IR 05000373/1999004
| ML20209F708 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 07/13/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20209F698 | List: |
| References | |
| 50-373-99-04, 50-373-99-4, 50-374-99-04, 50-374-99-4, NUDOCS 9907160108 | |
| Download: ML20209F708 (19) | |
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l U.S. NUCLEAR REGULATORY COMMISSION i
j REGION 111 l
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Docket Nos:
50-373,50-374 License Nos:
Report No:
50-373/99004(DRP); 50-374/99004(DRP)
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Licensee:
Commonwealth Edison Company
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l Facility:
LaSalle County Station, Units 1 and 2 Location:
2601 N. 21st Road l
Marseilles,IL 61341 l
Dates:
May 13 - June 22,1999 l
Inspectors:
K. Riemer, Acting Senior Resident inspector i
J. Hansen, Resident inspector R. Westberg, Acting Resident inspector Approved by:
Melvyn N. Leach, Chief i
Reactor Projects Branch 2 r
Division of Reactor Projects
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t 9907160108 990713 PDR ADOCK 05000373 G
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EXECUTIVE SUMMARY a
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LaSalle County Station, Units 1 and 2 l-NRC Inspection Report 50-373/99004(DRP); 50-374/99004(DRP)
~ This inspection report included aspects of licensee operations, maintenance, engineering and plant support. The report covers a 6-week period of inspection conducted by the resident staff.
Plant Operations
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The operators adequately implemented the station out-of-service procedure. The
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licensee's Nuclear Oversight department performed a satisfactory audit of the I
out-of-service program and identified a potential weakness with several long-standing l
out-of-service checklists (Section 01.1).
Operators and nuclear engineering personnel appropriately managed an identified fuel
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bundle leak. Appropriate standing orders and operating instructions were generated for, and understood by, the control room operating crews. The leak was below Technical Specification limits (Section O2.1).
A configuratia control event occurred due to the failure to update electronic data bases
following modification completion. The event itself held minor safety significance (Section O2.2).
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l The unexpected and repeated cycling of the Unit 2 "D" Suppression Chamber to Drywell
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vacuum breaker presented a burden to control room operators (Section O2.3).
l A non-licensed operator demonstrated a good questioning attitude during the conduct of
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rounds; the follow-up of the electro-hydraulic control system fluid leak enabled the licensee to identify a deficient procedure (Section C3.1).
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Weak procedural controls associated with valve pose.as resulted in an improperly
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configured valve. A procedure change request had been initiated but not acted upon to l
correct the deficiency. This item was similar to a prior, NRC identified, procedural l
Inadequacy documented in Inspection Report 99003, Section 01.2 (Section O3.1).
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Overall operator performar.ce was good and operators generally conducted activities in
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the main control room appropriately and safely. Shift tumovers were formal, panel walkdowns were thorough, and operators' attentiveness and communications were good (Section O4.1).
In some instances, however, operators did not consistently adhere to management
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expectations. Operators were inconsistent in announcing alarm checks and in one
- instance, did not adhere to station expectations for the conduct of heightened level of awareness briefings (Section O4.1).
Multiple challenges to operators occurred during the inspection period as a result of
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human performance weaknesses outside of the Operations department. The challenges were self-revealing and the ormtem appropriately respondea to these challenges (Section 04.2).
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The operator performing walkdowns of the standby gas treatment system demonstrated good attention to detail and good operating practices as evidenced by the identification of a rag in the system cubicle (Section M4.3).
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Maintenance
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Troubleshooting activities associated with loss of the Division 3 battery and charger.
indication were not effectively implemented by station personnel. These effods failed to determine the root cause of failure and the original problem recurred. Other examples of troubleshooting inefficiencies are discussed in Sections E4.2 and M4.4
- (Section M4.1).
- Maintenance depadment personnel performed well during the conduct of a sc! eduled
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high risk activity; The pre-job brief was thorough and contained pertinent information for the task. Supervisory oversight in the field was effective and contributed to the successful completion of the task (Section M4.2).
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Licensee maintenance activities associated with work on the safety-related Standby Gas Treatment System did not adequately control foreign material and prevent its entry into the system.' Consequently, the system was inoperable for a time period longer than nececsary (Section M4.3).
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Licensee troubleshooting activities directly impacted annunciators associated with the reactor water cleanup system which presented an unnecessary challenge to the operators. Other examples of troubleshooting inefficiencies are diccussed in Sections E4.2 and M4.1 (Gection M4.4).
Due to human performance errors committed during the main condenser cleanings, the
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time that the west waterbox was unavailable was unnecessarily extended during time periods when the east waterbox was potentially susceptible to mussel fouling. As a result, the Unit i reactor's main / normal heat sink was vulnerable to loss for a longer period of time than necessary (Section M4.5).
' Enoineerina The licensee's initial evaluation activities adequately addressed the discrepancies in
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~ bolting arrangements associated with transmitters installed on instruments in the reactor buildings of both units (Section E4.1).
Licensee troubleshooting activities associated with the reactor core isolation cooling
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system were slow to develop. Tne govemor valve was disassembled, inspected, reassembled, and re-installed without finding the root cause of its faile's to control speed.' The root cause of failure was found on the second troubleshooting attempt 3 days after the event. Other examples of troubleshooting inefficiencies are discussed in Sections M4.1 and M4.4 (Section E4.2).
Errors associated with the thermal overload setting for motors in the containment
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cooling system resulted in a system trip. This self-revealing error caused a small increase in containment pressure and presented an unnecessary challenge to control room operators. Prior corrective actions taken to address a similar past problem on
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Unit 1 were narrow in scope and did not address the potential generic application of the original problem (Section E4.3).
Plant Sucoort in general, actions taken by the licensee were adequate to protect personnel from a
radiological hazards (Section R1.1).
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Report Details Summarv of Plant Status During this inspection period, the licensee maintained Unit 1 operating at near full power except
.for scheduled down power evolutions to support condenser cleaning activities. Unit 2 remained operating near full power for the inspection period.
l. Operations 01-Conduct of Operations 01.1 Out of Service Prooram Implementation a.
InsMdion Scooe (717071 -
The inspectors interviewed Operations, Engineering, and Nuclear Oversight personnel to assess implementation of the out-of-service program and to assess adherence to procedural requirements and management expectations. Additionally, the inspectors l
reviewed the Updated Final Safety Analysis Report (UFSAR), Section 5.4.7, " Residual l
Heat Removal System"; LaSalle Administrative Procedure (LAP)-900-04, " Station Out-Of-Service." Revision 5; and Nuclear Oversight Assessment (NOA) 01-99-023, i
"Out-Of-Service Program."
b.
Observations and Findinas
The in,pectors identified several long-standing tagouts established in the reactor buildings of both units. Specifically, tagouts were in place to administratively control the status of some abandoned equipment such as the steam conde sing mode of the residual heat removal system. The inspectors verified that the UFSAR documented the steam condensing mode of the residual heat removal system as " abandoned in place."
The inspectors noted that the station Nuclear Oversight department had previously j
performed an assessment (Nuclear Oversight Assessment NOA 01-99-023) of the i
out-of-service program and identified that a number of out of service checklists had been in place for extended periods uf time, with some established for equipment abandoned in place. The licensee incorporated the Nuclear Oversight assessment observations into the corrective action program.
c.
Conclusions The operators adequately implemented the station out-of-service procedure. The licensee's Nuclear Oversight department performed a satisfactory audit of the out-of-service program and identified a potential weakness with several long-standing out-of-service checklists.
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Operational Status of Facilities and Equipment O2.1 Unit 1 Fuel Assembly Leak a.
Insoection Scope (71707)
1 The inspectors monitored operator response to, and management of, a fuel leak identified in the Unit 1 core.
b.
Observations'and Findinas Operators identified a fuel bundle leak in March 1999 (see Inspection Report 99002, Section E2.1). To minimize further degradation of the leaking bundle, operators inserted three control rods near the leaking bundle to suppress the flux around the 1 bundle.1 Operations management issued standing orders that delineated operating instructions for Unit 1 which contained increased monitoring requirements and operating limitations to address the fuel leak. In May 1999, operators noted an increasing trend in coolant and off gas activity levels. Nuclear engineers evaluated the data and concluded that insertion of a fourth control rod around the leaking bundle would reduce the coolant and off gas levels and minimize the potential for further degradation of the leaking fuel assembly. On May 22,1999, the operators performed a control rod pattem adjustment and inserted the fourth control rod around the suspect fuel bundle. Additionally, nuclear engineers provided the operating department with guidance to modify certain operating practices in order to minimize further fuel bundle degradation; The inspectom verified that operators were aware of the increased monitoring requirements. The inspectors determined that the new restrictions placed on operating practices were being implemented.
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Conclusions Operators and nuclear engineering personnel appropriately managed an identfied fuel bundle leak. Appropriate standing orders and operating instructions were generated for,
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and understood by, the control room operating crews. The leak was below Technical Specification limits..
O2.2 Confiauration Control Error a.
Inspection Scooe (71707)
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The inspectors reviewed the licensee's response to a training department-identified configuration control error associated with the standby gas treatment system fire
' protection system. The inspectors reviewed proble,; Mentification form (PlF)
L1999-02937.
b.
Observations anri Findinas On June 7,1999, a member of the training department performing system walkdowns with a license requalification class identified that valve 2FP053 (fire prctection deluge
. valve for Unit 2 standby gas treatment system) was not in the proper position. The valve was in the locked closed position rather than the (required) locked open position.
The individual contacted the Operations department field supervisor who verified the
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valve's proper position per the mechanical checklist and had the valve returned to the correct position. The mispositioned valve did not impact any safety-related equipment.
The licensee documented the occurrence via PlF L1999-02937 and initiated an accelerated investigation. The licensee determined that the valve's normal position had '
~ historically been locked closed. The licensee performed a modification during the previous refueling oblage that changed its normal position from locked closed to locked open when additional valves were installed downstream of the valve. Following completion of the modification, the valve's new required position had been updated in j
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the mechanical system checklist procedure but was not updated in the electronic work control system data base. Operators had recently established an out-of-service on the valve to complete scheduled repairs. When operators cleared th(; out-of-service on May 27,1999, the electronic work control system data base was used to establish the valve position. Since the data base had not been updated, the incorrect information was utilized to restore the valve to its required position.
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Conclusions A configuration control event occurred due to the failure to update electronic data bases following modification completion. The event itself held minor safety significance.
O2.3 Drvwell Vacuum Breaker Cyclina (Unit 2)
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a.
Insnadion Scooe (71707)
The inspectors reviewed the circumstances surrounding, and the licensee's response to, the unexpected cycling of the Unit 2 "D" suppression chamber to drywell vacuum breaker, b.
Observations and Findinos On June 17,1999, the Unit 2 "D" suppression chamber to drywell vacuum breaker unexpectedly cycled open, then shut. The licensee called in the event to the NRC Operations Center as an engineered se4ty feature actuation. The vacuum breaker cycled open P iin on June 18,1999, are operators again reported the event to the NRC Operatir.s Center. The licensee subsequently reviewed the reportability requirement, and retracted the notifications on June 22,1999. The vacuum breaker unexpectedly cycled three more times on June 18, June 19, and June 21,1999. The lit;ensee was stillinvestigating the events at the end of the inspection period. The inspectors will review the evsnt notification retraction, and station troubleshooting efforts, as part of the core inspections activities during the subsequent inspection period.
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Conclusions The unexpected and repeated cycling of the Unit 2 "D" Suppression Chamber to Drywell
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vacuum breaker presented a burden to control room operators.
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Operations Procedures and Docuenentation 03.1 Electro-Hvdraulic Control Valve Misaliunment
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Insoection Scope (71707)
The inspectors reviewed the circumstances associated with a valve misalignment in the Electro-Hydraulic Control (EHC) system. The inspectors assessed the similarities between this event and a similar NRC identified procedural inadequacy documented in Inspection Report 99003. The inspectors reviewed PlF L1999-02674 and the system operating precedure LOP-EH-06,"Startup and Operation of Fullers Earth Filtering Unit (EHC System)," Revision 7.
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Observations and Findinas On May 22,1999, a non-licensed operator identified a decreasing trend in the Unit 1
' EHC tank level. The operator's follow up inspection identified that the EHC fluid filtering pump had a seal leak of approximately one drop per second. The operator informed the field supervisor and isolated the leak by shutting the pump's suction valve.
The licensee documented the occurrence via PIF L1999-02674. The initial review by
- the licensee identified that the suction valve, which was found open by the operator, was requiisd to be in the closed position. The prints and <hecklist required the valve to be closed. The licensee subsequently determined that the operating procedure that govemed this system lacked clear guidance on controlling the valve's position.
Specifically, the procedure directed the opening of the suction valve, but did not provide
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guidance on valve closure upon system shutdown. The lack of clear procedural j
guidance was similar to NRC concems with procedural adequacy documented in Inspection Report 99003. Additionally, the licensee identified that a procedure change i
request (PCR) had been previously initiated for this procedure to clarify operating instructions conceming the required valve position but the PCR had not been implemented. This was similar to a violation issued in the previous inspection report for an instance where a control room annunciator response procedure was incorrect because a PCR had not been adequately resolved in a timely fashion. A violation is not
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being issued for this matter because the event was associated with a nonsafety-related system; additionally the NRC considers that not enough time had occurred since the prior report issuance for the licensee to fully implement corrective actions for the earlier
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Conclusions A non-licensed operator demonstrated a good questioning attitude during the conduct of
. rounds; the follow-up of the electro-hydraulic control system fluid leak enabled the licensee to loentify a deficient procedure.
. Weak procedural controls associated with valve positions resulted in an improperly configured valve. A procedure change request had been initiated but not acted upon to correct the deficiency. This item was similar to a prior, NRC identified, procedural inadequacy documented in inspection Report 99003, Section 01.2.
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04-Operator Knowledge and Performence (71707)
04.1 Operations Deoartment Standards and Exoectations a.
Inspection Scope (71707)
The inspectors monitored operator adherence to management standards and expectations during the conduct of routine control room activities. The inspectors also reviewed CWPI-NSP-OP-1-1, " Operations Department Standards," Revision 1.
b.
QWrvations and Findinas in inspectors observed operator performance during the conduct of heightened level of awareness briefings and during routine control room activities including panel monitoring and annunciator response. Operators generally adhered to licensee management expectations during the cond# of routine operations. The crews practiced three-way communications, hu.o productive tumover meetings, and maintained clear logs. The inspectors observed that the operators correctly referenced procedures. The licensee staff maintained a quiet and orderly control room, even when extra personnel were present in the control room. The inspectors observed good command and control by the supervisory staff. The inspectors noted, however, inconsistencies between some of the operating crews with respect to announcing control room alarms. The inconsistency was most pronounced during the conduct of panel alarm checks. Some crews informed the unit supervisor about the alarm checks prior to performing the test. Other crews did not always announce the test to the unit supervisor prior to the performance of the check, nor did the unit supervisor require the operators to do so. The inspectors discussed the matter with operations management.
Operations management subsequently issued a night order to the operating crews restating management expectations with respect to annunciator response. -The inspectors noted that the operators consistently announced control room alarms and alarm checks after the night order was issued.
The inspectors also noted a heightened-level-of-awareness briefing that was not conducted per management expectations. On May 20,1999, the inspectors observed the briefing conducted prior to performing a test of Volt-Amperes Reactive loading to demonstrate generator loading capability for summer readiness. The briefing was very comprehensive and involved thorough discussion among all the participants. The inspectors noted, however, that the control room operator who would actually be in charge of the control panels during the test was, not present for the brief. When the inspectors questioned the operator about the test, the operator was very knowledgeable about the test and demonstrated a complete understanding of what the test entailed. As a result, the inspectors did not have any safety concems with the conduct of this specific test. The inspectors considered the conduct of the brief without all involved personnel present to be a potential weakness. Operations management stated that this did not meet station expectations for the conduct of heightened-level-of-awareness briefings.
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Concluelons
~ Overall operator performance was good and operators generally conducted activities in the main control room appropriately and safely. Shift tumovers were formal, panel
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walkdowns were thorough, and operators' attentiveness and communications were good.-
In some instances, however, operators did not consistently adhere to management expectations. Operators were inconsistent in announcing alarm checks and in one instance did not adhere to station expectations for the conduct of heightened level of awareness briefings.
04.2-Challenoes to Main Control Room Ooerators a.
Inspection Scone (71707)
l The inspectors reviewod the circumstances surrounding several challenges to event free I
plant operations. The inspectors assessed the causes of the events and their impact on
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control room operators.
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Observations and Findinas During the inspection period, control room operators encountered several challenges to event-free operations. The impact to the operators resulted from human performance weaknesses which occurred during the performance of maintenance and engineering
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The repetitive failure of the Division 3 battery and charger indication power
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supply (see Section M4,1).
The troubleshooting of the Unit 2 leak detection system which resulted in a
125Vdc ground alarm and other miscellaneous alarms (see Section M4.4).
The unexpected partial reactor protection system actuation while performing
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surveillance testing on the Unit 2 Recirculation Flow Converter 2D (see Section M4.6).
j The Unit 2 containment cooling system trip due to incorrect thermal overload
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settings (see Section E4.3).
The inspectors verified that control room operators were knowledgeable on tIie plant syst_ ems and responded to the above events in accordance with approved procedures.
In addition, the inspectors noted that the operators documented the above events in the appropriate logs and entered these events into the corrective action program.
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Conclusions
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' Multiple challenges to operators occurred during the inspection period as a result of human performance weaknesses outside of the Operations Department. The challenges were self-revealing and the operators appropriately responded to these challenges.
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.A ikMpintenance M4 Maintenance Staff Knowledge and Performance M4.1 Loss of Hiah Pressure Core Sorav (HPCS) 125Vdc Amoere Indication a.
Inspection Scone (62707)
The inspectort :aviewed licensee troubleshooting activities associated with loss of the Division 3 ampere indication. The inspectors also reviewed PlF L1999-03022
. associated with this event, Work Request No. 990064575, and applicable drawings; interviewed involved personnel; and observed installation of the power supply in the field. The inspectors assessed the effectiveness of the troubleshooting efforts and associated impact on plant operations..
b.
Observations and Findinas On June 13,1999, the powe.sr supply for the HPCS 125Vdc'(Division 3) ampere indicatic: failed resulting in the loss of local and control room indications for the battery and charger. Electricians removed the power supply and tested it on the bench in the electrical shop. initially the power supply had no output with a 33 ohm load. After cycling the voltage potentiometer, a 4.8 ohm load was placed on the power supply to load it to its full rated load of 5 amperes. After running the power supply at full load for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, no anomalies were observed and the most probable cause of failure was thought to be dirt on the :,ontacts of the voltage potentiometer. The power supply was re-installed in the plant but failed again a week later. At the end of this inspection period
' the licensee had sent the failed component for refurbishment and investigation.
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Conclusions j
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Troubleshooting activities associated with loss of the Division 3 Battery and Charger
- indication were not effectively implemented by station personnel. These efforts failed to
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determine the root cause of failure and the original problem recurred. Other examples
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of troubleshooting inefficiencies are discussed in Sections E4.2 and M4.4.
I M4.2 Maintenance Department Performance Durina the Conduct of Scheduled Hiah Risk Actnnties a.
Inspection Scope (62707)
On May 25,1999, the inspectors observed the heightened level of awareness briefing for the performance of surveillanca LaSalle Instrument Maintenance (LIS)-NB-4188,
" Unit 2 Reactor Vessel Low Pressure and injection Line Low Pressure RHR B/RHR C
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(LPCI) Injection Valve Open Permissive Functional Test," Revision 8, and observed
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portions of the test in the field.
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Observations and Findinas The heightened-level-of-awareness briefing was thorough and comprehensive; involved personnel discussed the test, contingencies for possible failure scenarios, and past problems encountered during the performance of the test. The maintenance supervisor,
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who had prior experience performing the test, was present in the field. He provided
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technical guidance to the crew performing the surveillance and ensured that the work was conducted as written. The test was completed successfully and operators properly returned the equipment to service, c.
Conclusions Maintenance department personnel performed well during the conduct of a scheduled h~igh risk activity. The pre-job brief was thorough and contained pertinent information for the task. Supervisory oversight in the field was effective and contributed to the successful completion of the task.
M4.3 Foreian Material in the Unit 2 Standby Gas Treatment System Train a.
Inspection Scope (62707)
The inspectors reviewed the circumstances surrounding an instance of licensee foreign material exclusion control dunng the conduct of work on the safety-related standby gas treatment system. The inspectors reviewed PlF L1999-02779.
b.
Observations and Findinos On May'27,1999, during the conduct of an operability surveillance on the standby gas treatment system, an operatoridentified a rap in one of the system cubicles. The surveillance test was being run to verify sys.,m operability following scheduled maintenance on the system. One of the scheduled tasks involved changing the gaskets on the cubicle windows on the system. Following completion of the window gasket replacement task, the mechanical maintenance supervisor performed a foreign material exclusion inspection of the cubicles and then the doors were closed and lockwired shut.
During the performance of the operability test, an operator looked in one of the cubicle windows and identified a rag inside.
Operators secured from the test and shut down the standby gas treatment system train.
The licensee documented the foreign material concem via PlF L1999-02779 and initiated an accelerated investigation into the matter. The licensee generated a work package to open up and re-inspect all of the system cubicles for foreign material. None was found and the operators subsequently restarted the surveillance test and demonstrated system operability. The system retum to operability was delayed for approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> while the licensee addressed the foreign material concems.
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Conclusiorgi
.The operator performing walkdowns of the Standby Gas Treatment System demonstrated good attention to detail and good operating practices as evidenced by the identification of a rag in the system cubicle.
Licensee maintenance activities associated with work on the safety-related Standby Gas Treatment System did not adequately control foreign material and prevent its entry into the system. Consequently, the system was inoperable for a time period longer than necessary.
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M4.4 Leak Detection System Troubleshootina
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lnsoection Scone (62707) _
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The inspectors reviewed PlF L1999-02778 (ground alarm received during troubleshooting), control room logs for May 27,1999, and the licensee response to a
- self-revealing weaknesses identified during the conduct of troubleshooting on the Unit 2
' Leak Detection system.
> b.
Observations and Findinas On May 27,'1999, control room operators received a Division 2125Vdc ground alarm and other miscellaneous alarms. The operators took appropriate actions to confirm that
. the alarms did not correspond to actual plant conditions. At the time of the alarms,
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' Instrument Maintenance Department personnel were troubleshooting the Unit 2 Leak
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Detect lon system because of relay chattering problems. Instrument maintenance personnel had just initiated a trip of Reactor Water Cleanup ambient temperature relay per the troubleshooting plan. The instrument maintenance supervisor caserved the system intsraction and, after discussions with the Operations department, had the input to the leak detection module lowered below the setpoint. This cleared the alarms and l-125Vdc ground condition. Instrument maintenance personnel performed a functional test on the leak detectiori module and identified no deficiencies or equipment damage.
Additionally, system engineering personnel performed an operability assessment and determined no operability concems existed for either ths Reactor Water Cleanup or the Unit 2, Division 2,125Vdc system.
L The licensee determined that the apparent cause of the spurious alarms was due to an ~
f unknown characteristic of the test recorder used for troubleshooting. The recorder's
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negative leads on the digital input modules were tied together intemally.- This paralleled L
the 120Vac power supply of the leak detection module with the power supply of the annunciator circuit, which was supplied by the Unit 2, Division 2,125Vdc circuit.
Additional corrective actions for this event included completion of a training request to l
document information relative to the recorder's input characteristics, briefing of the other operating crews, a tailgate session on this event with all instrument maintenance personnel, and an evaluation of the need to add to the troubleshooting procedure a requirement for independent technical reviews of troubleshooting plans.
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Conclusions Licensee troubleshooting activities directly impacted annunciators associated with the reactor water cleanup system which presented an unnecessary challenge to the i operators. Other examples of troubleshooting inefficiencies are discussed in Sections E4.2 and M4.1.
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' M4.5 Main Condenser Waterbox Manway Leaks Followina Condensor Cleanina a.
Insoection Scope (62707)
The inspectors reviewed the circumstances associated with leaks from a main i
condenser manway following condenser cleaning activities. The inspectors reviewed
' PIFs L1999-02923 and L1999-03118.
b.
Observations and Findinas On June 6, Jua 13, and June 20,1999, the licensee completed cleaning evolutions on the Unit 1 main condenser waterbox. The licensee performed the cleaning evolutions to
. remove Zebra mussels from the Unit 1 condenser. Following the June 6 and June 20,
' 1999 cleanings, leakage occurred from the west lower outlet manway. Specifically, on
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June 6,1999, following the condenser cleaning, the licensee attempted to retum the waterbox to service and a leak occurred at the lower manway of the condenser.
'i Approximately 30,000 gallons of water spilled to the condenser pit floor. Operators and maintenance personnel successfully stopped the leak and re-isolated the waterbox for repairs. Following repairs to the manway, the operators attempted to place the waterbox back in service and a second leak occurred. The leak was mucn lower in severity (approximately thirty to 40 gallons per minute) and operators re-isolated the I
waterbox. Following repairs, the operators successfully placed the condenser back in
. service. The licensee documented the lower manway waterbox leaks via
. PlF L1999-02923. Subsequent to the June 20,1999, condenser cleaning, the licensee again experienced leakage through the west lower manway. The leak was approximately 9,000 gallons and operators isolated the waterbox for repairs.
Maintenance personnel repaired the manway and operators successfully returned the i
condenser to service. The licensee documented the leakage via PIF L1999-03118. The licensee identified that the decision to utilize a gasket, made of a material that had
. previously failed, was the main contributor to the leak.
While the maintenance activities and leaks occurred on nonsafety-related equipment, the events provided multiple, unnecessary challenges to the operators. The time that the waterbox was unavailable to the operators was extended and the operators were required to respond to the leaks and the need to reestablish maintenance boundaries.
In addition to operating the plant in an off-normal configuration longer than necessary, the operators had modified scram procedure contingencies in place during the time that the condenser was in a half-operation condition for cleaning. The operators received
"just-in-time" training for the evolution and had written guidance readily available for scram response. However, the amount of time that the operators spent in a condition that would have required a transient response that deviated from their normal training was unnecessarily extended due to the difficulties encountered in expeditiously returning
~ the condenser to a normallineup.
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' Conclusi$ns Due to human performance errors committed during the main condenser cleanings, the time that the west waterbox was unavailable was unnecessarily extended during time periods when the east waterbox was potentially susceptible to mussel fouling. As a result, the Unit i reactor's maln/ normal heat sink was vulnerable to loss for a longer
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M4.6 Unexoected Partial Reactor Protection System Actuation While Performina Surveillance Testing a.
Lrispection Scoce (62707)
The inspectors reviewed the circumstances associated with an unexpected partial
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reactor protection system actuation that occurred during the performance of surveillance i
testing. The inspectors reviewed LIS-RR-201D," Unit 2 Recirculation Flow Converter
"D" Calibration," Revision 1, and PlF L1999-03114.
b.
Observations and Findinas i
On June 18,1999, maintenance personnel performed LIS-RR-201D. During the performance of the testing, operators received an unexpected partial actuation of the reactor protection system. Plant personnel retumed the equipment to a safe condition, reset the reactor protection system, and documented the occurrence via PlF L1999-03114. The licensee also initiated an accelerated investigation to determine the cause of the event. The licensee's initialinvestigation results suggested that a typographical error in the procedure, combined with personnel error, contribut' d to the e
event. At the end of the inspection period the licensee was still investigating the matter.
Pending inspector review of the event, and review of the licensee's investigation, this matter is an Unresolved item (50-373/99004-01(DRP); 50-374/99004-01(DRP)).
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Ill. Enaineerina l
E4 Engineering Staff Knowledge and Performance E4.1 Transmitter Boltina Discreoancies
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a.
Insoection Scope (37551)
l The inspectors reviewed the licensce's evaluation of inspector-identified discrepancies relating to botting of instrument transmitters to instrument racks in the plant.
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b.
Observations and Findinas On May 28,1999, the inspectors identified discrepancies in the bolting arrangements for various transmitters installed on instrument racks in the reactor buildings of both units.
l Some of the transmitters were bolted to the racks with safety grade bolts, others were bolted to instrument racks with common steel bolts, and others were attached with screws to the instrument racks. The licensee initiated an investigation into this issue and identified two transmitters with only three mounting screws instead of the required four mounting bolts. The licensee documented the issue via PIF L1999-02896. The licensee's initial calculations showed that sufficient margin existed in this configuration even with three mounting screws instead of four bolts. Action requests were initiated to instail four mounting bolts on the affected transmitters. At the end of the inspection period, the licensee was still evaluating the extent of condition of the transmitter mounting arrangement discrepancies. Pending further investigation by the licensee of the extent of these discrepancies, this item is considered an Unresolved item (URI) 50-373/374-99004-02.
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c.
Conclusions The licensee's initial evaluation activities adequately addressed the discrepancies in bolting arrangements associated with transmitters installed on instruments in the reactor buildings of both units.
E4.2 Reactor Core Isolation Coolina System Govemor Problems ac Insoection Scope (37551)
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The inspectors reviewed the licensee's troubleshooting efforts in response to flow control problems associated with the reactor core isolation cooling system governor.
The inspectors reviewed the following items and documents:
LaSalle operating procedure (LOS) LOS-RI-Q5, ' Reactor Core isolation Cooling
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. (RCIC) System Pump Operability, Valve Inservice Tests in Conditions 1, 2, 3 and Cold Quick Start" PIF L1999-02941
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Work Requests Nos. 990061817-01,990061817-02, and 990061817-03
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The licensee's formal troubleshooting plan and critique of the 2E51-F361
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(govemor valve) maintenance in addition, the inspectors attended the troubleshooting meeting on June 9,1999.
b.
- Observations and Findinas On June 7,1999, while performing surveillance test LOS-RI-Q5, the RCIC governor
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. valve operated properly in bringing the turbine up to the required rated speed and flow.
However, the govemor valve would not respond to flow demand changes from the flow controller. After unsuccessful attempts to adjust the flow controller, the licensee declared the RCIC system inoperable.
Readings taken by instrument maintenance personnel during the surveillance test indicated that the controller was attempting to control speed. After personnel adjusted the govemor, there was still no response frcm the system. Two hours into the surveillance, the RCIC turbine was shut down and operators noted a dual indication on the govemor valve's control room position indicator. This condition had not been observed previously.
On June 8,1999,' after instrument maintenance personnel verified that the observed problems were not electronic in nature, the licensee decided to disassemble the govemor valve.' The licensee identified no unsatisfactory as-found measurements and noted no binding. One anomalous condition was noted. The spring seat guide bushing appeared to be wom elongated. On June 9,1999, the licensee reosembled the valve and placed it back on the RCIC turbine. In addition, the licensee conducted a troubleshooting meeting to review the troubleshooting plan and results to date, since a i'
root cause for the govemor's failure to control had not been discovered up to that point.
Subsequent to the troubleshooting meeting, a govemor valve expert proposed that an apparent root cause of the event was insufficient clearance in the spring seat bushing.
On June 10,1999, the licensee machined the spring seat and reassembled the govemor valve with new bushings. During post-maintenance testing, the problem with
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dual position indication recurred after the valve was stroked. Engineering personnel subsequently identified that the limit switches i1ad been improperly set because the bracket and roller were out of tolerance. The bracket was adjusted and the limit switches set. On June 11,1999, the RCIC surveillance was completed satisfactorily and the RCIC system declared operable.
c.
Conclusions Licensee troubleshooting activities associated with the reactor core isolation cooling system were not timely. The governor valve was disassembled, inspected, reassembled, and re-installed without finding the root cause of the valve problems. The -
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root cause was subsequently determined after consultation with an industry expert 3 days after the event. Other examples of troubleshooting inefficiencies are discussed in Sections M4.1 and M4.4.
E4.3 Containment Coolina System Trio Due to incorrect Thermal Overload Settina
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a.
Inspection Scope (37551)
The inspectors reviewed PlF L1999-03008, plant operating logs and the licensee's root cause evaluation relating to a trip of the containment cooling system. The system engineer for Primary Containment Ventilation (VP) system was interviewed regarding this event.
b.
Observations and Findinas f
On June 10,1999, the breaker for the 28 Drywell Chiller Water Pump, 2VP01PB tripped while the "A" loop was unavailable due to scheduled maintenance. As a result, both the 2B and 2C chillers tripped on low chilled water flow. Operators started the 2VP01CA pump and aligned the 2C chiller on the "A" chilled water loop. The 2C chiller is a partial capacity chiller which helped to maintain containment temperature and pressure. The operators then cross-tied the 2B chiller to the A" chilled water loop. These operations took approximately 45 minutes. The maximum temperatures reached in the retum air plenum were 108"F to 114*F (TS limit 135'F). The maximum containment pressure reached was approximately 0.46 psi (TS limit 1.69 psi; plant ad.Tiinistrative limit 0.7 psi).
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The licensee determined that the cause of the 2B pump trip was due to incorrect settings of the motor's thermal overload heaters. An identical trip had occurred on Unit 1 in December of 1998 and the drawings for both units were updated by Drawing Change Request 9900136. However, the settings on the 2B breaker were never verified
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to be correct. The thermal overload heaters were subsequently set via temporary Work Request No. 99-00, and the system was restored to its original lineup.
c.
Conclusions Errors associated with the thermal overload setting for motors in the containment cooling system resulted in a system trip. This self-revealing error caused a small increase in containment pressure and presented an unnecessary challenge to control room operators. Prior corrective actions taken to address a similar past problem on Unit 1 were narrow in scope and did not address the potential generic application of the original problem.
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IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Radiation Protection Obsen/ations a.
Inspection Scope (37551)
The inspectors reviewed radiation protection activities and observed performance in support of routine activities.
b.
Observations and Findinas Radiological control personnel performed duties in accordance with procedures. The technicians supported plant maintenance activities on several higher dose jobs such as heater bay entries and condenser work during scheduled plant down power evolutions.
The technicians were knowledgeable of area dose ra'ss and activities which could affect radiological conditions.
c.
Conclusion *
In general, actions taken by the licensee were adequate to protect personnel from-radiological hazards.
V. Manaaement Meetinas X1 Exit Meeting Summary
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The inspectors presented the results of these inspections to licensee management listed below at an exit meeting on June 22,1999. The licensee acknowledged the findings presented. The
' inspectors asked the licensee if any materials examined during the inspection should be considered proprietary. The licensee identified none.
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PARTIAL LIST OF PERSONS CONTACTED Licensee
'*. S. Barrett, Maintenance Manager
- J. Benjamin, Site Vice President
- C. Berry, Chief of Staff
. J. Bums, Chemistry Supervisor
. C. Crane,'Vice President, BWR Operations
- D. Farr, Operations Manager
- T. Gierich, Work Control Manager C. Howland, Radiation Protection Manager
- R. Krich, VP Regulatory Services o *M. Lohmann, Site Engineering Manager R. McConnaughay, Shift Operations Superintendent
- J. Meister, Engineering Manager T. O'Connor, Plant Manager *
R. Palmieri, System Engineering Manager K. Poling, Work Control Manager
- W. Riffer, Q & SA Manager
- F, Spangenberg, Regulatory Assurance Manager R. Stachniak, Nuclear Oversight Assessment Manager
- R. Varju, Chemistry -
- Present at exit meeting on June 22,1999.
INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering
- IP 62707:
Maintenance Observation
- IP 71707:.
Plant Operations IP 92700:
Onsite Follow-up of Written Reports of Nonroutine Events IP 92901:
Follow up - Plant Operations IP 92902:
Follow up - Maintenance IP 92903:
Follow up - Engineering ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50-373/374-99004-01 URI unexpected half scram 50-373/374-99004-02 URI transmitter bolting discrepancies -
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Closed None Discussed None
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