02, Regulatory Assessment Performance Indicator Guidelines, did not occur.

4C ORRECTIVE ACTIONS

Jse of electric tools, radios, cellular phones, portable radios, arc flash welders and other equipment that

luld result in EMI or RFI in relay rooms has been prohibited.

aming signs have been posted in the effected areas. Adherence to the posting is being emphasized to

Irevent EMI and RFI from interfering with or causing inadvertent actuation or response of sensitive

nstruments in the plant.

Longer term actions such as additional cable shielding or cable separation are being evaluated as well as

the extent of the entire digital EHC circuit susceptibility to EMI/RFI.

COMMITMENTS