IR 05000445/1993030
| ML20057A284 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 09/02/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20057A270 | List: |
| References | |
| 50-445-93-30, 50-446-93-30, NUDOCS 9309130319 | |
| Download: ML20057A284 (16) | |
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APPENDIX U.S. NUCLEAR REGULATORY COMMISSION i
REGION IV
c Inspection Report:
50-445/93-30
50-446/93-30
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licenses:
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NPF-89 Licensee-TU Electric Skyway Tower i
400 North Olive Street, L.B. 81 Dallas, Texas
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facility Name: Comanche Peak Steam Electric Station, Units 1 and 2
Inspection At: Glen Rose, Texas-Inspection Conducted: July 11 through August 21, 1993 Inspectors:
D. N. Graves, Senior Resident Inspector K. M. Kennedy, Resident Inspector G. E. Werner, Resident Inspector
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W. B. Jones, Acting Project Engineer, Section C T. Reis, Project Engineer, Section B R. C. Stewart, Reactor Inspector Approved:
k 1 Nb t. A. Yahdell, Chief, Projects Section B Date '
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Inspection St, mary Areas Inspected (Units 1 and 21:
Routine, unannounced inspection of onsite followup of events, operational safety verification, maintenance and
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surveillance observations, followup on corrective actions for violations,
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other followup, and review of licensee event reports.
i Results (Units I and 2):
P Management expectations regarding Operations Notification and
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e Evaluation (ONE) form initiations were not met (Section 2.2).
i Security response to two events was appropriate (Sections 2.3 and 2.4).
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A potential weakness in the scaffolding control program was identified
(Section 2.5).
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-2-Control of work activities in the switchyard was appropriate i
(Section 2.7).
In general,.the observed maintenance and surveillance activities were
well controlled and performed although one instance of a failure to follow procedures resulted in a noncited violation (Section 3.4).
The startup test program continued to be outstanding as observed during
the performance of three tests (Section 5).
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Summary of Inspection Findings:
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e Violations 445/91202-03,_445/9237-01, 446/9302-01, and 446/9302-02 were-closed (Section 6).
Inspection Followup Item 445/9313-02; 446/9313-02 was closed l
(Section 7).
Licensee Event Report 446/93-003 was closed (Section 8).
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Attachment:
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Persons Contacted and Exit Meeting
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DETAILS l
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1 PLANT STATUS Unit 1 operated at approximately full power during the entire inspection period.
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Unit 2 was in Mode I conducting additional startup testing at the 75 percent power plateau at the beginning of this inspection period. This testing was
completed on July 14. On July 18 Unit 2 achieved 100 percent reactor power.
Reactor power was reduced to 65 percent on July 19 in order to clean Heater Drain Pump 2-01 suction strainer. Unit 2 returned to 100 percent power on July 21 and the 100-hour NSSS acceptance run at'100 percent power was completed on July 26. The 50 percent load reduction test and full-power-plant trip were successfully completed on July 26 and 27 respectively. Unit 2 was
restarted and synchronized to the grid on July 30 with the unit returning to 100 percent power on August 1.
Unit 2 declared commercial operation on i
August 3 and remained at full power for the remainder of this inspection
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period.
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2 OPERATIONAL SAFETY VERIFICATION (71707,92701)
j 2.1 Plant Tours
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General housekeeping in the plant was determined to be good.
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storage of materials was appropriately controlled within safe zone areas.
Transient combustibles were observed to be properly stored; however, the inspectors did identify that a flammable storage locker in the auxiliary
building, 810-foot elevation, did not have a working latch and therefore the door could not be properly closed. This discrepancy was identified to operations management and was not corrected until the inspectors again pointed j
out the nonfunctional flammable storage locker. At the end of the inspection
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period the licensee had written Work Request 152391. to permanently repair the
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latch and installed a temporary locking device to keep the locker closed.
j Several other minor variances were identified and promptly corrected.
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2.2 Inadvertent Engineered Safeguard Features (ESF) Plant Ventilation Fan 21
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Actuation
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On July 16 while the inspectors were observing the morning shift turnover between Unit I reactor operators (R0s), the R0s identified that Primary Plant -
ESF Fan 21 was operating and had automatically started. No immediate cause
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for the fen's actuation was apparent. ONE form 93-1417 was written the following morning to document the ESF fan actuation. The ONE form also documented the fact that while ' performing _a slave relay test (K610) at
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approximately 3 a.m. on July 16, an R0 mistakenly manipulated the safety
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i injection sequencer block switch rather than the auto test switch. The operators had immediately performed a main control board walkdown but no abnormal equipment actuations were identified at that time.
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The ONE form disposition found that auto start of ESF Fan 21 was the result of the mispositioning of the Unit 1 Train A safeguards sequencer block switch.
l The ESF actuation was determined not to be valid and therefore nonreportable.
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During the shift turnover, no mention was made of the mispositioned switch.
Additionally, no entry was present on the unit operating log or any other
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shift paperwork regarding the mispositioned switch.
In discussions with l
operations management, it was not apparent that.a ONE form would have been
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generated to document the personnel error involving the sequencer block switch if questions about the automatic actuation of ESF Fan 21 had not been raised.
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An operations manager indicated that this did not meet management's expectations, and discussions with operations department were conducted to convey their expectations that ONE forms should be written for all personnel
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errors regardless of whether automatic equipment actuations occur or not.
2.3 Security Response to Weapon Intrusion Cn July 17 the inspectors observed the licensee's response to an event in
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which a loaded pistol was detected in a lunch box at the primary access coint.
The licensee's response was prompt, efficient, and in accordance with facility procedures. A security inspector, who was onsite at the time, was promptly
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informed and reviewed the licensee's followup actions. Security Field Report 1425-93 was reviewed by the inspectors and accurately reflected the-
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observed actions. A courtesy notification was made by the licensee to the NRC Operations Center to report the event.
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2.4 Security Keys Outside the Protected Area On July 19 at approximately 8:00 p.m. an auxiliary operator (AO) exited the protected area through the alternate access point while having security keys in his possession. The A0 left the protected area while going to the National
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Fire and Medical onsite facility for 17 minutes in performance of his duties.
t Security Field Report 1449-93 detailed the events and subsequent investigation i
by the licensee determined that the keys were not compromised. The inspectors reviewed the field report and found that the licensee had taken appropriate actions.
2.5 Scaffold Configuration
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On August 3, while conducting an inspection of the Unit 2 main steam penetration room, the inspectors observed that a section of tubing from a scaffold constructed around Steam Generator 2-02 Atmospheric Relief Valve 2-PV-2325 was resting on' and supported by a snubber.
Procedure STA-690,
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" Scaffold Erection and Control," Revision 0, Section 6.6.7.1, states that snubbers shall not be used as restraint attachments unless approved by
_.t engineering. Although the tubing was not attached to the snubber, the
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inspectors identified this as a weak scaffold configuration and brought it to the attention of the licensee. The scaffold was reconfigured to prevent the
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tubing from contacting the snubber.
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-5-The scaffold was constructed on May 29, 1993, and inspected by.a scaffold
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erection foreman twice after that. The erection foreman was unaware of any
configuration changes that had been made since the last inspection, indicating
a potential weakness in the control of the configuration of ' scaffolding in i
that the scaffolding may have been modified following initial erection.
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l 2.6 Emergency Core Coolina System Lineups The inspectors ~ verified that valves within Units I and 2 emergency core
cooling system major flow paths were properly aligned. The inspectors walked l_
down accessible portions of those systems and verified that valve lineups were in accordance with procedures.
Required auxiliary systems were found to be'
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operable. Main control board indications were found to be consistent with i
field conditions.
t The inspectors performed-a detailed walkdown of the Unit 2 turbine driven
auxiliary feedwater system in order to verify that the most recent lineups
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accurately reflected the in-plant conditions. Procedure.50P-304B, " Auxiliary Feedwater System," Revision 1, Attachment 1, " Valve Lineup Sheet"; and Attachment 2, " Electrical Lineup Sheet," completed June 21, 1993, were used to-check valve and breaker positions. All components were found to be in the
correct position as specified on the lineup sheets.
2.7 Switchyard Work Controls (
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The inspectors reviewed the licensee's controls for work in the 138 kV
and 345 kV switchyards. The review included interviews with an Independent l
Safety Engineering Group engineer, a shift supervisor, and maintenance support q
personnel.
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TU Electric Letter CPSES-920158, " Comanche Peak Steam Electric Station Conduct ~
l of Switchyard and Plant Transformer Maintenance," dated February 10, 1992,
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details several actions taken to maintain positive control over the switchyard. These controls included the following:
Signs posted on entrances stating that shift operations must be notified
prior to entry.
'i All entrance locks were replaced with one type of _ lock.
Controlled keys'
are available in the control room and Security Post 203.
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L Maintenance crews are to inform the shift supervisor what' effects the;_ _
maintenance activity may have, possible control room alarms, plant risks involved,-and any testing requirements associated with the switchyard:
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Additionally,enhancedmonitoringbyshiftoperationsandmanagementpahonnel'
in the switchyard was to be conducted during maintenance.
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l-6-i maintenance activities are divided between Comanche Peak and Fort Worth.
transmission personnel.
Several other informal precautions for control of' switchyard work were
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detailed by various site personnel, including:
Switchyard maintenance activities are discussed at the daily work
planning meetings.
Independent Safety Engineering Group performs risk assessment for large
scope jobs.
P TU Electric personnel continually monitor work when bucket. trucks or
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large equipment are in the switchyard to support the maintenance
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activity.
Overall, the licensee has developed appropriate guidelines to control: work in
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the switchyard; however, no procedural guidance or requirements have been
.ieveloped for work conducted by Fort Worth transmission personnel.
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2.8 ' Radiation Protection'0bservations The inspectors noted that there were few contaminated areas within the radiologically controlled area (RCA). Radiation areas were properly posted, contaminated areas were appropriately identified, and high radiation doors were closed and locked. Radiation protection technicians were cognizant of work being conducted within the RCA. Overall,. the radiation protection department continued to provide very good oversight and support of all
activities within the RCA.
2.9 Conclusions
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General housekeeping was good.
Several minor discrepancies were identified and corrected.
Radiation protection activities continued to be-very good.
The licensee's controls for work in the switchyard were appropriate-although
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no procedural requiren.ents had been developed for work performed by offsite-personnel.
The failure to promptly initiate a ONE form following identification of a known personnel error during the performance of a surveillance activity did not meet management's expectations. A potential
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weakness was identified in the control of scaffolding configurations.
3 MAINTENANCE OBSERVATIONS (62703)
3.1 Spent Resin Sluice Filter Bypass The inspectors observed a welder weldii. a section of piping associated with -
the installation of Design Modification 93-007. This design modification was-
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being accomplished to allow a bypass flow path around the spent resin sluice filter, in accordance with Work Order 2-93-048082-00. The work was conducted i
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inside a contaminated area using proper radiological work practices.
The gas metal arc welder's amperage setting was properly adjusted (Procedure WPSEP-301, "CPSES_ Welding Procedure Specification," Revision 4).
-i A fire watch was present and cognizant of his duties.
r 3.2 Heater Drain Pump 2-01 Suction Filter Cleaninq
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On July 20 mechanical maintenance technicians were observed during the initial phase of cleaning Heater Drain Pump 2-01 suction filter and removing the suction expansion joint (Work Order 1-93-045072-00).
The inspectors noted that the support for the suction filter piping rigging equipment appearet to lack appropriate structural strength. _ The work package was reviewed in detail and found to contain Technical Evaluation 93-918 which
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documented the approved lifting configuration. The inspectors confirmed that the installed rigging was not in conformance with the configuration specified in the technical evaluation.
Prior to the technicians removing the suction filter piping, the inspectors identified the technical evaluation to the
technicians, who then modified the rigging configuration to be in conformance with the work package. A note referencing the technical evaluation for proper.
rigging support was contained at the start of the work order instructions, but not immediately preceding the step which removed the suction filter piping.
The technicians indicated that they had reviewed the work package but had not-noticed the reference to the technical evaluation. A grevious maintenance crew had performed a number of the work document steps and then turned over-.
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the work to the observed crew. The poor placement of the note contributed to the oncoming work crew not being aware of the rigging requirements. The inspectors discussed the failure of the workers to review all work instructions and the poor placement of the note within' the wo.. instructions with a mechanical maintenance manager.
The heater drain pump was isolated with the use of a single valve for protection. A small amount of steam leakage past the isolation points was -
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observed during the maintenance activity. The technicians were cognizant of the system configuration and used appropriate safety precautions.
3.3 Various Maintenance Activities The inspectors al:;o observed the following maintenance activities:
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Work Order 1-93-040901-00, which directed the replacement of gaskets on
the Unit 2 chemical spray addition tank' discharge' flow orifice flange
for indicating Switch 4756. The flange was assembled _ and torqued per
Procedure MSM-G0-0203, " Flange Alignment and Fastener Torque Data,"
Revision 3.
When the catch containment beneath the flange was removed, j
the inspectors noted that the decontamination technician was aware that
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the inside of the catch containment was slightly contaminated; however, the technician was not aware of the levels. The technician questioned
several maintenance technicians about the contamination levels but they
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also were not aware of the count level, and continued to remove the catch. The inspectors discussed this-poor radiological work practice with the technician and the radiation protection lead technician.
Mechanical maintenance technicians replaced several Diesel'
Generator 1-01 cylinder cover gaskets (Work Order 1-93-032477-00).
Electrical maintenance technicians replaced flexible Conduit
No. C12004816 (Diesel Generator 1-01 space heater power supply)
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authorized by Work Order 1-93-048995-00.
Overall, good work practices were'used by-all maintenance technicians.
Proper
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use of procedures and work orders were demonstrated by the individuals.
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3.4 Differential Pressure Switch Calibration
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Calibration of Diesel Generator 1-01 Fuel Oil Transfer Pump 1-02 discharge strainer differential pressure indicating switch was performed by.
instrumentation'and control technicians using Procedure INC-2025, " Calibration ITT Barton Differential Pressure Indicating Switches Models 288, 289, 290, and.291," Revision 1 (Work Order 3-93-316948-01). During the calibration, excellent attention to detail was demonstrated when the technicians noted that'
Data Sheet ICA-105-2, Revision 1, contained references to Unit 2 drawings.and
appropriately obtained Unit I drawings for reference.
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The inspectors noted that the technicians did not use an. oil designated gauge, fittings, and lines as required by Procedure STA-608, " Control of Measurement
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and. Test Equipment," Revision 16. This requirement was intended to prevent.
cross contamination of systems. The measuring equipment had previously been used to calibrate a water system.
During the calibration, it was noted by the technicians that a small amount of water had entered the _ test lines. The
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calibration was stopped and the water was drained from the lines. No water was observed to have entered the fuel oil system and no immediate safety concern.was identified'by the improper use of the. test. gauges. The licensee
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has counselled the two technicians involved and provided in-shop training for'
all other technicians concerning the proper use of gauges. Although this was
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a violation of. Procedure STA-608, this violation will not be cited because the licensee's effort in correcting the isolated violation met the_ criteria for
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enforcement discretion specified in Section.VII..B.1 of Appendix C 10 10 CFR Part 2.
3.5 Lubrication Practices
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On. July 29 the inspectors examined the Units 1 and 2 emergency core. cooling system valve rooms. The' inspectors found the valve stem packing areas of Valves 1-8812A, 1-8812B, and 1-8821A to contain excessive lubricating grease.
Valve.1-8821A, a 4-inch gate valve which provides a crosstie between the two trains of safety injection, contained approximately 4 ounces of excess
lubricant.
The other valves contained lesser but excessive amounts of grease.
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The inspectors were concerned that the excessive lubricant would collect dirt
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which could migrate into the stem packing area and cause an operability l
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"Limitorque SB-2 Maintenance," Revision 1; and MSM-CO-6846, "Limitorque SBM-00 t
Maintenance," Revision 0; and found both procedures to direct the craft personnel to lightly or sparingly coat the valve stem threads with Termatex EP
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lubricant. The application of excessive grease on the stem packing area is considered a poor work prr.ctice.
The licensee was notified of the observation i
and agreed to evaluate the craft practice.
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On the same plant tour the inspectors noted a large unmarked gasket hanging from a conduit junction box in the Unit 1 Train A emergency core cooling.
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system valve room. The gasket was apparently left behind by craft personnel performing maintenance on a valve in the room. The licensee was informed of the gasket's unnecessary presence and it was removed.
3.5 Conclusions
The observations of various work activities produced mixed results.
Good. work practices and the proper use of procedures were demonstrated by numerous technicians; however, the following discrepancies were identified by the
inspectors.
i An improper rigging configuration,
Poor radiological work practices were used while removing a catch
containment,
'l Excessive lubrication on valve stems, and l
The improper use of test gauces, which resulted in a noncited violation.
- I 4 SURVEILLANCE OBSERVATIONS (61726)
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4.1 Unit 1 Train B Service Water Testing Work Order 5-93-504075-AC specified that Section 8.3.2 of Procedure OPT 207A, Revision 4, " Service Water Operability Verification," be conducted on Unit 1
Train B service water system. The surveillance verified the operability of the Service Water Pump.1-02 and associated valves as required by Technical
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Specification 4.0.5.
l-The inspectors observed the operators and unit supervisor (US) verifying i
l procedut il prerequisites. Working copies of the procedure were.given to the A0 participating in the surveillance; test. Test control was good with one-
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minor equipment problem being addressed before proceeding with the surveillance.
Excellent communications with the A0 were noted by the inspectors. The inspectors verified that the data collected met the acceptance criteria.
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The inspectors observed the-pre-evolution brief, testing, and restoration for Train 8 Safeguards Slave Relay K603 (Work Order 5-93-502851-AB). An
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appropriate brief was conducted by the US. Good communication and excellent-self-checking were used by the R0s.
All equipment actuated as expected with no deficiencies noted.
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During the restoration of the primary plant ventilation lineup, the inspectors observed the R0 starting cautioned tagged Exhaust Fan 16 (Clearance Number X-92-4192). The clearance tag had the switch position in " pull-to-
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lock" and stated that fire protection water was isolated to the fan. When the RO was questioned concerning the caution tag, he was not aware of the reason for the caution tag. The R0 indicated that the fan had previously been operating and therefore was returning the ventilation lineup to the previous configuration. The clearance had been in place for several months and the fan was normally operated to support plant ventilation. _ Operation of caution tagged equipment without understanding the conditions of caution was considered a poor and'possible hazardous practice. This observation was discussed with operations management who indicated that equipment should not be operated without an understanding of noted restrictions and conditions and that the observed action and response was not the normal expectation nor practice.
4.3 Conclusions The observed surveillance activities were well coordinated with good control provided by the US. Communications between R0s and A0s continued to be very-strong. One instance of operating a caution tagged component without understanding the equipment restrictions or conditions was identified as a poor and possible hazardous practice.
5 STARTUP TEST WITNESSING (72302)
5.1 Unit 2 - 10 Percent load Swings On July 14 Procedure ISU-231B, " Design Load Swing fests," Revision 0, was conducted to demonstrate the ability of the primary and secondary plant and the automatic. reactor control system to sustain a 10 percent rapid load reduction and increase. An appropriate pretest brief was conducted by a lead performance and test engineer. An outstanding additional briefing was given to the R0s by the US. This briefing discussed individual responsibilities for each of the three R0s, rod insertion limits, axial flux limits, and a detailed discussion of contingency actions for possible losses of secondary feedwater heaters and main feedwater pumps.
During the installation of the data acquisition computer, the inspectors noted the technicians performing the initial and independent verification concurrently.
Procedure STA-694, " Station Verification Activities,"
Revision 1, does allow concurrent dual verification, in lieu of independent m
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In questioning one of the technicians, he was unsure as to the use'of concurrent verification verses independent verification.
The. inspectors discussed with the performance and test manager the observed lack of understanding of the criteria in-using concurrent verification verses independent verification.
Each of the technicians used excellent self-verification techniques.
The US maintained excellent control and oversight of the testing. ' Reactor-power was at approximately 80 percent for both the load increase and decrease.
The plant responded as expected and the initial test results appeared satisfactory. On July 15 the test review group found that the data collected met the test acceptance criteria and released the plant to increase power up to 100 percent.
The inspectors reviewed Final Safety Analysis Report Table 14.2-3, " Unit Load-Transient Test Summary," and Regu.atory Guide 1.68 " Initial Test Programs'for l
Water Cooled Nuclear Power Plants," and found tht the requirements specified in these documents were appropriately reflected in Procedure 150-2318.
The inspectors reviewed the final data package for the load swings and found the disposition of initial startup testing problem reports to be appropriate.
5.2 Unit 2 - 50 Percent Load Reduction Test On July 26, 1993, inspectors in the control room and in the turbine building'-
observed the performance of.the 50 percent-load reduction test. The purpose of this test, conducted in accordance with initial Startup Test Prncedure 150-2638, "Large Load Reduction Tests," Revision 0, was to verify that the primary plant, secondary plant,. and the automatic reactor control systems could function to sustain a 50 percent step load reduction.
A comprehensive and thorough pretest briefing led by the lead test. engineer was conducted for the control room operators and others involved in' the test.
During the briefing, the lead test engineer discussed the purpose of the test, expected plant response, and the test acceptance criteria, precautions, and limitations.
The operators held.further discussions on the expected plant response and contingency actions to be taken, if required.
The 50 percent load reduction was ' initiated by the operator manually reducing turbine load by approximately 580 megawatts. Operators closely monitored plant. response during the transient and verified, in conjunction with the lead test engineer, that the acceptance criteria for the test were satisfied.
5.3 -Unit 2 - 100 Percent load Rejection
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Procedure 150-284B, " Dynamic Response to full Load Rejection and Turbine Trip," Revision 0, was conducted to demonstrate the ability of the primary and secondary plant and its control systems to sustain a reactor trip from 100 percent power, and to establish stable conditions following the transient.
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i A thorough pre-evolution brief was given by both the performance and test lead I
engineer and the US.
Expected system responses and operator actions were discussed to ensure the proper control system responses were obtained without
any undo operator interference.
Excellent coordination and command and control were demonstrated by.all testing participants. The US maintained positive control over the operation of the load rejection with performance and test personnel collecting test
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data.
Initial data indicated all systems responded as required. No abnormal
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ESF equipment actuations occurred. A review of the completed Procedure ODA-108, " Post RPS and ESF Actuation Evaluation," Revision 1, verified the plant equipment responded as designed with minor. discrepancies
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noted within the evaluation, none of which effected operability or safety.
5.4 Conclusions
The startup testing-program continued to be outstanding.
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coordination between the testing organization and operations personnel allowed for the smooth conduct of testing. Outstanding briefingt were given to.the operations crew.
Initial reviews of the test data indicated that all tests met the acceptance criteria and were completed satisfactorily.
j 6 FOLLOWUP DN CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
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6.1 (Closed) Violation 445/91202-03:
Roof Sealant and Hilti Bolt Corrosion This violation involved an instance where.past corrective measures failed to
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preclude the repetition of water introduction in the area of Hilti bolts and thereby introduced the media necessary for crevice corrosion.
Roofing material used as an environmental seal for the Unit I diesel exhaust muffler Hilti bolts had shrunk and water was present in the sealing area. The licensee identified that an unauthorized material. substitution was made by the previous roofing contractor and was not installed in accordance with design'
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specifications (ONE Form 91-1708).
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Design Modification 90-84 was developed to remove the old roof and' to' replace the roof on the Unit I and common buildings. Work Order 1-92-025736-00
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. implemented the design modification. The inspectors performed a walkdown of all Unit 1 and common area roofing with the system and design engineers, and found that the roof had been repaired in accordance with the design requirements. The inspectors also verified that Unit 2 roofing had been appropriately installed and no similar areas of concern existed on Unit 2.
Additionally, the inspectors verified that the new roofing material sealed those areas that had been identified as deficient in the. violation.
ONE Form 91-1708 documents the inspection of the base plates and 'Hilti bolts that,was conducted during the performance of Work Order 1-92-025736-00. No evidence of corrosion was found, and the sealant was found to have an adequate bond to the bolts to protect them from corrosion.
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6.2 (Closed) Violation 445/9237-01:
Failure to Record Work Orders for identified Boric Acid Leakage Observed During a Reactor Coolant System (RCS) Walkdown Conducted on October 3. 1992
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This violation involved the failure to follow procedures in that during the -
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conduct of an RCS walkdown on October 3,1992, all observations relative to boric acid leakage wert not documented, nor were corresponding initiated work-orders identified. - These omissions were contrary to the requirements of.
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Sectica 6.4.1.1 of Procedure STA-737, " Boric Acid Corrosion Detection and Evaluation," Revision 0.
L During this reporting period, the inspectors observed that Revision I to Procedure STA-737 contained attached data sheets listing all principle location components to be visually examined during the walkdown and the
requirement to record associated vork orders where sources of boric acid leakage are identified.
In addition, the inspectors reviewed the licensee's~
records relative to this data sheet documentation recorded during RCS
walkdowns conducted on November 12, 1992, and March 19, 1993,'respectively.
The inspectors concluded that procedural requirements were being correctly implemented and that the licensee's corrective actions were appropriate.
j 6.3 (Closed) Violations 446/9302-01 and 446/9302-02:
Failure to Follow
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Administrative Requirements - Precperational Testing
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These violations involved numerous examples of the licensee's failure to follow preoperational administrative requirements during the Unit 2
'i preoperational testing phase (446/9302-01) and the ineffective administrative handling of documents (446/9302-02).
The licensee's documented corrective actions included a complete review of all preoperational test procedures and test results to assure:the initial startup program was being implemented properly.
In addition, specific. training was
conducted for test personnel on the administrative details regarding the
conduct and documentation of initial startup testing. These corrective
actions were appropriate in that problems _of this nature were essentially eliminated during Unit 2 initial startup testing phase that was completed on
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7 FOLLOWUP (92701)
(Closed) Inspection Followup Item 445/9313-02: 446/9313-02:
Potential
. Gas Binding of the Centrifugal Charging Pumps from the Volume Control
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This inspection followup item was. initiated in NRC Inspection Report 50-445/93-13; 50-446/93-13, Section 7.4, to review the-licensee's actions to resolve concerns with the. potential for gas binding the centrifugal charging y
pumps from the volume control tank and to assess whether an industry generic
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concern existed. This inspection followup item was again reviewed in NRC f
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Inspection Report 50-445/93-18; 50-446/93-18, Section 6.2.
The licensee i
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B determined that the centrifugal charging pumps had become gas bound when a
-level switch in the positive displacement pump suction stabilizer became bound
allowing gas into the common charging system suction line.
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The licensee determined that the positive displacement pump suction stabilizer design was unique to Comanche Peak Units 1 and 2.
The positive displacement pump utilized a suction stabilizer which consisted of a water volume with a
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gas medium present to dampen suction oscillations. No bladder existed between the gas and water in the stabilizer and a single level switch on the suction
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stabilizer controlled a gas inlet valve (2-8204) which provided a gas supply-from either a hydrogen or nitrogen source.
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The system configuration which contributed to the events was determined to be unique to Mode 5 operation. When the pump was not in service, the pump suction stabilizer gas supply was maintained closed. Technical Evaluation TE-93-1080 dated May 19, 1993, established postinstallation
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functional testing instructions which should be performed to verify level
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switch operation.
The inspectors found the licensee's corrective actions to be appropriate to prevent similar instances in the future.
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8 ONSITE REVIEW OF LICENSEE EVENT REPORT (LER)
(92700)
(Closed) LER 446/93-003:
" Manual Reactor Trio Followino Inadvertent Closure of Feedwater Isolation Valve Caused by Instrumentation Channel Error" This report concerned a Unit 2 manual reactor trip from 23 percent of rated
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thermal power which was initiated based on rapidly declining level in Steam Generator No. 1.
The declining levels were the result of inadvertent
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actuation of anti-water hammer circuitry which caused the closure of a main
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feedwater isolation valve.
The circuitry was actuated due to failures in instrumentation providing input to the circuitry.
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The inspectors performed onsite inspection of the report and concluded the LER satisfied.the criteria specified 10 CFR 50.73(b) and that the corrective
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actions specified were adequate to prevent recurrence of this or similar events.
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However, the inspectors did consider the licensee's report and associated closure documentation too narrowly focused on the hardware failures of the
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event and neglected the fact that there were indications of an increased probability of actuation of the anti-water hammer circuitry that was not recognized by operations or engineering personnel, a
The anti-water hammer circuit responds to flow and temperature instrumentation-r inputs associated with the feedwater system. With the feedwater isolation valve open, a combination of high differential temperature between resistance temperature detectors mounted on feedwater lines outside and inside
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containment and low feedwater flow will satisfy the logic circuit and close i
the valve.
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-15-The inspectors considered that, given the present conditions, sufficient information was available in order that the prudence of continued operation with the anti-water hammer circuitry partially actuated should have been1 evaluated. Neither the LER nor the accompanying closure documentation suggested such an evaluation was accomplished, The inspectors presented this apparent inaction as a weakness in the operations / engineering interface.
The licensee then interviewed system engineering personnel to determine their awareness of the anti-water hammer circuitry status at the time of the event.
It was determined that engineering was aware of the failed resistance-temperature detectors and the steam leak in the vicinity of the flow transmitter.
Engineering had evaluated the steam leak and had made an informed determination that continued operation at low-power levels was acceptable.
Based on discussions with the engineering personnel, the inspectors' concern regarding the lack of an operations and engineering interface with respect to this matter was resolved. The interface had occurred and an informed decision regarding operability had been made. The LER closure package merely failed to reflect this.
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ATTACHMENT-1
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L 1 PERSONS CONTACTED Licensee Personnel
0. Bhatty, Site Licensing
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M. R. Blevins, Director of Nuclear Overview
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W. J. Cahill, Group Vice President, Nuclear Engineerine and Operations R. Flores, Shift Operations Manager T. A. Hope, Site Licensing Manager
D. R. Moore, Manager, Maintenance
C. L. Terry, Vice President, Nuclear Operations R. D. Walker, Manager of Regulatory Affairs for Nuclear Engineering
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Organization The personnel listed above attended the exit meeting.
In addition to.the personnel listed above, the inspectors contacted other personnel during this inspection period.
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2 EXIT MEETING
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An exit meeting was conducted on August 19,'1993. During this meeting, the inspectors reviewed the scope and findings of the report. The licensee did not identify as proprietary. any information provided to, or reviewed by, the-inspectors.
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