ML20235Y795
| ML20235Y795 | |
| Person / Time | |
|---|---|
| Site: | Yankee Rowe |
| Issue date: | 03/02/1989 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235Y791 | List: |
| References | |
| 50-029-88-22, GL-83-28, GL-87-12, GL-88-17, IEB-88-011, IEIN-88-085, NUDOCS 8903140601 | |
| Download: ML20235Y795 (52) | |
See also: IR 05000029/1988022
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-U.S2NUCLEARREGULATORYICOMMISSION- c
,4 REGION I'
,' . Report N'o.: 50-29/88-22-
Docket No.:: 50-29
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License No. :- DPR-3.
< Licensee: . Yankee Atomic Electric Company
580 Main Street-
Bolton, Massachusetts 01740-1398
(Facility Name: Yankee Nuclear power Station
. Inspection-at: Rowe, Massachusetts
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- Inspection Conducted: . November 15, 1988 - January 17,;1989
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Inspectors: Harold Eichenholz,. Senior Resident Inspector
Michael T; Markley, Resident Inspector
Dou las A. Dempsey, Reactor Engineer
Approved By: c48 M/ wbd .?/z/N-
Donald. R. Haverkamp, Chief / Date-
Reactor Projects Section Mo. 3C
Inspection Summary: Inspection on November 15, 1988 - January 17, 1989
Report No. 50-29/88-22
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Areas- Inspected: Routine onsite regular and backshift inspection by resident
inspectors- (480 hours0.00556 days <br />0.133 hours <br />7.936508e-4 weeks <br />1.8264e-4 months <br />). Areas inspected included licensee action on. previous
inspection findings, operational safety verification , engineered safety feature
system walkdown, radiological controls events requiring telephone notification
to the:NRC, plant events, maintenance observations, s' surveillance observations,
on-site review committee activities plant information reports, licensee event
reports, licensee response to NRC Bulletins, organization and administration,
allegation - followup, licensee response to selected safety issues,10 CFR Part~
21. reports, and Inservice Inspection Program.
' Resul ts : Two violations were identified: failure to conspicuous 1.y post a high
- radiation area (Section 6)', and failure to establish effective measures in the
form of clear proceaures, to- translate 10 CFR Part 50, Appendix B, Criterion
XVI corrective action requirements for documenting and reporting to management
significant conditions adverse to quality involving design deficiencies.
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I,nspection Summary (Continued) 2
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Strong management oversight and commitment to high quality work by licensee I
personnel was noted in day-to-day activities. It was noteworthy that, consid-
ering the complex level of activities during the refueling outage, there were ,
few personnel errors or plant events. Generally strong performance was indi-
cated in the areas of plant operations, security, maintenance and surveillance. {
l Areas that warrant increased or continued licensee attention include: recog- l
' nition of Technical Specification ambiguities (Section 4) and the need to sub- I
mit TMI Technical Specifications for radiation monitors (Section 10); ensuring
a consistent level of performance in documenting off-normal equipment condi-
tions (Section 4); improved thoroughness and followup by radiation protection
personnel in implementing program details (Section 6); expanded involvement of
maintenance support department engineers in equipment performance evaluations
(Section 8); and resolving deficiencies in the vendor technical information
program (Section 11).
The conservative manner in which the licensee approached and conducted plant
maintenance activities with the main coolant system in a partially drained
condition was consistent with its strong orientation toward nuclear safety.
Even during the refueling outage, the licensee provided a high level of support
for the NRC review and resolution of selected safe ty issues (Section 17).
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1. Persons Contacted.......................................... 1
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L2. Summa ry_ of Facility and NRC Activities . . . . . . . . . . . . . . . . . . . . . . -1
3. Licensee Action.or Previous Inspection Findings (I'P 92701,
92702)*................................................... 2'
Operational Safety Verification (IP;71707, 92709 60710)....
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4. , 7
a. Daily Inspection................... ................... 7
'b. System Alignment Inspection........v................... 11
, c. - Biweekly and Other Inspections. . . . . . . . . . . . . . . . . . . . . . . o 12
- .d.. Backshift Inspection............................. ...... 14
5. Engineered Safety Feature System Wal kdown (IP 71710). . . . . . . .
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14
6. Radiological Controls (IP 71707,83729)..................... 15.
.7. Events Requiring Telephone Notification to the 'NRC
(IP 93702).................. ............................. 17
8. Plant-Events (IP-93702,62703,-61726,71707)................ 18
a. Automatic ESF Actuation Due To Generator Static Exciter
Testing.............................................. .18
b. -Reactor Protection System Permissive Circuit Operated
Outside Technical Specification Limits............... 19
c. Nuclear Instrumentation Channels 7 and 8 Low Power Set
Point Inoperative.............. ..................... 20
d. Plant Startup From Refueling / Unplanned Reactor
Protection System Actuation.......................... 21
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9. Maintenance Observations (IP 62703). ........ .............. 23
10. Surveillance Observations (IP 61726,62703)................. 25
11. On-Site Review Committee Activities (IP 40500).............. 27- l
12. Plant Information Reports (IP 90712)........................ 31 ;
13 .- Review of Licensee Event Reports (IP 90712,92700).......... 32
y 14. Licensee Response to NRC Bulletins (IP 92701). . . . . . . . . . . . . . . 35
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T.able of Contents (Continued)
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15. Organization and Administration (IP 35701).................. 36
16. Review of Radiation Protection Related Allegation
(RI-88-A-0120)............................................ 36
17. Licensee Response to Selected Safety Issues................. 37
a. Storage Battery Adequacy Audit (RI TI 87-07,
IP 71707).............. ............................. 37
b. Loss of Decay Heat Removal Capacity When Reactor
Coolant System Is Partially Drained-PWR (RI TI 88-02,
IP 92701, 62703)........... ................... ..... 38
c. Information On High Temperature Inside Containment in
PWR Plants (TI 2515/98, IP 71707)............ . ...... 38
18. Part 21 Report - Main Coolant Stop Valve Disc Cracking
(IP 36100).... ... ........... .................. ........ 39
19. Inservice Inspection Program-Pumps and Valves (IP 73756).... 40
20. Unresolved Items.................................... ....... 40
20. . Management Meetings (IP 30703)...................... ....... 40
Attachments
Attachment 1 - NRC:RI Temporary Instruction 87-07 Storage Battery Adequacy
Audit
Attachment 2 - NRC:RI Temporary Instruction 88-02 Loss of Decay Heat Regional
Capacity When Reactor Coolant System Partially Drained
- The NRC Inspection Manual inspection procedure (IP) or temporary instruction
(TI) or the Region I temporary instruction (RI TI) that was used as inspection
guidance is listed for each applicable report section.
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DETAILS' l
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1. Persons' Contacted >
Yankee Nuclear Power Station- 1
N.St.Laurent,' Plant: Superintendent
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T. Henderson, Assistant Plant Superintendent ' !
R.1Mellor, Technical Director ' '
Yankee Atomic Electric Company (YAEC)
8. Drawbridge, Vice President and Manager of-Operations !
A. Kadak, President' 4 4 ,
The inspector also ' interviewed other licensee employees during the inspec-
L tion, including members of the operations, radiation protection, chemis-
try, instrument. and control, maintenance, reactor engineering, security,
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- t; raining, technical services and general office staffs.
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2. Summary of Facility and NRC Activities ,
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At the. start of the inspection: period on November 15,-1988, the plant was
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in Mode 5-(Cold Shutdown) with refueling ; outage activities in progress.
The plant was placed in' Mode 6 (Refueling) on November 21, 1988. The ;
licensee's planned seven-week ^ refueling outage' stretched into a nine-week "
outage ; principally due to: conducting the_ outage- through a period: that
included three major holidays, efforts required to recondition body-to-
bonnet ' mating surfaces on two main coolant loop isolation. valves,--unfore-
seen repair work on internal feedwater system components of all four steam
generators and post-outage equip 11ent performance problems with main tur-
bine . throttle valves and hydraulic control system.
A special population drill- occurred on November 29, 1988, and a spec'ial
population exercise for the Yankee Nuclear Power Station's emergency' plan-
ning zone communities occurred. on December 13, 1988. The exercise was
conducted by the Massachusetts Civil Defense Agency and the Vermont Emerg-
-ency' Management Agency for their participating towns. The exercise was .
' graded by the' Federal Emergency Management Agency.
On December 9, 1988, the licensee announced' the appointments of-
Mr. A. Kadak as President and Chief Operating Officer and Mr. E. Brown as
Chief Executive officer. These appointments were effective
%a January 1,-1989, upon the retirement of Mr. James Tribble, the former
President and Chief Executive Officer. Additionally, on December 9, 1988,
the licensee informed the NRC of its decision to procure a plant-
referenced' simulator.
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On January 11, 1989, the licensee initiated Core XX Physics Testing and a
reactor scram occurred due to electrical noise that generated a false high
startup rate signal. Subsequently, criticality was achieved with testing
being satisfactorily completed on January 13, 1989. The turbine was
phased to the grid on January 14, 1989. Whila removing the main generator l
from the grid for overspeed trip testing on January 16, 1989, a switchyard l
oil circuit breaker failed- to trip open, resulting in the motorization of I
the turbine generator for a ten-minute period. No damage to the turbine- j
generator was identified to have occurred as a result of this condition. "
Successful comp'etion of turbine testing and phasing to the grid occurred
on January 17,'1989. At the end of the inspection period the plant was at
33% of rated power and continuing with the post-outage power ascension
, program.
An NRC Region I (NRC:RI) specialist performed an inspection in the area
of design changes and modifications from November 28 through
December 9, 1988 (Inspection Report 50-29/88-23). During the period
December 12-16, NRC:RI specialists performed routine inspections in the
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areas of outage-related health physics (Inspection Report 50-29/88-21) and
steam generator and in-service inspection testing programs (Inspection
Report 50-29/88-24). A special inspection was performed December 27 30,
1988, by the Senior Resident Inspector and an NRC:RI reactor engineer as a
result of the licensee's notification on December 9, 1988, that procedural l
inadequacies had been identified that could have resulted in certain
reactor protection sy stem trip functions operating less conservatively
than that required by Technical Specifications (Inspection Report
50-29/88-25).
On November 20, 1988, Mr. M. Markley was assigned as Resident Inspector at
Yankee Nuclear Power Station (YNPS). The Senior Resident Inspector
attended a December 6,1988 meeting hosted by the NRC with industry repre-
sentatives that pertained to plant life extension and license renewal
issues. YNPS was recently selected 'as the lead pressurized water reactor
plant as part of industry efforts to demonstrate the licensee renewal
process.
3. Licensee Action of Previous Inspection Findings
(Closed) Inspector Follow Item 50-29/81-18-02: Recurring failure of
Westinghouse type SC-1 general purpose relays during performance of pro-
cedure OP-4606, Main Coolant Flow Trip (M.C. Pump Current) Functional
Test. Licensee consultation with the vendor indicated a misapplication of
these relays based on Westinghouse Service Bulletin I.L.4-766.1 H dated
July 1978. Subsequently, the relays were replaced with Brown Boveri Elec-
tric relays under Engineering Design Change Request (EDCR) 82-16. This
item is closed.
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However, the licensee's failure to receive the vendor bulletin contributed
to this problem. The licensee's slow development of a-program adequate to i
provide assurance that vendor information is current and complete remains '
a continuing NRC concern, with further NRC inspection to be conducted:
under Unresolved Item 50-29/85-12-02.
(Closed) Unresolved Item 50-29/88-05-03: Acceptability of testing reactor-
trip breaker direct current (DC) overcurrent trip devices using an alter- i
nating current (AC) multi-amp tester. The licensee performed procedure-
OP-4525, Surveillance Inspection of Rod Drive ACB's, testing the overcur-
rent trip devices with both DC and AC test sets. The inspector received
and discussed with the licensee the resulting data. For any current below
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'the instantaneous trip level, the breakers will trip sooner in DC service.
Consequently, use of an AC tester results in a more conservative setting.
Due to small magnitude of the error involved, the licensee's use of an AC
multi-amp tester in this application is considered acceptable.
This item.is , closed.
(Closed) Violation 50-29/82-15-01: Failure to perform 10 CFR 50.59 safety
evaluations. and use approved design change processes. Subsequent to the
issuance of this violation the NRC has not observed recurrence of concerns
in this area. Licensee corrective actions appear to have been effective.
The two most recent Systematic Assessment of Licensee Performance (SALP)
Reports (50-29/85-98 and 86-99) have noted that licensee strengths exist
"in the areas of safety review effectiveness and implementation of design
change control _ processes. Additionally, the inspector noted that the
administrative control measures which the licensee has in place will
assure that corrective action items pertinent to plant safety are effec-
tively and efficiently reviewed, assessed and acted upon by appropriate
licensee personnel.
This item is closed.
(Closed) Inspector Follow Item 50-29/83-04-02: Repeated reactor plant low
flow trips, sensed by main coolant (MC) pump current, caused by off-site
high voltage line disturbances form the basis of this item. Licensee j
review of these trips resulted in adjustment of MC flow trip system time I
delay relays eliminating false loss of flow signals while maintaining the
time delay feature within the bounds of plant safety analysis. Inspector
review of Licensee Event Reports. (LER), Plant Information Reports (PIR),
and NRC Inspection Reports revealed only four reactor plant trips due to
off-site line disturbances since 1983 and none due to MC pump current.
Review of procedure OP-4607, Low Main Coolant Flow (MC Pump Current)
Channel Calibration, results since 1983 indicates no setpoint instability.
This item is closed.
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l (Closed) . Inspector Follow Item 50/29/83-02-01: Operation of Vital Bus 1
L Ground Detector . test switch combined with an_ existing ground on No.-1 Bus
resulted in a low main. coolant flow-. differential. pressure reactor. trip.
PIR No. 83-2 justified temporary' disabling of both vital bus inverter test-
switches as another method;of testing the inverter ground monitor alarm.
Plant Alteration 85-02 permanently removed the test switches. Licensee
response to this event is considered appropriate.
This item is closed.'
(Closed) Unresolved Item 50-29/84-13-02: Review licensee's safety evalua-
tion for cross-tying plant electrical buses following' a September 5,1984
plant trip. This issue involved the cross-tying of all three 2400V buses
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through the No. 3 station service transformer (SST) and all three 480V
buses through the No. 6 SST. Inspector concerns involved: assuring that
the off-normal electrical distribution system lineup would not constitute
an unreviewed , safety question. On October 5,1984, the plant operating
organization issued' Yankee Plant Service Request No. 84-44, which reques-
- ted that the Yankee Nuclear -Services Division (YNSD) review the cross-
tyirg operations of September 5,1984, and- assess from a safety perspec-
tive.the control room' operator actions.
On - January 15, 1985, in Memorandum YRP 28/85, YNSD provided the results ,
of its engineering evaluation and proposed changes to cross-tying.proced- i
ures. The memorandum indicated that .in the cross-tyed configuration of
- concern, had a safety injection actuation signal initiated and had safety
loads (low pressure safety injection pumps 1, 2 and high pressure safety
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injection pumps 1, 2) started and operated, the voltage at _480V Buses 6-3
and 4-1.and Emergency Busses 1 and 2 would have been below the undervolt-
age protection relays setting. Accordingly, 10 seconds after LPSI and/or
HPSI starting, the tie circuit breakers would open and the safety loads
would be restarted by the associated diesel generator. Although this
would result in the successful operation of the safety loads, it is not
the design intent to rely upon the emergency diesel generators as the pri- .i
mary power source under this situation. The engineering memorandum recom- 1
mended an operating configuration that ensures that two out of three sta ' I
tion buses and their respective safety loads would be powered from off- l
site power should a safety injection signal occur.
The inspector reviewed the licensee's Yankee Atomic Electric Company Elec-
trical Operating Instructions, Rev. 5, and various operations department
procedures covering the normal and off-normal operations of the station's
2400V and 480V electrical distribution system. It was determined that 1
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appropriate instructions existed to ensure that cross-tying operation of
the electrical buses would be performed in accordance with TS's and cur-
rent engineering analysis.
This item is closed.
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(Closed). Inspector Follow Item 50-29/83-02-03: Issues related to LER
50-29/82-41-03L, No. 1 main coolant loop . pressure - channel low pressure
safety injection -setpoint out of tolerance, issued on December 16, 1982.
! Review of LER 50-29/82-41-03L-1 issued on June 14, 1983, verified that the
revised. report adequately addressed the. inspector's concerns.
This item is closed.
(Closed) -Unresolved Item (50-29/88-02-03): There were continuing failures
of main steam pressure switches between July 18, 1985 and December 3, 1987.
Based on these failures, concerns which were identified and collectively..
considered as an . Unresolved Item in' Inspection Report 50-29/88-02,
included: :
(1) the potential deportability of the pressure switch failure mode upon
completion of failure analysis of the switch;
(2) corrective actions to be~ taken by the licensee to preclude exceeding i
the Technical-Specification (TS) limiting conditions for operation in
the future;
(3) actions to ensure that the pressure switch problems are corrected;
and
-(4) promptness of. corrective actions taken for the pressure switch
problem.
In an NRC letter dated April 28, 1988, the licensee was requested to re-
spond to the above concerns. The licensee responded in a ' letter dated
June 30, 1988, which gave a chronology of events, a response to ach of
the above items, and a statement that their overall actions concern;1g the
pressure switches had been timely under the circumstances. Review -f the
letter indicates that the licensee has' adequately responded to con 9rns ,
(1)'and(2). .l
The SALP Report 50-29/86-99 dated September 15, 1988, Section H, "Engi-
neering Support", in part, states the following: " . . . Exceptions to this
normally good engineering support include an area of concern identified
during this SALP period involving an apparent lack of timeliness in l
resolving problems observed during plant operations regarding the continu- .'
ously degrading condition of the main steam line switches over a three
year period."
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On April 26, 1988, the licensee reported to the NRC under -10 CFR ~ 21 a -
. potential design defect found in ' the ASCO "Tri-Point" pressure switches.
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As.part of the NRC Office of Nuclear Reactor Regulation (NRC:NRR) Vendor
-Inspection Branch inspection of ASCO, Report No. 99900369/88-01,. an Unre-
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' solved Item (88-01-06) was identified,- in that ASCO may have failed to
adequately evaluate'under 10 CFR part 21 a potentially reportable extrus-
. ion phenomena of- the resilient cast polyurethane disc that was observed
during its 1982 environmental : qualification testing activities for the
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. subject pressure switches. . ASCO did not ' determine ' the applicability of
the phenomena to other ~ nuclear plant facilities. 'The licensee's Part' 21
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report indicated that ~ ASCO had claimed ~ not to have observed this problem;
with ithese particular units in the past. It was not clear to the: NRC
inspector at. the ASCO f acility 'whether the switch problem .resulted from-
in-service degradation or was a pre-existing condition involving a devia-
tion from material procurement specifications.
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Regarding'. the . final resolution of licensee actions to ensure that .the
pressure switch problems are ' corrected, the licens' eeimplemented. 'duri ng
, the current refueling outage Engineering Design. Change Request (EDCR) No.88-309. This EDCR replaced the ASCO p'ressure. switches with bourdon tube
type Barksdale. pressure switches. The' licensee's replacement followed the !
evaluation .of operational ' trending data of similar Barksdale bourdon tube '
pressure switches installed on an auxiliary steam line by Temporary Change
Request 88-232 on August 31, 1988.
This item is closed.
(Closed) Inspector Follow Item 50-29/84-13-01: Review licensee controls
to provide verification of redundant system / component testing prior to
removal of_ equipment. The licensee is evalutting the equipment c'ontrol . '
program to ensure that it promotes safety and reliability. The current
program requires actual testing of active components and inspection of
instrument channels. The inspector verified that the exiting program is
consistent with regulatory requirements and licensee commitments.
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This item is closed.
(Closed) Violation 50-29/83-14-02: Failure to properly evaluate a TS vio-
lation and take corrective action. Licensee commitment as detailed in the
November 14, 1983 response letter to the Notice of Violation were adequate
and complete. Inspector review of Plant Operations Review Committee meet-
ing minutes and licensee event reports indicated that management was
effective in implementing long term corrective actions associated with the
primary vent ' stack violation. Licensee corrective actions to prevent
recurrence included both hardware and surveillance procedure upgrades. l
Licensee management was aggressive in addressing problems subsequent to
the modifications.
This item is closed.
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(Closed) Unresolved 50-29/83-02-02: Follow primary vent stack (PVS) cor-
rective action commitments. Inspector review of EDCR.No.84-314 indicated
that modifications to' the PVS were. adequate tos prevent system failure
caused by moisture in the sample lines. Air dryers were replaced by heat
tracing and a moisture trap. Surveillance procedures were revised to pro-
vide guidance for cognizant personnel. The licensee adequately satisfied
commitments noted in NRC Inspection Report's 50-29/83-02 and 50-29/83-04. .
As a result of the modifications and program upgrades, system reliability 4
was.significantly improved.
This item is closed.
(Closed) Inspector Follow Item 84-20-08: Review licensee practices involv-
ing locked valve information on drawings. The inspector had noted 1) num-
erous examples of inconsistencies between various plant drawing and pro-
cedures pertaining to locked valve information and 2) an inconsistent
licensee approach to designating valve positions on drawings as a function ,
of plant status. The licensee has an open item on their corrective action '
tracking system (PROCTR) for the Assistant Plant Superintendent to elimi-
nate inconsistencies between actual plant configuration (valve lineups)
and : system drawings showing valve positions. The inspector has noted an
aggressive effort on the part of the operations department support staff
to identify and correct inconsistencies between procedures and drawings
regarding valve position information. In addition, active involvement of
licensed _ operators to identify discrepancies on drawings and procedures
has been increasingly observed by the inspector. Recently, the licensee
initiated a two year program that will upgrade valve tags. As part of
this effort, the licensee intends to review procedures and drawings on a
system-by-system basis for consistency.
This item is closed.
(0 pen) Unresolved Item 50-29/85-12-02: Establish a method to ensure
vendor information is current and complete as required by Paragraph 2.2.2
of Generic Letter (GL) 83-28. As discussed in Inspector Follow Item
, 50-29/81-18-02 above and Section 11 of this report, there appears to be
l- continuing weakness in the development and implementation of the licen-
! see's vendor equipment technical inform'ation program. This item remains 1
open pending review of additional licensee efforts to resolve NRC concerns
to improve performance in this program area.
4. Operational Safety Verification
a. Daily Inspection
During routine facility tours, the inspector checked the following
items: shift manning, access control, adherence to procedures and
limiting conditions for operations, instrumentation, recorder
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l traces, protective systems, control rod positions, containment tem-
- perature and pressure, control room annunciators, radiation monitors,
radiation monitoring, emergency power source operability, control
room and shift supervisor logs, tagout log and operating orders.
Observations and findings are identified below:
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During a tour of the vapor container on November 22,1988, the
.1spector noted two small pipes which penetrated the containment
shell and appeared to be insufficiently supported. Subsequent
discussion with the licensee determined them to be neutron shield
tank sample lines (1/2"-CRSL-152A-4 and 1/2"-CRSL-152A-5). The
licensee performed a walkdown . and an engineering evaluation.
The analysis concluded that both sample lines conformed to the
requirements of ANSI B31.1-1977. They were also noted to ' be
non-nuclear safety except at the containment penetration where
they were safety class 2. Neither pipe was seismically defined l
in the Systematic Evaluation Program (SEP). Review of the iso- l
lation valve configuration indicated that containment integrity i
would not be compromised for a line failure inside .the vapor
container (VC). Although the licensee's evaluation determined
that no additional pipe supports were required, they considered
it prudent to evaluate the need to strengthen supports to mini-
mize line flexibility and potential damage caused by workers
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traversing the piping. Additional supports, if determined i
necessary, will be installed during the 1990 refueling outage.
The licensee was proactive in addressing the inspector's con-
cerns. Review of the licensee's evaluation indicated that the
conclusions were technically sound. Proposed corrective meas-
ures adequately addressed ergonomic considerations.
--
The inspectors reviewed a sampling of the licensee's refueling >
procedures and observed refueling operations in progress in the ,
VC, control room and spent fuel pool (SFP) including: 1) removal
of Cycle 2 fuel from the core, placement in the upender, trans-
fer to the SFP and placement in the spent fuel racks; and
2) removal of cycle 1 fuel, ultrasonic inspection of new fuel
assemblies and subsequent transfer to the VC. The inspector's
discussions with licensee personnel in the VC and SFP areas
verified their knowledge of job requirements. Work was observed
to be progressing in an orderly and professional manner.
A review of the licensee's procedures demonstrated th > provis-
ions were provided 1) to verify that minimum water 'l evel re-
quirements were monitored during fuel handling operations; 2) to
verify that the radiation monitors for the SFP and VC were oper-
able and checked; and 3) to ensure that the SFP cooling and
cleanup system was operable and that applicable technical spec-
ification requirements are specified in the refueling procedures.
- _ _ - _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - - _ - _ -_ -- - _ - - _ _ _ _ _ _ _ _ _ _ - - _ _ - - - - - _ _ _ - _ _ _ _ _ _ -
. - _ _ .-. -_ - _ _ _ _ _ - _ - _ _ _
'3
- x *-' +
b .
. .
9
a
.
The following~precedures were reviewed:
--
Operating ' Procedure (0P)' 1100, Revision .11, " Dismantling
'
and' reassembly of the . Reactor Systems' ~ for Core XX
Refueling" '
>
--
OP-1209, Revision 12, Operation of the. Vapor Container (VC).
l; Fuel Handling Equipment
--
OP-1214, Revision 14, Component Movement within the New
Fuel: Vault'and Spent Fuel Pit
J
--
OP-1700, Revision. 14, Cycle XX Reactor Refueling' and
Component Inspection
- !
Ouring the refueling' outage, the inspector attended ~ daily plan- ?
ning meetings, observed refueling activities and associated
. evolutions, and reviewed the adequacy of management involvement.
~
During ' planning meetings, the licensee demonstrated a ' clear
understanding of safety significant issues. Conservative, tech--
i.icensee man-
nically sound
agement was highly resolution
involved was routinely
in daily observed.
activities. . Senior manage-
L
ment was regularly observed in the VC and primary . auxiliary
i
building (PAB) during inspector tours. The licen'see was respon-
.sive in addressing inspector identified concerns.
'
Inspector' review of refueling and associated activities indi-
cated good . performance. Communications with the control room
were maintained during core alterations. The inspector verified
that licensee personnel were using current procedure revisions.
Cognizant' personnel were knowledgeable of safety considerations,
TS requirements, and procedural guidance. Decay heat removal ,
capacity was well maintained including reduced level operations- i
initiated to support repair activities -- on non-isolable main ;
coolant system components. The shield tank . cavity - (STC) water
level and boric acid concentration was controlled as required.
Inspector review determined that containment integrity. was
secured when required.
One area noted as needing improvement was loose object control
around the STC. The licensee had to retrieve several small
objects from the bottom of the cavity. During a VC tour, the -
inspector observed an ink pen floating on the water surface.
Inspector review indicated that loose object controls around the ,
spent fuel pit was better in comparison. Separate from the
inspector's observations, the Plant Superintendent directed
personnel to improve performance in this area. i
i
__- - __ - -____ - --__ - _-_-_-____-____.-___-_.____---___-_ - __.--__-_ - ____-_____--__ ----__-_ ____---______-___ -.---__-.__-_- _-__-_:- _____ _J
z__ _
, '.'
.
- . 10
The licensee experienced reliability problems in ultrasonic fuel
examination equipment. The licensee revised procedures to ac-
comodate changes in fuel assembly movement sequence. Inspector
review indicated that fuel accountability was maintained. New
fuel assemblies were examined prior to the outage.. All fuel
assemblies entering second cycle use were ultrasonically exam-
ined. The licensee performed water chemistry analysis of the
SFP after each spent fuel assembly was transfered to identify
potential leaking assemblies. These identified assemblies were
returned to the STC for ' ultrasonic examination to obtain data
for use in fuel failure analysis.
No safety concerns were identified as a result of NRC review of
licensee activities in this area.
--
Due to the unique electrical system configuration of this facil-
ity, the ability to directly align the 120 volt a-c vital buses
to an operable diesel generator is limited in the event that No.
1 and 3 emergency diesel generators (EDG) must be rendered
inoperable for maintenance. Technical Specification (TS)
3.8.2.2, A.C. Distribution-Shutdown, requires that as a minimum,
120 volt a-c vital busses No. 1 and 2 shall be operable and
energized from sources of power other than a diesel generator
y but aligned to an OPERABLE diesel generator.
The inspector reviewed licensee Special Orders and supporting
documentation to verify that licensee actions adequately met the
intent of the TS. The ambiguity of TS 3.8.2.2 requirements was
discussed with the licensee who acknowledged the inspector's
concerns and indicated that clarification of this TS was war-
ranted. The inspector had no further questions.
--
On January 11, 1989, at 5:30 p.m., during the performacne of
procedure OP-4222, Rev. 10, Reactor Rod Control System Precriti-
cal Check, control room personnel observed that control rods
Nos. 1 and 10 could not be driven to their f ull-in position j
following their being pulled out to the nine-inch position. Rod 4
No. I would not insert past six inches and Rod No.10 would not I
insert past three inches. Operators attempted to fully insert
the rods using the pull down coils, however, this action was . ;
unsuccessful. The licensee was able to satisfy the safety ob- j
jective of the control rods by demonstrating that a manual scram )
signal caused the rods to fully insert. According to the Plant
Superintendent, this condition has been observed in the past and
it requirad : period of time after the refueling outage for the
i
control rods to stop exhibiting this off-normal characteristic. j
3
1
- _ _ _ _ - _ . _ _ _ _ _ _ _ _ _ _ _ _ . _ _- __ _ -______ __ _ _ _ _ _ _ . . - _ _ _ ,
_ _ -
. ,
..
'
11
.
Regarding. the off-normal condition, the inspector noted that:
1) no maintenance request (MR) was initiated to document ' the
off' normal equipment. performance, 2) there was no entry in the
, control room log that the condition existed, and 3) the shift
turnover log APF 2002.1 did not document-the off normal condi-
tion. On January 12, 1989, the inspector - interviewed an on-
watch control room operator and determined that the watch
stander was unaware of this condition. The inspector questioned
reactor engineering personnel as to why the condition was .not
documented by an MR, and was informed that until they identified
the appropriate corrective action an MR is not warranted. Given
this response, the lack of required control room documentation
to the off-normal equipment condition, and the resulting lack of
knowledge by an on-duty control room operator, the inspector
discussed the issues with the Plant Superintendent and indicated
that management attention was warranted to correct the identi-
fied deficiencies and preclude repetition.
Plant management's response was timely and appropriate, and ade-
quately addressed NRC concerns. Maintenance requests were
issued, control room logs were updated to reflect current condi-
tions, and appropriate plant personnel were counseled in the
importance of properly documenting off-normal equipment perform-
ance. It appears that the licensee's poor performance in docu-
menting off-normal performance of the subject control rods was
an isolated case and does not warrant additional NRC actions at
this time. l
b. System Alignment Inspection
The inspector confirmed the operability of selected piping system
trains. Accessible valve positions and status were examined. Power
supply and breaker alignments were checked. Visual inspections of
major components were performed. Operability of instruments essen- ,
tial to system performance was assessed. The following systems were
checked during plant tours and control room panel status
observations:
I
--
Spent fuel pool cooling system l
--
Emergency diesel generator units - e, -
--
Charging system (control board status observations)
--
Class IE electrical distribution system
.
No inadequacies were identified.
I
1
1
__-___- _-_____ _______ _ - - ________ _ - _____ _ -- _ ___ ___ a
. _ _ _ _ - _ - _ - _ _ _ -
'
' .
._,
l- l
.
- -
. 12
c. Biweekly and Other Inspections
(1) General Facility Observation
During plant tours, the inspector observed shift turnovers, com-
pared boric acid tank sample analyses and tank levels to Tech-
nical ' Specifications requirements, and reviewed the use of
radiation work permits and radiation protection procedures.
Area radiation levels and air monitor use and operational status
were reviewed. Verification of tagouts indicated the action was
properly conducted. No inadequacies vere identified.
(2) Fire Protection and Housekeeping
No inadequacies were noted regarding licensee housekeeping or
fire protection practices. A strong commitment to proper house-
keeping conditions and practices by the plant staff is routinely
observed by the inspector. performance in this area continues
to be viewed as a licensee strength.
No unacceptable conditions or safely concerns were identified
in the review of this program area.
(3) Observations of Physical Security
Selected aspects of plant security were reviewed during regular
and backshift hours to verify that controls were in accordance
with the security plan and approved procedures. Based upon a
review of licensee activities in this are, the inspector noted
the following:
--
On December 23, 1988, following protracted contract negoti-
ations, members of the Independent Security Union Local No.
I signed a two year labor contract with Burns International
Security Services. Burns is the licensee's security con-
tractor. The inspector verified that the licensee had ade-
quate strike contingency plans in place in the unlikely
event that the efforts to achieve a labor-management con-
tract were unsuccessful.
--
Inspector observation of physical security indicated good
performance with professionalism and attention to detail
exhibited by security officers. Search equipment was noted
to be operational with deficiencies corrected in a timely
manner. The vital and protected areas were well main-
tained. Access control personnel were observed to perform
proper searches and accountability verification. However,
on December 22, 1988, the inspector identified a contractor
worker in the service building who was without his security
identification badge and access control key card. The
..
_ _ _ - - - - - _ _ _ _ _ _ _ - _ _ _ _ _ - - - - _ _ _ - - _ . - - - . . _ _ _ _ . _ . _ _ - - - A
. . _
-.
- - _ - - _ . _ _ _ _ . _ _ - - - _- -
,
'
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.
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1.4 . 3: .. .13 -
'
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'
I e inspector informed ' the site security organization of the
condition and verified. that appropriate' corrective actions
were taken. The ' licensee's investigation determined that
the individual's key card, which was left' unattended in the-
, , *
turbine building, would not: have- allowed access to either
,
, access control or vital -areas"of the. plant. Because the
L individual did not:: appear. to .be knowledgeable about his-
expected duties upon becoming aware that' hel was separated
from his. identification badge: and key card, the licensee
~
enhanced the General Employee Training (GET) in this area.
, Licensee actions on thio item were appropriate and timely.
' '
--
Improvements in station . management oversight of security ~
activities continued to be observed by the inspector. The
following items reflected an improving trend in resolving M
security concerns:
-(a) As a result of licensee identified concerns involving
'the occurrance of tai 1 gating into access control areas
of the plant, a weekly audit of an access control area ,
or vital area was - initiated in January 2,1989 by
day-shift security personnel. This audit will verify _
that all personnel within the area are properly logged
into the area and will be used by licensee security
management to assess the level of compliance with this-
important security program requirement.
(b) A partition and door were installed to separate the
secondary alarms -station (SAS) from it's adjacent
area. This action was tak.en by the licensee to
strengthen control of personnel having access to the
SAS and Safeguards Information.
(c) Intrusion detection assessment system enhancements
were completed for the protected area and a projected
schedule was established for upgrading the secondary
power supply for the security system.
(d) Staffing' of the site security organization was
completed.
Implementation of the licensee's security program was generally-
strong.
. .
. - - _ _ _ _ _ - _ - _ _ - _ _ - . _ _ _ _ _ - _ _ _ _ _ _
.
g*- $ ;p
.
. '14
s
'
d. Backshift' Inspection
The inspector conducted backshift, weekend or holiday inspections on
'
November 15, 18, '25, 26, December 3, 12, -15, 17, 24, 1988' and-
January 3, 4 and 14,'1989. Operations and shift supervisors were
l questioned concerning log entries, main control. board annunciations,;
- refueling . operations, TS action statements in effect and equipment j
L out;of-service. Control room ' personnel were. attentive to and.' know-
ledgeable of plant and system conditions.
5.: -Engineered Safety Feature System Walkdown
'
<
The' inspector ~ independently verified the operability of a selected engi-
neered safety features (ESF) system by performing a complete walkdown of
.the accessible portions of the system to:
'
--
confirm - that the licensee's system lineup procedures match plant
drawings and the as-built configurations:
l --
identify Equipment < conditions and items that might degrade
performance;
--
ensure that no prohibited ignition sources or flammable materials
were present in the vicinity of the system without proper authori-
zation;
--
verify appropriate levels of cleanliness were being maintained;
--
verify technical specif# cation requirements were adhered to;
--
verify proper breaker position at local electrical boards and switch
positions at control boards;
--
confirm that support systems essential to equipment actuation and
performance were operational; and,
--
verify valves were properly positioned and locked as appropriate.
The emergency diesel oenerating system was reviewed. The inspector had
the following comment.
--
During review of procedure OP-4254, Rev. 2, Diesel Fuel Oil System
Alignment Check, it was noted that with the exception of F0-V-28,
valves required by procedure to be locked in position are not so
indicated on either form OPF-4254, Fuel Oil System,or drawing YM-C-1,
Elementary Flow Diagram, Fuel Oil System. The system walkdown showed
the valves to be properly locked in the positions required by the
procedure.
_ _ _ - _ _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _
_ , _ _
- _ _ _ - - - - _ - _ - _ _ _ _ _ _ _ ,
l
- =
,
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+
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. 15 )
i
Since this procedure i's normally performed only on.startup from cold
.
shutdown or as . directed by the plant operations manager, the .inspec-
tor expressed the concern that'use of the existing control room draw-
ing alone for maintenance tagging orders could lead to inadequate
system restoration. Inconsistencies between procedures and drawings,
- especially locked valve information, has been a long-standing NRC
concern. This item is discussed in Section 3, Inspector Follow Item
50-29/84-20-08.
The-inspetor had no further questions in this area.
6. -Radiological Controls
Radiological controls were observed on a routine basis during the report-
i ng - pe ri od.- Standard industry radiological work practices and conformance
to radiological. control procedures and 10 CFR Part 20 requirements were
observed. Independent surveys of radiological boundaries and random sur-
veys of nonradiological areas throughout the facility were taken by the
inspector.
In most instances, implementation of the Radiation Work Permit (RWP) pro-
gram was adequate, although problems were noted in RWPs not being updated
with ' current radiological survey -data. Specifically, the contro111ng ' RWP
(No. 88 - 01606, dated December 1, 1988), for steam generator work was not
revised to incorporate the radiological survey results of December 2,1988.
Also, at the time of inspection, these surveys were not available ~ for
radiation protection technician use at the VC control point. Upon identi-
fication of this matter by the inspector, the. licensee immediately' updated
the RWP and sent it w*th surveys to both control points. A similar prob-
lem was noted in that some RWPs controlling work in the shield tank cavity
(STC)- lacked current radiological survey data on January 7,1989. Al-
though - the licensee was not thorough in implementing the RWP program,
radiation protection technicians were observed to maintain positive con-
trol over radiological evolutions including confirmatory surveys at the
start of work.
During a tour of the VC on January 7,1989, the inspector observed the STC
to have an improper radiological posting. Title 10 CFR Part ~ 20.203(c)(1),
requires, in part, that each high radiation area be conspicuously posted
with a sign or signs bearing the radiation caution symbol and the words
" Caution" or " Danger, High Radiation Area". Contrary to this requirement,
the STC was not conspicuously posted as a high radiation area. It was
posted " Caution, Exclusion Area". When identified by the inspector,
cognizant radiation protection personnel immediately posted it " Caution,
High Radiation Exclusion Area". Subsequent review of the radiological
surveys indicated that a radiation intensity was accessible inethe STC
such that an individual could receive a whole body exposure of 450 milli-
rem in one hour. The licensee appropriately corrected the posting with
the words " Caution, High Radiation Area". This constitutes a violation of
10 CFR 20.203 (c)(1) (50-29/88-22-01).
- _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _ _ .
- - - . - . - - - - - . - . , - , , - - - - - . _ , . . - - - - . - - . , - _ - - - . - - - . . , - , - - - . _ . - - . - , . . - _ . - - - - - - _ - - .
3 -..
.
'- . 16-
The licensee was prompt in addressing the above described incident. In
addition to correcting the posting, the licensee held a meeting with the
cognizant personnel to ensure inadvertent personnel exposures did not
occur, to determine the causes and delineate corrective actions. Licensee
review determined .that positive radiological work controls were main-
tained. The incorrect posting occurred when the cognizant individual
inserted an exclusion area sign in front of the high radiation area sign.
Inspector discussion with this individual indicated that he did not know
the correct requirements for posting high radiation areas. Licensee re -
view of the Individual's qualifications and training indicated that he
should have known and that his training exam indicated adequate knowledge.
The licensee was unable to explain why this was not demonstrated at the
time of inspection. An adequate number . of radiation protection tech-
nicians were in the area and should have identified the inadequate posting
prior to the inspector's observations.
Licensee personnel stated that the STC had been posted as an exclusion
area to address changed radiological conditions when shielding was removed
from the STC clapper moat. They also stated that the posted condition
existed for only fif teen minates prior to identification by the inspector.
The licensee detailed additional planned corrective actions which included
issuing memorandum RP-89-2 to inform the staff of the need to improve per-
formance in this area, evaluating the use of.a permanent shielding fix-
ture for the clapper' moat,- and evaluating the RWP program to more closely
align RWP guidance and radiological survey data.
The licensee was aggressive in controlling work activities where the
potential for high personne'l exposure existed. The licensee routinely
demonstrated a conservative approach to protecting workers from exposure
to hot particles. The inspector noted improved licensee performance in
engineering controls to limit internal exposures as the outage progressed
and subsequent to NRC inspection 50-29/88-21. The following initiatives
were indicative of the licensee's properly directed efforts to improve the
structure and implementation of an effective radiological protection
program:
--
effective vapor container shielding to reduce exposure;
--
personnel contamination identification in the VC with the " clean
room" frisking station;
--
use of strippable coatings to control contamination;
--
general area dose rate postings throughout the VC;
1
_ . - . - . . - _ _ _ _ _ .
_.
_- _ __ __ _ _ _ _ _ _ _ _ _ _ _ - _ _ . _ _ _ _ _ ._ __ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ -
g - .
~
1
. 17
l --
onsite technical support and auditors from YNSD;
--
implementation of an ALARA logbook; and
--
implementation of arm contamination monitors to supplement whole body
friskers.
Inspector review of radiological work controls indicated that on an over-
all basis, with consideration of the significant level of activity asso-
ciated with the refueling outage, licensee performance was generally good.
However, a lack of thoroughness and followup by radiation protection per-
sonnel was' observed in program implementation. As indicated by recent NRC
a radiological and resident inspections, and licensee identified events, it
is evident that added management attention is warranted in this area.
7. Review of Events Requiring Telephone Notification to the NRC
The circumstances surrounding the following events, which required NRC
notification via the dedicated emergency notification system (ENS) line,
were reviewed. A summary of the inspector's review findings follows or is
documented elsewhere as noted below:
--
At 12:59 p.m. on November 16, 1988, the NRC was notified in accord-
ance with 10 CFR 50.72(b)(2)(11) that a loss of power event occurred
that resulted in the start of No. I emergency diesel generator. This
condition occurred as a result of testing being performed on the main
generator's static excitor, and is discussed in Section 8.a of this
report.
--
.At 11:00 p.m. on December 5, 1988, the NRC was notified in accordance
with 10 CFR 50.72(b)(2)(iii)(A) that a reactor protection system per-
missive circuit operated outside of TS limits. This inspector's
review of licensee actions and event details are contained in Section
8.b of this report.
--
At 11:25 p.m. on December 8, 1988, the NRC was notified in accordance
with 10 CFR 50.72(b)(2)(iii)(A) that the Channel 7 and 8 power range
nuclear instrumentation low power trip setpoint input to the reactor
protection system exceeded TS 2.2-1 requirements. This event is dis-
cussed in Section 8.c of this report.
. . .
_______....__.--m _ _ _ _ _ _ _ _ _ _
- ._ _ .- _ _ _ _ - _ - _ _
,
- . "
.
~
. 18
~
t--
At 2:50 p.m. on December. 14, 1988, the NRC was notified in accordance
with 10 CFR 50.72(b)(2)(vi) that appropriate government agencies. had
been notified that' EDTA, a non-toxic chemical, had been inadvertently
released to ~ the environment through the ' plant storm drains. The
EDTA,.of which less than 150 gallons had entered the storm drain, was
being used by a licensee contractor to chemically flush the service
.
water piping used with the vapor container. coolers. The inadvertent
release was caused by a leak in a heat exchanger tube of the vendor's
portable cleaning unit. The release'was isolated, samples were taken
at the release points and no adverse effects were identified.
At 7:00 p.m. on January 9,1989, the NRC was notified in accordance
'
--
with 10 CFR 50.72(b)(1)(V) that the safety parameter display system
(SPDS) was declared out of service due to an equipment inalfunction.
The hardware problem was corrected by the licensee's maintenance con--
tractor for - the system and the SPDS was declared operable 'at
3:25 a.m. on January 11, 1989. Subsequently on January 16, 1988, the
SPDS was found to be inoperable, and at 9:00 a.m. the NRC was noti-
fied of the , loss of this emergency assessment capability. As of the
completion of the inspection period, the system continued to be out
of. service, with the maintenance contractor providing corrective
maintenance for the equipment malfunction. Because of an apparent
decreasing trend in system reliability in the eight year old system,
and the need to update system software to be compatible with soon to
be. implemented emergency operating procedures, the licensee has
allocated within its capital budget process the funding for an up-
dated SPDS system. Current licensee plans call for the installation
of the new system in ' the Cycle XX-XXI refueling outage. In ' the
Linterim the inspector has noted that the licensee's staff aggress-
ively pursues both preventive and corrective maintenance activities
on the systems The inspector had no further questions.
--
At 9:05 p.m. on January 16, 1989, the NRC was notified in accordance
with 10 CFR 50.72(b)(2)(ii) of an automatic reactor scram on high
startup rate. This event is discussed in Section 8.d of this report.
8. Plant Events
a. Automatic ESF Actuation Due to Generator Static Exciter Testing
At 11:08 a.m. on November 16, 1988, with the plant in Mode 5 (Cold
Shutdown), a loss of power to station service buses 4-1 and 6-3 and
emergency buses 1 and 2 occurred. As designed, No. I emergency
diesel generator (EDG) automatically started and re-energized emerg-
ency bus 1. Since No. 2 EDG was out of service for maintenance,
emergency bus 2 remained de-energized. Operators restored power at
11:10 a.m., but were unable to re-align emergency bus 1 to the normal
power source (bus 4-1) due to failure of tie breaker BTIB to close.
The NRC was notified of the event via the ENS at 12:59 p.m. Interim
.'
repairs to BTIB were completed and emergency bus 1 aligned to bus 4-1
at 1:30 p.m.
l
__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
_ - _ _ _ _ _. -.
l
S
i
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l
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. 19
l
1
The event was caused by the removal of circuit boards from' the 1
generator static exciter (SE) unit during preparation for SE testing. I
Apparent failure of the SE had been the cause of a plant trip on
May 17, 1988, details of which are included in Section 13 of this in-
spection report as part of LER 50-29/88-08 review. Consequently,
when the SE was energized, a simulated generator field overvoltage
condition occurred leading to the loss of 480 Vac power.
As part of the inspector's review, it was noted that test procedure
OP-5000.237, Rev. O, Static Exciter Tests, provided no guidance to
test personnel regarding removal of SE components. Due to the com-
plexity of the circuits involved, neither the cognizant licensee
maintenance support department (MSD) engineer nor the vendor repre-
sentative were aware of the total effects of the temporary circuit
modifications involved. Consequently, an available method of iso-
lating plant protective circuitry from the SE via the generator loss
of field cutout switch was not utilized. Continuing licensee
strength in the area of engineering support was evidenced by the dis-
covery of the cause of the SE protective action by the cognizant
engineer during post-event review. Regarding failure of breaker BTIB
to close, the inspector determined that this and other General Elec-
tric AK series circuit breakers had been scheduled for vendor refur-
bishment prior to the event. This was accomplished during the
current refueling outage under Maintenance Request (MR) 88-1452.
Full details of the licensee investigation and appropriate corrective
actions are contained in LER 50-29/88-10 issued on December 15, 1988.
The inspector had no further questions of the licensee'as a result of
reviewing this event.
b. RPS Permissive Circuit Operated Outside TS Limit
On December 5, 1988, at 10:20 p.m., while performing surveillance
procedure OP-4613, Rev. 9, Reactor Permissive Circuit Calibration and
Functional Test, the high startun rate trip permissive circuit was
found to actuate at 14.'8 MWe decreasing. This condition ir. contrary
to TS Table 3.3-1, which requires that the permissive circuit for the
trip be enabled prior to reaching 15 MWe. This event was caused by
setpoint drif t of bistable TG-B/S-423. The licensee's corrective
action consisted of adjusting the bistable reset value to within the
TS limit.
The inspector discussed this event with the plant I&C supervisor and
learned that the root cause of the event was attributed to setpoint
drift and further corrective actions were not planned. The surveil-
lance procedure is required to be performed each refueling outage at
an interval not to exceed eighteen months. Because the licensee had
not implemented performance trending of the surveillance test data
_ _ _ _ _ _ _ . _ _ . -. !
_ _ _ _
.,
l
.
j
. 20
for this bistable, the inspector requested that the licensee provide
the basis as to why there was a satisfactory confidence level that
during the upcoming operating cycle the bistable would not drift :
below the required setpoint. The licensee subsequently performed the i
performance trend, which indicated that the bistable was replaced in i
1982; however, the extent of drift was steadily increasing from test '
to test and in the same direction as the last adjustment made. Based
on the additional insights provided by the performance trend graph,
the licensee replaced the bistable with a new unit as additional
corrective action. Although the licensee was responsive to NRC con-
cerns on this item, it did require NRC intervention for the licensee
to be thorough in its final determination of root cause for this
event. The inspector noted that MSD engineering personnel were not
involved with analyzing or providing corrective action recommenda-
tions for this event. As in the past, the MSD engineers continue to
be heavily involved in design related activities. As documented in
the previous SALP Report No. 50-29/86-99, the MSD engineers have not
been readily available to support plant personnel for routine activ-
ities. This has resulted, in part, in not developing equipment per-
formance trend analysis to the extent expected from a site engineer-
ing organization. This issue warrants continued licensee management
attention to resolve the NRC SALP concerns in this area.
The licensee issued LER 50-29/88-12 on January 4,1989, to document i
the event and their corrective actions. The inspector had no addi- I
tional safety concerns on this item. l
c. Nuclear Instrumentation Channels 7 and 8 Low Power Set Point
inoperative
On December 8, 1988, at 11:00 p.m., with the plant in Mode 6 and sur-
veillance procedure OP 4645, Rev. 6, Nuclear Instrumentation Channel
Calibration being performed, the licensee determined that nuclear
instrumentation power range channels 7 and 8 exceeded the TS 2-2-1
low power range trip setpoint. The licensee attributed -this event to
a faulty relay K1301, which resulted in a failure of the two channels
to switch from the high power scram setpoint to the low power set-
point upon actuation of a manual power scram set switch. The faulty
relay was replaced. This event was further reviewed by the NRC as
part of Special Inspection Report 50-29/88-25, which was in response
to the licensee's identification that procedural inadequacies had
been identified which had resulted in certain reactor protection sys-
tem trips that would not function at values less conservative than
that required by TS.
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Because the failure of the K1301 relay could preclude two of the
three power range neutral flux channels from actuating at the low
power trip setpoint, the licensee revised operating procedures to
place the Single / Coincidence selector switch for the power range
channels 6, 7, and 8 in the Sin'gle position prior to closing the
scram breakers and maintain the switch in this position until the
channels are switched to the high power setpoint at 15 MWe. The same
action will occur on plant shutdowns prior to decreasing load below
15 MWe.
The inspector viewed licensee response to the vulnerability of the
low setpoint trip function to single failure concerns as a conserva-
tive action. Furthermore, the licensee will be replacing all cir-
cuitry involved with this event as part of the nuclear instruments-
tion upgrade scheduled for the 1990 refueling outage. This event and
licensee corrective actions are documented in LER 50-29/88-14, issued
on January 7,1989. No additional safety concerns were identified as
a result of inspector review of this event.
d. Plant Startup From Refueling / Unplanned Reactor Protection System
Actuation
Plant heatup to Mode 4 was initiated on January 9,1989. Mode 3 was
achieved at 6:45 a.m. on January 10, 1989. At 7:36 p.m. on
January 11, 1989, an unplanned actuation of the reactor protection
system (RPS) on high start-up rate occurred. The plant was in Mode 3
at the time and performing control rod drop time measurement in
accordance with procedure OP 4703 in preparation for start-up physics
testing. Group "A" rods, which were at 82 inches and being withdrawn
to 90 inches, properly inserted to the full-in position in response
to the RPS trip. Plant operators noted that the high startup rate
RPS- trip occurred at the same time that the No. I boiler feedwater
pump was started. The nuclear instrumentation channels were being
supplied by the 120 volt a-c alternate supply output of the No.1
vital bus inverter. This alternate supply to the vital inverter is
derived from the same 2400 Volt a-c bus that provides power to the
No. I boiler feedwater pump. The licensee attributed the false high
start up rate RPS trip to voltage fluctuations on the nuclear instru-
mentation power source that occurred as a result of starting the
boiler feedwater pump. Since the vital bus inverter was undergoing
maintenance at the time of the RPS trip, the alternate supply output
from the inverter was used. At 11:09 p.m. the No. I vital bus
inverter was fully operable and providing 120 volt a-c output from
it's 125 volt d-c supply. The licensee notified the NRC via the ENS
at 9:05 p.m. on January 11, 1988 and will be documenting the actua-
tion of the RPS as an LER.
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On January 12, 1989, at.1:46 a.m. initial criticality of Core XX was
achieved per OP-2103, Reactor Startup and Shutdown, and OP-1701, Core.
- XX' BOL Zeru Power Physics testing'. The measured critical boron con-
-centration at hot zero power with all rods out was.2174 ppm, which
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was within +/- 10% of the calculated . design value -(2125) ppm) and-
within the acceptance criteria of the applicable operating procedure.
The licensee completed Core XXL startup physics testing on
January 13, 1989. The reactor engineering department completed all
startup physics testing and, following data reductions and review,
determined - that all tested parameters met required acceptance cri-
teria. The inspector found that the requirements stipulated in pro -
cedure OP-1701 for prerequisites, procedure steps, verification sig-
natures and acceptance criteria were met.' No discrepancies were
identified. Following delays due to turbine stop valve and turbine
governor oil ' pressure problems, the generator was phased to the grid
. at 11:16 a.m., January 15, 1989. Subsequently, at 10:00 a.m. on
January 16, 1989, as the generator ' was removed from the grid for -
overspeed trip testing, the Z126 011' circuit breaker (OCB)-that con-
nects _one of the 115kv lines to the switchyard did not trip. -This
resulted in. the turbine generator being motorized for a ten minute
period. At 10:10 a.m. , the OCB was manually tripped from the switch-
yard control cabinet. - A review of this condition was conducted by
the licensee's staff, the onsite Westinghouse field engineers and the
Westinghouse turbine generator engineering organization. The cause
of the breaker malfunction was a burned out trip coil. No unaccept-
able equipment operating conditions were _ identified and further-
inspections of the turbine generator were considered unnecessary.
While the plant was in Mode 2 and preparations were being made to
return the generator to the grid, a blowing steam leak on the upper
pressurizer manway was identified. The generator was . phased to the
'
grid at 9:04 p.m., January 16, 1989. As of 8:00 a.m., on
January 17, 1989, the plant was in Mode 1 with power being reduced to
remove the generator from the grid to facilitate turbine overspeed
testing. By 10:32 a.m. the licensee successfully completed turbine
testing, and at 2:49 p.m. on January 17, 1989, the generator was
phased to the grid and the power ascension program to full power was
initiated. Regarding the upper pressurizer manway steam leak, it
appears that the leak has become a slight wisp of steam and leakage
detection systems indicate minimal main coolant system leakage. The
licensee is inspecting the pressurizer manway leak during it's bi-
weekly containment inspections. The inspector had no further ques-
tions of the licensee on this matter at this time.
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9. Maintenance Ob'servations l
J
The inspector observed and reviewed maintenance and problem investigation
-
activities to verify compliance with regulations, administrative and main-
tenance procedures,- codes and standards, proper QA/QC involvement, safety
^
tag use, equipment alignment, jumper use, personnel qualification, radio- i
logical controls for worker protection, fire protection, retest require- d
The following
'
ments and deportability per Technical Specifications.
activities were included:
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Maintenance Request (MR) 88-1452; General Electric AK-50 series
breakers - Send _to GE Atlanta for inspection and refurbishment
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MR 87-1366; . Repair body-to-bonnet seating surfaces and replace disc
on No. 2 loop hot leg stop valve (MC-MOV-301)
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MR 88-1755; Replace disc and inspect. stem on No. I loop hot leg stop
valve (MC-MOV-325)
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MR 88-2029; Nuclear instrumentation source range channel No. 2 would'
not pass functional test
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MR 88-2115; Control rod indicating coil stacks - inspection
-
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MR 89-123; No. 1 vital bus inverter - no output
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MR 89-253; Pressurizer manway (top) steam leak
-- .OP-5000.248; Resetting emergency bus No. 1 tie breakers. . .For EDCR
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OP-4506, Rev. 10, Inspection of ECCS circuit breakers
Based upon a review of licensee activities in this area, the inspector
noted the following:
--
MR 88-1452 was initiated to inspect and refurbish safety-related bus .
tie breakers BTIB, BT2B, BT3B and emergency diesel generator breakers l
EG-1, 2 and 3 during the current refueling outage. !
The inspector reviewed documentation for breakers BT3B and EG-3 in-
cluding MR 88-1452, quality assurance involvement during refurbish-
ment and post-repair testing, work orders, vendor product quality
certification for replacement parts, and high current trip data from
retest procedure OP-4506, Rev. 10, Inspection of ECCS Circuit
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Breakers. 'The. maintenance; supervisor was interviewed concerning past
'GE AK series breaker. problems at the. facility including availability.
and quality of 2 vendor. information .with regard to breaker maintenance
in general and . lubricants' in particular, the apparent licensee dif-
ficulty in providing the correct overcurrent tr,ip. time data to the
vendor, the degree of licensee oversight of. vendor. performance and
the-licensee trending and failure analysis program. l
The - licensee appreciation of the potential . generic nature of past
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breake'r ' problems and pro-active approach towards' resolution of in-
dustry concerns was noted by the inspector. as -being responsive to
previous NRC concerns documented .in Inspection Report 50-29/87-06.
<
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Regarding MR - 88-2115, the licensee in response to its own and NRC
concerns for what appears to have been deteriorating performance of.
the rod position indication (RPI) system prior to the 1988 refueling
outage, established an inspection and repair program. Following "an
extensive' investigation led by a maintenance support department (MSD)~
I&C engineer, repairs were' made to the . coil stacks that drive the -
position indication light emitting diodes. Significant performance-
improvement in control room indication for the RPI- system was noted
by the inspector at the start of Cycle XX operations. The license'e
investigation has attributed .the deteriorated performance of the RPI.
system to: 1) elevated temperatures at the coil stacks located above
the' reactor head causing damage to the indicating coils; 2) coil
polarity problems associated with primary winding leads misidentified
by the manufacturer; 3) heat damage to RPI system cables; 4)'inoper-
able light emitting diodes; and 5) high resistance terminations at
containment penetration terminals. Items two through five were cor-
rected with the major and long-term problem being excessive coil
stack temperatures. Although minor improvements were made to deflect
cooling air into the coil stack areas, the licensee is continuing to
investigate additional ways to improve the reactor head ventilation
system.
To help evaluate the efficiency of the reactor head ventilation'sys-
tem, thirteen thermocouple with the capability of being read in the
control room were installed adjacent to various coil stacks via
Temporary Change Request No.88-394. The critical temperature com-
ponent in the indicating coil assembly is the varnish used in the
coil windings, which melts at 460 degrees F. Based upon the licensee
inspections, they have concluded that the primary winding tempera-
tures have been greater than 460 degree F. The licensee will be
closely evaluating the area temperatures adjacent to the coil stack,
especially during the summer months. Inspection and installation
procedures for the RPI system coil stacks have been modified to aid
identification of coil stack problems prior to inspection and to
ensure that following a refueling outage the RPI system is function-
ing properly. As of January 23, 1989, with the plant at 100% of
rated power and four containment ventilation system fans operating
normally, the highest thermocouple was indicating 394 degrees F.
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The ir.spector noted that the licensee approach to resolution of
concerns in this area was aggressive, with timely and appropriate
corrective actions taken.
No deficiencies or safety concerns were identified by the NRC in this
program area.
10. Surveillance Observations
<
The inspector observed tests or parts of tests to assess performance in -
accordance with approved procedures and LCOs, test results (if completed),
removal and restoration of equipment, and deficiency review and resolu-
tion. The following tests were reviewed:
--
OP-4571, Rev. 6, No. 2 Station Battery Service Test
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OP-4522, Rev. 10, Inspection and Maintenance of Station Battery No. 2
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OP-4524, Rev. 5, No. 2 Battery Charger Service Test
--
OP-5808, Rev. 2, Inspection and/or Maintenance of Vital Bus Inverter
No. 2
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OP-4645, Rev. 6, Nuclear Instrumentation Channel Calibration
--
OP-5755, Rev. 9, Inspection and Maintenance of ACB and/or Contractor
No. BTIA
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OP-4222, Rev. 10, Reactor Rod Control System Pre-Critical Check
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OP-1701, Rev.10, Core XX BOL Zero Power Physics Test
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OP-1702, Rev.14, Core XX Zero to Full Power Physics Test
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OP-4613, Rev. 9, Reactor Permissive Circuit Calibration and Func-
tional Test
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OP-4204, Rev. 37, Test or Operation of the Safety Injection Pumps and
Determination of ECCS Subsystem Leakage
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OP-8522, Rev. 3, Primary Vent Stack Radiation Monitor Surveillance
Procedure
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' Based ' upon a review of ' licensee activities in this area, the inspector
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On December 14, 1988, the licensee satisfactorily performed procedure
OP 4571, Nr.. 2 Station Battery Service Test. The test is performed
to satisfy the -18-month TS 4.8.2.3.2.d requirement which verifies
that battery capacity is adequate to supply and maintain in an
operable status all actual emergency loads.
~During. the conduct of procedure reviews the inspector noted the
following:
(1) A note following step 9 of OP-4571 incorrectly specifies that a
cell test lead be connected from the load resistor bank. to the
positive side' of Cell No. 2 vice Cell No.1. Maintenance.per-
sonnel' brought this to the attention of the cognizant engineer-
who directed the proper connection.accordingly.
(2) A note following step 15 of OP-4571 instructs maintenance per-
sonnel-to short out any cell approaching reversal potential (1.0
vdc) and continue the test. No guidance is provided to ensure
that a . new battery minimum terminal voltage be ' calculated sub-
.sequently as required by IEEE Standard 450-1975.
As a result of discussion with the licensee . cognizant maintenance -
services department engineer, it was indicated that procedure OP-4571
and other relevant procedures would be revised to address the inspec-
tor's concerns and . reviewed to ensure their conformance to industry
standards.
During ' performance of the test, the auxiliary operator was observed
. to question a low battery voltage indication on No. 2 Battery Dis-
tribution Switchboard. In ' response to questioning by the inspector
the shift supervisor indicated that while aware that a service test
would be performed he had neglected to inform the operator that the
test had commenced. The operator's response to the low voltage
indication was noted to be timely and correct.
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As required by TS Surveillance 4.8.2.3.2.c, the licensee performed
procedure OP-4522, Rev. 10, Inspection and Maintenance of Station
Battery No. 2. The inspector observed that all cell interconnecting
bars were removed and recoated with anti-corrosion material and posts
l- were cleaned despite the generally excellent condition of these
l components.
Procedure OP-4522 does not specify a torque value for installation or
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periodic tightness checks of cell connecting bar-terminal fasteners.
However, in response to the inspector's questions, maintenance per-
sonnel indicated knowledge of the correct torque values and the con-
sequences of overtorquing lead cell posts.
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lL While not committed to IEEE Standard 450-1987, the licensee on its I
own initiative issued Temporary Change No. '2 to OP-4522 to reflect - d
the cell-to-cell and terminal connection detail resistance guidance
contained in that' document.
The conservative licensee approach to station battery maintenance
issues raised by the inspector was both timely and appropriate, and-
favorably reflects general licensee responsiveness' to NRC-
initiatives.
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During performance of surveillance procedure OP-8523,. the licensee
noted that heat tracing for high range noble gas channel. of.the pri-
mary vent stack (PVS) was inoperable. Subsequent review indicated
that thes controlling breaker had been deenergized. The '1.icensee -
evaluation determined that the high range noble gas channel wa's oper-
able because the heat tracing was not needed for the current plant
conditions. Licensee corrective measures included reviewing the bus
loads and revising the auxiliary operator log sheets to require oper ' 1
ability verification of all PVS sample line heat tracing.
During inspector: review of PVS Technical Specification.(TS) require-
ments, it was noted that some cycle 18 refueling NUREG 0737 TMI Task
Action Plant; Item II.F.1 commitments were not included in current TS.
Specifically, requirements delineated in licensee letter .FYR 84-111,
dated November 19, 1984, for the PVS and steam line monitors, did not ,
exist in Table 3.3-4, " Radiation Monitoring Instrumentation". Dis-
cussion with licensee personnel indicated;that the requirements were
not fincluded inadvertently, with .the causerattributed to weaknesses
that existed at the time 'in - the . commitment tracking system. The
licensee stated that an' amendment would be initiated in January 1989-
to include these requirements. Licensee. corrective actions were
adequate and appropriate.
11. Onsite Review Committee Activities
The inspector attended regularly scheduled meetings of the Yankee Nuclear
Power Station plant operations review committee (PORC) on November 16, 20,
23, December 14, 19, 21, 23 and 24, 1988, and January 4, 5, 7, and
17, 1989 to ascertain that provisions of TS 6.5.1 were met.
--
On December 14, 1988, the inspector attended the PORC meeting to ,
observe the licensee's evaluation of proposed LER 50-29/88-10, Auto- l
matic ESF Acuation Following Breaker Action.
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+ - . Topics - discussed were the adequacy of cthe review of ' the test. proced-
L~
ure involved, th'e limits of 'PORC review of' highly technical one-time -
procedures, and ultimate responsibility for ' vendor oversight. .The
need to -take advantage of existing trip actuation " blocks" where
available was emphasized.
The committee's . approach was conservative ' and. thorough'. The provis-
ions of TS 6.5.1 were met'and no inadequacies ~were identified.
--
At PORC meeting 88-148 on December 24,1988, the licensee reviewed
- and disapproved procedure OP-6260, Rev. O, Nonreturn Valve . (NRV)
Accumulator Nitrogen Measuring and Charging. This procedure reflec-
ted the. reassignment of- responsibility ~ for the activities from the
operations department to the I&C department. In addition to the PORC
concerns, additional issues identified by the inspector required
resolution by. the licensee, which were 1) identify applicable Mode 4
. TS requirements, 2) address the impact of the test harness assembly
on the accumulator volume, 3) demonstrate the adequacy of the thermal
equalization criteria, .'and 4) ascertain if the Rockwell (the vendor
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of the' NRVs) technical' manual changes represented updated design
basis information.
Further- licensee review of' Item 4 above resulted in a determination
that an' error existed in the pressure versus temperature curve con-
tained in technical manual No. RAL-518 which was incorporated into
the procedure. In addition, bolting torques for some of the-NRV cap .
screws were revised. .The' vendor. is on the licensee Approved '. Vendor
List, which according to the licensee QA program, ensures that vendor
activities ~ are in conformance with 10L CFR 50, Appendix B. However,
it appears that the design basis changes 'being incorporated in the
technical manual were not receiving design verification by. the vendor
as required by 10 CFR 50, Appendix B, Criterion. III. In response to
licensee and NRC concerns, a YNSD engineering review of NRV technical
manual revisions was performed, as documented in YNSD memorandum YRP
28/89 dated January 6, <1988. This memorandum concluded that . final
technical information 'used by the plant staff for maintenance and
operational . activities on the NRVs was accurate, and had the incor-
rect data provided in the manual been used, it would not have
resulted in loss of. safety function.
Licensee procedure AP-0075, Rev. 2, Vendor Equipment Technical Infor-
mation - Program, provides for. the review and control of vendor tech-
nical information to ensure that appropriate and most current infor-
mation is available for maintenance and operational activities. This !
procedure requires that the cognizant department head (in the case of
'
the NRVs it would be the maintenance supervisor) ensures that the
technical information for the controlled technical manual undergoes a
,
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review for adequacy of technical content. Revision 3 to technical
manual RAL-5186 was issued as a controlled document on
November 22,1988, by the engineering assistant in the maintenance
department without any technical verification that information con-
tained in the manual was correct. Separately., from this controlled
document the I&C supervisor obtained revision 3 and was using it as a
basis for the development of the new procedure OP-6260. The only
person on site aware of technical manual discrepancies was'a mainten-
ance support department engineer, who was independently attempting to
resolve the discrepancies with the manual.
It appears that the current licensee program involving ve.ndor equip- j
<
ment technical information is neither well thought out nor adequately '
implemented. The NRC has identified in the two most recent SALP
Reports (50-29/85-98 and 86-99) that the licensee program for control
of technical manuals, as specified by Generic Letter 83-28, was slow
in developing. The inspector's observations involving inadequate
licensee performance in ensuring the accuracy of vendor technical
information for the NRVs further demosntrates that weaknesses con-
tinue to exist in this area.
In response to the inspector's concern, the licensee initiated
several corrective actions, including: 1) the removal of other tech-
nical manuals from controlled status until technical evaluation sub-
stantiated the accuracy of the manuals; 2) the issuance of Nonconfor-
mance Report (NCR) No. 88-23 to document the discrepancy involving i
receipt of incorrect technical information in the NRV vendor manual, '
evaluate the vendor QA program and determine appropriate corrective l
actions; and 3) the issuance of NCR No. 88-24 to document and resolve '
conditions that allowed the Rockwell maintenance manual RAL-5186,
Revision 3, to be made a controlled document by the maintenance
department without providing adequate review as prescribed by proced-
ure AP-0075.
The inspector noted that the licensee was now responsive to the NRC
concerns involving this item. Further, it appeared that the afore-
mentioned vendor technical information program implementation defici-
encies have become a catalyst for the licensee to resolve the current
inability to develop and implement an adequate program. Licensee
actions in response to this item will be followed under Unresolved
Item 85-12-02.
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Duringfthe current refueling outage, the lisensee implemented Engi-
neering Design Change. Request (EDCR) No.87-306, Protective Relay.
Improvements. One of , the implementing procedures .was OP-5000.248,-
Rev. 0,; Resetting Emergency Bus 1 Tie Breakers BTIA, .BTIB, EMCC ,
,
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Feeder- Breaker for EDCR 87-306. This procedure was originally re- '
l
3' . viewed by the PORC on November 26,'1988. Temporary Changes Nos. 1 &
-2 to procedure OP-5000.248 were submitted and reviewed by PORC at its
December 4 and 18,1988 meetings,'respectively. Subsequently, at its
December 19, 1988 meeting, which was' attended by the inspector,- the
PORC reviewed Tempo'rary - Change No. 3 to procedure OP-5000.248. Tem- -
porary Chan.ge No. 3 to procedure OP-5000-248 was necessary to correct
- errors caused by the -use of an incorrect time-current characteristic
curve. Because of.. the changes made to the acceptance criteria on the
breakers, the PORC requested that YNSD engineering perform an inde-
pendent review of EDCR 87-306 to assure that the, settings ha' ve been
made correctly and are acceptable.
The inspector - determined that further review iri this- area was . war-
ranted. As originally envisioned -in the EDCR, overcurrent trip
devices of a different type were to be replaced on both normal and
alternate'ipower supply breakers for ~480 a-c motor control center
,'. Et1CC-1~. .However, the design and design verification processes failed
to detect .the error that the Bill of. . Material s-- did - not list . the
-
>
replacement ~ devices and therefore they were not ' installed. The time-
current. characteristic curve specified for use in the EDCR was based
upon the change out of the old overcurrent trip device. A subsequent
engineering evaluation conducted on January 9,1989 (Memorandum YRN
44/89)_ has determined _that upon changing a molded case circuit
breaker on EMCC-1, the use of the existing overcurrent trip devices
provide the necessary protection coordination and meets the intent of
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the EDCR.
The inspector noted the PORC concern for ensuring the technical
accuracy of the breaker- trip device ' settings. However, they did not
...
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focus : on the fact that an error made during the original design
effort was not detected during the design verification . phase of the
EDCR. This matter was discussed with the Plant Superintendent who
acknowledged the inspector's comments and concerns.
The inspector viewed the fact that a design deficiency existed and
was identified during post modification testing was an unnecessary
challenge to the quality of licensee post-modification testing activ-
ities. The existence of.a design deficiency following the completion
of initial design activity and design verification activity is con-
sidered by the-NRC to be a condition adverse to quality. The inspec-
tor reviewed the licensee administrative controls established to
review conditions like that described above if PORC had identified
-
the design program deficiency as a problem.
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According _ to 10 CFR 50, Appendix B, ~ Criterion XVI, the licensee .is
-
required to establish measures to assure 'that significant conditions
adverse to qual _ity are ' promptly identified. and corrected. Also,
these-measures should assure that' those correctivevactions and those
actions. taken to prevent recurrence are documented and Lreviewed. by
the. appropriate levels of licensee ma'nagement. The' licensee's Opera- i
tional Quality Assurance Manual, Y0QAP-1A, Section XVI-Corrective
Action, identifies the YNSDHquality assurance department as being
responsible for review of. recommendations to prevent recurrence of a
significant ' condition adverse to quality. In addition, the YNSD
engineering and/or project departments are responsible for review of
conditions adverse to quality which ~ involve design deficiencies to
determine ' the. cause of the condition. and provide recommendations of
corrective ' action to preclude repetition of design deficiencies.
The inspector- determined that no effective measures, in the- form of
~
4
clear. procedures, had been established to translate these corrective
action requirements' of 10 CFR 50 and the YOQAP into working instruc-
^
tions for the licensee organizations responsible for dealing with
design program deficiencies. Specifically, . existing administrative
controls did not provide:(1) that the Quality issurance Department be
responsible -for review of recommendations to prevent recurrence, .and
(2).that Engineering and/or Project Departments be responsible for
review and determination of cause, and provide recommendations for
'
corrective action. This- lack of clear procedures is considered a
violation (50-29/88-22-02).
With respect to the overcurrent trip device design deficiency dis-
cussed ~ above, the inspector considered that, even if the' PORC had
initiated a Nonconformance Report to identify the- fact that a design
deficiency had existed up to the point of conducting post-modifica-
tion testing, such action would not ha've assured that the program-
matic quality assurance requirements would have been accomplished.
However, in response to the NRC-identified violation, prior to the
end of the inspection period, the licensee initiated the development
of a YNSD Engineering Instruction (WE-009) to provide the requisite
level of administrative controls to process identified engineering
deficiencies. On January 12, 1989, the licensee issued YNSD Service
Request MO-89-002 to review all Engineering Change Notices issued to
EDCRs in calendar year 1987 and 1988 and all calculation revisions
issued in 1988 for detection of engineering deficiencies.
The inspector had no further questions on this matter.
12. Plant Information Reports
Plant information reports (PIRs) prepared by the licensee per AP-0004 were
reviewed. The inspector determined whether the conditions were reportable
as dcfined in the TS and whether the licensee's system of problem iden-
tification and corrective action is being effectively utilized. The
following PIRs were reviewed:
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PIR No. Occurrence Date Report Date Subject
88-09 8/19/88' 10/14/88 The unauthorized: moving [
of' a " Radiation Area" ;
. posting and noncompli-
ance with .RWP- require-
-
ments. 1
PIR No. Occurrence Date Report Date Subject
.88-10 9/17/88 1/1/89 Extensive water level ~
oscillations in.. heater-
drain tank, and .No. 2
and No. 3 feedwater
heaters. Water. hammer
events experienced in- :
,
second point and third
point extraction steam
J ' lines.
PIR 88-09: This report describes an August 19, 1988 event involving a-
.special calibration project that was being performed by a Yankee Nuclear
Services Division radiological engineer in the radiation protection
department's: calibration trailer. The"PIR provides good documentation of .i
the' licensee's response to .the event, including corrective actions'imple- 'i
mented. Also documented in the PIR was the lice'nsee's concern that this ;
event, as well. as two similar incidents, reflected an apparent lack of t
detailed- followup by radiation protection personnel. Inspector observa-
tions in Section 6'of.this report suggest that the licensee was ineffec-
-
.tive in translating their concern in to appropriate corrective actions.
The inspector had no additional comments.
PIR 88-10: This event was reviewed in Inspection Report 50-29/88-16, l
Section 6.b. The inspector noted that the licensee had determined the j
cause of the occurrence and specified appropriate short-term and long-term
corrective actions.
13. Review of Licensee Event Reports
Licensee Event Reports (LERs) submitted to NRC:RI were reviewed to verify
that the details were clearly reported, including accuracy of the
description of cause and adequacy of corrective action. The inspector y
determined whether further information was required from the licensee, 4
whether generic implications were indicated, and whether the event war-
ranted onsite followup. The following LERs were reviewed. ,
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Event! ' Report
LER No. Date' .Date Subject-
88-08 5/17/88~ 6/16/88 -Reactor / Turbine Trip on Loss of Gener-
ator Field Excitation
' '
'88-09- 11/9/88- 1/6/89 Nuclear Instrumentation Gain Setting
Inadequacies
l 88-10 11/16/88 12/15/88 Automatic' ESF. Actuation Following
Breaker Action _
88-11 11/21/88 12/20/88 Battery -Charger No. 2 Failed Surveil-
lance Testing
88-12 12/5/88 1/4/89 Reactor Protection System Permissive
Circuit Operated Outside Technical
Specification Limits-
88-14 12/8/88 1/7/89 Nuclear Instrumentation Channels 7 and
8 Low . Power Set Points Inoperative
a. LER 50-29/88-08: Reactor / Turbine Trip on ! Loss of Generator Field
, Excitation. An onsite inspection consisting of review of licensee
'
documentation and discussions with the cognizant engineer was per-
formed on December 13-14, . ~ 1988. This event was last discussed in
inspection report 50-29/88-09, Section 8.
The LER accurately describes- the event as understood on the date of .
issuance and the ~short term corrective action taken. In the interim,
the aggressive licensee followup regarding this complicated event
resulted in greater understanding of its sequence and probable root
,
cause. 4 i.- <
. On May 17,1988, with the plant at 100% of rated power, a ' reactor
scram and partial loss of main coolant flow occurred due to loss of
main generator field excitation and consequent loss of the Z-126
Harriman high voltage transmission line, one' of two sources of 'off-
site power. The event was caused by 1) apparent failure of the gen-
erator static exciter field overvoltage protection unit, 2) trip of
the static exciter feeder breaker causing loss of generator field and
control power to plant protection relays, 3) low line impedance relay
action off-site due to the generator's shift to a self-excitation
induction mode of opetation, 4) rapid closure cf turbine control
valves leading to opening of the scram breakers, and 5) failure of
J
- _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ - _ _ - _ - _ _ _ _ _ _ - -
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the 'autom4 tic bus cross-tie logic to be initiated. Subsequently, the
licensee = initiated. Service, Request-No.88-195, dated May 20, 1988,- to
_
evaluate. the p.erformance of the static exciter, its impaction. plant
.
protectivo relays and the ability of the loss of field system to pro-
tect 'the : generator' and plant adequately.. Licensee discussio'ns with
. General Elactric Power Generation Engineering 'and ' detailed review of -
plant equipment. respon'se during the event resulted in identification
. of gthe' Fiel,1 Overvoltage Protection unit : as the : probable ' source . of
- the lossiof field' and the issuance -of EDCR 88-311, Exciter Control
Modification, on December 1, 1988. The' modification replaces an
existing self-ceset static exciter protection relay with a latching,
manual reset type and eliminates the 2400 VAC static ~ exciter feeder-
3 breaker trip feature from the generator loss of field and overcurrent
relays circuits. This long-term corrective " action. will enhance the
reliability . of the ' plant protective relay system and preclude a
similar loss of static exciter control power to protection relays.
The' need to address- in an updated LER the results of the engineering
studies and long-term corrective action: was discussed with the Tech =
nical Services Manager, who acknowledged the~~ inspector's concerns-
listed below and -' agreed t h a', a' supplemental LER was . appropriate:
--
The relay action at the Harriman end' of the Z-126'line' needs to-
'be tied to the' loss 'of generator field. Loss of the Z-126 line
contributed- directly to: the deenergization of 2400 - Vac . Bus :
No. 2.
---
The cause for failure of the automatic bus cross-tie logic to
be.. satisfied requires explanation.
--
Root cause' analysis is deficient in that a causal link between
the' apparent Harriman line fault and the loss of. generator. field a
is not established.
--
The licensee should inform the NRC regarding the resul's t of the
testing referenced in the LER.
--
Long-term corrective action entailing modification of the static
exciter and its affect on protective system response should be
addressed.
Strong engineering support at both the plant and YSND in response to
this event was noted by the inspector to be indicative of an on going
licensee. strength in resolving equipment reliability issues.
.
This LER remains open pending issuance of a supplemental LER by the
licensee.
.
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- b - b. LER
- 50-29/88-09: Th'e details of this event - are ' discussed < in Inspec-
tion Report 50-29/88-25. The inspector had no further questions on:
..this matter and this LER is' considered closed.
c. LER 50-29/88-10: The details.of this event are discussed in Section-
t. -8.a of.this report. 'This LER is closed.
d. LER 50-29/88-12: LThe- details of this ' event are discussed. in Section-
8.b of this-report. This LER is closed.
e. =LER 50-29/88-14:- The details of this event are discussed in Section
'
.
-8.c of this. report. This LER is closed. !
14. Licensee' Response to NRC Bulletins
The licensee response to NRC Compliance Bulletin No. 88-11, Pressurizer
Surge Line Thermal Stratification,- dated December 20, 1988, was reviewed.
- This review included adequacy of the response to NRC Bulletin require-
ments,- timeliness of the resp'onse,- completion of identified. corrective
actions and timeliness of completion.
The bulletin required,:in part, that the licensee conduct a visual inspec-
tion' (ASME,Section XI, VT-3)' of the pressurizer surge line to identify
-
potential pipe . movements caused by thermal stratification. These pipe
movements may - result in exceeding the design . limits for fatigue and
stresses. Bulletin guidance directed the licensee to evaluate the surge
line ' piping, pipe supports, pipe whip ' restraints, and anchor bolts for
gross' discernible distress or structural damage including possible plastic
deformation of the surge line.
The licensee -response to the bulletin was timely and appropriate. It was
distributed .to the appropriate personnel who scheduled timely' evaluation
prior to startup from the refueling outage. This evaluation included a
visual examination, dimensional measurements, 'and incorporation of pro-
visions for temperature monitoring.
The initial licensee iaspection, documented in Maintenance Support Depart-
ment (MSD) memorandum 019/89, observed no plastic deformation of the pip-
ing. The licensee did note a slight downward deflection (1-1/8 inch) of
the surge line at the spring hanger (CRB-H29) when the line went from
cold to -hot. The licensee is continuing to monitor surge line
temperatures.
This bulletin remains open. , .
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Independent of the visual inspection, as detailed in section (1)(a) of the
bulletin, the inspector noted that as part of the pressurizer surge line
configuration, a beam attachment for hanger CRB-H29 had been laterally
located approximately six inches from the original hanger beam attachment.
In response to inspector questions as to the nature of the as-found hanger
conditions, the preliminary licensee review indicated that the relocation
had taken place in 1977 and was implemented by a maintenance request.
However, documentation and discussions with the licensee were unclear in
determining whether the original hanger had been incorrectly located or
whether it was moved to address a problem. The licensee is in the process
of verifying that the relocation of the hanger conforms to system design
requirements. This matter remains an Unresolved Item (50-29/88-22-03).
15. Organization and Administration
During the inspection period, the inspector reviewed changes to the licen-
see staff or organizational structure as described below. The review l
included verification that the licensee onsite organization is as
'
described in the facility TS and verification that personnel qualification
levels conform to ANSI N18.1-1971, as described in TS Section 6.3.1. l
--
As a result of the retirement or the President and Chief Executive
Officer, the licensee announced on December 9,1988 the appointment
of the Vice President in charge of Nuclear Engineering, Environmental
Engineering and Computer Services to President, Chief Operating
Officer. In addition, the New Hampshire Yankee President and current
Chairman of Yankee Atomic Electric Company was appointed Chief
Executive Officer.
The inspector had no further questions.
16. Review of Radiation Protection Related Allegation (RI-88-A-0120)
On Decemoer 5, 1988, an anonymous allegation was received by the NRC
Region I office regarding contractor workers being directed by their
supervision to unnecessarily remain in higher radiation areas (30-120
MR/h) rather than being allowed to proceed to lower exposure areas or non- I
radiological areas when work was complete. Following NRC review, the j
Plant Superintendent was requested to conduct an investigation and provide j
the licensee findings to the inspector for review. During the discussion,
the Plant Superintendent indicated that contractor worker concern had been
raised regarding the lack of posted low exposure waiting areas in the VC.
He stated that he thought the issue had been resolved in a previous meet-
ing with contractor supervision.
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1
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The . licensee investigation was completed and presented. to the NRC on i
December 15, 1988. It included an evaluation of programmatic radiological !
work controls, a review of worker briefings and ALARA guidance, a listing i
of worker exposures ' for- tasks completed in the VC, and photographs .of
radiological postings including designated low ' exposure waiting areas.
The investigation also included a personal statement by a cognizant radia-
tion protection technician dedicated :to support contractor radiological
work evolutions'in the VC.
Inspector review of zthe licensee investigation indicated that a thorough
and timely programmatic evaluation had been completed. lNo anomalous
exposures were noted to have occurred among contractor support personnel.
ALARA guidance directed personnel in proper radiological practices to
reduce' exposure including the use of low exposure waiting areas. However,
the licensee investigation did not evaluate fully the alleged contention
that workers were being directed to unnecessarily stay in radiological
areas when ' work.was complete. Specifically, workers were not questioned
to determined. the validity of this concern. However, the dedicated RP
technician's statement indicated that he aad directed workers to go to
lower exposure areas or leave the radiological area, as appropriate. The
inspector also evaluated the allegation through discussions with contrac-
tor personnel and through observation of VC work practices and postings.
The workers stated that some instances had ' occurred. where they . were
instructed to remain in the VC beyond the duration of the task. However,
they characterized these instances- as being isolated in nature ~ and not
directed by. management initiatives. They also stated that the instances
had occurred in the early stages of the outage and were not recurring or
recent in nature. Inspector tours of the VC indicated good posting of low
exposure. waiting areas as well as specific postings to indicate the dose !
'
rates.
Based on the licensee investigation and the inspector's evaluation, the
allegation was determined to be unsubstantiated.
17. Licensee Response to Selected Safety Issues
As requested by NRC:NRR and NRC:RI, the inspector reviewed the licensee
response to selected safety issues.
a. Storage Battery Adequacy Audit
The NRC:RI Temporary Instruction (TI) 87-07 issued on December 29,
1987, required a review to determine if licensees assure that storage ;
batteries will, in accordance with the current licensing basis, re- 1
main properly operable. In this inspection period, the NRC performed
an audit to assess the adequacy of control over storage battery oper-
l
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ability. and compliance with existing NRC requirements using Attach-
ment 1 of the TI. Attachment 2 of the TI was provided to the -licen
see to assist the utility in providing information efficiently. The-
inspection findings'for this TI are contained in Attachment 1 to thisu
report.
"
This TI is Closed.
b'. Loss of Decay Heat' Removal Capacity with Reactor Coolant System
Partially Drained - PWR
The inspector. performed an inspection of- procedures and personnel
-readiness'to determine licensee actions to prevent loss of decay heat
removal during operations with the reactor coolant system partially
drained. This inspection was conducted in accordance with Region I
TI No. 88-02, dated' March 28, 1988. The results of the inspection
are contained-in Attachment 2 to this report.
In reviewing the licensee approach to resolving NRC concerns on this -
.
matter, the inspector was able to assess licensee readiness both
' prior . to, and during, partially drained main coolant system condi-
tions during the recent refueling outage. As a result, the inspector
determined .that .the licensee actions were representative of a con-
servative, technically sound, and thorough approach to resolving
conditions of potential safety significance.
This TI is closed.
c. Information on High Temperature Inside Containment in PWR Plants
As required by NRC Inspection Manual TI 2515/98, the inspector
assessed the adequacy of containment temperature monitoring and
obtained containment average ambient operating temperature profiles.
This information would allow the NRC to determine whether or not high-
containment temperatures are a plant specific problem or generic.
Previous inspection reports (50-29/87-11 and 88-16) have contained
information similar to that required by Exhibit 1 of the TI. The
inspector transmitted to NRC:RI on . December 23, 1988, an assessment
of the adequacy and representativeness of containment temperature
monitoring and average operating containment temperatures for the
_
1988 summer months of June - August.
The inspector identified no safety significant concerns as a result
of reviewing plant performance in this . area. The inspector deter-
mined that the- licensee has a pro-active containment temperature
evaluation program that: 1) is capable of identifying degraded con-
tainment cooling equipment performance, and 2) results in timely and
appropriate corrective actions that precludes the occurrence of
conditions adverse to plant safety.
This TI is closed.
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18. part 21 Report - Main Coolant Stop Valve Disc Cracking
On December 12, 1988, the licensee informed the resident inspector that
its prior identification of main coolant stop valve disc cracking warran-
ted the issuance of a Part 21 report. The licensee issued the 10 CFR Part-
21 report on December 14, 1988. Although no substantial safety hazard was
identified for the Yankee facility, recent metallurgical examination of a
l- cracked disc -identified in May,1987 and information provided in Informa-
l tion Notice 88-85, Broken Retaining Block Studs on Anchor Darling Check
l Valves, warranted the issuance of the Part 21 report to alert other poten-
tial users of components made of stainless steel 410. The observed crack-
ing of the' loop 2 cold leg stop valve disc was due to temper embrittlement
'
of the stainless steel 410 base material and residual stresses in the heat
affected zone of the stellite areas of the disc induced during the hard
facing overlay process.
The licensee disassembled, inspected, and replaced discs in the hot legs
l
of main coolant loops 1 and 2 during the refueling outage. Preliminary
visual inspection of the removed discs has found additional evidence of
cracking in one of the discs.
Th'e initial NRC review ~ of the disc cracking condition is contained in
Inspection" Report 50-29/87-06, Section 8. The condition was identified
x
during the 1987 refueling outage. As a result of a licensee engineering
, evaluation and replacement of the loop.2 cold leg stop valve discs, oper-
I
ation of the plant with the possibility of similar cracks in other loop
- stop valves was considered acceptable. The NRC found no unacceptable
- conditions with the licensee plans, which included a. confirmatory metal-
L lurgical examination to be conducted by a licensee vendor. The valve
discs were sent to the Westinghouse Research and Development Center for
i
evaluation. Licensee memorandum PED 482/88 dated December 8,1988, re-
l
viewed the results from the preliminary Westinghouse failure analysis and
l contained the results of the YNSD engineering staff independent evalua-
l tion. A subsequent memorandum YRP 2250/88, dated December 12, 1988,
evaluated the current licensee understanding of the issues associated with
the valve disc cracking, and recommended that the condition be reported
under 10 CFR Part 21 to ensure other plants are aware of the occurrence.
Additional investigation by the licensee is to include the analysis by
Westinghouse of samples from each of the valve discs removed from the hot
leg stop valves during the 1988 refueling outage. The licensee will re-
quest that the metallurgical examination of the samples be included in the
final Westinghouse report, which is expected to be released in mid
February, 1989. This report will be provided by the licensee to the in-
spector for subsequent transmittal to the NRC:RI Division of Reactor
!
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Safety for in-office review and evaluation. The licensee replacement of
main coolant loop isolation valve discs during the 1988 refueling outage
used new discs that have been redesigned by Westinghouse to improve their
long-term reliability. The redesign, which is documented in Engineering
Design Change Request No.88-313, includes using new disc material of 316
SST in lieu of 410 SST, changes in the disc springs, and revision in the
disc hard-facing process using stellite.
No unacceptable conditions were identified by the inspector as a result
of reviewing the licensee 10 CFR Part 21 report and corrective action to
address the disc cracking issue.
19. Inservice Inspection Program - Pumps and Valves
Based on additional information from the licensee, observations and find-
ings described in Inspection Report 50-029/88-14 are revised or supple-
mented as indicated below.
On page 3 of the report in the second paragraph, it was stated that a
spectrum analyzer is used to trend pump performance. While this is true,
the spectrum analyzer is used only when the normel hand-held vibration
monitoring equipment indicates a problem with the machine being tested.
Also, under normal circumstances, data from the hand held vibration probe
is compared with displacement measurements obtained from the installed
accelerometers and not with displacement data obtained from spectrum
analysis.
Additionally, on page 5 of the report in the first paragraph, it was
stated that a program for full flow testing of the primary safety valves
will be developed. It should be noted that a program is being developed
for setpoint testing of the primary safety valves and not full flow
testing.
20. Unresolved Items
An unresolved item is a matter about which more information is required
to ascercasi, whether it is an acceptable item, a deviation or a violation.
An unresolved item is discussed in Section 14 of this report.
21. Management Meetings
During the inspection period, the following management meetings were con-
ducted or attended by the inspector as noted below:
--
The inspector attended an entrance meeting held on November 28, 1988,
with an NRC:RI specialist inspector at the start of Inspection 50-29/
88-23, which consisted of a review of actions on NRC-identified con-
cerns, design changes and plant modifications, and licensee response
to NRC Generic Letter 83-28, Item 4.1 concerning vendor recommended
modifications to reactor trip breakers.
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--
The inspector attended an exit meeting held on Decemoer 16, 1988,
with an NRC:RI health physics specialist at the conclusion of Inspec-
tion 50-29/88-21, which consisted of s review of the imp % mentation
of the radiological controls program during .the current refueling
outage.
--
The . inspector attended an exit meeting held on Decenber 16, 1988,
with an NRC:RI specialist inspector at the conclusion of Inspection
50-29/88-24, which consisted of the review of steam generator eddy
current test results, inservice inspection, secondary water chemistry
results and licensee actions on previously identified NRC items.
--
On December 17, 1988, the inspector discussed items of mutual
interest during a drop-in visit at the resident office by the Vice
President / Manager of Operations and the recently appointed President /
Chief Operating Officer, Yankee Atomic Electric Company.
--
Exit meeting held on December 30, 1988, by the inspector and NRC:RI
reactor engineer at the conclusion of Special Inspection 50-29/88-25,
which resulted from the licensee determination that non-conservative
adjustment of nuclear instrumentation amplifier gains had occurred.
--
'At periodic intervals during the course of the inspection period,
meetings were held with senior facility management to discuss the
inspection scope and preliminary findings of the resident inspectors.
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ATTACHMENT 1
NRC:RI TI 87-07: STORAGE BATTERY AUDIT
A. Purpose
Region I Temporary Instruction (RTI) 87-07, Storage Battery Audit, was
performed to assess the licensee program to ensure that station wet cell
storage batteries will remain operable in accordance with the current
licensing basis. The audit included review of the licensee response to
RTI 87-07, Attachment 2, operating procedures and documentation, system
walkdowns, and discussions with the cognizant licensee maintenance ser-
vices department engineer. Surveillance observations relating to the main
station batteries are contained in Section 10 of this inspection report.
B. System Description
Direct current requirements at Yankee Nuclear Power Station (YNPS) are met
by three independent 125 Vdc distribution systems, each comprising a 125
Vdc lead-calcium battery, a 300 ampere static battery charger, and DC
distribution panels. A spare 150 ampere charger can be manually tied into
any of the batteries. Batteries No.1 and 2 supply 120 Vac vital buses 1
and 2, respectively, via static inverters. Each battery supplies inde-
pendent starting power for an associated emergency diesel generator. In
addition to the main station batteries, Technical Specifications (TS)
require an operable 24 Vdc battery and charger for the station fire pump
diesel. Non-TS related batteries supply the safe shutdown system,
security system, and non-essential UPS diesel generator.s.
C. Previous NRC Inspections
The failure of No. 3 battery service test on May 29, 1987, was addressed
in Section 9 of Inspection Report 50-29/87-06, dated October 23, 1987.
The results of a subsequent performance discharge test and vendor analysis
of test results demonstrated the ability of the battery to satisfy TS
requirements through operating cycle 19. Nevertheless, the licensee con-
cern regarding the rate of decrease in battery capacity reinforced the
previous licensee decision to replace No. 3 battery. In April 1988, the
old battery was disconnected and the new battery temporarily tied into the
existing system. Permanent installation of the new battery, static
charger, and distribution panels in a new dedicated battery room in ac-
cordance with' Engineering Design Change Request (EDCR)87-302, Battery No.
3 Replacement, dated January 28, 1988, was completed during the recent
refueling outage.
1
)
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At.ta'chment 1 2
A one-time correction of low specific gravities in Nos. I and 2 main
batteries was reported in Section 8 of Inspection Report 50-29/88-10,
dated September 13, 1988. No unacceptable conditions were identified as
a result of the senior resident inspector's review of this evolution.
D. Licensee Commitments
The licensee is not committed to comply with any edition of IEEE Standard
450, Recommended Practice for Maintenance, Testing, and Replacement of
Large Lead Storage Batteries for Generating Stations and Substations, or
any other battery-related IEEE Standard. IEEE Standard 450-1975 is en-
dorsed by NRC Regulatory Guide 1.129, Revision 1, Maintenance, Testing,
and Replacement of Large Lead Storage Batteries for Nuclear Power Plants,
and specified in NRC Inspection and Enforcement Manual, Part 9900 - Tech-
nical Guidance (see Section 9, Inspection keport 50-29/8'/-06). Hc m er,
licensee engineering is guided by Standard 450, and station maintenance
and surveillance procedures reference the standard.
The inspector reviewed the licensee DC loading profiles and bases. Elec-
trical sizing and loading are documented in calculation YRC-114, Revision
7, dated Dctober 20, 1988. The calculation employs the sizing method
specified by IEEE Standard 485-1978, Recommended Practices for Sizing
Large Lead Storage Batteries for Generating Stations and Substations.
YRC-114 and service test results confirm the ability of the batteries to
supply all actual emergency loads for the two hour duty cycle required by
TS. All EDCRs are reviewed by Yankee Nuclear Services Division for impact
on battery loading profiles.
F. Seismic Qualification
Batteries No. 1 and 2 are seismically qualified in accordance with IEEE
Standard 344-1975, Recommended Practices for Seismic Qualification of
Class 1E Equipment for Nuclear Power Generating Stations. Since No. 3
battery and its associated DC equipment are not required for the safe
shutdown of the plant, seismic qualification is not required. However,
the licensee has reviewed the battery and racks against applicable seismic
qualification utility group (SQUG) program criteria and NRC ground motion
versus SQUG bounding spectra limits and determined that the equipment is
seismically acceptable. The inspector verified that criteria for assuring
battery and rack seismic qualification were defined and incorporated into
periodic inspection procedures.
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At.ta'chment 1 3
G. Battery Rooms / Ventilation
The main station batteries are located in dedicated rooms posted as no
smoking areas. The inspector toured the rooms to examine general house-
keeping, battery and rack condition, and ventilation system operability.
Battery Rooms 1 and 2. were clean and free of debris and ignition hazards.
Still under construction, Battery Room No. 3 contained some construction
debris, but was adequately segregated from the battery. All rooms are
subject to periodic housekeeping surveys. No fluid bearing pipes pass
through the battery rooms.
Water used for addition to battery cells was noted to be stored in the
rooms, suggesting lack of pnsitive control of water quality. The licensee
stated that demineralized water exceeding the manufacturer's requirements
is obtained from the chemistry laboratory where it is routinely checked in
accordance with station procedures, and that the bottles would be removed
from the rooms. The inspector observed that battery water additions are
adequately controlled by procedure.
The licensee ventilation calculations and logs were examined to verify
that battery temperatures are maintained in accordance with the manufac-
turer's specifications and the facility design basis. The maintenance
services department trends outside, battery - room, and cell electrolyte
temperatures. Cell differential temperature is checked quarterly to
assure compliance with IEEE Standard 484-1981, Recommended Practice for
Installation Design and Installation of Large Lead Storage Batteries for
Generating Stations and Substations.
Loss of battery room ventilation is annunciated in the main control room
when air flow decreases below a specified value. Exhaust ducts are
located at room high points to ensure removal of combust *1e gases. Licen-
see calculations correlating unventilated room size with worst-case bat-
tery hydrogen generation rate conclude that hydrogen concentrations
greater than 2% cannot occur within the design operating basis of the DC
system.
Ventilation is verified by weekly and quarterly procedures and checked
each shift during routine operations department tours. Training in hydro-
gen hazards is included in the electrician training program. Station hot-
work is strictly controlled by procedure.
H. - Battery Charging and Maintenance Practices
Battery equalizing charge requirements are clearly specified in proce-
dures. Charging criteria are based upon station experience and vendor
recommendations and meet the requirements of Standard 450-1975. Specific
gravities are taken while the battery is on float charge and prior to
water additions. Pilot cells are rotated periodically. Hydrometers are
.
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calibration checked and correction factors applied to ~ specific gravity ]
readings. In response to the inspector's observation that specific grav-
ities are not corrected for cell water level, the licensee produced ade-
l quate justification from the manufacturer.
l' l
l A single cell charging procedure is available which, if necessary, permits 1
the evolution for five days, after which review by maintenance supervision
is mandated. Cell voltage-to-specific gravity criteria needed to invoke
the procedure is provided. The procedure specifies the maximum permis-
sible applied voltage as a function of cell specific gravity.
I. Performance Test and Replacement Criteria
The inspector reviewed battery performance and service test documentation
for adherence 'to TS periodicity requirements. Performance test current
and service test load profiles were verified to meet the requirements of
Standards 450-1975 and 485-1978.
As a result of procedure review, the inspector made the following obser-
vations to the licensee:
--
Operating Procedure (0P) 4519, Station Battery Discharge Test, does
not test the batteries "as found" as recommended by Standard 450-1975
in that (1) Prerequisite No. 2 requires an equalizing charge three to
seven days prior to the start of the test, and (2) Step 1 of the
procedure verifies all connections clean, tight, and free of
corrosion.
--
Procedure guidance adequate to ensure performance of battery service
tests "as found" is lacking in that OP 4570, 4571, 4572, Station
Battery Service Test, for batteries 1, 2, and 3, respectively, con-
tain no precautions. which would preclude the maintenance activities
prescribed by Standard 450-1975 for such tests. -
(1) Precaution 5 of OP 4501, Quarterly Check for the Station Bat-
teries, states that the procedure is not to be performed prior
to a service or discharge test since the battery must be. tested
in an "as found condition." However, neither OP 4570, 4571, or
4572 reference this procedure.
(2) The service test is performed on an 18-month cycle. OP 4522,
Inspection and Maintenance of Station Battery, is also performed
on an 18-month cycle, yet contains no precaution similar to that
of OP 4501.
(3) OP 2500, Station Battery Equalizing Charge. has no precaution
to preclude its use prior to a service test.
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TS 4.8.2.3.'2.d permits . the use of a performance test in lieu of a
service test when scheduled to be ' performed' at the same time as a
. service test. Since the licensee performance test is not "as found,"
the test would not reflect maintenance practices as specified by
Standard 450-1975.
--
Current procedures do not require annual discharge testing of batter-
ies which show signs of degradation or- have reached 85% of. expected
service life. However, the licensee reviews _ the results of- perform-
ance' tests for trends indicative of 'significant declines in capacity.
The licensee conservatism and sensitivity' to this issue was demon-
.
strated by its decision in April 1987 to replace No. 3 battery during
the 1988 refueling _ outage. .The inspector' concluded that administra-
,tive controls exist adequate to meet the intent of Standard 450-1975
regarding this issue.
The licensee acknowledged the inspector's concerns and agreed to review
them for . incorporation 'in future revisions of the applicable procedures.
J. Other Safety-Sign:ificant Batteries-
The inspector verified that procedures were in place and adequate to en-
sure the operability of the safe shutdown system, station fire pump,
security system, and non-essential UPS diesel batter'as.
K. Conclusion
The inspector found the licensee program for maintaining safety related
battery systems ',o be adequate. The program reflects the strong mainten-
ance engineering effort.which has been identified as a licensee strength.
The continued operability of these systems will continue to be assessed as
part of the routine inspection program.
i
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ATTACHMENT 2
NRC:RI TI 88-02: LOSS OF DECAY HEAT
, During the refueling outage, the licensee performed maintenance / repairs on the
main coolant system hot leg loop isolation valves MC-MOV-325 and MC-MOV-301
(loops 1 and 2, respectively). This evolution entailed reducing reactor cool-
l ant system inventory to just below the body-to-bonnet flange of the valve. On
1: December 14,-1988, prior to performing the evolution, the licensee conducted a
briefing with the inspector where the following items were discussed:
--
recent reduced' level operations at YNPS;
- - -
NRC Generic Letter 87-12 and associated response commitments;
--
INP0 SOER 88-03 concerns;
--
NRC Generic Letter 88-17 concerns; and
--
plans to repair and inspect MC-MOV-325 and MC-MOV-301 during the outage.
Licensee exparience with reduced MCS level operations prior to the issuance of
the~ generic letters indicated good performance. In June 1986, the licensee-
replaced the stem on the hot leg stop valve MC-MOV-325. In May 1987, the
licensee repaired the disc the cold leg stop valve MC-MOV-302. Both of these
evolutions were safely completed with adequate decay heat removal capacity.
The inspector reviewed the licensee response to Generic Letter 87-12. Also
reviewed was a licensee memorandum detailing commitment resolution. The in-
spector noted that program commitments and proposed actions which were com-
pleted included:
--
perform an analysis of a loss of shutdown cooling under low main coolant
level conditions prior to operation with fuel in the reactor vessel and
level below the top of the main coolant legs;
--
evaluate improvements in instrumentation;
--
review all procedures related to reduced level operation prior to the next
drain down operation; and
--
Jesign and manufacture temporary covers for the main coolant stop valves
to permit reestablishment of normal operating levels when the valve bonnet
is removed.
The inspector reviewed the licensee's procedures, training program, and
administrative controls relative to the generic letter and commitments.
Procedures were noted to provide guidance for both normal and abnormal
conditions. Procedures delineated personnel requirements, equipment
needs, and evolution restrictions. The training program adequately
addressed procedural guidance for redundant water level indication and
temperature monitoring, precautions for potential vortexing and air bind-
fng of pumps, and requirements for establishing vapor container (VC)
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integrity. Additional guidance was provided to incorporate time since
shutdown, time to uncover the core, and the availability of additional and
alternate equipment into the administrative decision making process.
Prior to performing the loop isolation valve repairs, the licensee had not
formally submitted its response to Generic Letter 88-17. However, the
licensee did revise procedures and training lesson plans to include spec-
ified concerns.
Inspector review of maintenance performed on valves MC-MOV-325 and
MC-MOV-301 indicated good licensee performance. The evolution was delayed
until late December when decay heat removal demands would be reduced. No
degradation of decay heat removal was experienced. No perturbations to
the MCS occurred. The evolutions did not require reducing the MCS level
below the flange area of the valve. Maintenance was performed on only one
valve at a time. Temporary valve covers were used to enable normal MCS
levels to be restored when repair efforts were suspended. Personnel were
appropriately trained and demonstrated strong safety and procedural know-
ledge. Operations personnel maintained continuous verification of MCS
level and shutdown cooling capability. Additional core cooling capability
(low pressure surge tank pump / cooler and two charging pumps) were avail-
able if needed. Tygon tubing was used to locally monitor MCS level. An
evaluation verified the accuracy of the system. A television camera was
used to monitor water levels. Two core outlet thermocouple were used to
independently monitor MCS temperatures. The equipment hatch was secured
with the necessary bolting. The personnel hatch was maintained open to
facilitate quick worker exit, if necessary.
Minor delays were experienced in restoring MC-MOV-301 to service due to
lapping the valve body-to-bonnet seal area. The licensee identified one
item needng additional attention for future evolutions. Specifically, the
loss of decay heat removal scenario for cold leg openings requires the use
of three safety injection pumps. Current licensee TSs do not allow the
use of safety injection during shutdown.
The licensee is currently evaluating a Technical Specification change.
Until that time, the licensee will not allow a cold leg opening when the
reactor head is in place or when fuel is in the vessel.
The licensee was effective in safely completing these repairs un:.;r re-
duced MCS inventory conditions.
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