IR 05000445/1993007
| ML20035A115 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 03/18/1993 |
| From: | Yandell W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035A113 | List: |
| References | |
| 50-445-93-07, 50-445-93-7, 50-446-93-07, 50-446-93-7, NUDOCS 9303240086 | |
| Download: ML20035A115 (20) | |
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l APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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Inspection Report:
50-445/93-07
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50-446/93-07
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Operating License:
NPF-87 Construction Permit:
CPPR-127 i
Licensee: TU Electric l
Skyway Tower l
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400 North Olive Street
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Lock Box 81
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Dallas, Texas 75201 Facility Name:
Comanche Peak Steam Electric Station, Units 1 and 2 f
i Inspection At:
Glen Rose, Texas
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Inspection Conducted:
January 3 through February 16, 1993
Inspectors:
W. B. Jones, Senior Resident Inspector
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G. E. Werner, Resident Inspector D. L. Kelley, Reactor Inspector Accompanying Personnel:
V. Gaddy, NRC Intern Approved:
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l L. A. Yandell, Chief, Project Section B Date
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Division of Reactor Projects
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i Inspection Summary Areas Inspected (Unit 1):
Routine, unannounced inspection of onsite followup
- J of plant events, operational safety verification, maintenance observation, i
surveillance observation, followup on corrective actions for violations, and followup of licensee event reports (LERs).
Areas Inspected (Unit 2):
Routine unannounced inspection of operational
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safety verification.
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Results (Unit 11:
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The control room operators responded very well to both _ reactor
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trips. 'The unit supervisor demonstrated good command and con +al functions during the reactor trip on January 18, 1993
(Sections 2.1 and 2.2).
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Operators exhibited a lack of attention to detail when understanding and
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following annunciator response procedures for main control board alarm l
indications. An operator failed to promptly and aggressively pursue'the
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I resolution of an alarming annunciator. Several other problems dealing with annunciator status and associated work orders were identified.
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inspection followup item (IFI) was identified to observe. operator j
awareness and response to control room annunciators (Section 3.3),
j Maintenance personnel performed work in accordance with the work l
instructions and used good work practices during the performance of the
'I maintenance activities (Section 4).
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Two instances of inadequate coordination amorg various organi7ations i
during maintenance activities contributed to safety equipment being out
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of service for an unnecessary length of time. An IFI was identified to
review the licensee's actions to enhance the work control process
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supporting time critical Limiting Condition for Operation Action Requirement (LC0AR)s. (Sections 4.1 and 4.2).
i The licensee appropriately identified and classified hardware
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deficiencies; however, _two examples of failure to remove work request tags following corrective maintenance were identified (Section 4.4).
Management's expectations were not being met for material
accountability. An office memorandum was subsequently issued clarifying
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and strengthening the requirements of the procedure (Section 5.1).
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The surveillance program was properly implemented.
Personnel i
performance during testing activities was generally very good I
(Section 5).
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Results (Unit 21:
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A Unit 2 annunciator on a common annunciator panel was identified as
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having been in the alarm condition for 6 days after the equipment
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clearance had been removed. The alarm tracking sheet indicated the
alarm condition was caused by the equipment clearance when, in fact,- a valid alarm condition existed. An IFI was identified to observe i
operator awareness and response to annunciator alarms (Section 3.3).
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Unit 2 radiological controlled areas were properly posted and surveyed.
- i Summary of Inspection Findings:
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.I IFl 445/9307-01; 446/9307-01 was opened (Section 3.3).
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.i Ifl 445/9307-02; 446/9307-02 was opened (Section 4.2)
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Violation 445/9247-01 was closed (Section 6).
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LER 445/91-003-01 was closed (Section 7.1).
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LER 445/91-007-01 was closed (Section 7.2).
- LER 445/91-010 was closed (Section 7.3).
- LER 445/91-011 was closed (Section 7.4).
- LER 445/91-031 was closed (Section 7.5).
- LER 445/91-023 was closed (Secti:n 7.6).
- LER 445/92-020 was closed (Section 7.7).
- Attachment:
Attachment - Persons Contacted and Exit Meeting
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DETAILS 1 PLANT STATUS (71707)
At the beginning of this inspection period, Unit I was at approximately 55 percent power.
Full-power reactor operation was achieved on January 10, 1993, following the second refueling outage.
On January 18 a reactor trip occurred, in part, because of personnel error during the performance of a solid state protection system (SSPS) surveillance.
The unit was returned to power operation the following day. On January 24 a reactor trip occurred during an overtemperature (OT) N16 surveillance test. With one OT N16 channel in test, a pressurizer pressure signal spiked low causing a second OT N16 channel to trip. Mode 1 operation was entered on January 25. The unit was operating at 100 percent power at the end of the inspection period.
The Unit 2 preoperational test program was essentially completed, with test and retest deferrals identified and approved.
All systems, buildings, rooms, and areas were turned over to nuclear operations. The radiological control area was expanded to include the Unit 2 coatainment and safeguards buildings.
All site activities, as of December 21, 1992, came under the control of Nuclear Operations programs with the exception of identified and management approved items previously initiated under construction and/or startup programs. The licensee requested an operating license via TU Electric Letter TXX-93001 dated January 30, 1992. On February 2, 1993, the licensee received a low-power operating license (NPF-88) authorizing the loading of fuel and low-power testing up to 5 percent of full reactor thermal power.
2 ONSITE RESPONSE OF EVENTS (93702)
2.1 Reactor Trip Caused by Personnel Error during SSPS Test On January 18, 1993, the Unit I reactor tripped from 100 percent power.
The licensed operators had completed testing of the SSPS Train A and were restoring from the test lineup at the time the trip occurred. The test had been cc ed in accordance with Procedure OPT-445A, Revision 2, " Solid State Protect:
'ystem Train 'A' Actuation Logic Test." However, during system restora'
a, an incorrect instruction was used and the inhibit switch was taken to normal.
This removed the SSPS Train A blocks and a reactor trip occurred.
The personnel error and procedure deficiency are being addressed in the NRC Operational Readiness Assessment Team Inspection Report 50-446/92-201.
N inspectors promptly responded to the control room and observed operators'
actions to stabilize the unit in Mode 3.
The unit supervisor immediately entered the applicable emergency operating procedure and properly coordinated the plant recovery. Motor-Driven Auxiliacy fccdwater Pump (MDAFWP) 1-01 was manually initiated because the SSPS Train A was in test and prevented MDAFWP l-01 from receiving an automatic start signal on lo-lo steam generator
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level. The shift supervisor made the 10 CFR 50.72(b)(2)(ii) notification to the NRC Operations Center within the required 4-hour period following the
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event.
The inspectors independently reviewed the posttrip data and verified that the
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required systems functioned as expected. The control room personnel response
was very good following the reactor trip.
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2.2 Reactor Trip Resulting from Instrument failure
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On January 24, 1993, the Unit I reactor tripped from 100 percent power. A surveillance was in progress on the Loop 3 power range nuclear instrument Channel N-43.
This surveillance required that the channel be placed in the
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trip condition which reduced the OT N16 reactor trip logic from 2 of 4 to 1 of 3.
While the surveillance was in progress, primary plant Pressure Instrument 1-PT-456 failed low for approximately 6 seconds. This pressure
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instrument pre" ides input to the Channel II OT N16 setpoint calculation. This lowered the Channel II OT N16 setpoint to approximately 82 percent, resulting i
in a reactor trip because of the reduced 1 of 3 OT N16 trip logic.
The inspectors were promptly notified of the reactor trip and responded to the site. The plant was stable in Mode 3.
The inspectors reviewed the posttrip
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data and concluded that the plant had responded as expected. The 10 CFR 50.72(b)(2)(ii) notification was made to the NRC Operations Center within the required 4-hour period following the event.
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The licensee's investigation into the event identified the cause of the pressure spike to be either a failure of the pressure transmitter power supply
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card or the transmitter itself..The power supply card was replaced. The
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removed power supply card was tested in the shop under varying conditions, but.
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the transmitter. Temporary instrumentation was installed to monitor Channel 1-PT-456 prior to reactor startup. No additional problems were noted.
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2.3 Conclusions i
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The operators responded very well to the reactor trips.
The unit supervisor demonstrated good command and control during the recovery. actions of January 18, 1993.
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3 OPERATIONAL SAFETY VERIFICATION (71707)
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The inspectors conducted control room observations and plant inspection tours
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in Unit I and the common radiological controlled areas, and reviewed logs and i
licensee documentation of equipment problems.
Security activities were l
observed at the primary access point and from the alarm stations.
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3.1 Plant Startup i
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On January 19, 1993, the inspectors observed startup activities to return the
unit to power operation.
The unit startup was accomplished in accordance-.with
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Integrated Plant Operating Procedure IP0-002A, Revision 9, " Plant Startup from
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Hot Standby." The inspectors observed control room activities to place the
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main feedwater system in service.
It was noted that communications between l
the unit supervisor and the balance-of-plant operator were not consistent.
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Licensee managements' expectation that directions be repeated back was not l
always performed or were sometimes incomplete.
The inspectors discussed this
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observation with the shift supervisor. The shift supervisor subsequently i
stopped the activity and reiterated to the control room staff the expectations l
for use of repeat-back statements. Subsequent communications were noted to be
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good. The inspectors observed that the operators utilized good self-
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verification techniques prior to manipulating components and ensured that the.
system responded as expected. After establishing main feedwater flow to the
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steam generators, the auxiliary feedwater system was secured in accordance with Procedure 50P-304A, Revision 9, " Auxiliary Feedwater System."
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3.2 Valve and System Lineup f
The inspectors walked down the Unit 1 instrument air system control board f
operator aid to verify that it actually reflected the current plant
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configuration. The instrument air system was found to be configured as
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indicated.
f The inspectors reviewed the Unit 1 locked valve log i.nd verified that the locked valves for chemical and volume control, boric' acid, hydrogen purge and
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exhaust, and component cooling water systems were locked in their correct
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positions or were deviated with proper approvals.
The. locked component list required Valves ICS-8479A-R0 and -B-R0 to be locked open; however, the t
respective remote valve position indicators did not indicate fully open.
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locked valve log did not indicate a deviation for these valves from' full open.
l The operators subsequently verified that the valves.were fully open and that l
the remote indicators were not properly aligned. The valve _ indications were i
corrected under Work Order 1-92-032417-00.
j The inspectors verified.that valves within the emergency core cooling system major flow paths were properly aligned. The inspectors walked down' accessible i
portions of the those systems and verified that the lineups were in accordance j
with the operating procedures.
Required auxiliary systems were found to be
operable. The main control board. indications were found to be consistent with
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field conditions.
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3.3 Main' Control Room Annunciator Status j
On January 25, 1993, at approximately 4:30 a.m., the inspectors noted that main control-room Panel X-ALB-13A, nonsafety-related Annunciator Windows 3.7, i
CR EMER LTG.BATT RM UNIT 1 FN TRIP /H2 Hi, and 4.7, CR EMER LTG BATT RM UNIT 2 j
FN TRIP /H2 Hi, were,in an alarm condition. ' Alarm Procedure ALM-0131, j
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Revision 2, " Alarm Procedure X-ALB-13A," identifies the probable cause.for
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these annunciators as air conditioning unit malfunction, exhaust fan
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malfunction, or hydrogen gas buildup due to charging of batteries.
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operator action is required; however, the procedure does direct the control i
room operator to dispatch an auxiliary operator to the applicable unit turbine
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building 830-foot elevation and correct the cause for the alarm.
The inspectors noted that the annunciator status sheet, dated January 24, 1993, i
identified that Window 4.7 was illuminated because of Clearance 2-93-0215 for j
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a Unit 2 Train C outage. The inspectors questioned the shift supervisor why both annunciator Windows 3.7 and 4.7 were illuminated.
He subsequently determined that the Unit I control room emergency lighting battery room fan had tripped earlier in the shift, but the Unit 1 balance-of-plant operator had
failed to dispatch an operator to correct the cause for the alarm.
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later determined that a spike on the battery room hydrogen monitor had tripped t
off the room exhaust fan.
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Operations Procedure ODA-401, Revision 5, " Control of Annunciators,
Instruments and Protective Relays," Section 6.1, establishes that, whenever
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any annunciator is lit, operators should promptly and aggressively pursue resolution of the indicated problem by following appropriate plant procedures.
In this instance, the operator failed to meet the guidance established in-j Procedure ODA-401.
The Unit 1 balance-of-plant has responsibility for responding to alarms on'the common annunciator panels in which Panel X-ALB-BA is included. Alarm
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t Window 4.7 was identified on the annunciator status log as having been'
annunciated since January 11 because of Clearance 2-93-0215.
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subsequently identified that thir clearance had been removed on January 20 and
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that the alarm was indicating a valid alarm condition.
The operators started
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I the exhaust fan and cleared the alarm condition.
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On February 9, 1993, the inspectors met with licensee management personnel to
review the status of Unit I control room annunciators in an alarm condition.
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During this review, the licensee identified two instances where the annunciator-status sheet, maintained by the operators, identified a work order
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which had been completed.
In each case, a new work request needed to be initiated to resolve an additional deficiency with the annunciator.
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requests were later initiated for each additional deficiency.
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The inspectors noted some similarities with.the conce'rns identified in NRC l
Inspection Report 50-445/92-20; 50-446/92-20, which initiated Enforcement i
Action EA 92-107.
The concerns included operator attentiveness to control
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board. indications, the effectiveness of the. shift turnover process, and communication within the operations organization. The cover letter dated -
July 23, 1992, also noted that the operators appeared to lack'a sense of the
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meticulous attention to detail expected and. required in the operation of a
nuclear power plant..Although operator performance has improved since the
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May 12, 1992, loss of spent-fuel pool cooling event and this most recent. issue
involved nonsafety-related annunciators, the inspectors are concerned with j
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some of the similarities previously noted.
The review of operator awareness and response to control room annuncirt. ors is considered an IFI (445;446/9307-01)
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3.4 Security Program Implementation
i The inspectors observed security access controls at the primary access point.
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Personnel and packages entering the protected area were properly surveyed.
l The inspectors observed personnel entry into vital areas and plant perimeter j
from the alarm stations. All observed activities were well implemented and
.l perimeter monitoring equipment was operable.
3.5 Radiological Control Area Controls The inspectors toured the Units 1 and 2 safeguards buildings and the common
auxiliary and fuel buildings.
It was noted that the radiation areas were properly posted, high radiation and very high radiation areas were locked and I
posted, and contaminated areas were identified by physical barriers.
Areas j
within Unit 2 which were recently included in the radiation controlled area i
had been surveyed and posted in accordance with the radiation protection i
procedure requirements.
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3.6 Conclusions The operators performed well during the plant startup and demonstrated good i
use of self-verification practices during control panel manipulations. The j
use of repeat-back communications were not consistently utilized. A concern
.j was identified regarding operator awareness and response to control room
Plant system configurations were appropriately maintained for instrument air-l
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and emergency core cooling systems. The security program was appropriately l
implemented and intrusion detection equipment was maintained operable.
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Good radiological controls were implemented for Units 1 and 2 radiation
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controlled areas.
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4 MAINTENANCE'0BSERVATION (62703)
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t 4.1 Diesel Generator (DG) Maintenance j
On January 20, 1993, the inspectors observed instrumentation and control (I&C)
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technicians repairing air leaks on DG 1-01 right bank butterfly control valve and on the starting air distributor block valve. DG l-01 was removed from service {LC0AR Al-93-0017) under Clearance 1-93-00341 and the work was r
performed using Work Order 1-93-029953-00. All authorizations had been
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obtained and the technicians used excellent work practices.
i Electrical maintenance (EM) personnel performed corrective maintenance (Wwk Order 1-92-031473-00) on the DG 1-01 jacket water cooler service water return
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valve (1-HV-4393). Work Order 1-92-031473-00 was also being accomplished f
under Clearance 1-93-00341 and active LC0AR Al-93-0017.
The EM personnel
removed a section of an internal jumper that had been pinched during a i
previous work activity. The jumper was worked in accordance with EM
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Procedure MSE-GC-1203, Revision 3, " Electrical Terminations Wire Sizes 26 AWG Through 10 AWG."
The EM personnel removed the damaged section of the wire, relugged, and reinstalled the lead on the correct terminal.
A quality control
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inspector verified that the wire was relugged correctly. An EM supervisor
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-observed the work. Good work practices were used throughout the activity.
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DG 1-01 had been removed from service and declared inoperable' at approximately 3:30 a.m. on January 20.
EM personnel were not aware that their work package
had been included under the LC0AR; therefore, other work activities associated with Units 1 and 2 took priority over work on Valve 1-HV-4393.
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checked several times on this work activity and began to question various organizations about the length of time DG l-01 had been inoperable.
The inspectors contacted the control room approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the DG t d been removed from service and the unit supervisor was unaware of the status of scheduled work.
The unit supervisor contacted EM and was informed that
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Valve 1-HV-4393 was currently being worked; however, subsequent checks by the
inspectors identified that the valve was not being worked.
The inspecto's-then contacted a work control manager about the delay in the maintenance
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activity on the valve and the work was then started immediately (4 p.m.',.
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Operation Notification and Evaluation Form 93-0222 was written by EM to identify the breakdown in communications among various onsite organizations
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and to address the reasons for managements' expectations-not being met. 15e
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inspectors _had the following concerns.
Operations was not aware of the status of work in relation to safety-
related equipment being out of service for maintenance. The DG was i
required per Technical Specification (TS) and a 72-hour shutdown action
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statement had been entered.
i EM was not cognizant of. the fact that the work on Valve 1-HV-4393 was
included under an active LC0AR.
W!.en operations contacted EM concerning status of work, EM informed the
unit supervisor that technicians were in the plant performing the task,
although work had not started.
The daily afternoon maintenance meeting failed to identify that this -
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work activity had not been started, thus further delaying the proper management of resources.
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4.2 Safety Iniection (SI) Pump Planned Outage j
On February 5,1993,- at approximately 5:35 a.m., SI Pump 1-02 (Train B) was removed from service to complete three work activities.
These involved:
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(1) retapping the pump shaft coupling housing base bolt holes
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(1-92-027931-00); (2) cleaning the station service water strainer to the pump
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bearing cooler (1-92-30586-03); and, (3) rework the strainer drain valve f
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(1-92-02320-00).
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The. inspectors observed that Work Order 1-92-027931-00 was initiated at t
approximately 8:30 a.m.
At 9:30 a.m. the inspector questioned the Unit I unit supervisor'about the status of the SI Pump 1-02 work activities and when the j
work activity would be initiated for the strainer. The. unit supervisor had j
understood that all the work activities were in progress. At 10:50 a.m. the
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inspectors noted that no work had begun on the strainer.
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It was subsequently learned that the work activity to rework the strainer drain valve work activity had been cancelled ard that this had been presented j
at the morning plan-of-the-day meeting. The inspectors noted that the Unit 1
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supervisor was not aware that the work had been cancelled by 11 a.m.
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Order 1-92-30586-03 was later worked and the LC0AR exited at 2:47 p.m.
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The inspectors discussed the delay in implementing the work activities on the
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SI pump with licensee management personnel. The inspectors were concerned
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i that. work activities"were cancelled after the LC0AR was entered.
In addition, i
the unit supervisor had not been appraised of the work activity status.
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was noted that the cleaning of an identical strainer on a containment spray i
pump was completed in less than 40 minutes.
On February 9,1993, the work l
control center manager issued an office memorandum to the Vice President,
Nuclear Operation identifying seven specific steps to provide an interim-
enhancement to the work control process supporting time critical LC0ARs. Two j
of the steps appear that they will provide an immediate enhancement for
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communication between the work group = + operations, j
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Work groups are to sign on and off clearances in the control room.
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Associated work documents will also be authorized and closed in the control room.
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Work groups will contact the unit supervisor when work activities are-l
restrained and will not be completed as scheduled. They will provide an
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The inspectors will review the licensees actions to enhance the work control
process. supporting time critical LC0ARs during a future inspection
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(IFI 445;446/9307-02).
l 4.3 Containment Spra_y Pump Bearing Inlet Strainer-
On February 5, 1993,_the inspectors observed the cleaning of the Train A
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Containment Spray Pump 1-01 bearing cooling station service water inlet strainer. This preventive maintenance was conducted in accordance with Work-i Order 3-93-323528-01.
Prior to beginning work,-the inspectors verified that j
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_all supporting-documentation was complete and authorization to begin work had
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The station service water supply to the strainer was isolated l
using a standby clearance. This effectively reduced the time MDAFWP l-01 was
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out of service. Once the strainer basket was removed, maintenance personnel
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removed debris from the strainer and drain valve. Once the debris was removed, the strainer was reinstalled.
During the work activity, overall
communication and coordination between maintenance and operation was good.
The inspectors noted that the containment spray system LC0AR was entered in
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the surveillance status log. However, no entry regarding the containment l
spray pump being out of service was made in the reactor operator 109 It was
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later verified that the reactor operators were cognizant of the containment
spray pump status.
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4.4 Status of Field Work Requests
The inspectors reviewed the material condition of safety-related components to verify that hardware deficiencies were being properly identified. Selected
work request tags were compared to the licensee's action work request tracking
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system to verify they were appropriately entered into the tracking system.
l The inspectors found that the licensee was appropriately identifying hardware deficiencies in accordence with their work control program. However, two i
examples were identified on the turbine-driven auxiliary feedwater pump where the work activity had been completed, but the work request tags had not been removed. These work requests were Nos. 100682, initiated August 24, 1991, for i
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a governor packing leak, and 122066, initiated March 25, 1992, for a governor oil leak.
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t NRC Inspection Report 50-445/92-14; 50-446/92-14, paragraph 7.1, identified a r
similar problem with the failure to remcve work request tags following
completion of the work activity.
Violation 445/9214-01 was issued on July 7, t
1992, concerning this deficiency. The inspectors determined that the l*
corrective actions for Violation 445/9214-01 had not been fully implemented at the time of this latest occurrence and that concerns regarding these
corrective actions will be discussed in NRC Inspection Report 50-445/93-12; 50-446/93-12.
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4.5 Conclusions
Maintenance work activities were performed in accordance with the work
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instructions. Communication between operations and the maintenance
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organizations did nc' provide for prompt entry and exit from time critical
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LC0ARs. An observation was identified concerning additional work request tags
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not being removed after the work activity was completed.
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5 SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and
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components to verify that the activities were being performed in accordance
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with the TS. The applicable procedures were reviewed for adequacy, test instrumentation was verified to be in calibration, and test data was reviewed
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. for accuracy and completeness. The inspectors ascertained tha't any ~
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deficiencies identified were properly reviewed and. resolved.
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5.1 Emergency DG Fuel Oil Sample
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'The inspectors observed mechanical maintenance and chemistry personnel
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sampling DG Fuel Oil Storage Tank 1-01 for water and sediment.
The sample was
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obtained to satisfy TS surveillance requirements (Work Order 5-92-500180-AH).
The inspectors reviewed the work order and identified that mechanical
maintenance personnel had removed the missile shield from the storage-tank without having 5:gned off the step in the work order indicating that the
correct component was selected. - The verification step for the correct component had signature blanks for mechanical maintenance.and chemistry.
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Several other steps had been compaeted; however, the steps had not been initialed cs being completed. Discussions with the two mechanical maintenance
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technicians ir.dicated that both individuals had verified that the storage tank
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missile shield matched the component identified in the work order. -The nspectors :,ubsequently met with the mechanical maintenance supervisor and i
identified the administrative personnel errors to him.
It'was confirmed that i
mar,aget'ent expectations were not completely met during the performance of the
surveillance activity.
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The work area was classified as a Housekeeping Zone 3.
Procedure STA-607, Revision 13, " Housekeeping Control," requires the logging of all items smaller-l than the largest opening to be. logged on Form STA-607-03 when material and
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tool accountability is posted as a zone requirement. The mechanical maintenance technicians properly posted the area and were logging toals and
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materials into the area.
During the performance of the work, a roll of paper
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i towels w a loggeo into the zone. Numerous individual sheets of towels were used and no reconciliation of the number of towel sheets used verses the i
number removed from the work area was performed. The inspectors questioned i
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the accountability control individual as to whether he was able to positively verify that all material had been removed from the area.
The individual was
M able to positively verify that all the towel sheets had been removed
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because of the logging practice. The inspectors noted that the accountability
control individual had met the housekeeping control administrative
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j The quality control inspector observing the closure of the tank indicated that.
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the practice of logging in rolls of paper towels and boxes of K-Dries (wipes)
was common.
The inspectors discussed these observations and concerns with the operations
manager. On February 11, 1993, the mechanical maintenance manager issued an
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office memorandum discussing the requirement of Procedure STA-697 and that-
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each item including sheets of paper towels are to be individually logged in i
and out of a material / tool accountability area.
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5.2 Channel Calibration On February 4, 1993, the inspectors observed I&C technicians perform a channel calibration on the current-to-pneumatic regulator and positioner for the component cooling water return pressure control Valve 1-PV-4553 on Train B Safety Chiller 1-06.
The calibration was conducted in accordance with Work Order 1-92-017452-0 and Procedure INC-4053A, Revision 1, " Channel Calibration Safety Chill Water System Condenser Pressure Control Channel 4553." Prior to beginning work, the I&C technicians verified the correct equipment was tagged and that the required clearances had been hung.
The I&C technicians tested the pressure control valve and verified that the valve positioner and current-to-pneumatic regulator were outside their accepted range as stated in the work order.
Using the instruction delineated in the work order and the procedure, the I&C technicians successfully performed the calibration.
Good work practices were exhibited throughout the entira evolution.
5.3 Hydrogen Rc:ombiner Analog Channel Calibration Test (ACOT)
Surveillance Test INC-7842A, "ACOT on H2 Recombiner X-AIC-Ill2B," was performed by three I&C technicians. A copy of the procedure was present at the test location. The inspectors noted that the I&C personnel rigidly followed the test procedure, signing each step as it was performed and including the required verification signatures where required. The I&C personnel maintained good communication between themselves and with the control room.
Each individual demonstrated a thorough knowledge of the testing procedure. The inspectors also noted that all testing instruments used were within their current calibration period.
The radiation work permit and industrial safety precautions were observed.
The results of the ACOT did not meet the acceptance criteria. The maximum gas span criteria was 3.5 percent and the test result was 4.0 percent.
It was determined that the gas analyzer testing cell had degraded and required recalibration. The cell was calibrated and the I&C personnel again performed the ACOT.
The rasults of the surveillance were within the procedure and TS acceptance criteria.
5.4 SI S_ystem Operability Verification Surveillance Test OPT-204A, " Safety Injection System Operability Verification," was performed by an auxiliary operator, a control room operator and a vibration analysis technician.
A copy of the procedure was present at the test location.
The inspectors noted that the testing personnel rigidly followed the test procedure, signing _each step as it was performed. The auxiliary operator maintained good communication with the control room.
Each individual demonstrated a thorough knowledge of the testing procedure.
The inspectors also noted that all testing instruments med were within their current calibration period.
The test results met t
'tance criteria and the requirements of the T f
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5.5 Charging System Surveillance Test OPT-201A, " Charging System," was-performed by an auxiliary operator, a control room operator, and a vibration analysis technician with assistance from radiation protection.
A copy of the procedure was present at the test location. During the performance of the test, a small leak was discovered in the pump discharge pressure test gage.
Radiation protection was
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notified and the technician barricaded the area and installed a drip collector. The leak was very small and it was determined that it would have no effect on the test performance.
The test results met the acceptance
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criteria and met the requirements of the TS.
5.6 Conclusions
The surveillance program was appropriately implemented.
Personnel performance
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during testing activities was generally very good. One example was identified
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where administrative requirements were not met. An observation was made concerning material / tool accountability and additional management guidance was provided to enhance the process.
6 FOLLOWUP DN CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
l (Closed) Violation 445/9247-01:
Control of Heavy loads Near the Reactor.
i Vessel Head
- This violation involved several examples of contractor personnel failing to i
follow procedural requirements while operating the polar crane in the vicinity i
of the reactor vessel-head. These procedural violations allowed heavy loads
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to contact vessel head components. - Additionally, the heavy loads snagged an I-beam extending from the refueling cavity liner.
TV Electric Letter TXX-93039, dated January 29, 1993, stated the cause for this violation was failure of contractor personnel to implement the requirements contained within plant procedures and to establish proper communications during the rigging process.
The review of the licensee's immediate corrective actions and subsequent field observations of rigging operations indicated that the licensee had taken appropriate and immediate actions to address the violation.
The long-term corrective action to prevent recurrence adequately addressed the rigging
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concerns.
7 ONSITE REVIEW 0F LERS (92700)
The inspectors reviewed the below listed LERs to determine whether corrective actions were adequate and whether the responses to the events were adequate and met regulatory requirements, license conditions, and commitments.
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7.1 (Closed) LER 445/91-003-01:
"Less than Adeouate Procedure Review leading to the Failure to Fully Satisfy ASME Section XI Testing Reauirements" During a Unit 2 ASME Section XI test requirement procedure review, the licensee identified that the residual heat removal inservice testing plan would not have been met for the pump discharge check valve full flow testing.
This same deficiency was found to be applicable to Unit 1.
Plant' Incident-
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Report FX-91-200 was initiated to review the master surveillance test list to ensure:
(1) consistency with the source documents, (2) adequacy of the-implementing procedures, (3) adequacy of scheduling activities and frequency, and (4) proper overlap when multiple procedures cover a single activity.
Revision I to this LER identifies that the overall inservice testing (IST)
plan review will be performed as discussed in LER 445/91-007-00, "Less than fully Adequate Procedure Review Leading to the failure to. Fully Satisfy ASME.
Section XI Testing Requirements." LER 445/91-007 is discussed in paragraph 7.2.
The inspectors verified that the licensee had implemented the above corrective action. During the sample review of the master surveillance test list and implementing procedures, the licensee idencified that the AFW check valve full flow test was not being performed in accordance with the IST plan requests..
The licensee's actions to resolve this finding are provided in'the
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LER 445/91-007 discussion.
7.2 (Closed) LER 445/91-007-01:
"Less than Adeauate Procedure Review leading to the failure to Fully Satisfy ASME Section XI Testing Reautrements" On March 15 and 27, 1991, the licensee identified examples where the acceptance criterion of ASME Section XI testing requirements for AFW check valves was not adequate.
The licensee initiated a review of IST implementing procedures to assure that the appropriate flow rate acceptance criterion was utilized for check valve stroke testing. This resulted in identifying deficiencies with the test of the component cooling water check valves.
The specific deficiencies were promptly resolved.
In August 1992, the licensee completed this review of the Comanche Peak Steam Electric Station Units, I and 2, IST plan.
This review identified 18 additional valves which were not within the scope of the IST plan but should have been. Several other valves were identified which specified additional test requirements. The licensee documented the results of this
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review on Operation Notification and Evaluation Form 92-795.
Based on an assessment of the scope of the licensee's corrective actions and their implementation, the inspectors concluded that the corrective actions were appropriate.
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7.3 (Closed) LER 445/91-010:
" Unit 1 Operated Outside Technical Specification Due to Auxiliary Feedwater System Test Line Isolation Valve Not Fully Closed"
On March 22, 1991, the licensee identified that the Train B MDAFWP 1-02-
recirculation test line isolation valve was partially open.
It was noted
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that, with the recirculation test line isolation valve partially open, the
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Pump 1-02 minimum flow was 8 gpm less than the TS 3.7.1.2 required flow of 430
gpm at 1372 psi, r
The licensee identified three poterMal causes for the Pump 1-02 recirculation j
test line isolation being partially open.
These were:
(1) the auxiliary j
operator and independent verifier failed to fully close the valve; (2) the
valve was disturbed after it was closed; or (3) the vibration through the line
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caused the valve to back off its seat. The licensee's corrective actions were i
directed at determining if vibration could cause the valve to partially open i
and to heighten the shift operations personnel awareness to ensure that each
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recirculation test line isolation valve associated with an AFW pump was-l closed. These corrective actions were found to be adequate to correct the i
potential causes. This issue is discussed further in paragraph 7.7.
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7.4 (Closed) LER 445/91-011:
"Oversicht in Preparation of a Temporary
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Modification Resulted in the Failure to Fully Satisfy a Technical Specification Surveillance Reauirement"
'l On March 22, 1991, the licensee identified that TS. Surveillance Requirement 4.6.1.9 had not been met for the 48-inch contair. ant purge
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outbound isolation Valve' l-HV-5538. The TS requires that eat., 48-inch and 12-
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inch containment and hydrogen purge supply and exhaust isolation valve "211
be verified to be locked closed at least once per 31 days. A temporary
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modification had been installed which placed a blind flange over
Valve 1-HV-5538.
This was performed because the valve had failed the local
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leak rate test.
TS Interpretation 014, Revision 1, " Containment Systems,"
initiated February 7,1991, specifies that the valves are operable with the
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blind flanges installed and that the same TS requirements are also applicable.
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recurrence. These were to:
(1) provide additional administrative controls'to i
enhance the temporary modification process for assessing TS surveillance j
requirements; (2) revise the LC0AR indexes; and (3) review the event through-i lessons learned with system engineering and operations.
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The inspectors verified that the licensee had implemented each of the
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identified corrective actions. The temporary modification process was revised to require that procedure changes be effective prior to signing tha'; the'
l temporary modification installation is complete. The tracking and active LC0AR indexes were revised to identify when specific actions ~ are required.
The lessons learned from this event were reviewed with the engineering and i
operations organizations.
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7.5 (Closed) LER 445/91-031:
" Containment Ventilation ~ Isolation Due to Conservative Radiation Monitor Setpoint"
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On December 6, 1991, the containment was being vented to decrease containment pressure.
Subsequently, the containment particulate, iodine, gaseous monitor gas channel spiked into an alarm condition. The. licensee determined that'the channel alarm setpoint had been set too low. The initial setpoint had been established based on no detectable noble gas activity.
The licensee revised the particulate, iodine, gaseous monitor gas channel alarm setpoint to use a default alarm setpoint when there is no detectable noble gas activity in the containment atmosphere. Other procedures for radioactive effluent releases were reviewed and revised to incorporate actual plant conditions into the radiation monitor alarm setpoint calculation. The revised setpoints were found to be consistent with the: effective' dose calculation manual and complied with 10 CFR Part 20 requirements The inspectors found the licensee's corrective actions to be appropriate.
7.6 (Closed) LER 445/91-023:
" Reactor Trip Resulting From Erratic Operation of the Main Turbine Electrohydraulic Controller
. On October 3,1991, with Unit 'I at 30 percent power, - a manual react'or trip was initiated because of a sensed Hi-Hi steam generator level.- _ The Hi-Hi setpoint tripped the operating main feedwater pump. A main steam pressure spike created during electrohydraulic control system testing caused the steam generator narrow range level transmitter to sense the level _ change.
The licensee implemented Design Modification DM-91-074 during the first refueling outage which provided a filter card with a lag time constant--in the
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steam generator narrow range level instrumentation.
This design modification-was incorporated by Work Orders C920007034, C910007089, C9100071899, and C910007379. The inspectors found this corrective action to be
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appropriate.
7.7 (Closed) LER 445/92-20:
" Motor Driven Auxiliary Feedwater Pump Test Line-Isolation Valve Mispositioned Due to Valve Operating Apparatus Design l
Problem On_ July 20, 1992, the reactor operator manua'ly tripped the reactor.from 100 percent power because of a loss of main feedwater to the steam generator.
t Both MDAFWP were started to supply the. steam generators. With both pumps in i
operation, the licensed operators noted an approximate 100 gpm difference
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between the MDAFWP 1-02 output and the total-going to the respective steam
~i generators.
It was subsequently identified that the test line:is'olation valve
'{1AF-0055) remote hand wheel was open approximately 3/8 of_a turn open. This
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condition was determined to have existed since July 2, 1992. During the
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period that MDAFWP 1-02 was inoperable, the MDAFWP l-01 and turbine-driven AFW
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I pumps were operable.
LER 91-010 documented in paragraph 7$3 identifies an almost ' identical event
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involving Valve IAF-0055. The previous corrective actions included locking l
the valve closed and analyzing the vibration on Valve IAF-0055.
Subsequent.to
.i the second event, the licensee determined that the design of the valve remote i
operator (reduction through four separate gear boxes) did not provide'a i
positive means for verifying the valve was closed. ;It was then determined that the most viable means of verifying the valve was closed was to. isolate
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Valve IAF-0055 with flow through the test line and confirm that the flow drops
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Procedure Change Notice OPT-206A-R6-4 to Procedure OPT-206A,-
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Revision 6, " Auxiliary Feedwater Operability Test," Section 10.3, provided the
positive verification of Valve 1AF-0055 position by monitoring flow through
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the test line.
This procedure change became effective. August 16, 1992. _On
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January 23, 1993, the licensee revised Procedure OPT-206A to include the same l
method for verifying the test lines were isolated for MDAFWP l-01'and the
turbine-driven AFW pump.
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ATTACHMENT 1
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1 PERSONS CONTACTED
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t 1.1 10 ELECTRIC
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0. Bhatty, Site Licensing
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M. R. Blevins, Director of Nuclear Overview
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J. J. Kelley, Vice President, Nuclear Operations i
B. T. Lancaster, Manager, Plant Support D. R. Moore, Manager, Maintenance J. W. Muffett, Manager of Technical Support & Design Engineering i.
C. L. Terry, Vice President, Nuclear Engineering and Support i
1.3 NRC Personnel 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 An exit meeting was conducted on February 16, 1993. During this meeting, the
inspectors reviewed the scope and findings of the report. The licensee did
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not identify as proprietary any information provided to,_ or reviewed by, the inspectors.
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ATTACHMENT 2
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LIST OF ACRONYMS
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ACOT analog channel calibration test
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i DG diesel generator EM electrical maintenance IFI inspection followup item
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I&C instrumentation and control l
IST inservice testing
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LER
. licensee event report LCOAR-limiting condition for operation action requirement
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MDAfWP motor-driven auxiliary feedwater pump
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overtemperature SI safety injection
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SSPS solid state protection system
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TS Technical Specification
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