IR 05000321/1993020
| ML20059K726 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 10/21/1993 |
| From: | Christnot E, Holbrook B, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059K712 | List: |
| References | |
| 50-321-93-20, 50-366-93-20, NUDOCS 9311160165 | |
| Download: ML20059K726 (16) | |
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UfdlTED STATES
/gareh NUCLEAR REGULATORY. COMMISSION D/9-4 REGloN 11
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E 101 MARtETTA STREET. N.W., SUITE 2900
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- j ATLANTA, GEORGIA 303234199 l-i
Licensee: Georgia Power Company.
P.O. Box 1295 Birmingham, AL 35201
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Docket Nos.:
50-321 and 50-366 License Nos.: DPR-57 and NPF-5-Facility Name: Hatch Nuclear Plant Inspection-Conducted:
September 5 - October 2, 1993 Inspectors: [/f4 /
/4////?3 p Ledna g Wert, Jr., Sr. Resident Inspector Date Signed
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/()l/E NS
% ' Edward ~ F/Christnot, Resident Inspector Date Signed k
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b lYV3 pBob. Ho"ly Resf dent Inspector Datg Sidned Approved by: ' acic
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Pierce H. Skinner, Chief, Project Section 3B Date Signed Division of Reactor Projects
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SUMMARY Scope:
This routine resident inspection involved inspection on-site in the areas of: operations including review of a loss of annunciators on a CR panel; surveillance testing; maintenance activities including:
review of a mispositioned fire protection valve; review of deficiency cards and significant event reports; modifications to address a solenoid valve problem; and review of open items.
Results: -One NCV was identified:
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The-non-cited violation involved a licensee identified instance of a-f fire protection system valve that was found incorrectly locked
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closed.
It was.apparently mispciitioned during surveillance
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activities. Questioning by operations personnel identified the
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problem (NCV 50-321,366/93-20-01: Hispositioned Fire Protection
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System Valve, paragraph 4b).
l During observation of a Unit I power reduction due to a reduced
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condenser vacuum, the inspectors noted good oversight by control e
room supervisors and strong teamwork by all personnel in response to l
the transient'(paragraph 2a).
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i During the inspection period, the licensee performed maintenance
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activities on the High Pressure Coolant Injection (HPCI) systems of
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both units. A small amount of leakage by the steam admission valves
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P 9311160165 931022
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s was corrected throuo's extensive work on the valve internals.
Corrective maintenance has also been performed on the steam line thermal traps. The inspectors noted that the activities were been generally well coordinated and HPCI inoperability was appropriately l
controlled (paragraph 4a).
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c REPORT DETAILS f
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1.
Persons Contacted t
Licensee Employees
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L. Adams, Nuclear Security
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- J. Betsill, Unit 2 Operations Superintendent j
K. Breitenbach, Engineering Support Supervisor
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C. Coggin, Training and Emergency Preparedness Manager i
- S. Curtis, Operations Support Superintendent
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D. Davis, Plant Administration Manager
- K. Dyar, Safety Audit and Engineering Review Supervisor
- P. Fornel, Maintenance Manager
0. Fraser, Safety Audit and Engineering Review Supervisor
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- G. Goode, Engineering Support Manager'
- M. Googe, Outages and Planning Manager
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- S. Grantham, Training and-Emergency Preparedness Supervisor
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J. Hammonds, Regulatory Compliance Supervisor
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- W. Kirkley, Health Physics and Chemistry Manager
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T. Metzler, Nuclear Safety and Compliance
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- C. Moore, Assistant General-Manager - Plant Operations
- J. Payne, Nuclear Safety and Compliance - Engineer
D. Read, Assistant General Manager - Plant Support
P. Roberts, Outages and Planning Supervisor
- K. Robuck,_ Manager, Modifications and Maintenance Support H. Sumner, General Manager - Nuclear Plant
- J. Thompson, Nuclear Security Manager
- S. Tipps, Nuclear Safety and Compliance Manager
- P. Wells, Operations Manager Other licensee employees contacted included technicians, operators, mechanics, security force members and staff personnel.
NRC Resident Inspectors L. Wert
- E. Christnot
- B. Holbrook
- Attended exit interview Acronyms and abbreviations used throughout this report are listed in the last paragraph.
2.
Plant Operations (71707) (92701) (93702)
a.
Operations Status and Observations Unit-1 operated at 100 percent RTP for most of the reporting period.
On September 28, reactor power was reduced to approximately S00 MWe during a loss of condenser vacuum transient. However, the problem was quickly corrected and power was increased to 100 percent RTP within 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />,
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-Unit'2 operated at 85 percent RTP throughout this reporting period.
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Several rods remain fully inserted to suppress neutron flux in the
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area of a suspected fuel leak.
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On September 2, Pete Wells wa's promoted from Unit 1 Operations M
Superintendent to Operations Manager.. He took over-for John Lewis
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who has been assigned to a two year tour with INP0.
L The inspectors reviewed plant operations throughout the reporting l
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period to verify conformance with regulatory requirements, TS, and i
administrative controls. Control room logs,. shift turnover records,
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temporary modification logs, LCO logs and equipment clearance j
records were reviewed routinely. Discussions were conducted with
- i plant operations, maintenance, chemistry, health physics, I&C, and
NSAC personnel.
Activities within the control rooms were monitored routinely.
j Inspections were conducted on day and on night shifts, during
weekdays and on weekends. Observations included control ~ room
.l manning, access control, operator professionalism and attentiveness,
and adherence to procedures.
Instrument readings, recorder traces, j
annunciator alarms, operability of nuclear instrumentation and t
i reactor protection system channels, availability of power sources, I
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and operability of the SPDS were monitored.. Control. Room
'j observations also included ECCS system lineups, containment
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integrity, reactor mode switch position, scram discharge volume
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valve positions, and rod movement controls.
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On September 28, Unit I reduced power to approximately'65 percent RTP due to a decreasing condenser vacuum. The cause of the lowered -
j vacuum was traced to a pressure switch which resulted in a SJAE-a steam supply valve shutting intermittently.
Initially, some offgas j
system and hydrogen injection system indications, along with an '
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erroneous report about circulating water. pump status made' diagnosis difficult. One of the inspectors was in the CR and observed the transient and corrective actions. The inspector noted that'the Unit 1 SS maintained calm oversight during the transient and the operators demonstrated good teamwork in their efforts.
Procedures,
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including alarm response procedures, were appropriately utilized.
While repeat backs or acknowledgements were not.used in'some communications during the event; the' inspector observed that the communications were more formal than communications' observed during previous events. However,. the communications becarae less formal
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after the initial indications of the problem were noted. The licensee determined that procedural requirements established steam supply pressure to the SJAE 'at.145 psig (as read on a local gauge).
This pressure is very near the 140 psig pressure switch setpoint which causes the steam supply valve to go closed. Subsequently, the procedure was changed to increase'the pressure of the steam supply-to approximately 150 psig. This pressure will be maintained until
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L the next refueling outage. During the.next outage the pressure
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- switch will be calibrated and adjusted. Reactor power was increased
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to RTP within 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
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T Several active safety-related equipment clearances were redewed to confirm that they were properly prepared and executed. ni_ * table
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circuit breakers, switches, and valves were walked down to verify i
that clearance tags were in place and legible and that equipment was
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properly positioned. Equipment clearance program requirements are
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specified in licensee procedure 30AC-0PS-001-05, Control of
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Equipment Clearances and Tags. The clearances for HPCI maintenance i
activities were closely examined.
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Selected portions of the containment isolation lineup were reviewed
to confirm that the lineup was correct. The review involved i'
verification of proper valve positioning, verification that motor and air-operated valves were not mechanically blocked and that power
was available (unless blocking or power removal was required), and
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inspection of piping upstream of the valves for leakage or leakage paths.
Plant tours were taken throughout the reporting period on a routine i
basis. The areas toured included the following:
Reactor Buildings Diesel Generator Building Fire Pump Building Central Alarm Station Station Yard Zone Turbine Building Intake Building During the plant tours, ongoing activitics, housekeeping, security, equipment status, and radiation control practices were observed.
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The plant had entered its non-outage work window. The inspectors observed that a significant amount of housekeeping activities (painting and general cleaning), were being conducted. The annual INPO evaluation is scheduled for November. The licensee is implementing several modifications to upgrade overall plant operations. Permanent mounting of the Unit 1 RB chiller units and upgrading of a temporary access passageway through the Unit 1 RB railroad airlock are examples. No significant discrepancies were identified.
b.
Unit 2 Emergency Preparedness Evaluated Exercise On September 15, the licensee conducted its 1993 Emergency Preparedness Evaluated exercise. The simulated emergency included full participation by FEMA, state and local agencies. The Emergency Response facilities, full communications network and the mobilization of resources were initiated. The onsite Emergency
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response organizations and facilities were activated. A normal operating crew used the CR simulator to respond to abnormal and emergency conditions throughout the exercise. The simulated emergency consisted of a withdrawn stuck control rod and subsequent 1000 gpm LOCA. Additionally, a fault and fire on 20 startup
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l transformer was simulated. The scenario contained equipment and component failures and degraded conditions that required the-operating crew to assess plant condition and make emergency notifications. An Alert, SAE and GE were eventually declared as
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required by procedure 73EP-EIP-001-05: Emergency Classifications and
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Initial Actions.
i The inspectors observed and participated in the licensee's
activities associated with the Emergency Exercise. Activities in
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the CR (simulator), OSC, TSC, and EOF were observed. One inspector
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observed the response of the Hatch Nuclear Fire Services to the
transformer fire and concluded that the response was adequate.
Concerns which had been identified during past fire brigade activities were not observed during this drill.
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Partial Loss of Unit 1 Annunciators On September 23, 1993, PM&MS personnel were inspecting aanunciator panel IH11-P654. This panel is a CR back panel and contains slarms-primarily associated with HVAC system A processes and components.
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As the panel was opened the panel was shorted against the casing.
This resulted in grounding of the alarm bus within the panel. All
63 active alarm windows associated with the panel were disabled.
However, the shorting of the annunciator panel did not affect the operation or operability of the various systems that had alarms located on the panel. The loss was immediately recognized and corrective actions were initiated. The SOS and another SR0 performed an evaluation for potential loss of emergency assessment capability. They determined that no significant impact on emergency assessment was present.
The inspectors independently reviewed the actions taken and the
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procedures that were used by the licensee. Procedure 34AB-Hll-001-IS, Loss of Fower to Annunciators-in Main Control Room,.was used by the operating crew in responding to the event. This abnormal operating procedure provides subsequent operator actions based upon
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the classification of-alarms that were lost. The alarms that were lost were classified as B0P annunciators. _ Additionally, the abnormal operating procedure directed the operators to emergency procedure, 73EP-EIP-004-05, Emergency Classification and Initial
Actions, for possible event classification. Section 16.0, Loss of
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Control Room Indications / Alarms / Annunciators, provides guidance as
to when an emergency notification should be declared. The inspectors also observed the panel where the grounding occurred and were briefed by a licensed operator who indicated he was present
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when a similar incident occurred several years ago. The inspectors were informed that, at one time, a warning label concerning the potential grounding issus had been placed next to the panel but was later removed as part of the operator aid program. The licensee initiated a SOR on September 30, in order to better determine the
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full extent of this occurrence. The inspectors concluded from the review and observations that the operating crew used the correct
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procedures following tFe loss of annunciators and performed the correct actions. Thr. impact on emergency assessment was assessed correctly and the crinditions that would warrant emergency event classification and rotification did not exist. The inspectors also
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considered the initiation of the SOR as a strength in the licensee's
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self assessment program.
i No violations or deviations were identified.
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3.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy. The completed tests reviewed were examined for necessary test prerequisites, instructions, acceptance criteria, l
technical content, authorization to begin work, data collection,
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independent verification where required, handling of deficiencies noted,
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and review of completed work. The tests witnessed, in whole or in part, were inspected to determine that approved procedures were available, test equipment was calibrated, prerequisites were met, tests were conducted
according to procedure, test results were acceptable and systems restoration was completed.
i The following surveillances were reviewed and witnessed in whole or in part:
Scram Discharge Volume Level (Thermal Sensors)
FT&C 57CP-CAL-137-1S: Bourdon Tube Style and Bellows Type Pressure Indicators 575V-E11-004-IS:
LPCI Discharge Line Level Instrument FT&C 575V-821-006-2S: Main Steam Line Pressure Instrument FT&C Paragraph 5 of this report contains a discussion of surveillance observations involving the RHR system.
i No violations or deviations were identified.
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4.
Maintenance Activities (62703)
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Maintenance Observations Maintenance activities were soserved and/or reviewed during the reporting period to verify that work was performed by qualified
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personnel and that approved procedures in use adequately described work that was not within the skill of the trade. Activities, procedures, and work requests were examined to verify; proper authorization to begin work, provisions for fire hazards, j
cleanliness, e.<posure control, proper return of equipment to service, and that limiting conditions for operation were me.
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The following maintenance activities were reviewed and witnessed in
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whole or in part:
MWO 1-93-3512: Calibrate Accelerometer IL51-N006 MWO l-93-4341: Repair Fire door latch
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l MWO l-93-4355: MSL Radiation Monitor drifting down MWO 2-93-1915: Recorder 2T48-R601A, Drywell Pressure, not advancing MWO 2-93-3315: HPCI valve 341-F008 indication i
MWO 2-93-1901: RHR Valve 2 Ell-F051A leaking
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MWO 2-92-3554: Replace CR 124 Thermal Overload Relays The inspectors continued to monitor the licensees progress in the replacement of 5 battery cells on the Unit 2 station service j
battery. Additional details of this activity can be found in IR 50-j 321,366/93-17. At the end of this inspection report two cells, 16
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and 89, have not been replaced. The licensee stated that the two
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l remaining cells were not available and must be manufactured. One j
cell that was replaced has been sent to a laboratory for failure
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analysis and preparations to sent a second is underway. The inspectors will continue to monitor activities in this-area.
Paragraph 7 of this report discusses observations of several i
modifications being implemented to correct solenoid valve failures.
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The inspectors observed portions of maintenance activities being conducted on the HPCI systems of both units. Extensive work was i
performed on the steam admission valves -to correct seat leakage.
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The licensee has focused increased attention on the valves, steam
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line thermal traps, and other aspects of the HPCI system. The inspectors notad that the work activities were well coordinated and
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l the HPCI inoperability was appropriately controlled.
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Hispositioned Fire Protection System Valve On September 4, the operations crew closed a fire protection ring header isolation valve as part of clearance 1-93-1384. The
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clearance was implamented for maintenance activities. At l
approximately 10:55 p.m. CST the Unit 1 SS was investigating why
water was flowing from the ball drip valves in the Unit I low L
voltage switchya-d deluge house.
It was discovered that valve lY43-F306D, in the fire protection ring header which supplies water to
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the Unit I low voltage switchyard deluge house and the intake
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structure, was closed and locked. The 1Y43-F306D valYe was not part of the ongoing clearance and it was not clear why the valve was closed. With this valve closed and the valves listed in clearance l
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1-93-1384 closed, a section of the fire protection ring header was l
isolated from the Unit 1 low voltage switchyard and intake structure. The intake structure contains safety related equipment.
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The appropriate LC0 was entered and immediate correctivt actions to l
restore the fice protection ring header was initiated.
Fire protection was restored to the affected areas in approximately 40
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minutes. A DC was subnitted to document the out of position valve-and maintenance department personnel conducted an investigation.
The licensee determined that on August 16, maintenance personnel had performed two different surveillance procedures for the fire system isolation valves. These procedures were being performed concurrently. Procedure 455V-FPX-034-05:
Fire Protection Isolation Valves - Yard Area, is a 31 day surveillance. This procedure verified valve position (open/ closed) and whether or not the valves were locked. The second procedure 42SV-FPX-035-IS:
Fire Protection Valve Cycling Surveillance, is a yer.rly surveillance and required the valves to be closed, reopened and then locked in the correct position.
Both procedures required independent verification of i
valve position and locked status. The investigation concluded that i
the cause for the mispositioned valve could not be determined and that apparently the valve had been manipulated without proper procedural controls. The licensee plans to cover the event with maintenance personnel during special tool box meetings. The event history, consequences of the valve being mispositioned and the
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importance of using established administrative controls when conducting word or when operating equipment will be discussed. The meetings are scheduled to be completed by October 29, 1993.
The inspectors conducted an independent review of the surveillance procedures to verify proper documeritation of valve position and that second person verifications were documented. The inspectors concluded that the valve could have been closed for as long as 18 days. A meeting with maintenance supervision was conducted to discuss the investigation and corrective action measures. The inspectors also verified the current valve position to be open.
After review of the licensee's corrective actions in this matter,
the inspectors concluded that the licensee actions were appropriate
and timely. This issue will not be subject to enforcement actions because the licensee's efforts in identifying and correcting the violation meet the criteria in Section VII.B of the Enforcement Policy, for non-cited violations. This issue is identified as NCV 50-321,366/93-20-01: Mispositioned Fire Protection System Valve.
0ne NCV was identified.
5.
ESF System Walkdown (71710)
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The inspectors conducted a walkdown of the Unit 1 RHR/RHRSW system.
Valve, switch, and electrical board lineups were verified in the CR and locally to ensure the lineups were in accordance with operability requiremc.its. Walkdowns of spaces were performed to verify equipment l
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I conditions, housekeeping and cleanliness. Various piping supports and hangers, instrument _ valve alignments, and other support systems were examined. The inspectors focused heavily on the RHR system instrumentation and relays during the review. The emphasis included instrumentation and relay setpoint data, calibration, and surveillance procedures. Additionally, the physical condition of the instruments was observed.
In preparation for the inspection the following documents were reviewed:
Unit 1 FSAR, sections 4, 6, 7, 8, and 10 Uait 1 TS, sin tions 3.2 and 3.5 Hatch Unit 1 Instrument Setpoint Documents
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Procedures: 34AB-T22-003-IS, Secondary Containment Control
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34SV-E11-001-15, RHR Pump Operability 34SV-Ell-002-25, RHR Valve Operability 34SV-Hil-002-IS, LPCI Cross Connect Valve Annunciator fest
341T-T45-001-IS, RB Instrument Sumr Valves Exercise
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42SV-Ell-001-IS, LPCI LSFT & Auto Actuation 42SV-E11-003-IS, RHR Isolation Valve Control LSFT.
57CP-T45-002-IN, GEMS LS 800 Level Switch Calibration 57SV-CAL-003-15, ATTS Transmitter Calibration 575V-Ell-004-IS, LPCI Discharge Line Level FT&C 57SV-E11-006-IS, LPCI Pump Start Timers Calibration 57SV-E11-007-IS, RHR Valve Select Timers Calibration
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57SV-S32-002-IS, Busses IC and ID UV Rclay Calibration 31E0-E0P-014-IS, Secondary Containment Control The inspectors reviewed instrument surveillance, calibration procedures, and setpoint documents for a total of 35 instruments. These reviews included system actuation ed isolation instruments, flow, pressure, and leak detection. Also, the secuence timers which would connect emergency AC loads on a LOCA signal were reviewed. The sequence timer settings were verified to'be as required by the FSAR and the instrument setpoint documents. During this review, the inspectors verified that the-
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surveillances were completed on time, and that the procedure acceptance
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criteria was in accordance with the instrument setpoint documents and TS.
l Valve stroke times and the a to complete isolations during an emergency were verified 1 ce -
iequired by the FSAR and TS.
Various
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alarm response procedures em arified to have conservative setpoints time to respond and assess system degraded that would allow the oper r
and abnormal conditions pr ior to becoming emergency conditions.
Leak
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detection and flood protection actions were verified to be contained in
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alarm response, abnormal and emergency procedures. The inspectors also
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conducted a past history review of various instruments and components (MW0s and DCs) to ascertain if'any generic problems would be identified.
During the inspection one inspector observed I&C personnel conduct procedure 57SV-Ell-004-IS, LPCI Discharge Line Instrument FT&C. The technicians were familiar with the evolution and had previously performed the surveillance procedure. The technicians established communications i
with the CR and documented the completed procedural steps, including i
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independent verification, as required. During the surveillance the inspector observed that some procedure steps identified isolation and vent valves as IV1, IV2, VVI, and VV2. Howt.ver, the valves that were being manipulated were identified with the standa-d P&ID identifier, not
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as IV1, IV2, VV1 and VV2. This discrepancy did not hinder the technicians in the performance of their task. The identification discrepancies were discussed with the team foreman at the job site. The foreman stated the procedural steps would be reevaluated.
The inspectors reviewed the activities involved with DCR 93-19. This modification was issued far the Unit 1 RHRSW valves IEll-F068 A and B.
These valves had become clogged with debris from the RHRSW when the
system strainers failed.
Details of the event are contained in irs 50-321,366/92-02 and 50-321,366/92-03. This modification authorized, for both valves, the replacement of the originally installed valve disc
stacks. The replacement stacks have 3/4 inch straight through holes drilled in the top one inch of each stack. This design will allow the valves to pass 8000 gpm even if the bottom seven inches of the disc stacks become 100 percent clogged.
The inspectors concluded that the instrument setpoint, calibration and surveillance programs were well developed, implemented and documented.
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The surveiliance procedures were conducted on time and the acceptance criteria were as required by the instrument setpoint documents, FSAR, and TS. The past history review of MW0s and DCs did not identify any generic maintenance problems involving instrumentation.
No violations or deviations were identified.
6.
Self Assessment (40500)
In order to monitor the licensee's problem identification and resolution processes, the inspectors periodically review selected samplings of Deficiency Cards and associated reports. Numerous DCs involving
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equipment problems identified during the months of June through September, 1993 were reviewed. Procedure 10AC-MGR-004-OS:. Deficiency Control System, directs licensee personnel in the requirements and
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responsibilities for accomplishing deficiency control. The procedure addressed three major components: preparing and processing deficiency reporting documents; reviewing and determining disposition of deficiency items; and determining deficiency reportability to higher authority.
Section 8.1, Identification and Correction of Deficiencies (Conditions Adverse to Quality), of the procedure contained a note stating: An employee may initiate a DC at any time or in any situation to report any problems or initiate changes to improve plant reliability. The procedure contained addi'. ion sections addressing condition adverse to quality, significant occurrence reports, evaluation of DCs, deficiency significance and reportability evaluations.
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The following were some of the more significant items reviewed:
DC Number:
Description:
1-93-3544 83 of 404 RWPs have administrative errors
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2-93-1897 HPCI valve 2E41-F008 digital position
indicates open when valve is closed 1-93-3476 thru 79 Various instruments do not have source
document setpoints data
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2-93-1901 RHR valve 2 Ell-F051A leaking, 1-93-3512 Peak Recording Accelerometer, IL51-N006,
will not calibrate.
2-93-1918 RCIC instrument 2E51-N657B, Steam line High i
D/P, not indicating properly
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1-93-3481 Fire door not latching.
i The inspectors verified that, for the items listed above, appropriate actions were taken by the licensee to address the deficiencies. This included updating the instrument setpoint index, establishing a fire watch, and issuing MW0s. Additionally, the. inspectors reviewed some issues which were characterized as significant by the licensee. A number of these items were addressed in SORS and ERT reports. The following is a list of the more important items reviewed:
Event number:
Description:
93-03 Flow blockage of IEll-F068A.
ERT 93-01 was
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i 93-06 Missed surveillance on fire pumps. SR l-
)93-001 was initiated.
93-11 Inoperable fire protection sealing device for greater tuan 14 days. SR 2-93-001 initiated.
i 93-27 High number of LERs on missed TS surveillances.
ERT 93-09. initiated.
93-31 Unit I scram on low reactor water level.
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ERT 93-11-initiated.
Review of the associated ERT reports, SRs, and SORS indicated that the various groups clearly stated the facts surrounding the issues.- Adequate analysis of causal factors was performed and appropriate corrective actions were recommended to management. The inspectors concluded from i
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these reviews that the licensee's d2ficiency identification and
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No violations or deviations were identified.
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Modifications (37700)
The inspectors observed and reviewed the licensee's activities associated
with DCRs92-155 and 92-160, Replacement of ASCO Normally Energized AC-l Solenoid Valves. The DCRs were issued to address a problem with.the
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valves sticking and failing to perform their-intended function upon i
demand. Details of this item were documented in IR 50-321,366/92-12.
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The licensee issued LERs 50-321/92-03 and 50-366/91-19, which were closed in IR 50-321,366/93-08. The inspectors review included the.10 CFR 50.59
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assessment. The inspectors noted that the licensee attributed the sticking to heat generated over a period of time as a result of the solenoids being continuously energized. The DCRs authorized the replacement of 19 of these solenoids in each unit. Y.%se solenoids -
control air operated valves in seven systems: Reactor Recirculation,
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Hydrogen-Oxygen Analyzer, Plant Service Water, Drywell Pneumatic, Process q
Radiation Monitoring, Reactor' Building HVAC, and Primary Containment
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Purge and Inerting. The activities observed involved valves in the plant service water system and were controlled by the following MW0s:
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2-93-2102: Replace solenoid for valve 2P41-F036B, service water
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valve for Room Cooler 2T41-B0028 2-93-2103: Replace solenoid for valve 2P41-F0378, service water valve for RHR 011 Cooler 2 Ell-00028
2-93-2106: Replace solenoid for valve 2P41-F037D, service water-valve for RHR 011 Cooler 2 Ell-C002D
2-93-2112: Replace solenoid for valve 2P41-F035A, Service water
valve for Room Cooler 2T41-B005A
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The inspectors concluded from these reviews and_ observations-that the
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licensee was adequately addressing the solenoid valve problem. The
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inspectors will continue to monitor these activities.
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Inspection of Open Items (92700) (92701)
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The_ fallowing items were_ reviewed'using_ licensee reports, inspections,-
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a.
(Closed) LER 50-366/91-18:
Error in FSAR Results in Missed TS _
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Surveillance. This LER addressed an ' item; involving spare electrical
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penetration X-228B, located on the Unit 2 Suppression Pool. Chamber.
The penetration had not been type B (LLRT) tested as required.
j Details of this item and related reviews are in irs 50-321,366/.
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91-18, 91-34 and 93-02. The inspectors reviewed Unit 2 FSAR Table
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3.8-5, sheet 15 of 18, dated July,1993.
It was noted that penetration 228B, was listed as a spare and required a Type B test.
Based on this updated FSAR table this LER is closed.
b.
(Closed) LER 50-321/92-05:
Loss of RPS Busses Causes ESF Actuation; and 50-321/92-12: Spurious Breaker Trip Results in Loss of RPS Bus and ESF Actuation. These LERs addressed ESF actuations that initially appeared to have no known cause.
LER 50-321/92-05 was issued when the 600V AC power supply to the motor of the RPS "A" MG set tripped. Followup indicated that a ground was present from a heater in the MCRECS on the same 600V AC bus that supplies the motor. LER 50-321/92-12 was issued when the output breaker from the generator of the "B" MG set tripped.
Followup consisted of functional tests and calibration of the protective relay circuits, under voltage, over voltage or under frequency. No problems were identified.
For LER 50-321/92-05, the ground on the bus may have contributed to the breaker tripping, and for LER 50-321/92-12 the generator breaker may have tripped due to a spurious protective circuit trip. The inspectors noted that during the initial operator response, documented in LER 50-321/92-05, an operator inadvertently went to the Unit 2 600V breaker, instead of the Unit I breaker.
t When he attempted to reset an already closed breaker, the Unit 2 breaker opened. The operators actions caused an unplanned ESF actuation on Unit 2.
This personnel error was adequately addressed.
The inspector reviewed information supplied by the licensee which indicated that substantial RPS upgrades are planned.and have been approved by the change control board. Additional information is documented in this report concerning other RPS LERs.
Based on the inspectors review these LERs ?re closed.
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c.
(Closed) LER 50-366/92-05: Component Failure Results in Loss of Power to RPS Bus and ESF Actuation; LER 50-321/92-10: Component Failure Results in Trip of RPS MG set and ESF Actuation; LER 50-321/92-25: Setpoint Drift in Protective Relay Results in Multiple
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ESF Actuations; and LER 50-366/92-29:
Loose Connection in Power Supply Cabinet Results in ESF Actuation. These LERs addressed ESF I
actuations that were caused by known hardware failures. The inspectors reviewed RPS information provided by the licensee. The RPS System Report, second quarter 1993, dated August 6, 1993, stated that the Change Control Board had approved substantial design changes for the RPS systems. These changes included removal and replacement of all obsolete components from the MG sets, supplying j
additional air conditioning to the RPS equipment rooms, and i
improvements to the protective circuits (overvoltage, undervoltage, and underfrequency).
Part of the change involved the installation i
of a four second time delay on the protective circuits to preclude
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trips from short term power perturbations. The inspectors also
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noted that no RPS power supply problem have occurred since January, i
1993. Based on the approved changes and recent system performance these LERs are closed.
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9.
Exit Interview The inspection scope and findings were summarized on October 6, 1993 with those persons indicated in paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.
Item Number Status Description and Reference 321,366/93-20-01 Open and NCV - Mispositioned Fire Closed Protection System Valve 10.
- Alternating Current ATTS - Analog Transmitter Trip System B0P - Balance of Plant BWR - Boiling Water Reactor CFR - Code of Federal Regulations
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CR
- Control Room CST - Condensate Storage Tank DC
- Deficiency Card l
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DCR - Design Change Request ECCS - Emergency Core Cooling System i
EOF - Emergency Operations Facility
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ERT - Event Review Team
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ESF - Engineered Safety Feature l
FSAR - Final Safety Analysis Report l~
FT&C - Functional Test and Calibration j
- General Emergency
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l GL
- Generic Letter
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gpm - gallons per minute HP
- Health Physics HPCI - High Pressure Coolant Injection System
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HVAC - Heating, Ventilation and Air Conditioning I&C - Instrumentation and Controls i
IFI - Inspector Followup Item IR
- Inspection Report KV
- Kilovolt Limiting Condition for Operation LC0
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LER - Lisensee Event Report
LOCA - Less of Coolant Accident L
LPCI - Low Pressure Coolant Injection System l
MCRECS-Main Control Room Environmental Control System
1 MSL - Main Steam Line l
MWe - Megawatts Electric MWO - Maintenance Work Order NCV - Non-cited Violation
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NRC - Nuclear Regulatory Commission NSAC - Nuclear Safety and Compliance OSC - Operations Support Center P&ID - Piping and Instrumentation Drawing PM
- Preventive Maintenance PM&MS-Plant Modification and Maintenance Support psig - Pounds per square inch
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- Reactor Building RCIC - Reactor Core Isolation Cooling System RHR - Residual Heat Removal RHRSW-Residual Heat Removal Service Water System RPS - Reactor Protection System i
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RTP - Rated Thermal Power RWP - Radiation Work Permit
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SAE - Site Area Emergency.
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SOR - Significant Occurrence Report
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SOS - Superintendent of Shift (Operations)
SPDS - Safety Parameter Display System SR
- Special Report SRO - Senior Reactor Operator SS
- Shift Supervisor
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TS.
- Technical Specifications
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TSC - Technical Support Center f
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