IR 05000413/1993026
| ML20059K700 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 10/29/1993 |
| From: | Freudenberger, Hopkins P, Lesser M, John Zeiler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059K688 | List: |
| References | |
| 50-413-93-26, 50-414-93-26, NUDOCS 9311160153 | |
| Download: ML20059K700 (23) | |
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UMTED STATES
/en #Ec%, NUCLEAR REGULATORY COMMISSION t
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4- REGION U -
T= e- })g g 101 MARIETTA STREET, N.W., SUITE 2900 l
% 'E ATLANTA, GEORGIA 30323 o199 ,
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Report No.c.: 50-413/93-26 and 50-414/93-26 :
Licensee: Duke Power Company i 422 South Church Street :
Charlotte, Docket Nos.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52 l
Facility Name: Catawba Nuclear Station Units 1 and 2 :
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Inspection Conducted: September 5, 1993 - October 2, 1993 !
Inspector: M' /o/M[/J R. J. Freudenberger, Senior Resident Inspector Date Signed ,
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Inspector: g M /s[2F41 f P. C. Hopkins, Resident Inspector Date Signed ,
a Inspector: bM /*[2Mf1 J.~Ze'iler, Resident Inspector Date Signed l
.h Approved by: M /d 9J
/e M. S. Lesser, Chief Date Signed l Projects Section 3A ;
Division of Reactor Projects i
SUMMARY Scope: This resident inspection was conducted in the areas of review of f plant operations, surveillance observations, maintenance :
observations, and licensee event reports. Backshift Inspections ,
were conducted on: September 7-10, September 16-17, and ;
September 23-2 [
t Results: Two violations were identified. The first involved two examples !
of failure to adequately implement the independent verification ;
process, which resulted in a reactor trip and a TS 3.0.3 entry (
(paragraphs 3.c and 3.d). The second involved two examples of i failure to report a TS violation and ESF actuation as is required i by 10 CFR 50.73 (paragraphs 3.f and 4.b). '
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9311160153 931029 3 PDR ADDCK 0500 ,
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l One Unresolved Item was identified involving the adequacy of_ the .i outside containment leakage testing program (paragraph 4.b).
One Inspector Followup Item was identified involving the control- !
of the amount of sealant material injected during leak sealing :
repairs (paragraph 5.e). i
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i REPORT. DETAILS
- Persons Contacted :
Licensee Employees j q
- G. Addis, Human Resources Manager ;
S. Bradshaw, Shift Operations Manager *
- J. Forbes, Engineering Manager -!
- R. Futrell, Regulatory Compliance Manager ;
- R. Jones, IAE Superintendent -
- W. McCollum, Station Manager .
W. Miller, Operations Superintendent !
- K. Nicholson, Compliance Specialist ';
- D. Rehn, Catawba Site Vice-President t Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personne ,
at NRC Resident Inspectors }
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- R. Freudenberger, Senior Resident Inspector !
- P. Hopkins, Resident Inspector >
- J. Zeiler, Resident Inspector
- C.-Yates, Intern .r s
- Attended exit intervie .i Acronyms and abbreviations used throughout this report are listed in the .;
last paragrap . Plant Status and Activities N Unit 1 Status Summary Unit 1 began the report period operating.at 100 percent power. On September 29, a turbine runback and associated reactor runback to 1 40 percent power occurred when the "A" Main Feedwater Pump tripped. The pump tripped while operations personnel were performing the weekly main feedwater pump over s peea i-ip test. _ *
Details pertaining to this rcnback are contained in pacagraph Later that day reactor power was reduced to 10 pe. cent and the ;
turbine was taken off line for rep 0irr! to the turt,?e electrical ;
overspeed trip device. The folloi,ing day, after these repairs 1 were completed, the turbine was "JlaC0d back on-line and reactor power was increased. The unit reuned full power 'on October 1 and !
operated at essentially full power for the remainder of the ' report
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I Unit 2 Status Summary t
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Unit 2 began the report period operating at 100 percent power. On l September 25, a reactor trip occurred due to a turbine trip, which !
was caused by the inadvertent closing of the "A" Steam Generator !
Main Steam Isolation Valve. The Main Steam Isolation Valve closed !
when IAE technicians opened the incorrect sliding link during i troubleshooting of a containment sump level control proble l Details pertaining to this trip are contained in paragraph 3.d.
Reactor startup commenced the following day and the unit was i placed on-line on September 27. The unit reached full power on l September 29 and operated at essentially full power for the !
remainder of the report perio l Inspections and Activities of Interest NRC managers visited the site in preparation for a Systematic ,
Assessment of Licensee Performance during the report period as !
follows:
D. Matthews, Director, Project Directorate 11-3, NRR, and Martin, Catawba Licensing Project Manager, NRR, were on site September 27 and 2 :
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J. Jaudon, Deputy Division Director, Division of Reactor Safety, Region II, was on site October J. Johnson, Deputy Division Director, Division of Reactor j Projects, Region II, was on site October j i Plant Operations (71707) : General Observations ,
The inspector reviewed plant operations throughout the report period to verify conformance with regulatory requirements, TS and ;
administrative controls. Control Room logs, the Technical 1 Specification Action Item Log, and the R&R log were routinely reviewed. The inspector observed shift turnovers to verify that they were conducted in accordance with approved procedures. The ;
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number of licensed personnel on each shift inspected either met or l surpassed the requirements of Technical Specification l Furthermore, daily plant status meetings were routinely attende Plant tours were performed on a routine basi During the plant tours, the inspector verified by observation and interviews that proper measures were taken, and procedures were followed, to ensure that physical protection of the facility met current requirements. Items considered included the adequacy of
, the security organization; the establishment and maintenance of s gates, doors, and isolation zones in the proper conditions; and the use of access control badgin . - . __ _ . .
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In addition, the areas toured were observed for fire prevention 1 and protection activities and radiological control practices. The !
inspector also reviewed PIPS to determine if the licensee was ,
appropriately documenting problems and implementing corrective -!
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q b. Door Labelling Discrepancies 1 On September 8, at approximately 2:00 p.m., the inspector noticed }
a part of a small laminated sign sticking out from the committed 1 fire door #AX353 at the door latch. The inspector pulled on the !
door to see if it would open and found that the laminated sign *
prevented the latching mechanism of the door from operating i properly. The door #AX353 was checked by security daily per procedure PT/0/A/4400/0lH. The inspector verified that on September 8, at 6:15 a.m., the door was checked by Security and no problem was noted. This fire door joins Room 370 (inside the RCA)
and Room 372 (outside the RCA). The small laminated sign was placed on the door knob by Radiation Protection to prevent personnel from exiting the RCA from Room 370. The sign stated,
"STO THIS IS NOT AN RCA EXI FOR ASSISTANCE CONTACT RP AT EXT. 5588." Similar signs were located on various doors-throughout the RCA that lead to areas outside the RCA. The inspector notified RP and the signs were removed by RP. These temporary signs were in addition to permanently mounted signs that adequately served the same functio The inspector also noted that the permanent sign mounted on the door contained information that was out of date. Permanent signs-were located on various doors throughout the plant. The inspector's review of the information located on several doors revealed that a majority of the doors had-signs attached-that contained outdated information. Fire Protection, RP and Security-
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information was outdated. The outdated information resulted from recent program changes and incomplete evaluation of items affected by the change The licensee established a team to identify corrective actions, including definition of responsibilities and development of revised standardized signs to ensure that doors with multiple functions are correctly identifim' and labelled, c. Technical Specification 3.0.3 Entry On September 23, both units were operating at full power. The "B" train of the Control Room Area Ventilation System was out of service for scheduled preventive maintenance. Work associated with WO 9303576401 and Nuclear Station Modification 50433 was in progress. The modification was part of an effort to improve the reliability of the Control Area Ventilation System. The work involved the deletion of a battery room fan and associated wirin While removing a wire, the IAE technicians traced the wire within
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the cabinet they were working in to verify it'was'the correct wire. Upon returning to the location to be cut, the technician :
inadvertently cut a wire located just below the wire'~ intende ]
This action caused the "A" Control Room Area Ventilation' System t Chiller to tri .;
With the "B" train out of service and a trip of the "A" train chiller, both units entered TS 3.0.3 at 1:15 The wire was
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reconnected and TS 3.0.3 was exited at 3:04 The significance of the removal of the wrong wire and'resulting !
trip of the chiller was exacerbated by the inoperability of-the >
redundant train. If ongoing work had been limited to the vicinity ;
of equipment that affected the operation of one train of the '
system, entry into TS 3.0.3 could have been avoided. The '
significance of the event was minimized due to the: fact that the ;
ventilation portion of the system was unatfected, Control Room '
pressurization was maintained, and the temperature in the Control i Room area did not increase substantially while the chiller was inoperabl j During review of the above issue, the inspector noted that .t
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independent verification was required when altering circuits / equipment (e.g., when removing wires). CNS Directive 4.2.2, Independent Verification, provides ir " ructions for proper >
self verification and independent verification. Step 3.2.2 of the .
procedure describes the process in which the " Doer" and " Verifier" a independently decide an action is correct before the " Doer" ;
performs an action. Part of this verification is the correct !
identification of the component (wire) to be manipulated. In this-
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instance, it appeared that the lead technician (the " Doer") did not adequately "self-check" to properly identify the correct wir *
Furthermore, there was insufficient verification on the part of the other technician to ensure that the correct wire was identified. The inspector concluded that adequate independent verification of the intended actions did not occur during this~ ;
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activit This issue is considered to be a violation of Technical !
Specification 6.8.1 for failure to follow the independent verification requirements in CNS Directive 4.2.2 and procedure ;
IP/0/A/3890/01. This issue is one of two examples in this report that collectively constitute Violation 413, 414/93-26-01: Failure to Adequately Follow Independent Verification Requirement , Unit 2 Reactor Trip !
On September 25, with Unit 2 operating at 100 percent power, IAE >
personnel were troubleshooting a control circuit problem in the~ 1 containment sump pump 2A. During this troubleshooting, an incorrect sliding link was opened, which caused the 3G "A" Main
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i Steam Isolation Valve, 2SM-7, to close. As a result, level- in the - !
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other SGs increase Level in SG "D" reached the Hi Hi level i setpoint, which resultt.J in a turbine trip. The reactor tripped as expected due to a turbine trip above 69 percent power. As a ;
result of the turbine trip, the main feedwater pumps tripped and a l feedwater isolation occurred. Both motor driven auxiliary !
feedwater pumps and the turbine-driven auxiliary feedwater pump '!
automatically started as expected. The turbine-driven auxiliary '
feedwater pump started due to Low-Low level in two SGs .during the' l subsequent SG 1evel shrinkage. The pump was manually secured by '
the operators per the emergency procedure shortly after the tri During the transient, reactor coolant system temperature cooled to I approximately 540*F, primarily due to the full actuation of l emergency feedwater. Following the transient, the unit was -
stabilized in mode 3. Decay heat removal by steaming to the condenser was delayed due to difficulties with turbine gland ,
sealing steam automatic pressure control and the-resulting low condenser vacuu The inspector responded to the site following notification of the -
trip and reviewed or monitored 1) operator response to the trip, ,
2) the cause of the trip, 3) licensee recovery actions, and, 4) ;
the licensee's preliminary trip investigation repor Based on .
this review, the inspector determined that the operators responded !
adequately to the trip and all safety systems performed as '
designed. Operator response to the trip was complicated by the l failure of the steam pressure control valve to open. During low !
power operation, this valve normally opens to supply main turbine gland sealing steam. The licensee was aware of the improper l
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operation of the valve and generated a work request that had been open since before the Unit 2 refueling outage that ended in April 199 l The improper operation of the main turbine gland sealing steam pressure control valve contributed to higher than normal steam j load while the unit was operating in mode 3. Two actuations of j the Low RCS Average Temperature Interlock (P-12) occurred while the licensee attempted to place the main feedwater pumps in service in preparation for plant restart. This interlock isolates ,
the steam dumps to the condenser when RCS average temperature !
decreases 4*F from normal (557'F to 553*F) to protect against an overcooling transient initiated by a malfunction of the steam dump .
control system. In both cases the actuations had no impact on ,
plant operation because the steam dump valves had modulated closed-prior to the P-12 actuatio The licensee is reviewing their procedure for preventing unnecessary P-12 actuation The inspector interviewed the two IAE technicians involved in the WL system troubleshooting and the events leading to the trip. The ,
technicians were investigating the computer high level alarm for !
the 2A WL sump when indicated sump level was normal. To test the ;
proper operation of the control circuits for the two pumps ,
associated with the 2A WL sump, the technicians developed a
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troubleshooting plan. The plan involved opening a slid'ing link in l the start circuits for each pump so that each pump could be !
stopped locally after being started with a simulated signal. The !
two links were identified as A-5 for pump 2Al and A-32 for pump .
2A2. Drawing CNEE-0260-02.14 indicated that link A-5 was located in electrical cabinet 2ATC14 and drawing CNEE-0260-02.15 indicated that link A-32 was located in cabinet 2ATC16. While reviewing the i two drawings, both technicians improperly identified the cabinet ,
location of one of the slide links. They assumed that link A-5 i was located in cabinet 2ATC16, where link A-32 was locate Prior ;
to conducting this test the technicians listed the links to be l opened in procedure IP/0/A/3890/01, Controlling Procedure for i Troubleshooting and Corrective Maintenanc Due to the error made !
in reading the drawing, link A-5 was listed to be opened in .
cabinet 2ATC16 instead of cabinet 2ATC1 Immediately following !
the trip, the technicians reviewed their actions and identified :
the error in cabinet location. This review confirmed that opening !
link.A-5 in cabinet 2ATC16 had caused the closure of the SG "A" '
main steam isolation valv i
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While reviewing the troubleshooting procedure the inspector noted l that independent verification was required when circuits and 'l equipment are altered (i.e., when sliding links are opened). CNS f Directive 4.2.2, Independent Verification, provides instructions I for using proper self verification and independent verificatio !
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Step 3.2.2 of the procedure describes the process by which the
" Doer" and " Verifier" independently decide that an action is !
correct prior to the execution of the actio Part of this !
verification is the correct identification of the component !
(sliding link) to be manipulated. Based on discussions with the l technicians, the inspector determined that they read the drawings ;
and developed the troubleshooting steps together. There appeare !
to have been too much reliance on the part of the lead technician t (the " Doer") to properly identify the correct cabinet locations i
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and insufficient verification on the part of the other technician (the " Verifier") to ensure that the correct cabinet was identifie The inspector concluded that adequate independent verification of the intended actions did not occur during this activit This issue is considered a violation of Technical Specification 6.8.1 for failure to follow the independent verification requirements in CNS Directive 4.2.2 and procedure IP/0/A/3890/0 This issue is one of two examples in this report that collectively constitute Violation 413, 414/93-26-01: Failure to Adequately Follow Independent Verification Requirement e. Unit 1 Runback On September 29, during the performance of PT/1/A/4250/04A, Feedwater Pump Turbine Weekly Test, the "A" main feedwater pump tripped. This initiated an automatic runback of Unit During
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the runback, the operators manually increated the rate of runback of the main turbine and took manual speed control of the running .
"B" main feedwater pump to prevent a high discharge pressure tri !
Power was stabilized at approximately 40 percent following the i transien l Licensee investigation into the cause of the runback revealed no . ;
discrepancies in the operation of the main feedwater pump turbine ;
controls. The apparent cause was the relaxation of the spring
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loaded " Lockout" pistol grip switch used to bypass turbine trip :
signals generated during the test. A similar instance occurred in December 1992 on Unit 2 and resulted in a reactor trip. During i the transient the load rejection bypass system failed to operate !
properly, since a hotwell and a condensate booster pump failed to j automatically start. The licensee attributed this to a failed :
fuse in the control circuitr !
The inspector interviewed the operators in the control room at the i time of the runback. Based on discussions with those operators !
and a review of transient data, the inspector noted that operator i actions to stabilize the plant were based on observation of' ~
appropriate supporting parameters and were directed or concurred !
with by shift supervision prior to their implementatio l: Reportability of Ice Condenser Doors Opening l
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During this report period the inspector became aware of an event !
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at the McGuire Nuclear Station involving a steam leak inside Unit i 2 containment. The increase in containment pressure due to this
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l steam leak resulted in the opening of the ice condenser doors and i the subsequent melting of some ice. The McGuire licensee reported i
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this event to the NRC in accordance with 10 CFR 50.72(b)(2)(ii)
- for an ESF Actuation resulting from the opening of the ice i condenser door i
The inspector reviewed the details of a transient that occurred at Catawba on January 31, 1993. This event occurred with Unit ~1 in l i
Mode 4, shutting down for a refueling outage, and placing the RHR ,
system in service. A water hammer caused piping to a vent valve i in the RHR system to fail, thereby releasing steam into' )
containment. Refer to Inspection Report 413,414/93-07. During !
this transient the ice condenser door opening alarm reportedly
annunciated when there was a corresponding increase in containment pressure. The leak was isolated when the operators closed the RHR suction valves from the Reactor Coolant System. However, these valves were reopened twice for a brief time during operator troubleshooting so that the cause of the abnormal plant response could be determined. Each time the valves were opened, the ice condenser door opening alarms came in because of the steam leak
inside containment and subsequent increase in containment l pressure. Each time the alarm annunciated, it immediately cleared upon operator acknowledgemen !
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The inspector reviewed Station Report and PIP (2-C93-0049) for' l this event, noting that licensee personnel had determined that i this transient was not reportable to the NRC. However, the !
inspector found no mention of an evaluation of the ice condenser i door opening alarms. Following the transient licensee personnel did conduct inspections of the ice condenser and found no ..
indications of significant ice melt. The inspector considered I that the ice condenser door opening alarms indicated that some of i the doors opened during the event, although it appears that th l
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doors may have immediately reclosed since the alarms cleared ;
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immediately. Regardless, the opening of the ice condenser doors constitutes an ESF actuatio .
The inspector reviewed the LER reporting requirements. 10 CFR' :
50.73(a)(2)(iv) requires that the licensee submit to the NRC '
within 30 days an LER for any event or condition that resulted in l a manual or automatic actuation of any ESF. The opening of the 1 ice condenser doors during this containment pressurization event :
is considered an au'omatic ESF actuatio After the inspector discussed this issue with licensee management, !
the licensee indicated that an LER would be prepared for this !
event. Since this issue was one of two events identified during !
this report period that were not reported as required, the !
inspector expressed concern over the adequacy of the licensee's '
process of screening PIPS for reportabilit The licensee ti indicated that a review of the event reporting process would be- ..
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Failure to report this event was determined to be a violation of I the requirements of 10 CFR 50.73(a)(2)(iv). This violation is one j of two examples in this report that collectively constitute *
Violation 413, 414/93-26-02: Failure to Submit LER on TS 6. !
Violation and ESF Actuation'. i Surveillance (61726) {
During the inspection period, the inspector verified that plant operations were in compliance with various TS requirements, such as ,
those for reactivity control systems, reactor coolant systems, safety <
injection systems, emergency safeguards systems, emergency power i systems, containment, and other important plant support systems. The l inspector verified that surveillance testing was performed in accordance <
with approved written procedures; test instrumentation was calibrated; ;
limiting conditions for operation were met; appropriate removal and :
restoration of the affected equipment was accomplished; test results met i acceptance criteria and were reviewed by personnel other than the
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individual directing the test; and any deficiencies identified during ;
the testing were properly reviewed and resolved by appropriate ;
management personnel. The following items were considered noteworthy !
for discussio I
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a. The performance of the nuclear service water pump train A l Performance Test (PT/0/A/4400/22A) was observcd in its entirety by j the inspector. A review of the procedure -revealed several changes j that were made prior to test performanc ,
The inspector reviewed the changes to the performance test procedure and a 10 CFR 50.59 evaluation that addressed the j changes. The evaluation was performed by qualified engineering i personnel and was reviewed by appropriate management personne j i
The purpose of the performance test was to verify IWV requirements ;
for the full stroke of valves 1RN9 and 2RN9 and to verify the !
operational readiness of nuclear service water pumps lA and 2 l The inspector reviewed the Nuclear Service Water System flow i diagrams (CN-1574 and CN-2574) series with the engineers. The i inspector also reviewed the Catawba Nuclear Station Technical j Specifications section 3_7.4, along with Operations Procedure :
OP/0/A/6400/0GC, Nuclea. ,ervice Water System. The inspector 1 observed the equipment to be used, evaluated personnel J qualification, and attended pre-job briefings. The inspector i noted that the procedures were properly execute j PT/2/B/4250/02A, Maintenance Weekly Trip Test, was also reviewed and observed in dept ;
I No noteworthy discrepancies or observations were identified. The 1 Performance Tests were professionally accomplishe !
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b. Program for Monitoring Outside Containment Leakage j i
The inspector reviewed the licensee's corrective action for PIP 0- !
C92-0678 involving. the failure.to perform portions of the outside -l containment leakage testing at the required TS frequency. This 1 problem was identified by the inspector in August 1992 when it was I determined that several portions of the ECCS system had not been !
tested during past refueling cycle intervals. TS 6.8.4 requires ;
that testing be performed at refueling cycle intervals or les ?
This problem was the result of licensee personnel failing to !
recognize these tests as TS requirements and failing to schedule l them correctly in the CPT computer scheduling program. The l failure to perform this testing at the required frequency was the ,
subject of Non-Cited Violation 413, 414/93-22-0 j During review of this PIP, the inspector noted that the license !
had determined that the issue was not reportable to the NRC. The ;
justification documented for this decision was that TS 6.8.4 was i an Administrative Requirement. 10 CFR 50.73(a)(2)(1)(B) requires j the licensee to report to the NRC any operation or condition !
prohibited by the plant's TS. The inspector reviewed the guidance in NUREG-1022, Licensee Event Report System, for reporting missed j TS Administrative Requirements. NUREG-1022, Supplement No. 1, .
Question 2.9, states that missed TS Administrative Requirements !
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- that affect plant operation must be reported. The inspector- !
considered the failure to conduct these tests during the refueling interval to potentially affect plant operation because leakage }
could develop and go undetected for longer periods than is {
necessary. The licensee stated that they had not previously j considered the frequency of the testing as potentially affecting 1 operation because it did not result in a' condition prohibited by the Technical Specifications. Therefore, the issue was not considered reportable. The inspector discussed the reportability ,
of this issue with NRC personnel from the office of AE00, who are !
involved in LER reporting, and with Region II management. Based !
on these discussions, the inspectors determined that this issue l was reportabl !
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Failure to report this issue was determined to be a violation of
. the requirements of 10 CFR 50.73(a)(2)(i)(B). This violation is ;
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one of two examples in this report that collectively constitute l Violation 413, 414/93-26-02: Failure to Submit LER on TS 6. i Violation and ESF Actuatio j
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The inspector reviewed the current controls for scheduling TS 6.8.4 testing. As a result of this review, the inspector determined that the CPT scheduling program had not been adequately corrected in August 1992 to ensure that each test is accomplished .
within each refueling interval. Since August 1992, two more tests
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have not been not performed at the required interva .se tests involved PT/2/A/4201/01 for the Unit 2 "A" train Safety injection
System piping, and PT/2/A/4206/06 for a portion of the Unit 2 t
. Chemical and Volume Control System piping. Both of these tests !
were to be performed during the Unit 2 operating cycle 5 or its associated cycle 5 refueling outage, which ended April 1, 199 Also, based on the current CPT schedule for seven other Unit I tests, these tests may not be performed during the upcoming operating cycle 7 or the associated cycle 7 refueling outag t The inspector determined that the corrective action for this PIP I was weak. The licensee had failed to correct the problem, which
l resulted in further instances of tests performed outside the TS frequenc At the end of the report period, the inspector was reviewing licensee corrective actions for leakage that is identified during ;
the performance of these tests to assess the effectiveness of the :
licensee's leakage reduction program. This issue will be tracked j as an unresolved item pending completion of this review. This !
item is documented as URI 413, 414/93-26-03: Adequacy of Outside Containment Leakage Reduction Progra . Maintenance (62703)
During the reporting period the inspector reviewed maintenance i activities to verify compliance with the appropriate procedures and T l l
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Methods used in this inspection included direct observation, personnel interviews, and records review. The activities associated with the followin'g activities were considered noteworthy: Maintenance Training Facility .
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The inspector reviewed the maintenance training facility for Catawba maintenance personnel. The corporate training involves generic areas such as team building, managerial and supervisory i skills, and communication skills, as well as company goals and ~ ;
philosophie ;
Mockups presently used included; emergency diesel generator, '
valves, limitorque valve motor operators, various breakers and relays, and steam generators. Layouts of shops and satellite work ;
areas were controlled by discipline for safety and efficienc '
Utilizing mockups for projects training, such as steam generators, valves, and breakers, was considered to be a positive attribute of '
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the maintenance training progra i Component Cooling System Maintenance i The inspector reviewed and observed major aspects of the component !
cooling system maintenance performed during the week of September j 1 l
After preventive maintenance on KC Pump 2A2 had been completed, the pump was placed in service at approximately 5:40 a.m. on September 15. Outboard bearing temperature indication increased ,
to approximately 165 degrees F within 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Test Procedure !
PT/2/A/4400/03A, for conducting a bearing stabilization test, !
specifies 160 degrees F as the test acceptance criterion, although .;'
this test was not being implemented at the time. ~ A computer alarm for associated analog point ID A0388 is.also set at 160 degrees .
Operators questioned exceeding this valu {
The inspector reviewed the 10 CFR 50.59 evaluation that was completed by licensee component engineering and determined that no 1 operability concern exists for the following reasons: l (1) Outboard bearing temperature had been stable at l approximately 165 degrees F for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />; j (2) Vibration had been monitored and found to be satisfactory; ;
(3) The licensee's Exxon representative was consulted regarding 1 the use of Teresstic 68 oil at the higher-than-expected temperature. The Exxon representative stated that the oil i can be expected to perform satisfactorily up to the range o degrees F. The basis for this conclusion was that *
the oil's oxidation rate doubles for every 18-degree ,
temperature increase above 150 degree l
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The component cooling pump manufacturer's engineering department ;
was also consulted about temperature limits for their 7308P i angular contact bearing (KC Pump 2A2 outboard bearing). The ;
bearing reportedly exhibited satisfactory performance for i continuous duty up to 225'F and for intermittent duty up to 250* ;
The cause of the high temperature was a'high oil level in the l bearing housing. The licensee performed the following followup !
actions to prevent high-temperature bearing conditions: l (1) They revised PT/l(2)/A/4400/03A(B) tt increase the bearing stabilization test acceptance criteria based on information ,
from both the bearing manufacturer and the oil manufacturer; !
and !
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(2) They implemented a change to the operator rounds sheet to lower the criteria for initiation of lubrication request '!
forms on the KC pump oil bubbler t The inspector observed the system tag out of the 2B KC heat i exchanger and the repair of 2B RN strainer. The inspector attended and observed tailgate meetings, including operator i turnover and the identification of affected component '
The scope of the operational and maintenance activities included :
the isolation and draining of the RN side of the 2B KC heat :
exchanger in preparation for tube cleaning. The 2B RN strainer ;
was also isolated for cleanin Operations hung R&R tags to support various train 2B work, which ;
included NV pump 2B, CA instrument calibrations and ND instrument :
calibratio ;
The inspector observed the coordination of work by operations, the ,
shift supervisor, the work control center, the SR0 and the Unit -i supervisor. The inspector also cbserved activities associated !
with the KC train 2B cross-train alignment for testing, recovery i from KC 2B cross-train alignment, and performance of RN flow '
balance for train "B" KC Heat Exchange Portions of the following work requests were observed: f i
WR 91064403 Install KC Cross-train Alignment !
WR 9204738601 Inspect and Remove RN Strainer 2B and Start i
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Backwash WR 9204738603 Restore Wiring to RN Strainer 2B Gear Box !
WR 9305845701 Preventive Maintenance on KC Pump 2B1 .
WR 9305845801 Preventive Maintenance on KC pump 2B2 I i
Overall, supervision and coordination of the working groups to !
accomplish the maintenance and testing discussed in this sectio !
was satisfactor , .
c. Unit 1 RN Upper Containment Ventilation Units Piping Replacement In June 1993, during the Unit 1 Condenser forced outage, the RN piping to the four Upper Containment Ventilation Units was inspected and several leaks due to corrosion were discovere This piping was repaired during the condenser outage. The licensee's Component Engineering group evaluated the condition of the piping and determined that major piping replacement was necessary. Component Engineering also determined that replacement work would directly impact the critical path of the upcoming outage work in upper containment. Licensee management decided to replace the upper containment portion of the RN piping prior to the outage, and then replace the lower containment and Auxiliary Building portion during the IE0C7 refueling outage, which was scheduled to begin October 30, 199 A team was formed to evaluate and plan the piping replacement modification. This team was comprised of personnel from Component Engineering, Design Engineering, Systems Engineering, Operations, Maintenance, Commodities, and Work Control. The modification package included Temporary Station Modification packages,10 CFR 50.59 evaluations, tailgate packages, and training document The team developed a plan that ensured that the modification would occur without delays and minimized the work duration. The team held training sessions with personnel involved with the piping modification and used mock-ups to ensure that roles, responsibilities and procedures were understoo The piping modification was implemented in three phases. Phase 1 began on September 13. Operations isolated and drained the RN side of all four cooling units per R&R tagout 13-150 This R&R tagout allowed maintenance to weld a temporary pipe cap on the four-inch supply line to the 18 and 10 UCVUs. The return lines to these units also were cut and capped. Thus, cooling water was temporarily isolated from the UCVU After the pipe caps were installed, operations cleared the R&R tagout and restored RN cooling water to the 1A and ID UCVUs. lA and ID UCVUs we e placed back in service to cool and maintain temperature in upper containment. Maintenance continued the piping replacement per WO 930521980 During the draining for Phase One several drain valves were blocked, which extended the draining period. The team evaluated this problem and decided to unblock the drain and vent valves associated with the lA and ID UCVUs using air that was regulated between 10-20 psig. This was performed prior to draining for Phase Phase 2 began on September 1 Operations implemented R&R tagout 13-1513 to again isolate the RN cooling water to all four UCVU This allowed maintenance to clear TSM WO 9306403801 (the cutting
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.i and capping of the IB and IC UCVUs piping) and implement TSM WO !
9306403701 (the cutting and capping of supply and return piping to {
IA and ID UCVUs). Operations then allowed Maintenance to complete l the cutting and capping of RN piping to lA and ID UCVU _
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Maintenance replaced piping per WO 9305219801 and restored cooling l water to 1B and IC UCVUs. These units were then placed in service :
to cool and maintain temperature in upper containmen :
i Again the RN drain and vent valves were unclogged (using air) and .i flushed. This action was taken to ensure that draining during ;
Phase 3 would occur quickl ;
i Phase 3 began on September 2 Operations implemented R&R tagout !
13-1673 to isolate and drain the RN cooling water to all four !
UCVU The R&R allowed Maintenance to clear TSM WO 93064037 01 ;
(for cutting and capping of IA and ID Units). In addition, j maintenance replaced the six-inch piping extending from valve IRN- !
407 (manual return header isolation) through the Crane Wall and 3 tied back into the supply header piping for I A,18,10, and ID ;
UCVUs. Maintenance performed the piping replacement per W0 :
930521980 .
After maintenance completed the Phase 3 work, Operations cleared l R&R tagout 13-1673 and restored RN cooling water to all four j UCVUs. Operations then placed the UCVUs in service to cool and '
maintain temperature in upper containmen !
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The inspector observed the ongoing maintanance, modification, installation, personnel training, post-modification testing and f
., return to service of the upper containment RN piping. The ;
multiple interfaces of the different working groups, the !
availability of supervision and management support were i noteworth l t
The work was completed in a timely manner; containment access was I well monitored and controlled; equipment was well controlled; and :
personnel were trained and briefed on crew turnover. Material !
conditions and personnel safety were also emphasized at regular j tailgate meetings. The modification was well planned and ;
implemented with minimal perturbatio l Diesel Generator Lube Oil Keepwarm Pump Maintenance [
The inspector reviewed the safety impact of performing maintenance l on the 1A Diesel Generator keep warm lubrication and pump while l; the emergency diesel generator is operable. The inspector reviewed the operating procedure OP/1/A/6350, Technical :
Specification 3.8.1.1.b., the licensee's TS interpretation, the .
vendor manual, and training lesson plans LP OP-CN-DG-DG3, j Operating the Diesel Generato )
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The inspector concluded that performing maintenance on the. lube oil keepwarm pump when the engine was operating had no effect on i nuclear safet =
e. On-Line Leak Sealing Repair Program .
The inspector reviewed the licensee's on-line leak-sealing repair i program. This included a review of leak-repair procedures,. 1 administrative controls, engineering involvement, and witnessing- J an actual leak repair activit !
The licensee performed on-line leak-sealing repairs on all classes l of piping components. Based on discussions with the engineering >
staff, this type of repair process was considered to be temporary ;
corrective maintenance until complete repairs could be made. Leak ;
repairs were performed using an approved maintenance procedure, :
MP/0/A/7650/63, On-Line Leak Repair Corrective Maintenance. This +
procedure required planned repairs to be reviewed by the engineering staff, who would determine if this type of repair >
process was required and if special instructions were necessar All leak repairs required a 10 CFR 50.59 evaluation to. ensure that ;
all applicable equipment concerns were considered. If the leak
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repair affected operation of the component or system, or if it ;
involved Class A, B, or C components, the repair was processed as .
a plant modificatio In addition, a maintenance representative l and the operations Shift Supervisor were required to approve the use of this process if the system was under pressur Leak repairs were performed by a contractor, USSI, in.accordance ,
with their procedure. This vendor procedure was reviewed by the l engineering staff. The vendor used a variety of sealant materials depending on the type of leak repair application. All materials i were tested and approved by the licensee's Nuclear Production !
Chemistry Department. The engineering staff provided the vendor !
with a maximum allowable component design pressure that was not to be exceeded during the sealing process, as well as the maximum -
amount of sealant material to be injected to ensure that the- ,
material did not enter the process lin On September 30, the inspector witnessed the on-line steam leak i repair of a 2-inch flange located between the 2B second stage reheater drain tank valve, 2HS-LT5200H, and the drain tank level i instrumentation. The inspector reviewed the procedure and i verified that the engineering staff had performed a 10 CFR 50.59 :
evaluation. The design engineering staff calculated a maximum allowable component design pressure of 1500 psig and estimated that 6 cubic inches of sealant material would be necessary to fill the volume in the flang ,
During the injection, USSI personnel encountered problems with the extrusion of sealant material from around the edges of the ring l clamp that was installed around the flange to hold the sealant j j
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inside. The vendor exercised considerable judgement in estimating the amount of material that remained inside the cavity. When the -
vendor realized that the calculated amount of sealant injected l would exceed 6 cubic inches, they appropriately contacted the !
engineering staff. The engineering staff provided a new maximum !
value of 8 cubic inches. The inspector later discussed with [
engineering personnel the method by which these sealant values l were obtained. The inspector learned that the original amount of ;
6 cubic inches was obtained under the assumption that the repair i activity was to be performed using a wire wrap around the flange l instead of the ring clamp that was actually used. With the rina l
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clamp, a larger cavity needed to be filled. The inspector i
, considered this to be a weakness in the licensee's control of the !
- . activity, which resulted from miscommunication between the vendor j
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and engineering organization j i
During the leak repair activity, the inspector noted that a j licensee maintenance technician was present; however, the j technician appeared to provide little meaningful oversight. The !
technician failed to maintain adequate attention to critical !
. parameters during the activity, (e.g., the maximum injection i
> pressures and maximum amount of sealant material 'used by the !
l vendor). l
- While reviewing the amount of sealant material injected, the !
inspector noted that a 2:1 compression ratio factor was being used i by the vendor. Specifically, after injecting the entire contents I of the injector gun, which contained 16 cubic inches, the vendor !
applied this factor and indicated that only 8 cubic inches had l been injected into the volum Neither the vendor nor the :
, licensee's procedures made reference to this factor, which j effectively doubled the total amount of material injected. USSI l personnel indicated that this factor was being used to account for ;
(1) off-gasing of the sealant material while curing, (2) air i entrained in the material, and (3) corrections for losses of the j material while it was being injecte Item (3) was considered a 1 nonconservative factor that was difficult to quantify for every ;
repai The inspector requested that the licensee provide further ;
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details to justify the use of this factor. This issue was l
- identified as IFI 413, 414/93-26-04
- Controls for Amount of Leak
- Sealing Material Injecte i
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Aside from the issues regarding program implementation discussed i in this section, the inspector determined that the licensee had l 3 implemented an adequate leak-sealing repair program that contained l
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appropriate administrative control i l Licensee Event Reports (92700) l
The following LERs were reviewed to determine if the information i
provided met NRC requirements. The following factors were considered:
adequacy of description, verification of compliance with Technical
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of potential generic problems, fulfillment of reporting requirements, !
- and the relative safety-significance of each even l 1 (Closed) LER 413/91-11
- Technical Specification Violatinn due to -l incorrect floor orifice orientation as a result of marc vnt- l deficiencies, inappropriate action, and defective proceo l
During a Safety System inspection on May 14, 1991, with Unit'1 in -
!
Mode 6, Refueling, the licensee discovered that the flow orifice !
j plate in flow element INIFE5000 Chemical and Volume Control System !
Cold Leg Injection "A" Header was installed in the reverse !
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orientation. Subsequently, 1NIFE5510, Safety injection System i j Cold Leg . Injection "B" Header flow orifice plate was installed in l l the reverse orientation. The Performance Group conducted i inspections because of concerns that several flow orifice plates -}
could have been installed incorrectly in safety related systems at l the Duke Power Company Oconee Nuclear Station. Both flow orifice !
plates were removed and reinstalled correctly. Design Engineering i evaluated the impact of the reversed flow orifice plates on the !
previous NI flow balance results and concluded that the NI flow rate would have been lower than Technical Specifications allow, l
but within safety analysis assumptions for total injectiun flo i A review of the equipment work history database revealed that both !
flow instruments were incorrectly installed during the Unit End of .l Cycle 4 Outage (May 1990). This incident'was assigned a root !
cause of management deficiency and contributing causes of ;
inappropriate action, defective procedure,-and management- !
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deficiency because no training had been provided. Corrective actions include explanation and discussion of this incident with maintenance personnel and procedural strengthening and training to j ensure proper orifice plate orientatio l The inspector reviewed maintenance records, including work requests, maintenance procedures and test procedures. It was l verified that on February 15, 1988, with Unit 1 in Mode 6, !
Refueling. in the End of Cycle 2 Refueling Outage, Maintenance l personnel performed work on flow element INIFE5000 (NV System Cold !
Leg Injection "A" Header) per WR 286190PS. The description of the l work requested was to investigate and repair a leak at the flow i element's flang j i
On February 14, 1990, with Unit 1 in Mode 6, in the E0C4 Refuelinq
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Outage, Maintenance personnel performed wcrk on 1NIFE5000 per WR j 523840PS. The work requested was to investigate and repair a leak ;
at the flang !
i On February 14, 1991, maintenance personnel performed work on flow (
element INIFE5510 (NI System Cold Leg Injection "B" Header) per WR l 525310PS. The work requested was to investigate and repair a leak j at the flang !
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, On May 14, 1991, with Unit 1 in Mode 6, Refueling, in the EOC5 Refueling Outage, a Performance Engineer discovered that the flow '
orifice plates for INIFE5000 and 1NIFE5510 were installed in the i reversed orientation. The inspections were conducted by the f Performance group in response to concerns of improperly orientated :
orifice plates at Catawba and the Duke Power Company Oconee *
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Nuclear Statio '
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The inspector verified that inspections were performed on all ;
essential and safety-related systems to ensure that flow orifice j plates, which impacted TS, were correctly installed and oriente i
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They also verified that INIFE5000 and 1NIFE5510 were reinstalled
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correctly per WR 525310PS and WR 523840PS, respectivel In addition, the orifice plate orientation was verified to be correct :
for each flow element, and a past operability evaluation of the NV !
and NI Systems was completed satisfactoril ,
The inspector reviewed the adequacy of procedural changes, training, and management review of the orifice events. The inspector determined that the licensee responded appropriately to j the issu j (Closed) LER 413/91-24: Technical Specification 3.0.3 Entry as a !
Result of Both Trains of Control Room Area Ventilation being Inoperable due to Equipment Failur *
On October 9, 1991, at approximately 9:12 a.m., with Units 1 and 2 in Mode 1, at 100% power, both units entered Technical Specification 3.0.3 when both trains of the Control Room Area Ventilation and Chilled Water Systems were declared inoperabl '
Train "A" was declared inoperable after its chiller tripped due to i spurious actuation of the low refrigerant temperature cutout
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switch. An investigation revealed that the root cause-of the !
Train "A" YC Chiller trips was corroded switch contacts. The j Train "B" YC Chiller inoperability-was attributed to a failure of t the chiller to start. A chiller motor overload occurred because ,
of a problem with the guide vane actuator. YC Train "A" was '
declared operable and returned to service after the low refrigerant temperature cutout switch was replaced. Train "B" YC Chiller was evaluated and declared operable after corrective action was performed on the guide vane actuator. TS 3.0.3 was exited at 3:15 p.m. The root cause was equipment failur Immediate corrective actions restored both chillers to operable status. The licensee's planned corrective actions included replacing the guide vane actuator on the "B" Chiller. Additional long-term corrective actions were implemented upon completion of an investigation of both incidents, along with ongoing design review of. historical VC/YC reliability problem The inspector reviewed work requests and inspection procedures and found that maintenance personnel investigated the " motor overload" problem on "B" YC Chiller using WR 564560PS and discovered that
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the chiller guide Jane linkage was slipping because some' set j screws on the actuator shaft were loose. The set screws were re- ,
tightened and place 9 on recurring inspection procedures'by ,
maintenance. Mai,tenance Engineering Support personnel provided '
an operability si atement for the chille Review of WR 564570PS revealed that it was initiated to allow r instrument personnel to transfer the low refrigerant temperature .
cutout switch from "B" YC Chiller and install it on "A" YC '
Chiller. Instrument personnel installed a' temporary jumper on "B" YC Chiller, and Performance Engineering personnel provided an >
operability statement and initiated a TSM for "B" YC Chiller to l allow the jumper to remain in place so that the unit could be declared " functional."
Instrument personnel recalibrated the new temperature cutout i switch on "A" YC Chiller, and operations successfully restarted ,
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the chiller uni ~!
The inspector reviewed the licensee actions in pursuing corrective actions in reference to the numerous failures of the VC/YC systems. The licensee had done an in-depth review of the !
Operating Experience Program datcbase for the 24 months prior to !
this incident. Their review reaaled four LERs that involved an ;
entry into TS 3.0.3 because both trains of the VC/YC System had ;
been declared inoperable. All four of the LERs involved equipment .
failure Entry into TS 3.0.3 because of two inoperable trains of '
the VC/YC System was a recurring proble Consequently, the Licensee's engineering design, engineering support, maintenance and instrument personnel provided a modification to the VC/YC system controls that has resulted in ,
considerable improvement in the system reliability and simplified maintenance. The inspector observed many portions of the modification implementation. The inspector concluded that the a long-term and short-term responses by the licensee were adequat . Exit Interview i The inspection scope and findings were summarized on October 6, 1993, with those persons indicated in paragraph 1. The inspector described
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the areas inspected and discussed in detail the inspection findings listed below. No dissenting comments were received from the license The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspector during this inspectio ,
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Item Number Description and Reference VIO 413, 414/93-26-01 Failure to Adequately Implement Independent Verification Process (paragraph 3.c and 3.d).
VIO 413, 414/93-26-02 Failure to Submit LER on TS 6. Violation and ESF Actuation (paragraph and 4.b).
URI 413, 414/93-26-03 Adequacy of Outside Containment Leakage Reduction Program (paragraph 4.b)..
IFI 413, 414/93-26-04 Controls for Amount of Leak Sealing Material Injected (paragraph 5.e).
8. Acronyms and Abbreviations AE0D - Analysis and E"aluation of Operational Data, Office for CFR -
Code of Federal Regulations CNS -
Catawba Nuclear Site CPT -
Catawba Periodic Test (computer program)
DPC -
Duke Power Company ESF -
Engineered Safety Feature E0C -
End of Cycle IAE -
Instrument and Electrical KC -
Component Cooling Water System LER -
Licensee Event Report NRC -
Nuclear Regulatory Commission NUREG - Nuclear Regulatory Guide NV -
Chemical and Volume Control System NI -
Safety Injection System PIP -
Problem Investigation Process (report)
RHR -
Residual Heat Reinoval System R&R -
Removal and Restoration RCA -
Radiation Control Area RN -
Nuclear Service Water System ROAB - Reactor Operations Analysis Branch RP -
Raiiation Protection SG -
Main Steam System SR0 -
Senior Reactor Operator TS -
Technical Specifications TSM -
Temporary Station Modification UCVU - Upper Containment Ventilation Unit URI -
Unresolved Item USSI - Utilities and Support Specialist Incorporated VC -
Control Room Area Ventilation System WL -
Contairment Floor and Equipment Sump WO -
Work Request WR -
Work Request YC -
Control Room Area Chilled Water System