ML18100A613
| ML18100A613 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 09/10/1993 |
| From: | Hagan J Public Service Enterprise Group |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NLR-N93148, NUDOCS 9309210312 | |
| Download: ML18100A613 (9) | |
Text
Public Service Electric and Gas Company Joseph J. Hagan Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 08038 609-339-1200 Vice President - Nuclear Operations SEP 10 1993 NLR-N93148 United States Nuclear Regulatory Commission Document-control Desk Washington, DC 20555 Gentlemen:
RESPONSE TO NRC'S INSPECTION REPORT 50-272/93-19; 50-311/93-19 DOCKET NOS. 50-272; 50-311 Public Service Electric and Gas (PSE&G) has received the NRC _
Inspection Report 50-272/93-19; 50-311/93-19, dated June 28, 1993.
Within the $Cope of this report, several events were identified which dealt with management/supervisory oversight, inattention to detail, and procedural compliance at Salem.
PSE&G was requested to provide a collectiye assessment of performance issues and planned corrective actions to address these issues/events.
These events included two reactor trips, an ammonia gas release, a trip of a vital electrical bus, a service water pump tagging error, and the failure of a main condenser radiation monitor.
Accordingly, in the attachment to this letter, PSE&G assessment and response to the identified concerns.
PSE&G documents other corrective action efforts that been in place or are in progress.
submits its In addition, had since Should you have any questions regarding this transmittal, please do not hesitate to contact me.
9309_210312 930910 PDR ADOCK 05000272 G
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Document Control Desk NLR.:...N93148 Attachment ( 1-)
C Mr. J. c. Stone Licensing Project Manager Mr. T. Johnson Senior Resident Inspector Mr. T. Martin, Administrator Region I Mr. Kent Tosch, Manager, VI 2
New Jersey Department of Environmental Protection Division of Environmental Quality Bureau of Nuclear Engineering CN 415.
Trenton, NJ 08625 SEP 1 o 7993
REF:
NLR-N93148 STATE OF NEW JERSEY
)
)
SS.
COUNTY OF SALEM
)
J. J. Hagan, being duly sworn according to law deposes and says:
I am Vice President - Nuclear Operations of Public Service Electric and Gas Company, and as such, I find the matters set forth in the above referenced letter, concerning the Salem Generating station, Unit Nos. 1 and 2, are true to the best of my knowledge, information and belief.
My Commission expires on 1993 KIMBF.IU Y JO BROWN NOTARY eusuc Of NEW JERSEY Mr td1H1ol'4 upm Apnl 21. 1991
ATTACHMENT 1 PSE&G shares the NRC concerns stated in Inspection Report 50-272/93-19; 50-311/93-19, dated June 28, 1993.
PSE&G also noted that some events, at Salem station, were not being conducted in accordance with the expected high standards.
Accordingly, PSE&G initiated corrective actions to address these concerns.
These corrective actions and initiatives, which included the establishment of a comprehensive self-assessment team, were discussed with NRC (Region I) management, on July 16, 1993.
As discussed on July 16, PSE&G management identified the need for a collective evaiuation of recent occurrences/issues to identify any common threads.
The self-assessment team is sponsored by the Vice President and Chief Nuclear Officer, and is composed of a*
diverse selection of experienced personnel from PSE&G's.Nuclear Department, including bargaining union personnel. Additionally, an outside consultant, an industry expert, and co-owner representation is included in the self-assessment team.
The team was,chartered to evaluate selected occurrences, issues, and events over the past two years to determine and identify commonalities.
The selected occurrences/events will be reviewed using the Management Oversight and Risk Tree (MORT) analytic technique to identify preliminary issues from which problem statements will be drafted and validated.
- The team will then develop corrective action recommendations and provide assistance in the implementation of them.
It is anticipated that this effort will require approximately four months of dedicated full time involvement by the team members.
Phase 1, which primarily focuses on information gathering has been completed.
Presently, the team is in phase two of the investigation.
In this phase, the team will start developing the problem statement(s).
This phase will take approximately 6 to 7 weeks.
However, while the self-assessment team performs its investigation, PSE&G has taken other short term initiatives and corrective actions to ensure continued* acceptable performance.
Some of these initiatives are as follows:
- 1.
Instituted a supervisory monitoring program.
This program includes an increased field presence of first line supervision, thus ensuring that work is being performed in accordance with the established work standards.
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- 2.
Increased management field time by streamlining management meetings, thus allowing management to provide a more visible field presence to oversee activities.
- 3.
Improved troubleshooting (procedures) at-Salem station by requiring a risk evaluation of the activities and elevating management approval as the risk increases.
- 4.
Continuing an aggressive review and assessment, tracking and reduction of long standing equipment problems and failed components.
While implementing these initiatives to ensure continued improvement, PSE&G will assess their effectiveness for modification as appropriate.
Regarding the specific events mentioned in your report; the following is a brief description of each event, followed by PSE&G's root cause determination and corrective actions.
EVENT Unit 1 Reactor Trip Due to Loss -of Circulating Water Pumps On June 6, 1993, an automatic reactor trip occurred due to a Main Turbine trip from low condenser vacuum.
The loss of condenser vacuum resulted from a loss of Circulating Water flow.
Diving activities, to clean the Circulating Water (CW} System trash racks, were in progress at the time of this event.
ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS PSE&G's investigation determined that the loss of the Circulating Water (CW) flow resulted from the sudden release of large amounts of debris from the trash racks and the river bottom.
The released debris consequently blocked the flow of river water through the remaining travelling screens.
A Significant Event Response Team (SERT) determined the root causes of the event to be: (1) the buildup of debris on the trash rakes; (2) less than adequate risk assessment for, and control of, the trash rake cleaning activity by the maintenance department; and (3) a failure to fully complete the corrective actions following a similar event in 1989.
SERT recommended the following short term corrective actions:
(1) cleaning the trash racks and river bottom, as necessary, to restore the operability of the cw system (completed); (2) repair of the CW trash rake to enable it to extend and clean the entire length of the trash racks (completed), and (3) the repair of other miscellaneous equipment issues (completed).
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Other SERT's Long term recommendations relative to the overhaul or replacement of the entire cw trash rake and rack system, is being evaluated by PSE&G management.
The development of enhanced CW System operating and work practices to prevent recurrence is being considered, and a work standard will be incorporated into the work order system to address the recommended cleaning and inspection techniques.
This standard will be in place by the next scheduled refueling outage (lRll).
EVENT Unit 1 Reactor Trip Due to Main Feedwater Isolation On july 11, 1993, while performing surveillance procedure Sl.OP-ST.SSP-OOlO(Q), "Engineered Safety Feature Solid State Protection System (SSPS) Slave Relay Test - Train B, 11 *it was determined that the relay which controls main feedwater isolation for the No. 13 and 14 steam generators was inoperable.
While the repairs to the relay were being performed, the main feedwater regulating valve for the No. 14 steam generator inadvertently went closed, resulting in the water level in that steam generator
- dropping to a level sufficient to cause an automatic reactor trip.
ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS PSE&G's investigation determined that the cause of the reactor trip was the closure of the 14 steam generator f eedwater regulating valve (14BF19).
The 14BF19 closure resulted when a technician lifted an improper lead, while repairing a Solid State Protection System (SSPS) relay, causing the feedwater isolation of the No. 14 steam generator.
Additionally, the investigation revealed that inadequate procedural detail and supervisory direction in the SSPS troubleshooting plan contributed to the technician error.
Corrective actions completed involved: (1) a procedural revision, requirin*g additional supervisory concurrence for future troubleshooting activities to be performed at the Salem station and (2) a review of the lessons learned from the event with all appropriate maintenance personnel.
EVENT Unusual Event Declared as a Result of Inadvertent Ammonia Release On July 10, 1993, while on a routine tour of the Turbine Building, the Unit 1 nuclear shift supervisor-(NSS) encountered ammonia fumes in the Unit 1 turbine building, 100-foot elevation (ground level).
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ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS PSE&G's investigation determined that the ammonia hydroxide storage tank loop seal was lost, resulting in the ammonia gas
_release.
The loop seal was lost (blown out)-by a pressure build-up in the tank as a result of higher than normal ambient temperatures (outside air temperatures exceeded 100°F during the three days prior to the release)~
Ammonia hydroxide (27% by weight ammonia hydroxide solution) was stored in the on site storage tank.
The storage tank is normally pr~ssurized with a 2 to 3 psig nitrogen cover gas, which raises the boiling temperature in the tank.
However, during this period of high temperatures, the bulk temperature of the Ammonia Hydroxide increased, thus increasing the internal tank pressure to the point where the loop seal was lost.
Short term corrective actions taken included: (1) restoration of the the loop seal; (2) ventilating the turbine building; and (3) dilution of the ammonia hydroxide in the storage tank.
The long term corrective action is to reduce the stored ammonia hydroxide concentration to 15% during the summer months.
The 15%
solution has a boiling point of 136°F, therefore minimizing the risk of boiling due to high ambient temperatures.
At other times when ambient temperatures are not as high, 27.5% ammonia hydroxide may be stored in the tank.
Additionally, the loop seal design (adequacy) is.being re-evaluated by Engineering and Plant Betterment (E&PB).
EVENT Service Water Intake Inspections On June a, 1993, divers assigned to perform silt inspections at the Salem service water (SW) intake structure entered the wrong pump bay.
The work order summary described the work as "No. 11 through 16 SW pump; bay silt level inspection," although the specific work order activity, for the work being performed, called for an inspection of the No. 11 SW pump bay.
Divers erroneously dove into the No. 16-SW pump bay, instead of the No.
11 SW bay.
While preparing to tagout the No. 16 SW pump for inspection, the maintenance supervisor realized the error, promptly stopped work and informed the senior shift supervisor.
ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS The maintenance supervisor performed a tagout reverification of the No. 11 SW pump and passed the work order.to PSE&G mechanics.
The mechanics were assigned to assist the divers in moving equipment from bay to bay.
Neither the mechanics nor the divers verified that the proper SW bay was entered according to tags hanging.
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PSE&G's investigation into this event found that this event was actually caused by poor communication practices, inattention to detail and inadequate tagout verification.
(No. 11 SW pump was properly tagged out, however the divers entered the wrong SW bay.)
As a short term corrective action, the maintenance engineer and senior maintenance supervisor met with the owner of the diving company to explain the severity of the incident and plan appropriate correction action.
All employees of the diving contractor were given notice of the incident and additional tagout verification training.
Additionally, a procedure change request was submitted to SC.MD-GP.SW-0001, "Service Water Silt Survey."
The revision request is to add a precaution to ensure that the divers verify proper tagging and enter the correct SW bay.
This incident was reviewed with the Maintenance Department at the June 1993 safety meeting.
EVENT Trip of the lC Vital Bus On June 9, 1993, the lC vital bus sensed an undervoltage condition, which resulted in an automatic start and blackout loading of the lC emergency diesel generator (EDG).
At the time of the event, maintenance personnel were conducting a monthly functional surveillance test of the lC 4 KV vital bus.
This test was being conducted in accordance with procedure Sl.MD-FT.4KV-0003, "Engineered Safety Feature Actuation System Instrumentation Monthly Functional Test lC 4 KV Vital Bus Undervoltage."
While securing from this monthly surveillance test, the technician inadvertently mispositioned a test switch, thus satisfying the logic for single vital bus undervoltage.
The EOG started, loaded, and re-energized the lC vital bus per design.
ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS PSE&G's investigation found that the root cause of this event was personnel error and inattention to detail.
The maintenance technician did not self ~check as required by station work practices.
This event was reviewed with applicable personnel, and positive disciplinary action was implemented with the technician involved.
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EVENT 2R15 Radiation Monitoring system Inoperability On July 7, 1993, the 2R15 monitor was removed from service due to water accumulation in the sampling line.
The 2R15 channel (Condenser Off-Gas) is used to provide early indication of a primary to secondary leak in a steam generator.
In the event of a leak in any steam generator with the 2R15 channel inoperable, the 2R19 (steam generator blowdown process monitor), 2R40 (condensate process filter monitor), and 2R46 (main steamline process monitor) would provide indication for the identification and mitigation of the leak.
ROOT CAUSE DETERMINATION AND CORRECTIVE ACTIONS PSE&G's investigation determined that stuck open condenser shell ball check float valves allowed water to carry over to the condenser waterbox priming tank.
Additionally, it was determined that silt and scale, which carried over with the water from the condenser waterboxes, caused priming tank drainline blockage.
Therefore, as the vacuum pumps remove entrained air from this priming tank and discharge it past the 2R15 sample line to the exhaust stack, water will collect in the 2Rl5 line.
The root cause is attributed to inadequate design; causing the ball check valves to stick open due to the accumulation of river debris.
Short term corrective actions taken included draining the 2R15 sample line and replacing the sample filter.
addition, the priming tank drain line, the ball check valves and the priming tank have been cleaned.
and drying In float The long term corrective action planned is to install a new loop seal and remove the check float valves.
A design change package (DCP) had been initiated (prior to the July event) to prevent water carryover.
This modification is presently scheduled for the fall of 1993 for Unit 1 and for the fall of 1994 for Unit 2.
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