ML20151J351
| ML20151J351 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 07/18/1988 |
| From: | Callan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | Withers B WOLF CREEK NUCLEAR OPERATING CORP. |
| References | |
| NUDOCS 8808020231 | |
| Download: ML20151J351 (2) | |
See also: IR 05000482/1987032
Text
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In Reply Refer To: g lg g
Docket: STN 50-482
.
Wolf Creek Nuclear Operating Corporation
ATTN: Bart D. Withers
President and Chief Executive Officer
P.O. Box 411
Burlington, Kansas 66839
Gentlernen:
Thank you for your letters of April 8 and April 28, 1988, in response to
our the NRC letter of February 8,1988. This letter acknowledges receipt of
ycJr response to our Safety Systen. Outage Modificetions Inspection (NRC Report
No. 50-482/87-32). We will review the irnplementation of your corrective
actions during a future inspection to detennine that full cortpliance has been
achieved and will be raintained.
Sincerely.
On$3} Db d Q
L J. CALLAN
L. J. Callan, Director
Division of Reactor Projects
cc:
Wolf Creek Nuclear Operating Corporation
ATTN: Otto Maynard, Manager
of Licenst 1
P,0, Box 411
Burlington, Kansas 66839
Wolf Creek Nuclear Operating Corporation
ATTN: Gary Boyer, Plant Manager
P.O. Box 411
Burlington, Kansas 66839
Kansas Corporation Comission
ATTN: Robert D. Elliott, Chief Engineer
Fourth Floor, Docking State Office Building
Topeka, Kansas C6612-1571
Kansas Radiation Control Program Director
RIV:DRP/A C R /A D:DR
ATHowell DDCharrberlain LJCallan
7/e/88 7//f/88 7/g88
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8808020231 880718
POR ADOCK 05000482
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Wolf Creck Nuclear Operating -2-
Corporation
bectoDMB(IE01)
bcc distrib by RIV:
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Myron karman, ELD, MhBB (1)
RRI R. D. Martin, RA
SectionChief(ORP/A) ORP
RPB-DRSS 8. DeFayette, R!!!
RIV File Callaway, Rill
MIS System RSTS Operator
Project Engineer, DRP/A G. F. Sanborn, E0
Lisa Shea, RM/ALF P. O'Connor, NRR Project Manager
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W$LF CREEK NUCLEAR OPERATING CORPORATION
John.A.
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ET 33-0051 i
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V. S. Nuclese Regulatory Commission - - -
ATTN: Document Control Desk
Washington, D. C. 20555
,
Reference Letter dated Februsry 8, 1988 from D. M. Crutchfield,
NRC to B. D. Vithars, VCNOC
Subject: D3chet No. 50-482: Inspection Report 50-492/87032-
Safety Systems Outage Modifications Inspectier
Gentlemen
The purpose of this letter is to establish the revised sum itts1 dste for
the response to Inspection Report 50-482/87032 concerning the Safety Systems
Outage Modifications Inspection (SSOMI) conducted at Wolf Creek Generatire
Statior. ksed on discussions with the NR0 Project Manager for Volf Croek
Genorating Station, Volf Creek Nuclear Operating Corporation (VONOC) will
respond to the subject nspection Report on or before April 29, 1998.
The Reference transmitted the SSOMI Inspection Repart and requested a
response to the concerns identified in the Inspection Report. Due to the
length and complex nature of the SSONI Insp<ition Report, VON 00 verbs 11y
requested and receisoi an extension for su Mitting the repsonse to this
Inspection Report.
If you have any questions concerning this matter, please contact me or
Mr. O. L. Maynard of my stsff.
Very truly yours,
t h 1
>
.Tohn A. Miley
Vice President
Engineering & Technical Services
JAB /jad
cc B. L. M rt19tt (NRC)
D. M. Crutchfield (NRC)
R. D. Msrtin (NRC)
P. V. O'Connor (NRC), 2
PO Ni 411 i B.svym a 66839 > Fhv4 (316) 364 6831
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April 28, 1988
1
U. S. *iuclear Regulatory Commission
ATTN: Document Cantrol Desk
Vashington. P C. 20555
1
i Reference: 1.etter dated February 8 1986 frota D. M. C r ut ch f i e ltt .
NRC to B. D. Withers, WCNOC
i Subject: Docket No. 50 '.82: Response to Safety Systems
Outage Modifications 1.woection Report 50-482/87032
i,e n c l ern e n :
'
Attached is Wolf Creek Nuclear Operating Corporation's response to the
l Safety Systens Outage Modiiteations Inspection Report transmitted in the
l Referene*. The response provides a description of programmatic and
- organizational enhancements made at 'lolf Creek Generating Station subsequent l
l
to the inapection as well as detailel respanses to the spec i fi c findings.
If you hsve any questions concerning this natter. please co1 tact me or
j Mr. O. L. Maynar.1 of my staff.
I
i Very truly yours. ,
i
!
I Bart D. Withers t
i President and i
! Chief E ucutive Ofilter [
>
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- ect B. L. htrtlett (NRC). ./a
l D. M. Cr ut e'i f i eld ( NRCT , w/c
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P. W. 0*Connat ( NRC) . 2 w/a ;
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9
RESPONSE TO
SAFETY SYSTEMS OUTAGE MODIFICATIONS
INSPECTION REPORT
(50-482/87-032)
APRIL 28, 1988
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W$LF CREEK
NUCLEAR OPERATING CORPORATION
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- INDEE TO SS(MI ITINS L
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] SECTION I - OVERALL CONCLUSIONS fAfg1
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INTRODUCTION 1
MANAGD(ENT CONTROLS 1 i
, ENGINEERING SUPPORT AND EVALUATIONS 2
) CORRECTIVE ACTIONS 3
SUMARY 3
JECTION II
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l DESIGN AND PROCURDfENT INSPECTION ITDtS
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2.2.2.1 PMR 2024: BATTERY CNARGER AC ALAPM SETPOINT 1
2.1.2.2 PMR 899: ACC'.MULATOR LEVEL TRANSMITTERS 4
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2.1.2.3 PMR 2167: ELECTRICAL EQUIPMENT ROOM No. 1403 CHILLER 6
2.1.2.4 PMR 1634: REACTOR COOLANT DRAIN TANK ISOLATION VALVE 8 .
'
- 2.1.2.5 PMR 1613
- VALVE LEAK 0FF CONTIGURATIONS 11
2.1.2.6 PMR 2109: FEEDWATER VALVE REPLACDiENT * '
2.1.2.7 PMR 2206: AUXILIARY BUILDING FIRE DETECTION SYSTDt 13 !
2.1.2.8 PMR 2222: CONTAINMENT COOLING FAN DAMAGE 16 l
i 2.1.2.9 APPENDIX J LEAK TEST REQUIRDiENTS 18 !
I 2.1.2.10 BATTERY DISCHARGE OF OCTOBER 15, 1987 20 I
! 2.1.2.11 RATTERY SIZING CALCULATION E-3 22 !
l 2.1.2.12 BATTERY PERFORMANCE TEST 24 l
l 2.1.2.13 DC SYSTEM LOV VOLTAGE ALARMS 26 '
2.1.2.14 DIESEL GENERATOR BREAKER OPERATION 27
.
INSTALLATION AND TESTING INSPECTION ITDfS
3.1.2.1 PMR 2262: MARATHON TERMINAL BLOCK REPLACDtENT *
3.1.2.2 PMR 1722: VALVE MOTOR-OPERATOR TESTING 29
3.1.2.3 PMR 1883: HARDLINE SPLICE REPLACDiENT * l
1.1.2.4 PMR 2018: ASCO SOLENOID VALVE REPLACD(ENT 33 !
3.1.2.5 PMR 2329: RAYCHEM SPLICES 36
I 3.1.2.6 PMR 1628: ESV BUILDING CABLE REPLACD(ENT 39
4
3.1.2.7 CONTAINMENT PRESSURE TRANSMITTERS 41
! 3.1.2.8 SAFETY EVALUATIONS * f
3.1.2.9 TECHNICAL SPECIFICATION TESTS 43 t
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! 3.2.2.1 TDiPORARY MODIFICATION TM0 37-120 GK 45
l CLAMPED OPEN CRVIS DAMPER f
1 3.2.2.2 PMR 2106: PRESSURIZER SPRAY VALVE BONNET REPAIR 49 !
l 3.2.2.3 PMR 2084: CCW PIPE VALL THINNING 34
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j 3.2.2.4 PMR 2116: VALVES EF-V090. EF V038. EF.HV47. AND 59
, EF.HV48 HARD SURFACING [
l 3.2.2.5 PMR 1903: REPAIR OF ESV LEAKAGE /VALL THINNING j
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i 3.2.2.6 PMR 0904: ESSENTIAL SERVICE VATER CHECK VALVES 62
{ 3.2.2.7 PMR 1363: CHARGING PUMP CONTROL VALVE CAVITATION 63
! DAMAGE
3.2.2.8 SAFETY ANALYSIS REVIEV * i
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j 3.2.2.9 PRESSURIZER SAFETY VALVE TESTING 65 !
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}' *Since no concerns or weaknesses were identified in the Inspection Report. l
l VCNOC has not responded to these items.
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SECTION I
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Page 1 of 3
April 28, 1988
01TFRALL CONCLUQlMS,
i INTRODt/CTION
During the second refueling outage at Wolf Creek Generating Station, a Safety
Systems Outage Modifications InJpection (SSOHI) was conducted by the NRC's
Office of Nuclear Reactor Regulation, The SSOMI was completed in two
portions. The first portion dealing with Design and Procurement was conducted
on November 2-13, 1987, while the second portion dealing with Installation and
Testing was conducted on November 9-20,1987.
'
The SSOMI identified both strengths and weaknesses in the modification
activities that were performed at Volf Creek Generating Station (VCGS). These
findings were documented and transmitted to Wolf Creek Nuclear Operating
Corporation (VCHOC) in NRC Inspection Report 50-482/87032. This Inspection
j Report stated that, 'The modification activities inspected by the SS0MI team
- during the Wolf Creek outage, including procedures, installed equipment and
materials, and workmanship by crafts, were generally in accordance with NRC
requirements and licensee commitments'. In addition, specific strength were
noted related to, '
...the acquisition and control of equipment and materials,
the trend analysis of quality findings and reported deficiencies, and
worknanship by maintenance personnel * .
l The Executive Su= mary of the Inspection Report also identified weaknesses in
i the general areas of Management Controls Engineering Support and Evaluations,
i and Corrective Actions. Each of these areas is specifically addressed in
] Section I of VCNOC's response to the Inspection Report. Section II of VCNOC's
! response presente a detailed response to each of the SSCMI team findings
categorized as either a weakness or concern.
It should be noted that findings categorized as strengths hsve been omitted
from Section II. Each finding in Section II is presented with a Restatement
of the Finding, a General Discussion of the Finding, a Response to the
Finding, Actions Taken, and Conclusions based on the Finding.
MANAGD4ENT CONTROLS
As stated in URC Inspection Report 87-032, Safety Systems Outage Hodification
Inspection. ' modification activities inspected by the SSCHI team during the i
Wolf Creek outage, including procedures, installed equipment and materials,
and workasnship by crafts, were generally in accordt'ce with NRC requirements !
and licensee connitments' . However, as a result or w'CNOC management concern )
with regard to the significant operational events that occurred during VCGS's (
second refueling outage and individual issues identified by the NRC, VCNOC has ;
, instituted several organizational enhancements to alleviate any perceived '
weaknesses in VCN00's overall management control.
!
In order to more closely control day to day work activities during outages. (
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the Outage Manager will report to the Plant Manager rather than the
Vice-President Nuclear Opetations. The Outage Manager's function and
authority will be clearly reflected in Administrative Procedures. The Outage
Manager will have a support staff consisting of Scheduling personnel and two
Senior Technical personvel.
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April 28, 1988
As an improvement to the Maintenance Organization, Maintenance has been
combined with Facilities and Modifications ta form an organization titled
Maintenance and Modifications. This organizational change combines all
maintenance activities under a single manager and creates a large skilled
labor pool to be used on any maintenance or modifics. tion task. In context
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with this change, significant management attention has been focused on ,
assuring that unneceriary levels of supervision have been eliminated and
establishing more direct management control in all work activities within
Maintenance and Hodifications.
In additior, to theso organizational enhancaments, VCNCC Management formally
restated to all personnel the importance of strict adherence to written
procedures during the performance of work activities, testing, equipment
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repair, and plant modifications. This is being reinforced by mandatory
pru-work briefings. Daily management meetings have been established to ensure
1 direct management control and supervision of all ongoing work activities.
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To eahance corcur.ications and provide more managtment involvement in
day-to-day activities, the daily planning meeting has been restructured to
focus more on problems and corrective actions than on work status. The
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meeting is attended primarily by management persor.nel to provide the necessary ;
level of authority to resolve problems and take necessary corrective actions. l
The meeting is normally attended by one or more of the Corporate Officers to
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provide senior management support,
j The above organizational modifications and programatic enhancements will ;
strengthen the performance of WCNOC and subsequently VCGS. These actions >
should minimite the potential for operational or management weaknesses during
future outages at VCGS. The individual examples identified in this section ,
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are fully discussed in other sections of this response to NRC Inspection i
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Report 50-482/87032. ;
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ENGINEERINO SUPPORT AND EVALUATIONS l
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i NRC Inspection Report 50-462/87032 made the statement that. 'The engineering ;
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support provided for a number of recent modifications and maintenance ;
. activities was found to be inaccurate or lacking in thoroughness.'. ,
- The Inspection Report also stated that, 'The SSCMI team found that modified !
designs were traceable to the original design bases and regulatory
! requirements, that correct design information was utilized, and that
applicable design controls were iuple: rented. ' It should be noted that the
activities discusseo as engineering scpport in the Inspection Report include ,
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activities which are performed by different organizations within WCNOC and not ,
just the design engineering group. Engineering sopport for day-to day I
operational and maintenance activities is performed by various groups under
the Plant Staff. Engineering support for modifications and other design
activities are performed by Nuclear Plant Engineering (NPE). ,
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The organizational enhancements and increased m.anagement involvement discussed l
in the Management Controls section of this response will improve the support !
activities being performed by the enginee_ing groups. The interaction between
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organizations in the dr.ily management notings will help to focus efforts into
] a singlo direction so that each organization is aware of what is required to
accomplish any given task. In addition, these meetings ensure that individual
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Page 3 of 3
April 28, 1988
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work assignments are being performed by the organization with the proper
experience and expertise to accomplish the task in the most effective manner. t
WCNOC believes that with this strong foundation in the design area along with
enhancements made because of events during the second refueling outage and
items identified by the $50MI team, the weaknesses identified by the SSCHI
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inspection in the engineering support and evaluations area will not reoccur at
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Volf Creek Generating Station.
CORRECTIVE ACTIONS !
NRC Inspection Rep 0rt 87-332 idtntified several examples which indicate
- weakness involving the adequacy of corrective actions for identified
l deficiencies, including the identification of root causes, evaluation of
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related areas for similar deficiencies, and actions to prevent recurrence. It
- should be noted that an earlier NRC Inspection concerning corrective action i
j was conducted during the periods May 18 22, and June 2-3, 1987. Upon t
l receiving this NRC Inspection Report. 87 011, on November 3, 1987 VCNOC took ,
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steps to enhance the corrective action program as documented in letter WH l
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88 0028, dated January 29, 1988. An integrated corrective action program in t
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the form of a VCU0C General Procedure. KGP.1210, ' Corrective Action for
- Progracmatic and Implementation Deficiencies', has been developed. The
! procedure establishes a standardized method for all VCNOC organizations to
document tnd respond to progracnatic or implementation quality problems. i
During a VCNCC Quality Department audit conducted between December, 1987 and !
February, 1988, concerning the implementation of this procedure, several i
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inconsistencies were identified in the methods variouJ organizations were
using to implement the proceiural requirements. This has resulted in a g
complete review of KGP-1210. The procedure is currently being revised to (
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provida plant personnel with a more usable explanation of determination of
root causes. It is expected that the revision to KGP-1210 should be
tw91emented by June 1, 1988. A training program is currently under I
development to provide direction to the peruonnel responsible for i
implementation of the revised FGP 1210. In addition, a seminar by EG&G on
' Accident Investigation', is schedu14d to be conducted at the Volf Creek l
Generating Station during Hay, 1988. The above noted revisaon to KGP-1210 :
and training will serve to strengthen the overall corrective action program of [
VCNOC. ;
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StHuARY
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VCNOC believes the actions described above in conjunction with the specific
actions described in Section II of this response fully address the weaknesses
identified by the SSCHI Inspection Report. It is acknowledged that during the
SSOMI review of modification activitias and significant operational events {,
several specific weaknesses were identified, however, VCNOC believes chat the l
overall organization and program enhancements described above will serve to [
optimize the present and future operation of VCGS. [
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SECTION II
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1 2.1.2.1 PHE 2024: BATTERY CEARGER AC ALARM SETPOINT
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FINDING
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Thie PHR changed the battery charger AC input alarm setpoints to eliminate [
spurious AC alarms and was required because of previous changes to the AC i
system made it.1985 by PMR IMS which reduced the AC input voltage at selected }
safety related and non-safety related battery chargors. PMR 2024 indicated r
that the cause of spurious AC undervoltage alarms was an incorrect voltage [
- transformation ratio assumed in the original system Relay Setting Calculation
) (H.12). A review of the latest revision to this calculation indicated that
k the transformation ratio was corrected in April 1983. The correct voltage !
l transformation ratios were indicated for nine of the eleven battery chargers !
! on Relay setting Tabulation Drawing E.11028(Q) issued in June 1984, however
] the new relay settings had not been added at that time.
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- The SSOHI team reviewed Bechtel Voltage calculation (8 8). which was the basis
l of PMR 1345, searching for other possible reasons for the spurious
j undervoltage clarms. The impedance data used as a calculational input for one t
! of the safety reined load unter transformers was based upon General Electric (
i test data. however this impedance value did not agree with the transformer's t
l nameplate data. Engineering Department personnel indicated that although the [
q test data used in the calculation was not specific to the equipment installed i
! at Wolf Creek Generating Station (WCGS), the error accounted for a calculated !
voltage error of lese than two percent. The STOMI team considered that the !
failure to identify the error in the 3echtel Voltage Calculation is indicative :
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of a weakness in engineering evaluations. [
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) CENERAL DIFCUSSION OF FINDING:
puring the review of PMR 2024 TMR 1345 system relay calculation N 12
l vn1tage calculation 8 8 and relay setting Tabulations (Dr& wings E.11027 and
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i E 11028(Q)) The S$0HI team identified two distinct concerns
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! 1. Corrections made in June 1983 to Calcula', ions H.12 and 8 13 concerning
3 battery charger low AC input voltage alarms and potential transformer
l ratios, were only partially incorporated into relay setting tabulations
j E 11027 and E 11028(Q) during the June, 1984 rev;sion to those
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documents.
2. The impedance data used in Calculatten 3 8 for one of the load center ;
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transformers was based on the manufacturers test data which does not
- agree with the transformer naceplate.
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I RESPONSE TO THE FINDING:
1. The corrections made in the subject calculations identified a lower ;
j setpoint value for the battery charger low AC input voltage. It is j
l important to note that the purpose of the alarm is to alert the Control
l Roca operators to low AC input voltage on the battery chargers. The
i original setting provided for proper monitoring of the electrical
] distribution system at Wolf Creek Generation Station. It is good
engineering practice to not eliminate the conservatism in the system
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Page 2 of 70
April 28. 1988
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j design setting on the sole basis that a revision to a design esiculation
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identifies additional available margin. Therefore at the time of the
calculation revision, the new setpoints calculated did act need to be
incorporated into the setpoint documents for Wolf Creek. Only after the
ala rms became frequent due to the implementation of PHR 1345. which
optimized the transformer saps for the Wolf Creek Electrical
Distribution System. did a need arise to reduce the alarm setting to the
value identified in the previously revised design calculation.
] It is true that for tem of the eleven battery charger control power
, transformers, the subject setpoint document listed the wrong
] transformation ratios. These two chargers were added as design
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enhancements during 1982. The oversight was corrected promptly when
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discovated but did not affect the conservatism of the alarm setpoint.
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2. The transformer manufacturers test data and certified test data report
which were used as a basis for the subject Voltage Calculation B.8 are
a judged to be kccurate as issued. The subject certified test data
i report reflects the actual results of a performance test on the
1 installed equipment as certified by the manufacturer. It is noteworthy
! that the equipment serial number recorded on the test data and to
! which the referenced calculation refers, also matches the serial number
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stamped on the transformer nameplate. Therefore, the test data and
i calculation are applicable and specific to th: transformer installed at
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Volf Creek. In addition, at the time the transformer was procured. the
nameplate was not required to reflect the values recorded on the
certified test report (reference ANSI C57.12.80 1973) and therefore,
only reflected the design impecance value. It was, in more recent
revisions, that the applicable industry standards for transformers (501
KVA and larger) required that tne actual test data be reflected on the
nameplate.
M c WsION:
1. The $$CMI team identkfied that there were two incorrect non.1E battery
potential transformer ratios on the applica'le o Relay Setting Tabulation
drawing. However, these errors are not considered reflective of general
engineering weakness and were corrected when discovered. The item
concerning the lack of incorporation of the revised calculation into
the applicable Relay Setting Tabulation for the battery chargers is not
considered a deficiency. The fact that the input voltage lov alarm
retpoint was 94! ton a 480 volt base) instead of the 902 value,
determined by the design calculation is considered conservative. These
types of rargins are not utiliaed unless necessary in order to maintain
the carimum safety margin for protection systems at Volf Cregk Generating
Station. This approach deconstrates a strength in engineering
evaluations, and therefore, requires no further action.
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Page 3 of 70 ,
l April 28. 1988
i 2. The $$ CHI team item concerning engineering's failure to identify an
apparent error in Voltage Calculation B.8 due to data inconsistencies i'
between transformer nameplate data and certified vendor test reporte
I does not constitute a deficiency. The subject Calculstion. 38 as well
i as the cited certified vendor test report data, at. considered correct ,
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and applicable to the trantformer installed. At the time the transformer [
was procured, the nameplate was not required to reflect the values
recorded on the certified test report (reference ANSI C57.12.40 1973) and i
4 therefore, only reflected the design impedance value. It was. in more
1 recent revisions. that the applicable industry standards for transformers .
(301 KVA and larger) required that the actual test data be refiscted on !
- the nameplate. Therefore, no further action is required and no revision !
to these documents or the transformer nameplate is required. l
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Page 4 of 70
April 28, 1988
2.1.2.2 FMR 899: ACCUMUI.ATOR LEVEL TRAN8MITTFIS
FINDING
This PKK replaced Accumulator Tank Barton level transmitters with Rtsemount
level transmitters and relocated them to the side of the tank us.ng the
existing sensor taps. The $$CMI team identified the following discrepancies
with this PMR
a. The new sensor connections to the reference leg were five feet higher,
which provided an additions 1 41.36 cubic feet of water in the tank at the
minimum level setpoint than designed. As a result, a sraller volume of
nitrogen gas remainwd in the Accumulator Tank to provide for water
injection into the primary system in the event of a LOCA. The Technical
Specifications required that a minimum of 818 cubic feet of water be
I
injected from the tank into the primary system in the event of a LOCA.
l The actual tank pressure required with the new volume of water was not
determined. The dasign nitrogen gas pressure of 585 peig had some
allowance for conservatism, however this allowance was also unknown.
b. A root cause analysis for changiag the level transmittera was not
provided. Although a significant amount of data existed te stify the
change, this data had not been formally communicated within e e company.
In addition, the Q. list, which lists all safety related equipment in the
plant, was not revised as required.
The failure to evaluate the change in nitrogen gas pressure required for
Accumulator Tank injection, including calculation of the root cause for the
modification is a weakness in the engineering area.
ctNEPAL DISCUSSION OF FINDINO:
a. The design modification stipulated in FMR 899 called for utilization of
the same tank taps. stanopipe taps, and diaphragm seal locations as the
original installation. The replacement Rosemount transmitters were
relocated to a lover elevation than the Bartons (approximately 5 feet to
17 feet difference depending on transmitter) and are now placed at the
f midpoint between the diaphragm seals rather than above the upper seal,
b. Many letters were written as a result of the Barton instrument problems
identified at VCGS. The responsible engineer's correspondence file on the
subject was turned over to the SSCMI team for review. Although this file
did not contain all the project correspondence, it did include the minutes
of a meeting held at Volf Creek on January 25 1984, with representatives
in attendance from KGLE (including the Project Director). Union Electric.
Vestinghouse. !TT Barton, and Nuclear Projects Incorporated. During this
meeting. KGLElUE failures were discussed, including failure modes. and
acticn plans were established.
A review of the FMR package indicates that Q. List Change Notices were part
of the package and were referenced on the Modification Document Form
(KGF.6). Neither the $$CMI team nor the responsible engineer located the
Change Notices in the copy of the package provided to the SSCMI team.
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April 28, 1988 ;
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RESPONSE TO TifE FINDING [
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a. Since the tap connections and diaphragm seal locations were unchanged, the {
'
original tank level setpoint calculations remain valid. The replacement
of a transmitter as well as its relocation from above the upper diaphragm f
seal to the seal midpoint would result in the need for calibration. This !
was performed by Instrumentation and Controls personnel for PHR 899 in
accordance with STS IC-908A ' Channel Calibration Accumulator Level [
Tsensmitters'. These actions result in the tank watvr content remaining ;
the same as prior to the modificat2on and being within the Technica1
Specification l
bounds. No engineering reanalysis of the effect of r
increased water content was necessary. l
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b. The January 25,
'
1984 meeting minutes and other correspondence such as a
January 27, 1984 le*.ter from John Ba;1cy of the Wolf Creek project to (
Kent Brown. KG63 Vice. President (subject Barton Transmitter problems ;
and intended soluttens) clearly show that ransgement and the project }
as a whole was being informed of the Barton transmitter problem. j
During discussions between the $50HI team and the responsible engineer.
it was z.entioned that Q. List change documents did not exist for the newly ,
installed tracimitters. The responsible engineer could not remember (
generating such documents and thus acknowledged the co9cern. A review of ,
the FMR package was undertaken a,; a result of this finding revealed that !
the Q-List Change Notices did exist. !
f
00NCt.USION: ;
a. No changes were made to the system which would require a new analysis.
VCNOC does not consider this item to be a deficiency.
b. VCNOC believes that the project. including upper management. was aware
of the problem with Barton transmitters. and that existing documents j
indicate that a root cause determination was sought as a part of [
resolving the issue. The FMR package does contain an appropriate Q. List [
Change Notice. i
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April 28, 1980
2.1.2.3 Pte 21671 ELECTRICAL FOUTIMENT ROOH NO. 1403 CHILLER
FINDINot
This FMR added additional cooling to Electrical Equipment Room No. 1403 and
installed a room temperr.ture iridicator controller and an automatic chiller
water control valve. ?!C 185 and TV 185, respectively. A Field Change Request
(TCR) was subsequently issued to delete TIC 185 and TV 125 and to add a manual
globe valve. V150. Tgeshangerequiredtheoperatortomanuallycontrolthe
Ecom temperature to 75 F 3,4"F by adjusting valve V150. This installation of ;
a manual valve was inadequate because a tuperature indicator was not provided
to measure the temperature of Room 1603, the TS surveillance procedures did
not include this room for periodic surveillance and the room was not required
to be monitored for gnvironmental conditions. In addition, the basis for the
acceptability of 75 T was not addressed. The failure to evaluate the effect
of the FCR change on the PMR anc the failure to document the basis for the
design change is an example of a general weakness in the engineering area.
GENTRAL DISCUS,5 ION OF FINMNG t, l
f
In Item 2.1.2.3 the S$ CHI teau determined that the installation of a manual
valve (via an FCR) was inadaquate because a temposature indicator was not
provided to measure the temperature of Room 140). the surveillance
procedures did not include this room for periodic surveillance and the room ;
was not required to be monitored for er.vironmental conditio is. Inagdition '
the $$ CHI team advised that the basis for the acceptability of 75 F room i
temperature was not addressed in the FMR. The $$0MI Team indicated that [
failure to evaluate the effect of the TCR change on the iMR and the failure l
to document the basic for the design change is an example of general r
l veakness in the engineering area, i
RgSPONSE to THF FINDING
l
FMR 2167 was revised, as requested by TCR 02167 F.009 because of natorial [
unavailability. to allow the temporary replacement of the three way flow i
control valve GL.TV.185 with a e.anual globe valve. The disposition of the !
subject TCR stated that the aforementioned globe valve 'shall' be replaced k
with the three.vay flow centson valve upcn availability. Although the ;
three vay valve has been received but not yet installed. THR 2167 hse been
i revised and reissued to pcovide for the installation of the three.vay
- valve. Additionally, in the interim the disposition stated that the room [
l temperature was to be frequently nonitored and the globe valve adjusted to
e.aintain the room design temperature. T h '. s was to be acceeplished. >
once the unit had been placed in service, by the Auxiliary luilding operator !
,
at least once per shift 6nd documented per ACM 02 030 'bading Sheets and
l Shift Round Instructions Checklist'. At the t iu of the SSCMI. the l
l
additional fan coil unit had not been placM in service. This revision to the ,
I design package demonstrates not a weakness in engineering, rather, an (
l engineering strength. Additionally. an installed temperature indicator is not l
varranted for the temporary use of the globe ealve. l
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The Techn(cal Specification surveillance requirements do not address the !
area temperature monitoring f nr the roarn, because this roem is considered a !
mild environment as defined in USAR Page 3.11(3).29. [
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April 28, 1988 ;
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The air handling unit ( SGLO2) for the room and its associated power and
control are not safety related as there are no safety design based
associated with the system. The additional f an.'cott unit SGL20 was added to
operate An parallel with the original $GLO2 unit to provide increased
neoling capability for tha room. The reason that the design change was !
assued, was to provide for th: installation of a room cooler that would j
provide cool air in the vicinity of the non-safety related, yet temperature !
sensitive. Full Length Pod Control Cabinet. An evaluatien of the cooling .
load for the room was conducted as well as for the heat sensitive rull
Length Rod Control Caninet. The Engineering evaluation included the review !
of existing supplier documentation for the cabinet. and the performance of a
calculation to deternine the cooling capacity requitad of the new unit.
The basis for the design change van documented or, ~ m- PHR cover sheet form.
with further supporting documentation (i.e.
-
c3.ulations. suppliar
documentation) existing as backup information, testinghouse documentation l
provided inforg.ation that the preferred temperature would be l
spgroxingtely 77 F. but not to exceed 30-104, ambient F. This was the basis for the !
75 F 1 5 F design temperature. l
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CONCLUSION:
The disposition stated that the room temperature was to be frequently j
monitored and the globe valve adjusted t4 maintain the room design l
temperature. At the time of the $$0MI. the additional fan coil unit had not
'
been placed in service. Since the unit his been pieced in service the room
temperature has been read by the Auxiliary Building Operator at least once per ;
shift and documented per ADH 02 030 ' Reading Sheets and Shift Round [
Instructions checklist *. ,
,
As demonstrated in the discussion above, the effect of the TCE change was [
evaluated and the basis for the design change was documented. VCNOC does not
consider this item to be a deficiency, i
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April 28, 1988
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2.1.2.4 PMR 1634: REACTOR COOLANT DRAIN TANK ISOLATION VALVE
! FINDING:
This PMR installed an isolation valve upstream of relief valve H-7160 to
simplify inspection and repair of the relief valve. Previously, repair or
replacement of the relief valve required a plant shutdown. The following
, discrepancies were identified
a. The Results Engineering Group issued Temporary Modification 86-24-4B in
,
March 1986, to gag Reactor Coolant Drain Tank relief valve HBV-7160. The
1
10 CFR 50.09 Safety Evaluation performed indicated that this modification
,
did not affect th: tank's overpressure protection because the tank was
'
protected by relief valve HBV-7169. Although valve HBV-7169 had a larger
spring to acccmmodate a higher set pressure, the evaluation indicated that
the setpoint was below the design pressure of the relief tank and
therefore provided adequate overpressure protection. However, the Safety
Evaluation did not evaluate the required flow rate, the relative flow
rates of the two valves at 110I of the tank design pressure (110 psi) and
,
'
the differences in configuration. Therefore, the evaluation did no.
demonstrate the second relief valve provided equivalent or adequate
protection for the tank.
{ b. The new isolation valve added by PMR 1634 had less flow area than the
- relief valve inlet, contrary to cht' tequirements of Paragraph UG-135,
, Appendix M. Section VIII, of the ASME Boiler and Pressure Vessel Code
Division 1-1974. An analysis to verify that the isolation valve would not
reduce the capacity of the relief valve was not performed.
c. In addition, instrumentation was not installed at the isolation valve
location to enable appropriate emergency actions if the tank was
] overpressurized.
The failure of the safety evaluation to demonstrate enat the second relief
valve provided adequate overpressure protection for the drain tank and to
verify that the isolation valve would not reduce the capacity of the installed
relief valve is an example of a general weakness in the engineering aree.
GENERAL DISCUSSION OF FINDTNG:
a. The SSOMI team felt that the 10CFR50.59 Safety Evaluation did not
demonstrate that the second relief valve off of the Reactor Coolant
Drain Tank (RCTT provided equivalent or adequate protection for the
tank, as the r taf valve that was gagged. The RCDT is an ASME Code
Section VIII tat with a working pressure of 100 psig. This tank has
two relief valves off of it, one set at 100 psig and the other at 25
psig. The 25 psig set relief valve is the only relief valve which ir
required by design for providing overpressure protection. The 25 pseg
relief valve was gagged by the subject Temporary Hodification Order. The
associated 10CFR50.59 Safety Evaluation lacked sufficient documentation
that the system bases for ths two relief valv2s with different setpoints
was underscood. The system consequences of gagging the 25 psig relief
was not discussed. Thc evaluation did not document how relief valves
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Page 9 of 70
April 28, 1988
considered identical but not exactly alike provided the same
overpressure protection and relief capacity for the RCDT.
b. The SSOMI team determined that the new isolation valve added by PMR 1634
had less flow area than the relief valve inlet, contrary to the
requirements of Paragraph UG-135, Appendix M.Section VIII, of the ASME
Boiler and Pressure Vessel Code Division I-1974. The SSOMI team indicated
that failure to verify that the isolation valve would not reduce the
capacity of the installed relief valve is an example of a general weakness
, in the engineering area.
c. In addition, the SSOMI team indicated that instrumentation was not
installed at the isolation valve location to enable appropriate emergency
actions if the tank was overpressurized.
RESPONSE TO THE FINDING:
,
a. The Safety Evaluation clearly stated that the two relief valves were
supplied by the same manufacturer and are identical in size, style,
type, assembly number, and material specifications. Additionally,
it stated that the ASME code relief requirements for the tank were
maintained. The evaluation did not state that after full accumulation of
the relief valve, the relief capacity is a function of the valves' orifice
size and that the orifice sizes of the two valves were identical. The
root cause of this finding is an inadequately documented review to support
the subsequent evaluation conclusions.
b. During the design orocess of PMR 1634, a review of ASME B&PV Code, Section
VIII, Paragraph UG-135 and Appendix M was made. Engineering made the
interpretation that ' full area stop valve' meant and was intended to mean
that the isolation valve between a pressure vessel and its pressure
relieving device was to be of the identical line size as the piping and
relief valve. Subsequent to the concern expressed by the NRC, Engineering
discovered that an interpretation had been made by the ASME
(Interpretation VIII-1-83-338) for the definition of a ' full area stop
valve' that confirmed that the minimum flow area within the stop valve be
at least equal the inlet area of the pressure relief device. The incended
stop valve had a minimum flow area of 2.64 square inches versus 3.14
square inches for the pressure relief valve. A technical evaluation of
the stop valve to be utilized indicated that no actual reduction in
capacity of the pressure reducing device would occur (i.e., design
function would not have been effected).
c. Engineering recognizes that isolation of HBV-7160 is not a recommended
mode of operation with the RCDT in service, but that maintenance
activities for HBV-7160, if necessary, are not possible without a means of
isolation. The RCDT is an unfired pressure vessels thus, it is
pressurized only from external sources. If HBV-7160 is removed from the
RCDT as a means of overpressure protection, then administrative action
would be required to remove the sources of pressure from entering the
RCDT, or ensure that HBV-7169 is available to the RCDT, ands comply with
the Code requirement that an ruthorized person monitor and restore the
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April 28, 1988
stop valve to a locked open status. Permanent local instrumentation for
monitoring an activity as infrequent as postulated above is not considered
warranted.
ACTIONS WHICH HAVE BEEN OR WILL BE TAKEN:
a. In the two years since this evaluation, significant experience and
progran development has occurred. The Results Engineering 10CFR50.59
guidance has been augmented to include in each Safety Evaluation the
design bases or function of a component and fully describe how this
component and its system are affected by the change or modification.
Relief valves which appear indentical and hr.ve different setpoints
have different springs, but at full accumulation are, in fact, identical.
This should be documented when identical relief valves are discussed.
- b..c.
i
Subsequent to the review of the ASME Code Interpretation VIII-1-83-338,
PMR 1634 was withdrawn from implementation status. Based on current
system performance without the modification, this de ign change is not
i presently deemed necessary.
CONCLUSION:
a. The system was restored on December 9, 1986. WCNOC considers this
, item closed.
b. c.
Even if the proposed modification had been implemented, the
modification would not have effected the original relief capacity of the
!
valve. Subsequent to the review of the ASME Code Interpretation
VIII-1-83-338 PMR 1634 was withdrawn from implementation status. Based on
current system performance without the modiffestion, this design change is
not presently deemed necessary,
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April 28, 1988
2.*.2.5 PMR 1613: VALVE LEAKOFF CONFIGURATIONS
FINDING:
This PMR redesigned the leakoff configuration for valves BG-HV8146, BB-8074
A,B,C, and D. BB-8055 BG-LC459 and BG-LCV460. The PMR added flexible hoses
and a shutoff valve on the leakoff lines of each of these valves. Since these
valves were subject to Reactor Coolant System (RCS) pressure and temperature,
the flexible hoses could have been pressurized if the valve packing leaked
with the leakoff isolation valves closed. The manufacturer's rated pressure
for the flexible hoses is less than RCS pressure, therefore the flexible hoses
are subject to failure. The failure to adequately evaluate this modification
is an example of a general weakness in the engineering area.
GENERAL DISCUSSION OF FINDING:
PMR 1613 r3 designed the valve stem packing leakoff configurations for valves
BG-HV8146 BB-8074A,B,C and D. BB-8085 (not 8055), BG-LCV459 and BG-LCV460.
This PMR added flexible metal hose and a shutoff valve on the valve stem
packing leakoff lines of each of these valves.
Since these valves are subject to Reactor Coolant System (RCS) pressure and
temperature, the flexible metal hoses can be pressurized to the same RCS
pressure if the valve packing leaked and the leakoff isolation valves are
closed. The area of concern identified by the SSOMI team in the subject PMR
is the fact that the manufacturer's rated pressure for the flexible hoses is
less than RCS pressure, therefore the flexible hoses are subject to failure.
RESPONSE TO THE FINDING:
Valves BB-8074A,B.C and D are 3 inch, manually operated, normally open, gate
valves located in the RTD bypass loops. Valve BB-8085 is a 3 inch, manually
operated, locked open gate valve located in the RCS letdown line (reference
USAR Figure 5.1-1). Valves BG-LCV-459 and BG-LCV-460 are 3 inch air operated
level control valves also in the RCS letdown line Valve BG-HV-8146 is a 3'
air operated globe valve in the centrifugal pump discharge line to RCS loop 1
ccid leg (reference USAR Figure 9.3-8).
These valves are on lines which have a design pressure of 2^85 psig and a
design temperature of 650 F. The normal operating pressure and temperature
are approximately 2235 psig and 5880F. The flexible motal hoses selected for
use are Swagelok models SS-6HO-6-L6 or SS-6H0-1-6-L6 with a SS 3/8' T X 3/8'
NPT adaptor fitting.
The Swagelok catalog sheet for flexible metal hose connector identifies that
the maximum working pressure rating at 70 F for these models of hoses is 1610
psig. Using the recommended derating factor of 0.74 at 600 F, the maximum
working pressure is approximately 1190 psig. If the shutoff valve downstream
of a given flexible metal hose is closed, the flexible metal hose would be
subject to the same operating pressure ( 2235 psig) and temperature ( * 588
F) as the main valves, assuming leakage of the primary packing and no leakage
from the secondary packing to containment atmosphere.
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April 28, 1988
WCNOC does not consider this item to be a deficiency. The basis for the WCNOC
position is as follows:
1. The purpose of the shutoff v41ve is to preclude packing leakoff from
other valves connected to the common header from back-flowing into the
packing chamber of the valve curing maintenance. Tha subject valves
(BB-8074AD,BB-8085 BG-HV-8146, BG-LCV459 and BG-LCV460) have backseats.
The maintenance manuals for these valves require that prior to working on
the packing chamber, the packing chamber be isolated from the main
pressure by the use of backseat. Therefore, during the maintenance of
the subject valves when the leakoff shutoff valves are isolated the
flexible metal hoses will not be subject to RCS pressure.
2. The subject valve packing leakoff connections tie into a 2' header which
discharges to Reactor Coolant Drain Tank THB09 via line HB-056-HCD-3'
(reference USAE Figare 11.2 1.3 The reactor Coolant Drain Tank has an
internal design pressure of 100 psig and a design temperature of 250 F
(referente USAR Table 11.2-1). Line HB-060-HCD-2' connected to line
HB-056-HCD-3' is provided with a relief valve Hb-7160 set at 25 psig.
The disposition to EER 86-XX-46 stated that the shutoff valves on the
valve leakoff connections are to be maintained normally in the open
position. Therefore, during the normal plant operation when the shutoff
valves are open the flexible metal hoses will not be subject to RCS
pressure. In fact, during normal plant operation, the pressure in these
flexible metal hoses is expected to be less than 25 psig.
3. It should be nogedthatthe nominal burst pressure for thess flexible
metal hoseg at 70 F is 6440 psig. Using a recommended derating factor of
0.74 at 60 F, the nominal burst pressure is 4765 psig (reference Swagelok
Catalog Sheet). At the normal RCS pressure of 2235 psig, there is still
a safety margin of 2 available.
CONCLUSION:
Based on the above discussion, WCNOC does not consider this item to be a
deficiency.
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April 28, 1988
2.1.2.7 PMR 2206: AUXILIARY BUILDING FIltE DETECTION SYSTEM
.
F2 1I,NG:
This PMR revised the fire detection system in the Auxiliary Building and
installed 3-hour fire resistant material on a hatch. The revisions were
issued in response to additional combustible material loading as a result of
the installation of a tool storsge area and an anti-contamination clothing
storage area in the basement of the Auxiliary B' 31 ding. The increased
combustible loading deviates from the commitments of the USAR, as indicatea
below.
a. USAR Page 9.4-2, indicated that Fixed Vater Suppression Systems were
installed in areas with a high fire or loss potential. No fixed system
was installed in the areas in question.
b. USAR Table 9.5.1-2 stated that an automatic pre-action sprinkler system
was installed to protect cable trays in the Auxiliary Building at
elevation 1974'-0' and that vertical cable chases were protected with an
automatic wet pipe system. Uncovered cable trays containing the power
cables for the 'A' and 'B' Auxiliary Foed Pumps pass vertically through
one of the areas in question with less than 20 feet separation between the
combustible material and no sprinkler system provided.
c. USAR Table 9.5A-1 indicates that safety related systems are isolated or
separated from combustible materials: the USAR also indicates that these
systems are separated when practical. The installation of the two storage
areas in close proximity to safety related systems violates this
guideline.
The SSOHI team was concerned that combustible loading in the Auxiliary
Building was increased without implementation of the commitments of the U54R.
GENERAL DISCUSSION OF FINDING:
,
PMR 2206 revised the fire detection system in the Auxiliary Building (Area
5) and installed 3-hour resistant material on a hatch that connected
areas at elevations 1974' and 1988'. The revisions were issued in response
i to additional combustible material loading in the vicinity. Engineering
Evaluation Request 87-21-04 requested an evaluation of the additional fire
loading as the amount and location of these combustible materials were
deemed necessary to support plant operatien and maintenance activities. The
{
SSOMI team was concerned that comoustible loading in the Auxiliary
Building was increased without implementation of the commitments of the
USAR.
RESPONSE TO THE FINDING:
a. Page 9.5 2 of Rev. O of the USAR includes Power Generation Design Basis
Fcur, which states that fixed water suppression systems are installed as
required in areas with a high fire or loss potential. Further, criteria
for determining the need for these systems is in substantial compliance
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Page 14 of 70
April 28, 1988
with the American Nuclear Insurers (ANI) * Basic Fire Protection for
Nuclear Power Plants' (March 1976). It should be noted that this design
basis is not a safety design basis.
The area in question. Rooms 1128 and 1129, maintain a relatively low fire
or risk potential as the increase in the fire loading from the additional
combustible materials does not substantially increase the risk or loss
potential from an exposure fire. This conclusion was based, in part, on
the fact that proper storage of combustibles (e.g. NFPA-30 rated
containers, metal shelving, and bins) and housekeeping controls would be
maintained.
b. The subject area is relatively uncongested which promotes effective fire
fighting ability. In general, sprinklers are located to provide corridor '
bay coverage where concentrations of cable trays occur. Typically,
sprays are provided where two or more stacks of trays are present with
two or more trays in each stack. Also considered are the congestion in
the area and the height of the trays above the floor. In the case of the
subject area, the cable tray concentration and loading is minimal, and
as such does not warrant sprinkler coverage.
In Appendix 9.5B, Fire Hazards Analyses of Rev. O of the USAR, paragraph
two of Section A.1.7.2 Safe Shutdown Capability addresses the issue of
both motor driven auxiliary feedwater pumps' power cables being located
in Room 1128. The principal rationale set forth in the analysis is that
the turbine driven auxiliary feedwater pump is not affected by a fire in
this area and will be available to bring the plant to a safe shutdown.
Other supportive information is provided in USAR section A.1.7.2 (second
paragraph), such as the distance between the cables being nineteen feet,
no other safe shutdown equipment, trays, or exposed conduits are located
in the room, traffic to other areas of the plant cannot pass through the
room, and transient combustibles are limited to those required for pump
maintenance.
c. The reference to USAR Table 9.5A-1 is taken out of context. The section
that is being referred to is under Section D, General Guidelines for
Plant Protection. The WCGS Summary of Compliance with Appendix A of ITRC
Branch Technical Position (BTP) APCSB 9.5-1 for item D.2.a is that
safety related systems are isolated or separated from combustible
materials, where practical. Where this is not practical, special
protection is provided to prevent failure of both safe shutdown trains
by a single fire. Also, reference is made to the Fire Hazards Analysis,
Appendix 9.5B.
The need for fixed water suppression systems is considered not required
for the subject plant modification. Since, the Turbine Driven Auxiliary
Feedwater pump is unaffected by a fire in this area and the PMR provides
additional fire protection afforded by the installation of 3. hour-rated
fire resistant material to the floor hatch between Rooms 1207 and 1129
and the installation of fire detectors, therefore a fixed water
suppression system is not warranted.
The establishment of a separate storage facility outside of the
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April 28, 1988
Auxiliary Building was not considered practical. As discussed in Item b
above, the turbine driven auxiliary feedwater pump is not affected by a
fire in this area. The tarbine dri,en auxiliary feedwater pump is
considered to be the redundant safe.cy related train for a fire in this
area, and thus protection is affo ved in the event of a single fire.
The subject storage aram i; actually not in close proximity to the
required turbine driven auxiliary feedwater pump train. The storage
area is basically twice removed by two separate three-hour barriers from
the turbine driven auxiliary feedwater pump train, and thus safe
shutdown is assured.
- CONCLUSION:
Although tho initial placement of combustibles in this area was not fully in ,
accordance with USAR discussions, the design modification meets or exceeds all
USAR commitments. The PMR design ensures that the turbine driven auxiliary
feedwater pump train is protected and isolated from a fire in this area.
WCNOC does not consider this item to be a deficiency.
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2.1.2.8 PMR 2222: CONTAINMENT COOLTNG FAN DAMAGE
FINDING:
This PMR implemented corrective actions following the failure of a fan blade
in Containment Fan Cooler (CFC) SGN01B. The failure damaged the cooling unit
and required er.tering a TS LLniting Condition for Ope ation (LCO) Action
Statement. The cause of ;he failure was determined to be loosening of the nut
which held the fan blade to the hub of the fan rotor. Subsequent inspection
revealed four other loose nuts on the CFC SGN01B. In addition, the licensee
determined that a similar failure which was attributed to loosening of the
blade nuts had previously occurred at another facility. The licensee
instituted an inspection procedure to verify the tightness of the nuto during g
each refueling outage, but did not investigate and determine the root cause of
the failure. Possible causes for these failures are insufficient torque on
the nuts to produce the required preload, excessive torque causing
overstressing of the blade shafts, inadequate blade shaft size or strength and
excessive vibration. The failure to investigate the root caure of these
failures is an example of a general weakness in angineering evaluations.
GENERAL DISCUSSION 3F FINDING:
In Item 2.1.2.8 the SSOMI team determined that the root cause investigation of
the fan blade failure in Containment Cooler SGN01B was insufficient and that
the failure to fully investigate the root cause of the event to be a general
weakness in the engineering evaluation.
- iPONSE TO THE FINDING:
. :. the investigation performed of the fan blade failure, visual examinations
of the blades and examinations of the blade threaded connections by the
magnetic particle method were conducted. Due to the nature of the failure of
the broken blade, which was broken transversely across the threaded root
portion, and the fact that no cracks were found in like areas of the remaining
fan blades, it was concluded that inherent material deficiencies or the
existence of overstressed conditions were unlikely root causes. The nature of
the blade failure and the subsequent damage incurred to the remainder of the
fan made it difficult, if not impossible, to distinguish if the contact of the
fan blade tip to the shroud housing occurred prior to or after the fracture of
the blade root. This key aspect prevented determining whether the fan blade
root nut loosened or deficient fan blade material was the root cause of the
fan blade failure.
Based on the above and the isolated instance of a fan failure at another
facility of similar design (Hydrogen Hixing Fan manufactured by Joy
Manufacturing) from which very little information could be derived, it was
concluded that the root cause of the event could not conclusively be
determined. Effective prevention of another such type of failure by
inspections of blade tip angles, torque checks or the blade attachment nuts,
and lubrication of the motor bearings of other like vanaxial fans and
continued monitoring was deemed most appropriate.
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April 28, 1988
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ACTIONS WHICH HAVE BEEN OR WILL BE TAKEN:
Lubrication of the motor bearings, inspection of the blade tip angles eted
torque checks of the blade attachment nuts is completed at each refueling
'
outage as required by the Preventive Hair.tenance Data Base Program.
Verification of acceptable vibration levels are also conducted in like ;
fashion. '
i
- CONCLUSION
?
Based on the above discussion. WCNOC does not consider this item to be a
deficiency.
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April 28, 1988
2.1.2.9 APPENDIX,J LEAK TEST REQUIREMENTS
FINDING:
PMR's 1143 and 2109 required the encapsulation of hinge pins for feedwater
valves due to leakage. The SSOMI team determined that 10 CFR 50, Appendix J
required leak testing had not been performed on these valves. The licensee
indicated that the Steam Generators and attached secondary systems inside
containment were closed systems and that for all accident conditions, the
secondary pressure was higher than containment pressure. Therefore leak
testing of the valves was not required. The SSOMI team questioned whether the
Steam Generator System was required to be maintained pressurized in the ovent
of a design basis accident and whether the instruments, instrument lines and '
appurtenances on the Steam Generators and other secondary systems were
adequately protected in the event of a high energy line break. Further action
is necessary to clarify the containment boundary and leak testing requirements
with respect to the secondary systems, the assumed condition of the secondary
systems during a design basis accident, and the design of the secondary
systems with respect to high energy line breaks. This general concern has
been previously identified at other plants and is under roview by NRR. There
were no further concerns identified with respect to these PHRs.
GENERAL DISCUSSION OF FINDING:
During the review of PMRs 1143 and 2109, the :iSOMI Team identified that
10CFR50, Appendix J required leak testing had not been performed on the
associated valves. The team questioned the containment boundary and leak
testing requirements with respect to the secondary systems, the assumed
condition of the secondary systems during a dtsign basis accident and the
design of the secondary systems with respect to high energy line breaks.
RESPONSE TO THE FINDING:
The valves associated with the above identified PMR's are Feedwater Isolation
Check Valves AE-V-120, AE-V-121. AE-V-122 and AE-V-123 and Feedwater Chemical
Addition Isolation Valves AE-V-128 AE-V-129, AE-V-130 and AE-V-131. These
valves arc associated with the Main Feedwater Line Penetrations P5, P6, P7 and
P8,
As discussed in Safety Evaluation Seven, in USAR Section 6.2.4.3, the
containment penetrations associated with the steam generators are not subject
to GDC-57, since the containment barrier integrity is not breached. The
boundary or barrier against fission product leakage to the environment is the
inside of the steam generator tubes, the outside of the steam generator shell,
and the outside of the lines emanating from the steam generator shell side.
USAR Figure 6.2.4-2 shows the steam generator and associated secondary systems
that serve as a barrier to the release of radioactivity pose.-LOCA. USAR
Figure 6.2.4-1 Sheets 5, 6, 7 and 8 show the configuration of the subject
ponstrations.
As indicated in USAR Section 6.2.6.3, Containment Isolation Valve Leakage Rate
Tests (Type C tests), the valves associated with the piping systems connected
to the secondary side of the steam generators isolate the steam generatorJ and
are not considered containment isolation valves and are, therefore, not leak
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Page 19 of 70
April 28, 1988
tested. All portions of the secondary side of the steam generators are
considered an extension of the containment. The above identified USAR Section
further elabotates and specifically excludes penetrations PS, P6, P7 and P8
from Type C testing. As shown on USAR Figure 6.2.4-2, the water level in all
steam generators is maintained above the tubes following a LOCA to preclude
the entrance of the containment atmosphere into the secondary side of the
steam generators. As discussed in USAR Section 6.2.6.1.1, following the
containment stabilization period of the Type A Test (ILRT), the secondary side
of the steam generators are vented outside of the containment to ensure the
most conservative test configuration during the ILRT.
The high energy line pipe break locations and types of brecks are identified
in USAR Figures 3.6-1 and 3.6-3. The stress results that were utilized to
determine the break types and locations are provided in USAR Table 3.6-3. The
high-energy pipe break effects analyses criteria and results are provided in
USAR Table 3.6-4. The results of the analysis demonstrate that the for all
postulated breaks, including the design basis LOCA, containment intqgrity is
maintained and no essential systems are impacted.
CONCLUSION:
As discussed above, the subject valves and associated penetrations have
previously been identified in the USAR as being exempt from local leak rate
testing. In addition, their configuration and compliance with 10CFR50,
Appendix J requirements, relative to Type A Te* ting, (ILRT) have also been
previously provided in the above identified USAR Sections.
The high enargy line break evaluation and supportive existing USAR information
has been identified for clarification as requested. The Safety Evaluation
Reports, NUREG-0830 and NUREG-0881, describe, in Sections 3.6.1, 3.6.2, 6.2.3,
and 6.2.5, the staffs recognition and acceptance of the above identified
information.
.
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Page 20 of 70
April 28, 1988
- l 1 2.10 dATTERY DISCHARGE OF OCTOBER 13. 1987
FINDING:
During maintenan e of the Division E Vital Bus NB02 on October 15, 1987, both
Station Batteries ware subjected to a deep discharge resulting in a loss of
both vital buses. The root causes of the discharge are being reviewed by
Region IV and will be addressed in separate correspondence. As part of this
inspection, the SSOMI team reviewed the adequacy of the battery capacity and
associated design calculations.
The maintenance which deenergized the bus was expected to last less than 30
hours. Based upon the nominal ampere-hour capacity of battery NK14
Operations personnel performed a calculation and estimated that the battery
would provide 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> of service with a 35 ampere load. The S30MI team found
that the basis for the estimate that the batteries would provide 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> of
service van inadequate. The licensee indicated that the estimate was made by
dividing the b.ttery rating of 1650 ampere-hours by 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> which yielded a
permtasible d scharge rate of 35 ampt However, the sctual load on the
battery during the discharge was recorded in the control room each shift as 70
amperes. Battery Sizing Calculation E3, indicates that steady state loads of
220 and 100 amperes would result in discharge rates of 20 amperes per positivo
plate (APPP) and 16 APPP for Batteries NK12 and NK14 respectively. The
battery cell characteristic curve indicates that the battery capacity would
provide 10-hours of service at these discharge rates. Based on Calculation
E-3 and the cell characteristic curve, the SSOHI team calculated that a 70
ampere load would have resulted in a discharge time of 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />.
In addition, the SSOMI team noted that during removal of the NB02 Vital aus
from service, system operating procedures SYS NB331/4 and SYS NB331/5 were not
utilized. These procedures specified the requirements and precautions for
system operation ar.d isolation and specified a maximum discharge time of 200
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minutes. The licensee subsequently indicated that operational procedures are
not routinely used for removing and returning equipment to service. The
failure to utilize the appropriate operational procedures and incorporate the
l precautiens and requirements of these procedures for the removal and return of
equipment from service in accordance with the requirements of the Technical
Specifications and 10 CFR 50, Appendix A, is considered to be a weakness. The
SbcMI team considers that, If the operations Department had complied with the
procedural requirements, or had used the battery sizing calculations provided
by Engineering, or had consulted with Engineering, the deep discharge and
resulting loss of both vital buses would not have occurred. j
l
The battery discharges occurred on October 15, 1987. Following these events, i
the batteries' conditions were not recorded prior to recharging. Based upon
tha results of the earlier October 7, 1987, performance discharge test on
battery NK12 discussed in Section 2.1.2.12 of this report, and the fact that
the unplanned discharges went deeper than the performance test, at Isast cell
32, and probably other cells, reversed polarity during the unplanned
discharges.
The failure to provide adequate controls for the removal from service of a
safety system which resulted in a loss of the Station Batteries is a weakness.
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Page 21 of 70
April 28, 1988
In addition, the failure to involve the Engineering Department, either through
the use of system procedures or by consultation during the battery discharges,
is a significant weakness.
GENERAL DISCUSSION OF FINDING:
Station procedures were not utilized to remove Vital Bus NB02 from service and
there was a failure to provide temporary power to Station Batteries NK12 and
NK14. Additionally, enginevring was not utilized to perform discharge
calculations.
RESPONSE TO THE FINDING:
.
The root cause of these events has been attributed to cognitive personnel
error by Operations, Maintenance and Outage management personnel in failing to
plan for th capability to provide temporary power supplies to the batteries
if the NB02 outage was extended. Preparations to supply the ba*.teries with
alternate power were in progress when the Low Voltage Alarms verw received,
however, the task was not completed prior to discharge of the batteries. This
situation existed because prior to this event, station policy was to utilize
work request procedures and tag out procedures to control plant equipment
during outage work. Also, implementation of the temporary modification to
bring in alternate power to the bus was too time consuming.
As a result of the battery discharges, an evaluation of the batteries was
performed. This evaluation concluded that all of the batteries were
capable of performing their design function based on a review of the
specific gravity, voltage, electrolyte level, and electrolyte temperature
for each cell.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN:
Programmatic changes have been incorporated which require either the use of
existing procedures or developaent of a new procedure to take equipment out of
service and to restoro equipment to service. Prior to this tim 9. the work
request procedure and the clearance order procedure were used to control
these work activities.
By Septembet 1, 1986, a specific procedure will be prepared which will provido
instructions for deenergizing a vital bus with requirements for powering
Station Batteries from an n1 ternate source. The preparation of this procedure
, and its use will preclude future similar oc .erences.
Plant and Nuclear Plant Engineering procedures have been changed to enhance
the use of engineering talent and skills. These procedure modifications
enanges should result in proper personnel involvement in a specific problem
area.
The events described above were addressed in Programmatic Deficiency Report
(PDR) OP-87-81 and Licensee Event Report (LER)87-049. The implementation of
the corrective action will resolve the concern identified by the SSOMI team.
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April 28, 1988
2.1.2.11 BATTERY SIZING CALCULATION E-3
FINDING:
Bechtel Calculation E-3, 'Cisss 1E Battery System,' Rev. O, dated January 12,
1987, was reviewec by the SSOMI team and tho following discrepancies were
identified:
a. The calculation assumed a constant load on the DC System based upon a full
load rating of the 7.5 KVA for the Battery Inverter. However, in
calculating the DC current, the DC voltage was taken at the nominal 125
VDC level. Because inverters try to deliver a constant KVA load, as the
battery voltage decreases during a discharge the current drawn by the
inverter from the battery will increase. These errors would add "
approximately 10% to 15Z to the required battery size.
b. The input data did not document the cell characteristics used by the
computerized calculation.
c. The calculation did not consider the minimum cell temperature permitted by
the Technical Specification.
The battery sizes selected for batteries NK11 and NK13 are 25% and 42% larger
than the calculated required size. The errors noted above can be enveloped by
the existing battery and there are no safety concerns with th9 installed size
of the batteries. The inadequacies identified in the battery sizing
calculation are symptomatic of a general weakness noted by the team in
engineering calculations.
GENERAL DISCUSSION OF FINDTNG:
Station batteries NK12 and NK14 were subjected to a deep discharge due to
extended loss of power to their chargers. As a part of their invostigation,
the SSOMI Team examined the adequacy of the battery capacity and associated
Bechtel design Calculation E-3, Rev. O, dated January 12, 1981. (The subject
SSOMI report refers to Bechtel Calculation E-3, Rev. O, dated January 12,
1987. This is in error. The referenced calculation revision is dated January
12, 1981).
RESPONSE TO THE FINDING:
a. The load profile used in calculation E-3 included continuous and momentary
loads that are conservatively assumed to be constant during the design
batia duty cycle. Since the total load on the subject batteries consists
of mostly constant resistance types of loads (e.g., control panel
indication lights, control circuits, instrumentation and emergency
lights), the above assumption is considered conservative as the resistive
load currents decrease under low voltage conditions.
It should also be noted that, as verified by Westinghouse, the inverter
vendor, the subject inverter draws 58 amps at 135VDC, approximately 62
amps at 125VDC and 70 seps at 305VDO. Therefore, the use of 68 amps as a
steady state load over the entire 200 minute profile is conservative and
acceptable since this value approximately equals the maximum current draw
_ _ _ _ _ _ _ _ _ - _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _________________ _
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Page 23 of 70
April 25, 1988
.
which occurs only at 105VDC, for a short duration near the extreme end of
the discharge profile.
b. The computer program software was itself an independent and controlled
standard program of the Architect Engineer which contains the subject
, data for the batteries used at Wolf Creek Generating Station. The
y' standard computer program inherently contains the applicable battery cell
characteristico, therefore these characteristics are not provided as user l
entered data every time the computer program is used. It is indicated on
page 10 of tne subject calculation, that the correct battery type and
manufacturer was, in fact, selected and recorded on the calculation.
c. The capacities of the subject batteries have been evaluated and previously l
- aiscussed with the NRC (Safety Evaluation Reports, NUREG-0881 (Wolf r
i Creek), April. 1982 and NUREG-0830, October, 1981 (Callaway), Section i
i 8.3.2.2) with regard to temperature performance and other factors, The l
subject batteries are sizej in excess of 50 percent of the initial battery !
'
capacity (i.e., are 50% oversized) thus enveloping the requirements for
l temperature, voltage and specific gravity fluctuation, as well as the l
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replacement criterion of 80 percent. The subject batteries meet IEEE ;
Standards for battery sizing and are acceptable. This item was !
specifically discussed with the SSOMI team in order to document that l
2 minimum cr.11 temperatures were evaluated by WCNOC prior to fuel load for i
Cycle III. i
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CONCLUSION: l
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The battery sizes installed are adequately designed and provide more than the
,
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required capacity. It is not felt that the above observations are indicative
or representative of a general weakness in engineering calculations.
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April 28, 1980
2.1.2.12 BATTERY PERFORMANCE TEST
FINDING:
In order to evaluate the battery discharge of October 15, 1987, the SSOHI team
reviewed the performance test performed for Battery NK12. The purpose of the
performance test was to demonstrate the actual capacity of the battery
compared to the manufacturer's published rating.
Performance Test STS MS 022, performed on Battery NK12 on October 7,1987, was
interrupted prior to the completion of tt.e test to jumper out Battery Cell No.
32. This cell had dropped 80 millivolts in 10 minutes to 1.692 volts. The
SSOMI team estimated that the battery would have teached its test limit in
less than 1/2 hour if the cell had not been jumped. The test was restarted
approximately 6 1/2 hours later. When the test was restarted the battery
voltage had increased to a voltag' which existed two hours before the test had
been stopped. As a result of the failure to recognize that the battery would
recover lost capacity during the extended outage, the performance test
incorrectly showed that the battery had a capacity of 138.75Z. The SSOMI team
calculated that if the performance test had been left to continue until
completion, the battery capacity would have been calculated at 125I. While
the battery has less capacity than the assumed by the licensee as a result of
the performance test, the battery has 50! more capacity than that required by
the test acceptance criteria. The failure to adequately test and evaluate the
results of the battery performance testing is considered to be indicative of a
general vsakness in engineering evaluations.
GENERAL LISCUSSION OF FINDING:
This item concerns the jumpering of a weak cell (132) during the October 2,
1987 performance discharge test of battery NK12. The finding concerns the
time taken to jumper the weak cell, approximately 6-1/2 hours, and the
battery capacity obtained from the test.
The procedure used in performance of this test, STS MT-022, was written
to incorporate the requirements in the Technical Specifications, and the
recommendations in the Gould Manual and IEEE 450. Step 6.4(4) of IEEE 450 states 'if an individual cell is approaching reversal of its polarity
(plus 1 volt or less), but the terminal voltage has not yet reached its test
limit, the test should continue with a jumper across the weak cell'.
RESPONSE TO THE FINDING:
There are two reasons which can be attributed to tha performance teat
being stopped for approximately 6-1/2 hours. The procedure did not specify a
maximum allowable time for interrupting the test. In addition, although
jumper cabler had been prepared prior to the test, the availability of
the jumper cables was not checked immediately prior to the start of the test-
Maintenance personnel did not recognize the time sensitivity of this while new
jumper cables were being made.
The Gould ibnual does not address performance or duty cycle testing. IER
450 lists recommendations for the performance and duty cycle tests, but
does not identify the maximum allowable time for interrupting a test. As
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! April 28, 1988
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addressed in IEEE 450 Step 6.4(4), the jumper could be placed directly across
the cell, which would short the cell and completely discharge it, or the
test could be stopped and that cell disconnected from the battery replacing it
with a jumper. Since IEEE 450 states a cell is approaching reversal at plus 1
volt or less, a determination was made when writing the procedure to ,
disconnect the cell from the battery to keep it from being completely
discharged.
,
Gould was contacted after the test was performed as to their recommendation
for jumpering a cell, and a maximum test interruption time. Gould indicated '
they would accept either method for jumpering a cell, and if we choose to
jumper a cell that a test interruption of approximately 15 minutes should not
effect the battery capacity value obtained from the test.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN
Procedure STS MT-022 will be revised to incorporate the Gould recommendation
of 15 minutes, as the maximum time allowed to interrupt the test. Due to +
this 15 minute time limit, another step will be added to the STS to have I
the jumper cables cleaned and ready to install prior to starting the test.
These changes will be completed prior to July 1, 1988.
>
The battery capacity, listed in Step 5.2.5 of STS HT-022 performed on October
2, 1987 will be corrected to show a capacity of 120.72. This value was :
the proven capacity at the time the test was stopped. A Fluke meter had been !
installed to monitor cell #32, and Maintenance Engineering was present during ,
I the test interruption. The voltage of cell 132 dropped quickly, with only a
i few minutes between the 1.692 volt reading and the 1.080 volt reading when l
l the test breaker was opened. If the test had continued after cell #32 was !
jumpered (in the recoemended 15 minutes), the test would have continued !
for a very short period before it would have been stopped again to jumper :
cells #38 and #50. l
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CONCLUSION:
i
A revision will be made to the applicable procedure by July 1, 1988 to !
incorporate the resolution of the finding and prevent recurrence. Training '
for personnel in conducting and evaluating battery capacity testing will be
i developed and implemented for personnel prior to the next performance of STS !
!
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April 28, 1988
2.1.2.13 DC SYSTDI LOW VOLTAGE ALARMS
IJNDING: ,
In order to evaluate the battery discharge of October 15, 1987, the SSOHI team
1
reviewed the alarms associated with the DC System to ensure that the design of
the alarm setpoints were adequate. A review of the DC System alarms detailed
on Relay Setting Drawing E-11028(Q indicated that four DC undervoltage alarms
existed in each Battery System. These alarms should have provided sufficient
Jrning to prevent the DC System low voltages experienced on October 15, 1987.
.
GENERAL DISCUSSI0F OF FINtING:
Station procedures were not utilized to remove Vital Buss NB02 from service
l and there was a failure to provide temporary power to Station Batteries NK12
i and NK14.
.
l RESPONSE TO THE FINDING:
t
There are four DC undervoltage alarms for each battery system. Each battery
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system consists of a 125 VDC battery bank, a battery charger and associated i
equipment. The charger DC undervoltage alarm indicates the loss of a battery
charger at 123 VDC. The DC switchboard bus undervoltage alarm indicates low
DC voltage at 112.5 VDC. The distribution switchboard undervoltage alarm
, indicates a loss of the DC distribution panel at approximately 86 VDC. Each
- of these alarms displays in the
- ontrol room through an NK system trouble
- window which will reflash for each alarm. The inverter DC undervoittge alarm
'
indicates the loss of DC input to the inverter at 82.5 VDC. This alarm
j displays in the control room through an inverter undervoltage window. These t
alarms provide the control room with indication of a loss of DC system
function, but are not generally anticipatory in nature. During the October
15, 1987 event, undervoltage alarms came in at approximatvly the same time as
the initial Engineered Safety Features Actuations (i.e., Control Room l
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i Ventilaticn Isolation Signal. Containment Purge Isolation Signal and Fuel
l Building Isolation Signal).
l ACTIONS WHICH HAVE BREN OR VILL BE TAKEN
By September 1, 1988, a procedure vill be prepared which will provide i
instructions for doenergizing a electrisal safety related division with ,
- requirements for powering Station Batteries from an alternate source. l
FONCLUSION:
1
Implementation of the corrective action will resolve the concern idsntifieo by l
the SSOHI team.
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April 28, 1988 i
2.1.2.14 DIF ,
EINDINGt ;
The SSOMI team reviewed the design of the closing circuit for the Emergency
Diesel Generator (EDG) output breakers, NB0111 and NB0211, and concluded that j
the design is inadequate, in that the ' anti-pumping' logic prevents the '
breakers'from closing onto a cleared, deenergized bus. In the event that both ;
the normal and alternate 4160 VAC Vital Bus feeder breakers,NB0109 and NB0112, i
are open and the CDG mode switch is in the ' auto' position, the ' anti-pumping'
relay will be energized continuously, thus preventing the EDG output breaker
from closing. Operator action is required to cycle the EDG mode switch at the
local station in arder to clear the ' anti-pumping' logic and close the EDG
output breaker to reenergize the 4160 VAC Vital Bus.
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The requirement for manual operator action appears to represent an unanalyzed
condition, in that the deenergized 4160 VAC Vital Bus cannot be energized i
automatically by the EDG in this condition. This design deficiency was !
discussed in a conference call between the licensee and NRC Region IV ;
canagement on December 8, 1987, and will be reviewed by NRC Region IV. The
inability of the EDG output breaker to automatically close onto e cleared. [
deenergized bus is considered *.a be a design weakness. ;
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GENERAL DISCUSSION OF FINDING:
The SSOMI team review of the design of the closing circuit for the Emergency
Diesel Generator (EDG) output breakers concluded that the ' anti-pumping' logic
of the diesel breaker prevents the breaker from reclosing onto a deenergized
bus after a manual trip is initiated from the Main Control Room. Operator ;
action is required to cycle the EDG mode switch at the local station in order
to reset the ' anti-pumping' logic and permit reclosure of the EDG output
breaker. The inability of the EDG output breaker to directly reclose on to a
cleared, deenergized bus was considered by SSOHI to be a design weakness.
I
7ESPONSE TO THE FINDINGt
The above concern is related to the reclosing feature (m4nual or auto) of the !
subject breaker after a manual trip when offsite power is not available and
when power is being supplied by the diesel generator prior to the subject :
manual trip. It was found that the stated condition resulted from manual
l
interruption, via the Control Room breaker hand switch, of the as designed <
fully automatic sequence for diesel start, loading and restoration of !
essential AC power under loss of offsite power conditions. e
!
As originally designed, the diesel generator is normally in the standby mode
whereby, on loss of offsite power, it will automatically start and its output
breaker will automstically close on to a cleared, deenergized bus, consistent
with its design intent. No manual actuation or intervention is required for
pettormance of this function. Tripping the output breaker and subsequently
attempting to manually reclose it from the thin Control Room was not the
original design intent, nor is it intended under future designs, that such
interruption be entertained under the stated loss of offsite power conditions.
A meeting was held with NRC, VCNOC and representatives of Bechtel (VCGS A/E)
te discuss the existing design and operatio. of the breaker. The relationship
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Page 28 of 70
April 28, 1988
of the design to Regulatory requirements and considerations for modificaties
to the existing dcsign were also discussed.
The dasign was in compliance with relevant Regulatory requirements and that
the existing design operates correctly under the relevant normal and design
basis accident scenarios. However, after discussion with the NRC, it was
concluded that it would be beneficial to have suitable provisions to allow
reset of the circuit and allow resultant breaker reclosurs from the Main
control Room. This capability would allow for more timely recovery should
intentional or inadvertent manual trip of the diesel output breaker occur
under loss of offsite power conditions.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN: ;
Based on review of the subject control circuit and its design features, it was
concluded that the subject diesel generator ureaker was not designed to be
tripped and reclosed nanually from the Main Control Room under the stated
conditions. The entire diesel generator start and loading sequence (including
breaker closure) and power restoration is designed for automatic operation
without manual intervention. However, upon subsequent discussion with the
NRC, it was agreed that a design change providing the operator, in the Main
Control Room, with a capability to teclose the diesel generator breaker on a
deenergized bus would be a beneficial enhancement. Wolf C-eek has procured
the necessary materials and is ready to implement the modification.
CONCLUSION:
The proposed design change will enhance the capability for manual control from
the Main Control Rcom to reclose the diesel generator breaker if manually
tripped during a loss of ot'fsite power event.
,
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April 28, 1988
!
3.1.2.2 PMR 1722: VALVE HOTOR-OPERATot TESTING f
l FINDINGr
- :
- Th!.s PXR performed valve motor operator testing and torque and limit switch !
O settings in response to NRC Inspection and Enforcement (IEE) Bulletin 85-03, i
J regardine torque and limit switch settings in valve motor operators. In [
. addition internal operator wiring was modified to distribute the limit switch !
j and indi;ation contacts to different rotors.
! The SMR. PHR changes, drawings, calculations, and WR packages for several l
1 affected valves were reviewed. Operators for the five motor operated valves !
!
(HOVs) identified below were inspected for conformance to design requirements l
l and proper workmanship.
i ,
'
- Valve Number Function
i
BB-HV8000A Pressuriser Block Valve
BB-HV80005 Pressurizer Block Valve
AL-HV031 ESW to Motor Driven AFW Pump A
AL-HV030 ESV to Hotor Driven AFW Pump B
EM-HV8923B SI Pump B Suction Isolation
The following discrepancies were identified
a. Deficiencies were identified in two of the valve operators. The spare
conductors of the control cable in each Pressurizer block valve, which are
located inside containment, were not properly protected to prevent
possible interference with the operation of the valve. Bechtel Detail
Drawing E-11013, required spare conductors of safety related cables in the
Reactor Building to be protected with Raychem end caps. Contrary to this
requirement, the spare conductor in Valve BB-HV8000A was unprotected, and
the spare conductor in Valve BB-HV80005 had been originally protected with
tape which subsequently became unraveled. Drawing E-11013 allows the use
of tape for protection of conductors outside, but not inside, the Reactor
Building. In addition, insulation damage was noted on several conductors
of the control cable in Valve BB-HV8000A. Based on these findings. WR
4954-87 was written for Valve BB HV8000A and WR 4953-87 was written for
Valve BB-HV80008 to correct the deficiencies and to evaluate the
insulation damage,
b. A concern was identified in the complexity of drawings required to
identify the wiring configuration for conduct and verification of
maintenance and modifications of the mytor operated valves (HOVs). As
many as seven different drawings and wiring lists were required to fully
inspect the wiring configuration of each MOV reviewed. For example, the
drawings required to inspect Valve AL-1:VU30 included a design schematic, a
vendor wiring diagram which also included a partial schematic, two field
wiring lists, and three design change documents. Other valves had wiring
changes required by the vendor that were specified in writing by vendor
change requests, but were not indicated on the vendor viring drawings.
Differing conventions for identifying the wire termination points on
wiring diagrams were also ident!fied. In some instances, wiring diagrams
identified field wire terminations, and in others tne internal wire
designations duplicated field wire designations.
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Page 30 of 70
April 28, 1988
The difficulty 4.n using the large number of inconsistent drawings to make
changes to wiring had been previously identified by the station Electrical
Maintenance Department. Engineering Evaluation Request (EER) 8 6-EH-0 3
described the problem of multiple drawings and inadequate cross
referencing between plant and vendor drawings. The SSCHI team was
concerned that, although the EER was approved and submitted on July 18,
1986, an evaluation or disposition for the EER had not been made.
EER 87-KC-08 was written to correct a vendor wiring drawing that used the
same wire numbers twice. The engineering evaluation rejected the
recommended drawing change on the basis that a review of four related
design drawings indieeted the viring was inadequate. The EER response
referenced Bechtel Specification E-01016 ' Electrical As-Built Drawing
Criteria.' Note N. as the reason for not correcting the wiring drawing.
Note N states that internal vendor wiring inconsistencies which do not
affect the circuit electrically or functionally will not be incorporated
into the as-built drawings. The SSCHI team considered that this
resolution was inadequate because as-built wiring drawings are routinely
used for maintenance and modification activities.
4
Except for the discrepancies in the Pressurizer Relief Valves d. :ussed in
d
Section 3.1.2.2.a. the workmanship observed was good. The fact that few
l problems have been identified in motor operators is attributed to the
diligence of the maintenance craft and engineers and is considered a strength.
GENERAL DISCUSSION OF FINDING:
a. During field walkdown with the inspectors to check the actuator wiring
installed in accordance with PHR 01842 (not 01722 as referenced), it was
found that spare conductors were not isolated correctly. It was also
noted that several conductors of cable 11BBG39AG were abraded and
needed to be checked for insulation damage within valve actuator
BB-HV8000A.
b. EER 87-KC-08 identified an anomaly on a vendor wiring diagram, involving
the duplication of vendor wire numbers. It was recommended that one set
j of the duplicated wire numbers be revised to preclude confusion.
The SSOHI team concern dealt with what was termed 'the complexity of
drawings required to identify the wiring configuration for conduct and
verification of maintenance and modifications of the motor operated
valves (HOVs)'. The design documents used on PHR 1722 were of the
stundard format and consisted of:
a I
a) Schematic drawings (E-03's) - drawings used to show the valve
operator's internal e*ectrical configuration and its interface with
other systems and components,
b) Internal wiring diagrams - vendor supplied internal wiring
configuration for each valve. Represents vendor provided or vendor
side wiring.
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Page 31 of 70
April 28, 1988
c) External wiring diagrams - drawings or listed information that shows
the configuration of external cables, their associated wires and
termination points. Wires installed external to the equipment which
are needed to fit or configure that equipment into the overall
schems are considered as field wires or jumpers. The termination
list ar.d jumper 110t are included in this category.
When any electrical modification is made, the possibility exists that at
least one, and in many ceaes all three of the above documents will be
revised by either Assuing a document revision on a document change
notice. Due to time constraints, a needed revision of the modification
documents associated vith valve AL-HV030 was accomplished by issuing
three document change notices.
RESPONSE TO THI 7INDING:
a. The use of tape within the Reactor Building is not a design approved
means to isolate or protect spare conductors. The root cause is
recognized to be a lack of attention to the specific details by
electricians, QC, and Maintenance Engineering personnel. The
abrasten on conductors was due to original installation methods.
b. The general description, specifications and details for vendor equipment
are provided in vendor instruction manuals. It is necessary that this
information be reviewed prior to routine maintenance or modification
activities.
The instruction manual for the equipment shown on the subject vendor
wiring diagram includes information that eliminates the confusion
i regarding tht duplicate wire numbers. Thersfore, note N on Bechtel
Drawing E-01016, ' Electrical As-Built Drawing Criteria', applies to the
identified anomaly and no drawing revision is required. Therefore, the
disposition is adequate and WCNOC does not considsr this item to be a
deficiency,
i The electrical design documents used for plant modifications are based on
i the system utilized by the Architect / Engineer (A/E) for the original
.
plant design. Each document type is used to convey its portion of the
l
'
total picture. Once an individual bucomes familiar with the scheme used.
the system is not ' difficult'. With regard to what the inspector
described as ' inconsistent drawings *, it must be recognized that the
above three document types were consistent with respect to one another
for any particular operator. However, due to the fact that each vendor's
internal wiring diagrams are different and site installation
characteristics for each operator may be d.fferent (e.g. slack in field
s run cables,, it is possible that the set of electrical design documenta
for a particular operator may be different (or 'not consistent') with
those of another operatcr.
With regard to the SSOMI team's consents on dispositioning Engineerina
Evaluation Requent (EER) 86 EM-03, Nuclear Plant Engineering is
addressing the concerns reflected in the EER se part of the werk scope of
FMR's 1722, 1842, 2071, 2073 and 2076.
1
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Page 32 of 70
April 28, 1908
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN:
a. Work Request 14953-87 installed an appropriate end cap on the spare
conductors in BB-HV8000B. Work Request 14954-87 installed approved end
caps on the spares in valve BB-HV8000A. Work Request 14954-87 also
reworked the abraded conductor insulation in accordan:e with the criteria
defined in E-11013.
Maintenance Engineers were reminded of the Raychem end cap criteria
for spare conductors within the containment, and measures were taken to
prevent further conductor degradation by installing protective
sleeving on the abraded conductors.
CONCLUSION:
a. This item does not point to a significant program breakdown. The
improper isolation of spare conductors is not a major defect. The
abrasion noted is a result of previous incorrect installation and the
problems were resolved expediently when identified.
b. WCNOC realizes that the wiectrical design document format may be somewhat
confusing to an individual who is unfamiliar with the A/E's system.
Hove.rer, the system does work and provides the information needed to
support plant operations. Although a ' standard' approach is desirable
and is used where possible, differences in vendor drawings and field
installation configurations do cause variations in the method used to
achieve the same end results.
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Page 33 of 70
'
April 28, 1988
3.1.2.4 PME 2018: ASCO SOLENOID VALVE REPLACI! MENT
i
FINDING:
[
This PHR replaced twelve safety related, seismic Category I, environmentally
qualified. Asco solenoid valves on air operated valves in the Reactor Coolant
System, Chemical and Volums Control System, Residual Heat Removat System. High ;
Pressure Core Injection System, and Liquid Radiological Vaste System. The ;
modifscation was initiated as a result of shorting of electrical wiring within !
the solenoid housing aused by limited space within the housing, splicing of l
pigtail leads, and Raychem sleeving o' wires with damaged insulation. The PHR
replaced solenoid vrives using slectrical pigtails with solenoid valves using -
terminals. ,
The PMR, VRs. procedures and docunentation associated with the installation
[
were reviewed. A field inspection was conducted on three solenoid L
'
installations that had been completed at the time of the inspection. The
Installations were inspected against the assembly and mounting detail drawings ,
and work instructions in V:ts that implemented the PHR. Solenoid valve serial j
numbers were verified against material requirements for the valves that were i
inspected. The fc11owing concerns were identified: ;
t
a. The 10 CFR 50.59 Lafety Evaluation was inadequate in that the seismic and (
environmental equivalency of the solenoid valves being installed was not j
documented. The written evaluation described only the improvement in j
safety because the leads would not short out in the new model solenoids. l
l
The safety evaluation for changes involving substitution of components
would normally be expected to reference equivalency or superiority in i
form, fit, function, materials, mounting, and qualification, which woald [
equate the change to a quality level at least consistent with the ;
originolly analyzed design. i
b. The air supply line for the ASCO solenoid valve EJ-HCV88908 had inadequate
seismic support between the solenoid valve and the polar crane wall. The l
supply line had approximately eight feet of rigid and hard copper tubing r
that did not havo support. The unsuppo.ted tubP4 cont %ined both an !
unsupported drain valve and the solenoid air isolat h <alve. r
i
c. 'h e 3/8-inch diameter stainless stwel air tubing for the Asco solenoid !
alve serving Valve EJ-HCV88905 had one loose tubing support between the !
Asco solenoid valve and the air operator.
d. Work Request 1042-87 which replaced Asco solenoid Valve EM HV8881 had one [
instance of enclear work instructions. Step 26 required recording the t
valve serial number without reference to which valve. Consultation with
the personnel who had written the work instructions and performed the work -
was required to ascertain that the serial number recorded was for the l
valve which had been removed. In this case, ;he unclear instructions did
not affect sc.fety, f
F
r
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Page 34 of 70 .
4
April 28. 1938
L
REFERAL DISCUSSION OF FINRIPGr
a. SSOMI team review of PHR 02018 Asco Solanoid Valys Replacement identified I
l a concern with the 10CFR50.59 Safety Evaluation. The identified concern
- is an isolated case that was an omission in the preparation of the i
j 10CFR50.59 faiety Evt.luation because the solenoids utilized in the design
>
were procured earlier as replacement parts to the appropriace technical j
i and quality requiremer.ts. i
l b. The air supply line for ASCO Solenoid Valve EJ-HCV-88905 appeared to be l
sustalled with inadequate seismic supports. Approximately eight feet of i
,
rigid and hard copper tubing were not seismically supported, as well as a i
drain valve and the solenoid air b olation valve.
l c. During field walkdown of valve EJ.HCV88908 a loose 5/8' air line j
i was identified. ;
1
.
4 d. Work Request #1042-87 written for valve Di-HV8851 contained a confusing 7
) step for the recording of a valve serie.1 number. j
1 i
1
RESPONSE TO THE FINDING i
i
l a. The new model solenoids were originally procured as replaca'ents for the
! solenoid valves. The spare parts had been purchased in accordance with ;
'
the original Westinghouse Purchass Order which included seismic and ;
i environmental qualification requirements. In addition, the Haterial
l Received Report (HRR) includes a certificate of conformance documenting
'
the compliance with Westinghouse Purchase Order and the applicable Codes [
j and Standards. Based on this discussion, the seismic and environmental i
considered during the !
equivalency
~
of the replacement parts were '
! procurement process: therefore, no hardware deficiency has been
i identified. However, reference to this equivalency should have been
j documented on the 10CFR50.59 Safety Evaluation.
i
l b. The Instrument Air System at WCGS, of which the subject tubing is a part,
f is non-safety related and non-seismic. The copper tubing in question is '
.
) designed to ANSI B31.1, and the branch line feeding the solenoid on Valve
i
EJ.HCV.88905 is field routed and supported in accordance with t
)
Specification 10466.H 203. Appendix X. In the event of the fsilure of l
I this air supply tubing, the valve will return to its fail-safe mode.
i Trom the standpoint of !!/1 considerations the subject tubing was !
reexamined by an engineering walkdown subsequent to the $50HI Review. The :
l valkdown confirmed that no adverne II/I condition exists with the mbject [
)
installation and no !!/I considerations need be made for the sub9ct r
) tubing installation. l
c. The cause of the loose air lir.e support is unknown. [
t
t
i
, d. The root cause of the confusing work instruction on valve Dt-HV8881 was !
j the lack of adequate review of work instructions by the maintenance [
r
1 lead electrical engineer.
i i
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Page 35 of 70 l
April 28, 1988
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN
c. The loose air line support was tightened in accordance with Work Request
- 4802-87.
d. Step 36 was an informa tion only item for maintenance. It was not a
requirement of the installation, therefore no corrective action to correct
the intent of the step was taken. Work instructions are currently being
reviewed in a much more attentive manner prior to issue in attempt to
ninimize confusing items in the future.
CONCLUSION:
a. VCNOC scknowledges that the 10CFR50.59 Safety Evaluation for PMR 2018
Asco Solenoid Valve Replacement should have identified the reference to
equivalency and suitability of the repiscement solenoids. In order to
preclude further omissions of this nature, the subject deficiency will be
brought to the attention of those personnel performing safety evaluations
through reviev of the SSCHI team audit findings and the VCNOC response.
No further action is warranted at this time,
b. As discussed above, the subject installation does not require additional
seismic or II/I consideration, and as such WCNOC does not consider this
,
item to be a deficiency.
c. The identification of the loose air line st'pport was corrected on WR
- 4802-87.
d. WCNOC acknowledges that confusing work .nstructions existed. Current
plans for more detailed reviews. word processing capability, and the
normal recognition of experience will minirize these type of problems.
These improvements will be implemented by September 1, 1988.
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Page 36 of 70
April 28, 1988
3.1.2.5 PMR 2329: RAYCif?N SPL'@
FINDING:
This PHR did not require field work and was used to document the disposition
of 38 deficient Raychem splices identified in VR 4443-87 that were to be
dispositioned 'use-as-ds'. The Raychem splices were not installed in
accardance with the Raychem instructions in that overlaps were less than the
required two inch minimum and bend radii were less than the required five
times the outside diameter. The PMR had been approved based on Wyle Nuclear
Environmental Qualification Test Report No. 17859-02P, Revision A. The Wyle
test report qualified seven Byron and Braidwood Generating Station specific
configurations and thirteen Zion Generating Station specific configuratjans
with overlaps as little as 1/2 inch and bend radii of 1.2 times the outside
diameter.
The PMR, the VR which documented the 38 splices and the Wyle test report were
reviewed. In addition, the Nuclear Plant Engineering (NPE) personnel who
conducted the engineering evaluation and the Instrument Maintenance (IM)
personnel who had participated in the original walkdevn of the splices were
interviewed. The following concerns were identified:
a. The PKR did not contain an evaluation or documentation which indicated
that the WCGS design LOCA environment is equivalent to or less than severe
than the design LOCA environment that was used as a basis for the Wyle
testing. Evaluation and documentatica of the LOCA conditions is required
to establish a basis for use of the Wyle test report at WCGS.
b. VR 4443-87 documented the recommended disposition of 'use-as-is' for the
38 splices. The WR listed the splices and stated that all splices, as a
group, had seal lengths of greater than 1/2 inch but less than two inches,
and that the minimum bend radius was less than five times the shrink tube
outtr diameter. The VR did not document the configuration of each
individual splice or provide measured bend radii or overlaps. The EER
disposition that accepted the splices for 'use-as-is,' based on the Wyle
test report, s*.ated that the splices with bend radii as lit'.le as 1.2
times the outside diameter of the splice were tested. It also <cated that
the tested splices had bend radii more severe than the splics.s identified
at VCGS. However, documentation that each splice has a bend radius
greater th:n the bend radius tested by Wyle (stated as 1.2 times the
outside diameter) was not available.
The Vyle test report covered tests of tventy Raychem splices with
different configurations, tubing sizes and wire types. Only one splice
tested was of a configuration similar to the 38 deficient splices at WCGS.
The SSOMI team considered that the confirmation of each of the deficient
splices at VCGS should be documented to confirm that the results of the
Wyle tests are applicable.
c. The Vyle test report documented that the Raychem tubing was bent while it
was heated. The VCGS splices were performed in accordance with vendor
instructions which allowed the splices to cool befote bending. Bending
the cooled Raychem tubing is less conservative because of the reduced
pliability of the tubing at lower temperatures.
.
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Page 37 of 70
April 28, 1988
l
During a previous NRC Environmental Qualification (EQ) team inspection,
questions were raised reearding the lack of documentation for sizes and
lengths of machine screva used in Raychem splices. The maximum working
di aeter of Raychem tubing would be exceeded if the machine screw used to
connect the terminal lugs were too long. Following the EQ inspection, an
Engineering Evaluation Request was initiated by the licensee to establish the
acceptance criteria for conducting field measurements of tubing diameter to
insure that maximum Raychem working diameters were not exceeded. At the time
of the SSOMI inspJction, WR 4943-87 and other similar WRs were in process to
, inspect all suspect splices. The SSOMI team concluded that the WR appeared to
adequately verify and correct Raychem problems associated with exceeding the
maximum working diameter, but did not add ess the concerns discusseo above
regarding the applicability of the Wyle test report. The failure to
adequately document and evaluate the eng4neering disposition of the
nenconforming splices is a weakness in the engineerin5 area.
GENERAL DISCUSSION OF FINDING:
a. The concern was that PMR 2329 did not contain an evaluation or
documentation to show that the parameters of Wyle test report No.
17859-02P enveloped the WCGS environmental conditions.
b. The NRC was concerned that Work Request (WR) #4443-87 gave a 'use-as-is'
disposition for 38 kaychem splices with seal lengths of greater than 1/2
inch but less than 2 inches and bend radii less than five times the splice
outer diameter without specific documentation of the configuration of each
splice.
c. The Raychem splice was bent while heated in the Wyle Labs test report
(17859-02P) versus bending while cool for the WCGS splices. The NRC
considers the bending of cooled splices to be less conservative.
RESPONSE TO THE FINDING:
a. PHR 2329 did not contain the evaluation of Wyle Test Report No. 17859-02P
because Environmental Qualification Work Packages (EQWP's), not MR's,
are used at WCGS to document environmental qualification analysis.
An applicability review of the test report was performed prior to the
release of the PMR as stated in the Engineering Disposition to WR i4443 87
which was attached to the PMR. However, this revies was not formally
documented prior to the release of the PMR and included in EQWP-E-01013.
The documented review is required to be included in the appropriate EQWP
by Nuclear Plant Engineering Procedure KPN-D-313.
b. Only two of the 38 splices had seal length less than two inches. WR
14214-87, which is referenced in VR #4443-87, documents the seal length
for each splice. Instru=entation and Controls personnel verified verbally
to Nuclear Plant Engineering (NPE) that the bend radii of the splices were
not less than 1.2 times the outside diameter of the splice, however, this
phone conversation was not documented. While documentation of the bend
radius of each splice should have been provided, the lack of documentation
would not impact the 'use-as-is' disposition. Confirmation that the bend
_ _ _ _ _ _ _ _ _ _ - _ _ - _ _
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Page 38 of 70
April 28, 1988
radii were greater than 1.2 times 0.D. allowed the use of only one test
report (No. 17859-02P) to address the deficiencies.
It should be noted that another Wyle Labs test report (No. 17859-02B),
which waa reviewed and determined applicable to WCGS, successfully tested
a Raychem splice which was bent back on itself with essentially zero bend
radius. The test parameters of this report bounds the WCGS conditions.
This report was subsequently included in the Equipment Qualification Work
Package.
c. The vendor irstructions state that the tubing is not to be flexed until
after cooling to the point it is comfortable to touch. This would prevent
thinning of the tubing at the point of bending. Since the splices tested
by Wyle were bent while heated, the testing indicates that acceptable
qualification exists even if thinning may have occurred. In addition, the
splice which was successfully tested with essentially zero bend radius in
Wyle test No. 17869-02B was bent while cooled.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN
Verbal information utilized for dispositions, will te subsequently documented
and included with the appropriate documents prior to formal closeout of the
document.
CONCLUSION:
l
a. While it is true that the evaluation is not in the PMR, the performance
and documentation of qualification test evaluations is addressed by NPE
procedures. The results of these evaluations are in the EQVP's and are
nt. required to be included in PHR's. This is not considered to be
a deficiency.
b. Subsequent to this disposition. It was decided that all 38 splices should
be replaced with splites completed strictly in accordance with the Raychem
installation instructions. This replacement has been completed.
The NRC concern is partially addressed in that all the specific splice
seal lengths were provided in WR #4214-87. While the bend radius for each
splice should have been provided, inclusion of this information would not
have changed the original 'use-as-is' disposition,
c. The concern regarding bending of the splices while heated or cooled is not
considered significant in t!at successful qualification tests have been
performed for splices bent both while cool and while heated.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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Page 39 of 70
April 28, 1988
3.1.2.6 PMR 1828: ESV BUILDING CABLE REPLACDfENT
IJUDING:
This PMR replaced cables routed to the Emeraency Service Water (ESW) building
based upon the need for additional circuits at the ESW structure and the
identification of several failures in existing cables. Cable failures were
discovered during the performance of surveillance testing in which circuit
breakers failed to trip open on a non safety related load shed signal during
Safety Injection actuation. Investigation by the licensee resulted in the
identification of grounded and open circuit conditions in a number of cables
which had been pulled through the duct bank system from the Main Power Block
to the ESW building. Subsequent evaluation of the failed : ables identified
damage in the form of cuts and nicks in the insulation and jackets of these
cables. This damage was assumed to hr.ve occurred during the initial cable
pull. Consequently, this PMR was issued to pull new cables to the ESW
building.
,
Although the licensee perforced an evaluation of the damaged cables, an
additional evaluation to determine the root cause of the failurcs in the
original safety related cables routed to the ESW building was not performed.
The SSOMI team noted that banding material had been found in a duct bank
associated with some of the damaged cables and was considered by the licensee
to be the cause of the failures to the cables in that duct bank. However, the
root cause for cable failures in redundant trains and cables associated with
other duct banks has not been determiaed. The SSOMI team was concerned that
the conditions associated with the original cable pulls were not evaluated to
provide assurance that the cable failures were not the result of a generic
condition.
GENERAL DISCUSSION OF FINDING:
The SSOHI team identified a concern with PMR 1828, ESW Building Cable
Replacement, that the root cause for control cable failures had not been
determined. The SSOMI team was concerned that an evaluation was not performed
to eliminate the possibility of a generic condition affecting the opposite
train.
RESPONSE TO THE FINDINGt
The original revision of PMR 1828 provided a design for replacement of control
cables in both safety related trains. After removal of the damaged train A
control cables information was available to justify revision of the PMR to
exclude the other train of control cables. The justification for concluding
i that the failures were not indicative of a generic condition involved the
following facets:
(1) During the design development of FMR 1828 detailed cable pulling
calculations were performed in order to add the maxinum number of
l spare control cables possible. These calculations represented a
l limiting case (more severe than the original design) which
established that the original ductbank design (e.g. distance between
manholes, slope of the ducts, etc.) provided for a safe pulling
l
t
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Page 40 of 70
April 28, 1988
length for the original control cable installed. Therefore, the
ductbank design was eliminated as a potential root cause for th6
control cabla failures.
(2) A review of the number of control cable failures and their physical
routing within the ductbank was accomplished. This review revealed
that seven conductors had failed in the A train and one conductor had
failed in the B train. In addition, the A train conductors had the
'
same physical routing within the ductbank.
(3) An evaluation of the damaged cables removed during the train A cable
pull revealed damage to the outer jackets as well as conductor
insulation damage at various locations. Based on discussions as well
as visual observations of the cable (exposed copper was not
corroded), some of the damage to the cable occurred during removal
- from the ductbank. However, some damage cccurred prior to removal
'
based en visual observation of copper corrosion found on the exposed
conductor (in one case the conductor had completely corroded away).
This damage is judsed to be the leading contributor to the control
cable failures that probably occurred during the initial
installation.
(4) The available spare control cables were assessed for future
contingencies. In order to maximize the available spare conductors,
auxiliary relays wcre added to train B control circuits to provide
4 two additional train B control conductors.
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(5) The fact that only one control cable has failed in train B provides
evidence that the contcol cables were not damar,ed during installation
as indicated by the large number of faili,res in train A. This
conclosion is based on the premise that cables that have a common
failure mode should have approxJmately the same averrge time to
failure under the same conditions. Therefore, if any other control
cables in train B are affected, additional failures in train B should
have been identified.
1
Based on these considerations,. adequate justification s;isted to craciude that
, the failure mechanisms were isolated to train /. only. Br.s ed on this
j conclusion. PHR 1828 was revised to eliminate ths train B control cable
i replacement.
CONCLUSION:
VCNOC believes that adequate justification exists to conclude that the control
cable failures were not indicative of a generic condition affecting the
opposite train. It is tras that the justification was not assembled as a part
of the subject FMR and, therefore, not readily available for the SSOMI team
involved with the installation and testing inspection.
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Page 41 of 70
April 28, 1988
3.1.2.7 CONTAINMENT PRESSURE TRANSMITTERS
FINDING:
During plant inspections associated with other modifications, it was noted
that the connection box cover for Containment Pressure Transmitter PT-934, was
missing one of two screws. Maintenance or modifications were not in progress
'
on the transmitters. A field inspection of the other pressure transmitters
identified the following discrepancies.
PT.934 - Missing 1 of 2 connection box screws.
PT-935 - No discrepancies noted.
PT-936 - Missing 1 of 2 connection box screws.
PT-937 - Missing 1 of 2 connection box screws.
PT-938 - No discrepancies noted.
PT-939 - Missing 1 of 2 connection box screws.
The licensee indicated that the missing cover screws may have been left out
during a Raychem splice inspection. These discrepancies indicated a lack of
attention to detail in maintenance and modification activities but were
considered to be minor in nature.
CENERAL DISCI)J' YON OF FINDING:
The inspection team found one of two connection box cover screws on several
of the containment pressure transmitters missing. Although the inspection
report admittoi this to be minor in nature, it concludes that the missing
screws indicate an overall lack of attention to detail in performing
maintenance or modifications.
RESPONSE TO THE FINDING:
Although the actual reason for the missing screws could not be determined, it
is most likely that at some time during construction, startup or commercial
operation the cover screws were lost. It is possible that because personnel
were aware that the covers servad no direct safety function such as
environmental sealing or steam impingement protection and because one screw
adequately holds the cover in place, efforts we-e not made to obtain
replacement screws.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN:
When Instrumentation and Controls was notified of the missing screws,
replacement screve were immediately obtained and installed. The SSOMI
Inspection report has been discussed in a monthly shop meeting with emphasis
placed en workmanship requiring attention to detail and has been routed as
required reading.
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Page 42 of 70
April 28, 1988
CONCLUSION:
The impact of the missing screws is considered minor in nature, however,
workmanship and attention to detail has been emphasized in monthly shop
meetings. No further specific action is considered necessary.
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April 28, 1988
3.1.2.9 TECIDTICAL SPECIFICATION TESTS
FINDING:
The SSOHI team monitored the performance of Technical Specification
Surveillance Tests (STS) STS IC-280A, ' Analog Channel QP Test Ctrl Rm
Detection Train A,' and STS IC-433, ' Channel Calibration HIS Post Accident
Monitoring N61,' to ensure that they were performed in accordance with the
requirements of the listed test procedures and were administratively
controlled by procedure ADM 02-300, ' Surveillance Testing.' STS IC-280A
verified the operability of the Chlorine Detection Control Room Ventilation
Isolation System and STS10-433 calibrated the Post Accident Monitoring
Huclear Instrumentation System (NIS).
The performance of STS IC-280A was in accordance with requirements. Test
personnel were knowledgeable and appeared qualified to accomplish test
objectives. However, several weaknesses were observed in the test
instructions of STS IC-433. A lack of detail in some sections of the
procedure resulted in confusion on the part of the Test Technician. For
l
example, a note to Section 6.3.1.3.1 incorrectly referenced ' sero power' as a
prerequisite for bypassing certain steps of the procedure. This note should
'
I have referenced a Nuclear Instrumentation System (NIS) Source Range level. In
I
addition. Sections 6.3.2.2.2 and 6.3.2.3.2.1 specified test equipment
connections which could not be accomplished without removal of the appropriate
solid state circuit card. The removal and reinstallation of the circuit card
and any subsequent requirement for equipment warm up were not detailed in the
, procedure. Consequently, interpretation on the part of test personnel was
( required in order to accomplish the test objectives. As a result of these
discrepancies, the test perfornance was suspended until the procedure was
revised.
The S50MI team was unable to determine the extent of this concern because of
the limited sample of tests and test procedures available for review. The
test personnel were knowledgeable and this test could have been accomplished
through application of the skills and experience which they possessed.
However, the SSOMI team was concerned that detailed and accurate test
instructions were not provided to ensure that test objectives and applicable
TS requirements are fulfilled in approved surveillance procedures.
GENERAL DISCUSSION OF FINDINO:
During the pe rf ormance of STS-IC-433 the inspector identified what he
considered several weaknesses in the test instructions. The term 'Zero
Power * vas considered in.dequate because nuclear instrumentation system
was not specifically mentioned as the source reading to determine 'Zero
Power". Additionally, two paragraphs identified test point connections
that required circuit card removal to gain access to them. The procedure
did not specify removal and reinstallation of the circuit card.
_ _ _ _ _ _ _ _ _ _ _ _ ____ ______
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April 28, 1988
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RESPONSE TO THE FINDING
The procedure was initially developed directly from instructions contained in
the controlled technjcal manual by personnel very familiar with the ,
equipment. The manual instructions assume that the performer has the drawings l
In the manual readily available. It is possible that when the procedure
was previously performed the technicians had the manual with them to aid in
physically locating specified test points.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN:
'
The test was suspended to allow the test performer tire to research and
change the procedure. Temporary procedure change (TPC) MA 87-481 was written
to clarify the steps in question. Follow.fng TFC approval the test was
satisfactorily completed. An ongoing review of procedures is providing a high
level of confidence that test objectives and Technical specifications are met.
CONCLUSION:
,
The inspection report states that 'The test personnel were knowledgeable and :
this test could have been accomplished through application of the skills and
experience which they possessed.' The actioria taken bf the test performera
when questions were encountered were proper. Thn test was stopped,
'
clarification was obtained, and the procedure was enhanced prior to
continuing. This is considered to be a normal par *. of improving procedure t
instructions as a result of experience. The weaknesses found in STS10-433 '
did not compromise the valid performance of the test. No further action is
considered necessary.
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April 28, 1988
3.2.2.1 TEMPORARY MODIFICATION TMO 87-120 CK: CidhPED OPEN CRJIS D3MPFR
FINDING:
This modification clamped the Train A Control Room Emergency Ventilation
System supply damper in the open, actuated position in response to several
failures of the actuating linkage'. The SSOHI team determined that the
licensee had not adequately determined whether the system remained operable
and capable of pressurizing the centrol roem as required by TS 3/4.7.6.
TS 3/4.7.6, ' Plant Systems - Control Room Emergency Ventilation System,'
requires that the Control Room Ventilation Isolation System (CRVIS) be
operable in all modes and capable of pressurizing the control room to 0.25
inches of water (gauge) upon detection of radiation or toxic gas in the air
intakes. In addition, Section 3.1 of the USAR and 10 CFR 50, Appendix A.
require that safety systems be designed tc automatically protect againct
single failures of passive and active components. The system configuration
entsblished by the temporary modification provided a bypass path for supply
air to the centrol room if the Train A fan failed to automatically start on a
CRVIS initiation signal. Upon CRVIS actuation, the Traic B CRVIS fan would
start and discharge air to the fan discharge plenum, however the clamped open
Train A damper would permit backflow through the idle Train A CRVIS fan and
bypass the control room. In this configuration, the CRVIS would not be able
to provide the required positive pressure in the control room, assuming the
single failure of Train A CRVIS fan. Additionally, the licensee had not
performed a calculation or a functional test to demonstrate tha ability of the
Train B CRVIS to maintain the tequired control room pressure in this degraded
mode.
Additional concerns associated with this temporary mocification were noted as
follows: -
I
a. The licensee failed to recognize the requirement for the safety system to !
'
remain operable with a single failure without operator action. In order
to ensure the operability of the CRVIS, the temporary modification
required an operator to remove the clamp from the failed CRVIS damper.
l
Although these actions would pe rmit Train A to be isolated upon fan
i failure and therefore satisfy the single failure design of the system, the
l need for operator action to meet the single failure design of a safety
system does not conform to the requirements of 10 CFR 50, Appendix A.
b. Even though the operator actions did not meet single failure design
requirements, the specified operator actions would not be sufficiently
responsive when considering the design requirement of the CRVIS to
maintain a positive prcssure in the control room in the event of radiation
or gas in the air intakes. The emergency instructions require the
operator to don a self-contained breathing apparatus, go to the damper,
climb a ladder to the blocked damper, remove the clamp and manually ensure
that the damper has closed. Furthermore, the SSOHI inspector noted that
these instructions would have been difficult to implement in an emergency
because they were not found in the Alarm Response Procedure as normally
expected, but were included as an addendum to the temporary modification.
_ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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Page 46 of 70
April 28, 1988
c. Despite having performed repeated Safety Evaluations on this and other
CRVIS dampers which were sLailarly clamped open, the licensee failed to
recognize that additional testing or calculations vera necessary to verify
that the system remained operable with the temporary modification
implemented.
d. Appropriate corrective action in preventing rupeated damper fs' lures was
not taken Five CRVIS damper failures were experienced during the period
of June 25 to November 3, 1987. As a result, replacement operating gear
to repair the broken train A CRVIS supply damper was not available.
Appropriate corrective actions require a consideration of past defects and
noncompliances in basic components important to safety, VCGS Procedure
'
ADH 01-033, ' Instructions Describing Reportability Review and
Documentation of Licensee Event Reports and Defect Deficiencies,' Rev. 16
specified evaluation and reporting requirements pursuant to 10 CFR 21.
The licensee had not identified the above failures as potentially
reportable nor evaluated the failures per the above procedure.
GENERAL DISCUSSION OF FINDING:
a..b..c.
The SSCHI team stated that the 10CFR50.59 Safety Evaluation did not
adequately de te rmine if the CRVIS damper blocked in its safeguards
position by the subject modification impaired the operability of the
CRVIS function in fulfillment of the systems safety function.
Additionally, they stated that the temporary change introduced a stated
compromise of the single failure criteria which is not in accordance
with the general design criteria for nuclear power plants.
The Technical Specifications require two independent Control Room
Emergency Ventilation Systems to be operable in all HODES. The ACTION
statement during HODES 5 and 6 states that with both Control Room
E=ergency Ventilation Systems inoperable suspend all operations
involving core alterations or positive reactivity changes.
RESPONSE TO THE FINDING:
a. b..c.
In the USAR Chapter 15 analysis, the bounding worst single failure has
been ascertained to be the failure of the filtration fan in one of the two
filtration system trains. Operator action is required to isolate the
train with the failed filtration fan. At the same time, one train of the
control room pressurization system will also be isolated. Prior to
i s e'.a tion , a potential pathway exists allowing air from the control
building to enter the control room, bypassing the control room filtration
filters. After isolation, one control room pressurization fan and one
'
control room filtration fan operate for the duration of the accident. No
bypass pathways then exist for unfiltered air to enter the control room.
.
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Page 47 of 70
April 28, 1988
Blocking the subject damper open in its safeguards position did not put
the system in a condition outside of previous analysis nor create a
different type of accident nor increase the probability or passibility
of a malfunction from previous analysis. Safety Evaluation Three
of USAR Section 6.4.4 for the Control Room Ventilation System states that
"no single failure will coepromise the systems safety functions.' In
view of the inherent design aspects of the system, the denial of the
damper to go closed upon occurrence of an active failure does not put
the system outside of previous analyzed system failures since other
limiting failures exist.
The subject dampers are closed by their motor operators when the air
conditioning units fan motor is deenergized. They do not have a spring
returnt hence, the damper failure mode is 'as is'. Clamping these
dcmpers open would place them in their safeguards position where they
could fulfill their intended CRVIS safety function. A single failure per
10CFR$0 Appendix A means an occurrence which results in the loss of
i
the capability of a component to perform its intended safety function. -
Clamping the damper (s) open does not compromise the CRVIS safety
function. The designated operator action was not essential, but wonid
have placed the system in a censervative tested configuration.
d. Defect Deficiency Report 87-122 was initiated on November 17, 1987, as a
'
result the SSOMI team concern about performing a 10 CFR Part 21
reportability evaluation of mechanical problems associated with damper
GK-D-084 and its actuator GK-H2-40A. A review of the maintenance work
requests for dampers / actuators GK-D-080/GK-H2-29A, GK-D-081/GK-HZ.0290
GK-D-084/GK-HZ-40A, GK-D-085/GK-H2-40B was conducted. *his review
identified that the actuators wr:e reworked during 1984 with some
machining being conducted on the cmaplings. In 1085, CK-HZ-40A ard B were
replaced due to the actuators being jammed. In 1987, failures of
GK-H2-29A. 40A and 40B, occuteed which required replacecent of the
actuators. Discussions with a vendor representative indicated that these
failures could be attributed to a misalignment of the coupling and the
saddle because of previous maintenance and the method of clamping the
dampers when blocking them open or closed. The vendor has subsequently
provided appropriate tolerances and coupling clearances to ensure proper
coupling alignment. WCNOC concluded that this deficiency was not
reportable pursuant to 10 CFR Part 21.
The appropriate tolerances and coupling clearances were obtained and an
alignment jig was fabricated to assist in alignment of the saddle and the
coupling. Three of the above dampers were realigned. The fourth danper
was inspected and determined to be within the tolerances provided.
CONCLUSI0?h
a..b..c.
The 10CFR50.59 Safety Evaluation was not deficient in its analysis of the
subj2ct change. The condition described in thu evaluation was bounded by
the analysis presented in Chapter 15 of the Updated Safety Analysis
Report. Damper replacement parts were installed and the CRVIS system was
restored on November 26. 1987.
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Cection II
Page 48 of 70
April 28, 1988
d. As discussed above, VCNOC believes the cause of the repetitive damper
problems during 1987 have been identified and corrected
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April 28, 1988 i
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3 3.2.2.2 PMR 2106: PRESSURIIEE SPRAY VALVE BONNET REFaIR
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FINDING:
- ?
This PHR involved the installation of gland plugs or set screws in four j
'
injection holes as permanent modification to the Pressuriser Spray Valve. The ;
four injection holes were drilled in the bonnet of the Pressuriser Spray Valve ;
! in order to provide an injection path for a liquid sealant (Furmanite) which ;
] was used to repair the body-to-bonnet steam leak. j
i
i The engineering disposition of Engineering Evaluation Request (EER) 85-XX-37,
'
i which requested that NPE approve the use of certain sesling corgounds in
temporary repair procedures at the discretion of the Maintenance
i Superintendent, previously approved the repair of leaking mechanical joints in
- piping components such as flanges, valve packing, and bolted valve bonnets by i
l the use of sealant injection, provided that the sealant chemistry I
"
requirements, application procedure, and system limitations specified in the ,
engineering disposition were followed. The disposition approved the generic l
!
use of liquii sealing compounds such as Furmanite and authorized drilling
i holes into pressure tcta N ng parts of ASME Code Class I components in order
l to facilitate the repair process.
!
WR 00101-87 and associated revisions, the vendor work request and procedure, !
- the engineering disposition to PMR 2106 and other associated documentation !
l vhich were a part of the work package were reviewed. The following concerns i
were identified:
(
) a. Section 3.2, ' Bolted Connection,' of the application procedure, which was (
i detailed in the engineering disposition to EER 85-XX-37 and used to repair ;
- the Pressurizer Spray Valve, was act verified to meet the ASME Code t
j requirements. The Justification of Engineering Resolution for EER [
i 85-XX-37 indicated that the disposition ensured that Code requirements I
i were not violated. NPE subsequently indicated that the requirements cited l
l in the Justification of Engineering Resolution were obtained from the !
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Vendor and not from the ASME Code as indicated. When requested by the [
SSOHI team, the licensee could not demonstrate that the tequireswnts !
j provided by the vendor met the Code requirements. (
'
)
b. The SSCHI team considered that the 10 CFR 50.59 Safety Evaluation of EER l
!' 85-XX-37 was inadequate, in that it did not identify that drilling holes ;
- into pressure retaining parts of ASME Class I components involved changes
' the facility. Although the Safety evaluation performed for VR
to !
00101-87 Rev. 3, correctly determined that the holes drilled in the f
] pressurized bonnet were a change to the facility, the explanation given i
, for determining whether this instance involved an unreviewed safety
j question was inadequate because it failed to address the safety ,
} significance of the modification to the Pressuriser Spray Valve using EER
i 85-XX-37.
i
! c. The engineering disposition to EER 85-XX-37 required the sealing compound
- injection pressure to be calculated so as to limit the injection pressure f
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and thereby limit the stress on the flange bolts. Documentation of these j
calculations was not available. Additionally. the maximum pressure used ,
to inject the sealant compound in the body-to-bonnet area of the (
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Page 50 of 70
April 28, 1988
Pressurizer Spray Valve was not recorded. Because the maximum pressure
was not calculated and records did not exist to demonstrate the pressure
used, the flange bolt stresses could have been exceeded for the
Pressurizer Spray Valve during the injection process.
d. A Safety Evaluation was not performed for the vendor work procedure to
repair the Pressurizer Spray Valve by sealant injection as required. ADH
07-100 requires that a 10 CFR $0.5.' Safety Evaluation be completed for all
procedures reviewed by the Plant Safety Review Committee (PSRC),
GENERAL DISCUSSION OF FINDING:
a. During the review of PMR 2106, the SSOHI team determined that the
Engineering Disposition to EER 85-XX-37 was not verified to meet the ASME
Code requirements.
b. During the review of PMR 2106, the SSOHI team determined that the Safety
Evaluation associated with EER 85-XX-37 was inadequate in that it did not
identify that drilling holes into pressure retaining parts of ASME Class 1
components involved changes in the facility. Also, the SSOHI team
determined that the Safety Evaluation performed for WR 00101-87, Rev. 3
was inadequate in that it failed to address the safety significance of the
modification to the Pressurizer Spray Valve using EER 85-XX-37.
c.,d.
The repair of the pressurizer spray valve (PMR 2106) was a SSOHI team
audit item. The content of the PMR was a repair instruction on holes
drilled into the packing box of the pressurizer spray valve to stop a
body-to-bonnet leak by the use of '?urmanite'. The PMR issued was not
implemented and was cancel!.ed. A replacement of the valve packing box
was performed instead. .
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During the investigation, two concerns were expressed in the peocedures :
for allowing Furmanite to inject the valve.
1) Documenting the injection pressure of the Furmanite compound.
2) No Safety Evaluation was performed on the Vendor Procedure
used to implement the vendor work plan.
RESPONSE TO THE FINDILQ1
a. The disposition to EER 85-XX-37 provided generic guidelines to facilitate
temporary on-line sealing of leaking components. This disposition was
used for the temporary on-line sealing of the packing box flange on valve
BB-PCV-455B and applied the guidelines set forth in Section 3.2, ' Bolted
i Connection *, of the subject disposition.
The disposition to EER 85-XX-37 also identified systems which come into
contact with p-imary fluid and required approval from WCNOC Management i
prior to performing sealant injection on these systems. However, the
disposition does not clearly identify the Code (s) to which the
requirements for drilling holes into ' Bolted Connections * comply with and
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Page 51 of 70
April 28, 1988
did not include provisions to verify code compliance for specific
components to which these generic guidelines would be applied.
Work Request 700101-87, Rev. 3 requested an engineering evaluation of a
proposed permanent repair to the temporary injection holes. The
engineering disposition to VR #00101-87 Rev. 3 required that the
injection holes made on valve BB-PCV-455B during the temporary on-line
sealing process be permanently weld repaired in accordance with the
Section XI repair and replacement program.
b. 1. The Safety Evaluation issued with EER 85-XX-37 did not identify a
change in the facility as described in the safety analysis report. As
indicated on the Safety Evaluation, this evaluation ' addresses only
the suitability of the sealant materials, the injection procedures and
the effect of the procedure on thi sealed components'. As previously
discussed in the response to SSOMI item 3.2.2.2.a. the disposition to
EER 85-XX-37 provided generic guidelines to facilitate temporary
on-line sealing of leaking components and did not apply to any
specific component.
2. Vork Request 00101-87, Rev. 3, requested an engineering evaluation of
a proposed permanent repair to valve BB-PCV-455B which had previously
been sealed on-line by Furr.anite. The proposed repair involved using
gland plugo or cet screws to seal the injection holes made during the
on-line sealing process.
After review of the specific request to provide a pormanent repair
using gland plugs or set screws. Engineering determined that the
injection holes would need to be volded pcr ASMI Section XI
Repair / Replacement Program. The engineering disposition and
associated Safety Evaluations performed address only the specific
repair request in WR 00101-87, Rev. 3. Therefore, the Safety
Evaluation provided for the disposition to WR 00101-87 Rev. 3, which,
as discussed above, has as its scope only the permanent repair of the
temporary injection holes, and is considered adequate within the
confines of the scope of the final permanent repair. The subject
safety Evaluation was not intended to address the alteration
(temporary) made to the pressurizer spray valve to facilitate on line
sealing.
c. An Engineering Evaluation Request, (EER 85-XX-37), disposition was
used in preparing and planning the injection of the pressurizer spray
valve. The disposition gave generic criteria to be met when using
Furmanite to inject a component to stop leakage. The disposition
required that the injection pressure should be limited suen that when
the injection pressure times the beating area of the sealant plus the
system operating pressure times the area subjected to system pressure
shall not exceed 1.1 times the flange bolt allowable stress. This
formula is used to figure injection pressures. This value has been
recalculated and the injection pressure specified (4500 psi) was a
conservative number.
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April 28, 1988
A second part of this concern was that the injection pressure was not
recorded. There was no requirement in the work package Instruction
Checklist to record the injection pressure.
d. At the time of the injection of the valve, there were no I
procedural requirements to process a Safety Evaluation (10 CTR 50.59) for
' Vendor Procedures'. At this time there are no procedural requirements i
to process a safety Evaluation for ' Vendor Procedures'. Howeywr,
PSRC review of these procedures is required. '
} ACTIONS VMICH HAVE BEEN OR VILL BE TAKEN l
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a. The guidelines provided in the disposition to EER 85-XX-37 for temporary
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! on line sealing were intended to be generic guidelir.es only and did not
'
apply to any specific component (s). Th!s disposition will be withdrawn '
and modified to mandate provisions for verification of Code compliance }
'
! prior to applying the generic guidelines for temporary on line sealing of
specific components. This corrective action shall be accomplished prior ;
to June 1. 1988. !
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b. As indicated in the response to SSOMI item 3.2.2.2.a. EER 85-XX-37 is l
being withdrawn and will be modified to mandate provisions for Code
j compliance verification prior to performing any temporary on-line sealing *
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of specific components. The assoc!sted Safety Evaluation will be provided
with the modified EER dispositi?n. ;
CONCLUSTON: l
f i
s. VCNOC agrees with the SSOMI teams observation that the guidelines outlined l
l in the dispositien to EER 35-XX-37 were not verified to meet ASHI Codo
- requirements for all components. t
r
As indicated above, these generic guidelines were not applicable to i
specific components. Therefore, the previous disposition is being !
!
withdrawn for revision to indicate that application of the guidelinis
'
needs to be verified for compliance with the applicable design Code of the .
j specific application prior to implementation. !
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l It should be noted that the ASHE code neither allows nor disallows
temporary drilling of components for the purpose of on-line sealing.
Verification of Code Compliance in these cases needs to consider the ,
effect of this type of temporary condition, i.e. drilling holes into I
component parts, on the original design (structural) basis of the subject ,
component,
f
r
In a letter dated January 25, 1988, from L. C. Shao. Director Division of
Engineering & Systems Technology. USKRC. to J. L. Milhoan. Director <
Division of Reactor Safety. Region IV. USNRC. concerning the use of h
sealing fluids on primary pressure boundary ccaponents the NRC evaluated !
the concern identified at WCGS. The NRC stated that. 'In conclusion. l
temporary on-line leak sealing of components is an acceptabic alternative [
to an unscheduled plant shutdown to effect a permanent repair provided !
!
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1
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, Page 53 of 70
April 28, 1988
i
that the applicable guidelines are met and the Quality t.ssurance measures ,
are followed for proper selection, procursuent end opplication of
sealants'.
h. As discussed above, VCNOC ecknowledges the SSOMI team concern regarding
the safety Evaluation associated with EER 85-XX-37. ,
i
The SSOHI team concern regarding the adequacy of the Safety 5 valuation i
provided with work request WR 00101-87 Rev. 3 is not consiuered to be a
a deficiency. As discussed above the subject work request and associsted
safety evaluation was limited in scope to only address a final permanent
repair.
c.,d.
,
Although not documented, the injection pressure specified 4500 psi, was ,
- proven to be a conservative number. Also, there was no requirement to
doc'iment the actual injection pressure but QC accepted the pressure that
was used. Baced on these two facts, no corrective action is necessary
for item 4.2.2.3.c.
l
l A Safety Evaluation is presently not required for Vendor Procedures. The
Work Controls Task Force is reviewing the Vendor Vork Plan Procedure (ADH
i 01-043). This procedure will be revised by August 31, 1988, to require l
t
safety evaluations to b) performed for vendor procedures. Due to the
i procedural requirements and actions being taken, no further corrective
! action is required.
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Page 54 of 70
April 28, 1988
3.2.2.3 PMW j084: CCV PIPE VALL THINNING
,
FINDING:
This PMR involved application of a weld overlay on a Component Cooling Vater
(CCV) line servicing the Train A Residual Heat Removal (RHR) Heat Exchanger in
order to repair a pipe section downstream of Valve EJ-V033. The licensee's
ultrasonic examinction of the piping section determined that the pipe section
was below minimum will thickness. Although subsequent ultrasonic ex4minations
dete rmined that these results were erroneous because laminar inclusions
(acceptable conditions), rather than the wall inner diameter, were being
identified, the SSOMI tuam identified the following concerns:
a. The licensee did not declare Train A of the CCV and RHR systems inoperable
per TS after identifying that the piping was below minimum wall thickness.
The licensee subsequently issued a guidance memorandum on July 29, 1987,
directing the plant operators to consider system as inoperable if
requirements for minimum piping wall thickness were violated. The general
matter of the licensee's handling of these and other similar operability
matters was subject of an NRC:NRR-licensee meeting in NRC headquarters on
November 17, 1987.
b. The riping was repaired without being isolated and drained of water, even
though the test results showed wall thinning down to nearly 1/16 inch
(about 22 percent nominal). Although Velding Procedures WPS1-0000,
'ASME/ ANSI General Requirements,' Rev. 2, permitted welding under these
i
conditions, the SSOMI team considered that the procedure represented a l
high risk of wall burn through, threatened system pressure boundary
integrity, and therefore represented a unconservative repair procedure.
c. Major changes in the work instructions for veld overlay repairs on the
EJ-V033 piping were implemented by Revision 2 to VR 0702-87 but were nct
incorporated into the revised ASME Section XI work instructiont 4-
required by Section 9.3.6.1 uf ACM 01-036, 'VCGS ASME Section XI Repair
and Replacement Prograv.' Rev. 2. ADM 01-036 required that work packages
contain complete and concise work instructions to accomplish repairs and .
provided guidance for content. Revision 2 to the VR fmplemented changes l
in the basic repair procedure and included requirements for in-service !
leak testing and radiography. The existing work instruction was annotated ,
to delete all existing steps by Revision 2, but replacement work steps I
were not provided. Additionally, the repairs were compiled without craft
or QC signoff of the revised work instructions.
d. The post modification leak testing of the piping was not accomplished as
rsquired by procedure until two months following completion of the work. !
e. During the review of this FMR, the SSOMI team also noted that ASME
required radiography was incorrectly deferred by the engineering
disposition of Corrective Work Request (CVR) 0702-87, Rev. 1, for about
six months. 10 CFR 50.55a(g)(5)(iii) requires NRC notification when
conf o rmance with certain code requirements is impractical. The licensee
did not initially notify the NRC when the radiography was deferred.
1
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Page 55 of 70
April 28, 1988
Following identification of similar oversights by the NRC Resident
Inspectors, the licensee submitted a Code Relief Request for the
radiography of PHR 2084 repairs on August 24, 1987.
GENERAL DISCUSSION OF FINDING:
a.
The NRC states that at the time the ultrasonic testing determined that
there was a below minimum wall condition on a pipe section downstream of
valve EJ.V033, plant operators should have declared Train A of the CCW and
RER systems inoperable. VCNOC did not initially declare Train A of the
CCW and RHR systems inoperable, since when it was initially determined
that the CCW and RHR piping was below the code mininum wall thickness
allowed for new pipe, the Plant Staff was not aware that this condition
represented a potential noncompliance that needed to be expeditiously
i evaluated by Engineering to determine whether or not the as-found pipe
1
thickness was sufficient to maintain maximum design basis stress below the
q code allowable stresses.
b. The piping section. SA-106Gr8 Carbon Steel Pipe. 0.375' nominal wall
- thickness, was repaired utilizint an external weld overlay which extended
i around the entire circumference of the pipe. This weld repair was
j performed without the piping section being drained of water, even though
- the ultrasonic examination indicated that the piping had localized areas
] of wall thinning as thin as .086*. Although the applicable velding
procedures pe rmitted welding under these conditions, the SSCHI team
j considered that the procedure represented a high risk of wall burn
through, tarentened systen pressure boundary inttausty, and therefore
'
represented a unconservative repair procedure,
c. Revision 2 to Vork Request 00702-87 deleted all previous work
instructions, implemented changes to the basic repair procedure, includen
requirements for inservice leak testing, and deferred the required
radiographic examination until the next refueling outage. Complete and
concise work instructions were not developed and incorporated into the
revised ASHI Section XI work instructions as required by the applicable
V7NOC procedure. Subsequently the repair was completed without craft
signoffs of the revised work instructions.
!
d. The required post modification leak testing of the piping was not
accomplished until two months following completion of the work,
e. Because the intent of the veld overlay was to re?torv the nominal pipe
wall thickness to .375 inches and this repsir exceeded the lessor of 3/8
inch or lot of section vall thickness, radiograph = of the repaired area in
accordance with the ASHI BLPV Code. Section '; ;. Subsection ND was
required. However, further review of the repair process revealed that
1. the area of repair would contain an irregular surface on the
interior of the pipe due to postulated erosion.
2. the repair was to be conducted with the pipe filled with water.
These two factors were judged to take examination by the radiography
method difficult to interpret with meaningful results because of the
m ,
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Page 56 of 70
April 28, 1988
d
irregular surface and that the water would induce diminished sensitivity.
- In lieu of radiography, Engineering determined that surface examination of !
'
each veld deposit layer and adjacent heat affected sono by the liquid
penetrant or magnetic particle method would provide adequate assurance of
the suitability of service by the repair weldment until the Code required <
,
examination or suitable raterial replacement could be performed, !
RESPONSE TO THE FINDING: !
a r
1 a. When it was initially determined that the CCV and RHR piping was below
the code minimum wall thickness allowed for new pipe, the Plant Staff was
'
not aware that this condition represented a potential noncompliance that
needed t.o be evaluated by Engineering to determine whether or not the
'
as-found pipe thickness was sufficient to maintain maximum design basis
stress below the code allowable stresses. Therefore, the time between
] initially discovery and subsequent declaration of the EJ piping as
inoperable was inappropriately long.
i
j Although the November 17, 1987, meeting discussed in the finding is not a
j major issue for this item, it should be noted that the meeting was held at
a the request of VCNOC and the primary subject of the nesting was the VCHOC
pipe wall u.spection ;,rogra= and the results obtained to that date.
]
] b. VCNOC personnel considered the following factors whon developing this ,
'
repair procedure and concluded that this repair could be performed with an '
acceptable level of risk.
1) Pressure / temperature of portion of system being repaired. This !
'
a portion o: the CCV/RHR .ystem had been removed frem service and
! allowed to cool ts ambient temperature. The system head i
- pressure, not system operating pressure, was present during the ,
j repair operation.
{
l 2) To minimize the possibility of wall burn through, the first veld
layer was deposited utilizing the Gas Tungsten Arc Velding i
- process, maintaining as low amperage as possible, while remaining '
- within the Velding Precedure Specification limitations, to localize
1
and reduce heat input. Additional weld metal was deposited utilizing
the Shielded Metal Arc Velding process, increasing amperage and/or
electrode diameter with subsequent layers. ;
) 3) Previous experience of WCNOC personnel had been that had the velder
' burned through* the pipe wall it would create minor leakage, and ;
'
j not a serioue pipe failure.
i
. 4) VCNOC personnel performing the repair, were in constant contact
2
with the control room to initiate system isolation and drain down
,
if the welder ' burned through' the pipe. ,
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Page 57 of 70
April 23, 1988
i c. The applicable procedures for work requests and ASME Section XI Packages
4 contain different requirements for the devel',,pment and revision of work
instructions. Personnel failed to follow correct procedural
requirements for development and revision of the ASME Section XI Package
work instructions. per ADM 01 036.
d. het modification testing for this repair consisted of an ultrasonic
thickness examination, radiogrisphic examination and a leak test at
normal operating temperature ar.d pressure. However, due to the assumed
,
internal damage to the pipe from cavitation erosion, it was determined
'
that obtaining code acceptable radiographs, and their subsequent
interpretation, would be extremely difficult, if not impossible. Based
on this assumption, the radiographic examination was deferred until the
next refueling outage.
The work instructions for post modifiestion testing did not clearly
define the timeliness of the required testing. Subsequently, upon
completion of the ultrasor.ic thickness examinations the work package was
- incorrectly placed in a ' hold' file for completion of testing during an
4
upcoming refueling outage prior to performing the required leak testing.
e. The reason for deferring that radiographic examination without prior NRC
notification was a failure to recognize the applicability of 10 CFR
I 50.55a(g)(5)(iii) to post maintenance testing. The requirements were
interpreted to be applicable only to inservice testing and not post
j maintenance testing.
l ACTIONS VHICH HAVE BEEN OR VILL BE TAKENt
a. Procedure requirements ensure that engineering is promptly notified of
wall thinnir g concerns, and that engineering evaluations are completed
j promptly to support operability determinations. These procedures will
, minimize the time period for identifying equipment which is in an
- inoperable condition.
c. WCNOC Maintenance / Modification personnel, are developing a standardized
, work package preparation program which will place all work instructions
in a word processing program for producing step by step work instructions
on a standardized format. This program will be developed and
- implemented by August 31, 1988.
'
d. The required post modification leak test has been performed.
'
.
Maintenance Engineers have been cautioned to follow up with tiecly review
and completion of NDE requirements and subsequent post modification tests.
e. Upon notification from the NRC that deferring post maintenance testirg
seguirements of AEME Ccde Class 1, 2, and 3 components was governed by the
requirements of 10 CFR 50.55a(g)(5)(iii). VCNOC requested and received, on
June 23, 1987, temporary relief from ASME Section XI in order to defer the
radiography required by the Code. On June 30, 1997. (not August 24. 1987
as stated in the report) a formal request for relief alonr. with the
Technical Justification for the pipe section downstream of valve EJ-V033
,
was submitted to the NRC.
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Page 58 of 70
April 28. 1988
l
CONCLUSION:
<
a. Subsequent to the determination that the EJ piping could potentia 11v
exceed Code allowable stress for a worst caso design basis event, it was
declared inoperable. The timeliness in requesting the evaluation and
making that determination was inappropriately long. Procedure
requirements ensure that engineering is promptly notified of wall thinning
] concerns, and that engineering evaluations are completed promptly to
support operability determinations. These procedures will minimits the
'
, time period for identifying equipment which is in an inoperable condition.
b. In conclusion. VCNOC personnel determined that performing this weld
l repair with ' stagnant' water in the system could be satisfactorily
- accomplished without putting the system or plant in jeopardy,
c. The completion of the standardized work package preparation program w!11
1 resolve this concern.
!
d. Typically the required post modification testing is performed as
soon as possible upon completion of work, therefore timeliness of
testing is not normally specified. Eovever, in this case where a
.
'
deferment of the radiographic examination was being performed, the leak
test should have been specified to be performed when the system was
- returned to normal operating temperature and pressure.
J
Clearly, deferment of a required post modification radiographic
j examination is an unusual deviation from normal operating procedures. In
- future instances when requirements are deferred, the timeliness of all
J testing will be clearly specified in the work instructions.
e. At the time of the deferment of the radiography for piping downstream of
valve EJ.V033. VCNOC did not recognize the requirement of 10 CTR 50.55a to
notify the 4mmission for this case. Since VCN0C is now aware of this
]
requirec*et, the Commission is being notified of cases in which post
j maintenance testing for ASMI components is going to be deferred.
4
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Page 39 of 70
April 28, 1988
3.2.2.4 PMR 2116: VAT,VES EF-V090. EF-V058. EF-ifV47 AND EF-ifV48 HARD
SURFACIPO
FINDING:
This PHR involved the final repairs of Essential Service Water (ESV) system
piping, including EF.V090 piping downstream of Valve EF-V058 on the opposite
train. Additionally, this modification involved replacement of a carbon steel
24' X 16' bell reducer with a stainless steel replacement more resistant tc
erosion and corrosion. Adjacent piping was also hard surfaced with either
stainless steel or stellite veld overlays. The PHR, associated VR packages
and in progress welding and fitup of a new piping bell reducer at EF-Vn58 were
reviewed. On November 12, 1987, during the $50HI inspection, work on the
above VRs ano all safety related pipe fitting and walding activity conducted
by the Haintenance Department were suspended by QA Work Hold Agreement 123.
The Work Hold Agreement, issued jointly by the QA and Maintenance Departments,
cited for fourteen Conditions Adverse to Quality involving PHR 2116 as ths
basis for the work suspension. These included improper piping cutouts,
marginal or inadequate pipit 4g fitups, failure to temporarily cupport piping
for spool remeval, out of tolerance spool fabrication, bypassed QC hold
points, improper veld buildups and overlays, and others. This work hold
followed a previous QC requested work stoppage.
Maintenance and QC Department management indicated that the problems
associated with PHR 2216 were caused by the Maintenance Department's lack of
experience in major pipe fitting nodifications. Previously, such vork was
perf o rmed by contractors under the direction of the Facilities and
Hodifications (F&M) Department. This sedification was transferred to FEH on
November 13, 1987, and work resumed following review and revision of work
,
instructions on November 14, 1987.
No concerns were identified with respect to this work. However, the SSOHI
team's review of testing requirements identified that the hydrostatic test
instructions for replacement of ESV piping downstream of Valve EF-V58, did not
consider possible overpressurlastion of adjacent systems, the testing
pressurized a portion of the ESV system to 220 psig and required a test relief
valve set at 239 psig. The procedure provided a single valve isolation for
thirteen heat exchangers served by the piping. No provisions were included to
ensure that the adjacent components were aligned such that test boundary valve
leekage will be vented to atmosphere or the untested portion of the system.
The SSCHI team was concerned that the test boundary valve leakage without
component protection could result in pressurisation of the heat exchangers in
excess of the pressures allowable under ASHE Section XI.
CENERAL DISCUSSION OF FINDING:
The SSCHI team finding concerning the Hydrostatic Test performed downstream
of valve EF.V038 per Vork Request $2931 87 is outlined in 3 items:
1) Instructions issued with the test package did not consider the
possibility of overpressurizing adjacent ASHE systems.
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Page 60 of 70
April 28, 1988
2) The valve lineup for the test provided only single valve isolation
for thirteen ASMI heat exchangers. Test instructions did not provide a
means of venting possible leakage past single isolation boundary
valves to atmosphere or to the untested portion of the system.
3) Soundary valve leakage may have subjected several ASME heat exchangers
to pressures er.ceeding ASME Sectiot. XI allowances.
RFSPONSE TO THE FINDING:
Subsequent to ths finding. F.evision 5 to Vork Request 2931 47 added several
open valves to the lineup to permit venting boundary valve leakage into the
untested portion of the EF System.
Valves ET.V33? and EF.V227 open to the atmosphere, provided overpressure
protection to heat exchangers in some adjacent systems as follows:
SGL11A was isolated from the bydrostatic test by boundary valve EF.V057.
On the inlet side of this heat exchanger, valve EF.V056 was open with
valve EF.V227 vented to atmosphere.
SGK04A was isolated from the hydrostatic test by boundary valve EF.V040.
On the inlet side valve EF.V039 was open with valve EF.V227 vented to
atmosphere.
SGG04A was isoleted from the hydrostrtic test by boundary valve EF.V147.
On the inlet side of this unit. valve EF.V146 was open and EF.V227 vented
to atmosphere.
SGL15A was isolated from the hydrostatic test by valve EF.V042. On
the vs.it inlet side, valve ET.V041 was open. Valve ET.V227 was vented to
the atmosphere.
SGF02A was ivolated frem the hydrostatic test by valve ET.YO48. On its
inlet side, valve EF.V047 was open with ET.V227 vented to the atmosphere.
SGL12A was isolated from the hydrostatic test by valve EF.V030. i
Upstream from this unit valve EF.V029 was open with EF.V227 vented to the
atmosphere.
SGLO9A was isolated from the hydrostatic test by valve EF.V033. On the
inlet side. Valve EF.V032 was open, and EF.V227 vented to atmosphere.
SGL13A was isolated from the hydrostatic test by valve ET.V036. On the
inlet side of this unit. valve ET.V035 was open. ET.V227 vented to
accosphere.
SGL10A was isolated from the hydrostatic test by valve EF.V038. Upstream.
Valve EF.V037 was open with valve EF.V227 vented to atmosphere.
Clearance Order 87 1228.EF shows valve EF.V272 open and valve ET.V332 open
to atmosphere, providing added protection against overpressuriaation for the
heat exchangers listed above.
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Page 61 of 70
April 28. 1988
The outlet from heat exchanger EEG01A was isolated by valve EF-HV59. Also,
valve EF-VOS8 was removed during the test. Note that with EF-V058 removed.
line EG-208HBC 16 is open at the flanged end of pipe spool EF03 5006. This
provided a vent to a tmos phere preventing accidental pressurization of the
EEG01A shell side in case of boundary valve leakage.
Containment cooler heat exchangers SGN01A and SGN01C were isolated by
valves EF-BY45 EF-HV47, and EF-HV49. Thus these heat exchangers, were
'doublo' isolated from the test boundary after that portion of the line was
filled and vented.
SGK05A and the diesel generator coolers on 'A' train were double isolated
from the hydrostatic test by valves EF-V053. EF-V055 and EF-V273.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN
VCNOC believes the finding as stated was correct. Prior to the
hydrostatic test Work Request 2931-87 was revised accordingly, thus ensuring
that the heat exchangers mentioned above would not be pressurized in excess of
ASME Section XI limits.
A revision to the hydro.tatic and pneumatic test procedure HGH.M00C-02 will be
made to add precaution 7.2.4.1 'The test instruction must include provisions
for over pressure protection of systems or components adjacent to single
isolation test boundary valves. Leakage past these single isolation boundary
valves must not subject other systems or components to pressure exceeding ASME
Section XI allevances' . This procedure revision will be completed by July 1
1988.
CONCLUSION:
VCNOC agrees that the subject finding is correct and the corrective actions
taken in response to this finding should preclude ue pressurization of heat
exchangers in excess of the pressures allowed by ASME Section XI.
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Page 62 of 70
April 28, 1988
3.2.2.6 PMR 0904: ESSENTIAL SERVICE VATER CHECK VALVES
FINDINGt
This pMR installed isolation valves for Essential Service Water (ESV) Check
Valves EF.V0046 and EF.V0076 to improve the maintenance and testing of the
check valves. The PHR added two new gate valves. EF.V0345 and EF.V0346. The
review of the PMR and the associated work packages found that clearance Order
l No. 871061EF, which was used to establish the clearance boundaries for the
work, did not provide correlation between the initials and signatures of the
individuals establishing and verifyleg the boundary as required by 10 CFR 50
Appendix B, Criterion XVII, ' Records' Criterion XVII requires that quality
records shall, as a minimum, identary .Te inspector or data recorder, other
licensee procedures, such as surveillance procedures, typically include a
tabulation which correlates the individual's initials and signatures to permit
positive identification. The SSCHI team considered that the personnel
performing valve lineups should be clearly identified.
CENERAL DISCUSSION OF FINDING:
During an NRC review of Clearar.ce Order 87 1061.EF, which was used to
establish clearance boundaries for implement.ation of PMR 0904, it was fou2d
i that there was no correlation between the initials and signatures of the
individuals establishing and verifying the boundary. The NRC's basis for this
Finding, as stated, is that 10 CFR 50 Appendix B. Criterion XVII ' Records'
! requires that Quality Records shall, as a minimum. identify the inspector or
l data recorder.
RESPONSE TO THE FINDING 1
10 CFR 50 Appendix B, Criterion XVII specifically states Inspection and Test
l Records shall, as a minimum, identify the inspector or data recorder, the type
of observation, the results, the acceptability, and the action taken in
I conjunction with any deficiencies noted.'
l The Clearance Order form is used by operations to establish and document safe
working boundaries for maintenance / modification activities and is not
considered an inspection or ttst record.
l CONCLUSION:
VCNOC does not consider this item to be a deficiency based on the requirements
of 10 CFR 50 Appendix B. Criterion XVII. It should be noted that VCNOC
r.anagement desires and is capable of identifying the individuals establishing
clearance bouadaries. This can be secomplished through a process of
determining the shift in which the clearanec was established and reviewing
operatiens Special order $7, ' Safety Tagging for Persennel Authorized to
Perform Tagging Activities'. This Special Order lists tagging Authorities as
well as individuals authorized to hang and remove tags. In addition, this
Special Order specifies personnel authorized to sign on and off of Clearances.
Additional methods are being reviewed to improve the capability to identify a
specific individual involved in tagging under the safety tagging program.
This review will be ccmpleted by June 1. 1988.
,
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gection II
Page 63 of 70
April 23, 1988
j,32.2.7 FMR 1363: N"IlfG FUMP CONTROL VALVE CAVITATI00f **"I
I l E DIG.L
This PMR replaced the trim in Charging Pump Plow Control Valve 30.PCV121 with
a new design. The former valve tria experienced cavitation damage because of
the high flow and high pressure drop while in service.
VR 4430 86, used to implement PMR 1363 for Valve PCV.121, did not note that
PMRs 1613 and 1635 were performed concurrently. Contrary to Note 9 on Copes
Vulcan Drawing D.283137 which required a total of nine packing rings to be
installed, step 7 of the work package was annotated to indicate that twelve
rings of packing were installed. The licensee indicated that the reason there
were more packing rings installed was because the licensee had implemented
PMRs 1613 and 1633 concurrently with FMR 1363. PMRs 1613 and 1633 removed
packing leakoff piping and lantern rings and replaced braided asbestos packing
with graphite packing. More rings of replacement packing had to be used to
replace the originally installed packing. A review of PMRs 1613 and 1635 by
the $$0MI team found that the installation of the new packing material was
acceptable, and the team noted that a supplemental valve repacking instruction
was attached to the VRs which implemented the requirements of PMR 1635 for
packing replacement. The failure to annotate VR 4430 86 to cross reference
the above PMRs for documentation completeness is considered a weakness.
GEN 11tAL DISCUSSION OF FINDING:
The concern was that in the work instructions for implementing PMR 1363.
reference Vork Request #04430 86, states to repack the valve in accordance
with the technical manual, which states that nine (9) rings of packing needs
to be installed. According to Vork Request #04430 86, twelve (12) rings of
packing were installed. PMR 1633 changing valve packing to a non. asbestos
material, also allowed the removal of the lantern ring. which in turn, made
more room for packing in the stuffing box. The concern expressed by the $50MI
toam was that PMR 1635 was not referenced on Work Request (04430 46.
RESPONSE TO THE FINDIN3:
During the implementation process of PMR 1633, packing is fabricated by
the mechanics using dies and ribben type packing. Numerous valves have
been repacked in the plant with only one known failure. The generic
instruction sheet used for repacking gives a stuffing box dimension. The
number of rings is not considered as important as the inside and outside
diameter of the packing ring. The quantity, as specified on drawings, is
considered more of a purchasing number than application number. For
examples if a valve is repacked and there is room for more packing or not
enough room for the packins as stated by the drawing, the mechanic is going
to pack the valve using good maintenance practices.
It should also be noted that packing is a consumable item and as the
service life of the valve increases, more packing will be installed
depending on valve performance, not the number of packing rings specified on a
drawing.
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Page 64 of 70
April 28, 1988
It should also be recognir.ed that PMR 1635 changed the thought process
of repacking a valve. Asbestos type packing, as specified on most
drawings, is very seldom if ever used.
EqHCLUSION:
Valve SG-FCV121 was repacked on November 11, 1986 on Work Request #52181-86.
The leak off line was removed. (PHR 1613 on October 5, 1987). This PMR has a
requirement that before the leak off line can be removed, the valve aust be
packed with graphoil packing: which was completed by work Request $52181-86.
The valve trim change out was completed on October 9, 1987 per Work Request
- 04430-86. All work was performed per the dicection given in their respective
PMR's and by using good maintenance practice. Therefore, it is delt that no
corrective actions or changes to the program need to be performed.
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April 28, 1988
3.2.2.9 PRESSURIZER SAFETY VALVE TESTING !
FINDING:
The SSOHI team reviewed the ASME Code Section XI testing of the Pressurizer
safety valves. The test procedure and the implementation of the test i
procedure were inadequate because the test procedure did not use the
representative temperature of the valve when installed in the system as
required by TS 3/4.4.2.2. Additionally, because the 'as-left" valve l
temperature was not recorded for valves which were tested and reset, the TS
requirements could not be substantiated.
Three direct acting Code Safety valves made by the Crosby Valve and Gage
Company were installed on the Pressurizer. ASME Section XI Article IWV-3500,
required that the valves be tested on a rotating basis so that each valve is
tested at least once every five years. This five year cycle for valve testing
began with facility consnercial operation.
As a result of NRC Region IV concerns with the adequacy of the testing of the
safety valves, the licensee conducted setpoint testing of the three installed
valves (BB-8010A, BB-8010B, and BB-8010C) during the current outage. The
licensee elected to test the valves by the use of a local bench test becauss
of dissatisfaction with the contractor which had previously tected the Main
Steam safety valves. Th'a pressurizer safety valres were previously tested by
the valve vendor between 1977-1978 and had not exceeded their ASME Code
testing periodicity requirement. Additionally, three spare valves had been
tested in March 1987. The inspector reviewed the detailed test procedures and
data and identified the following concerns.
a. Five of the six valves tested had setpoi .s well beoow the minimu's TS
limit of 2461 psig. Additionally, the 'C( talve setpoint was found to be
below the Pressurizer Power Operated Relief Valves (PORVs) setpoint,
although the licensee indicated that this safety valve had not lifted :
durlag a prior plant transient which had caused the PORVs to lift.
The valves were bench tested in accordance with a method acceptable by the
ASME Coda, using a low volume, high pressure test rig. The valvus were
variously heated to sinulate ambient installed conditions using eithwr
heat blankets or a ' hot box' equipped with electrical heating elements.
As corrective action ene 'B' and 'C' valves were replaced with spara
safety valves and the 'A' valve was reset and reinstalled.
b. The SSOMI team also noted that the safety valves exhibited greater thc.n
expected setpoint deviation with respect to temperature variations. l
Dia. gnostic testing of the safety valves, pe: Jorce 1 as a result of (
discrepancies identified in the 'B' and 'C' valve testing, indicated thst
the valve setpoint dropped about 0.87 psia por degree Fahrenheit (F)
1;.c rea s e . The diagnostic testing was perforced at various ambient
temperature condit t
a vinging frvm 80 to 17S degrees F and various nnzzle L
rinc settings. D.s nozz1t, ring adjusts the valve litt sensitivity. The ,
licensee performed an informs 1 statistical evaluation of this data and l
founi the temprature setpoint relationship to be linear. A review of the
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Page 66 of 70
April 20, 1988
Electric Power Research Institute (EPRI) test data for similar valves
found the temperature setpoint shift observed at WCGS to be two or three
times and the maximum inferred from the EPRI data,
c. The temperature conditions used to test the installed valves were
different from the temperature conditions used to test the spare valves.
The installed valves were tested per procedure STS MT-005, ' Pressurizer
Code Safety Valve Operability,' Revision 1, which specified that the
valves be heated to 120 to 200 degrees Fahrenheit (F) to simulate the
ambient condition as required by the TS. The spare safety valves wore
tested by detailed test instructions baaed on the Crosby Vat"- Manual
which specified that the valves be heatad to 120 to 140 - - F.
Additionally, test temperature data was not required nor collectra for the
valves that were tested and reset and the licensee could not substantiate
that the test temperatures represented the "as-insta11ed' valve ambient
conditions as required by TS 3/4.4.2.2.
d. NPE had not been involved in the evaluation of dita nor the determination
of the correct test temperatures. As a result of the SSOMI team concernt,
the Maintenance Department issued EER No. 87-BB-21 on November 16, 1987,
requesting specification of a valve test temperature range which would
satisfy the TS requirements. The disposition to this EER, issued on
November 18, 1987, provided a temperature range of 70 to 120 degrees F and
direction for obtaining temperature measurements. The SSOHI team
considered that the EER disposition was unsatisfactory because the
temperature recommended by NPE did not have a correlation with the actual
installed conditions.
e. Pressurizer safety valves are equipped with guide and adjusting rings
which control the valve blowdown. The ASME Ccde and associated test
requirements assume that guide ring settings established dr. ring vendor
certification testing result in repeatable valve configurations which do
not require periodic testing. Therefore bench testing, which does r.ot
change the ring settings, is allowed even though it does not verify actual
blowduwn perf o rma ncs . During the inspection, the SSOHI team found that
the ring settings for the ""Tre Pressurizer ssfety valves were not set as
required by the manufacturer to ensure a proper valve bleedown
characteristic. Furthermors, the guide rtng position hsd not been
verified on the installed Pressurizer safety valves, and the testing
procedures did not include steps to verify guide ring position wnenover
the Pressurizer safety valves wer* tested.
f. Tne licensee fa116d to eval * ate tha information contained in I&E
Information Notico 66-05, 'Hain Steam Safety Valve 7est Failures and 1.ing
Setting Adjuatments,' and I&S :nformation Notice 06-05, Supplement 1,
which identitled valve performance protlems resulting from impreperty
established guide ring se+ sings. Incorrect ring settings had been found
to re ult an insufficient relief capacity and have possibly contributed to
premC.ure valve operation and'or reseating failures. Although the I&E
Information N7ti;e addressed ibin S tetti safoty valves and not the
Pressurizer safety v11ves, the Prossuriser safety 'alves at VCG5 are
essentially identical in configuration to the Main Steam aafety valves and
whould have been evalusted. t
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April 28, 1988
GENERAL DISCUSSION OF FINDING:
a.,b.,c.,e.
Four maintenance items were identified conaerning the pressurizer safety valve
testing.
1) 3.2.2.9.a - 5 of 6 valves tested below the setpoint.
2) 3.2.2.9.b - Temperature seemed to have more of an impact on setpoint than
would be expected.
3) 3.2.2.9.c - Test temperatures used had no correlation with ambient temper-
atures at the pressurizer.
4) 3.2.2.9.e - The guide ring and blowdown ring settings were not verified.
d. As a result of questions concerning the ambient temperature conditions of
the Pressurizer Code safety valves during power plant operation and the
temperature influence with regard to setpoint acceptance testing,
Engineering was requested to provide the temperatures to be utilized and
where physically on the valve to monitor that temperature during testing.
EER 87-BB-21 was dispositioned providing an ambient temperature range of
70 to 120 F. This temperature range was based on an evaluation of normal
operating containment conditions judged to be reasonably accurate in the
immediate area of the Pressurizer Code Safety valves. Locations for
temperature monitoring on the valves during setpoint testing were also
provided.
f. Although tha Pressurizer Code Jafety valves were not the subject of IEE
Information Notice 86-05, ' Ma i'4 Steam Safety Valve Test Failures and Ring
Setting Adjustmentd' And ILE information Notice 86-05 Supplement 1, ehe
pressurizer code safot; valves are similar and should have been evaluated.
EESSONSE TO THE FINDING _1
a. b., c., e.
1) The three pressurizer code safety valves removed from the system, were
tested using a low volume, high pressure rig, utilizing a heat bir.aket
tv simulate operational ambient temparatures stated in tbc ".utinghouse
equipment specification. The test required the valve to lift (pop)
at 248S 1 1: psi. O'. the three valves cecoved from the pressuri2er, the
first tested witi.8a tolerance and the cther two tested below the
Technical Specification limit. Thtee replacement valves were tested in
a similar fashion with additional criteria, and tva of the m valves
tested out of tolercnce.
Of the two valves removed from the pressurizer that tested low, it was
found that the mechenic who tested these valves believed that when
the valves hissed er chattered indicated the setpoint, as found when
testing relief valves. The mechanic did not know that a safety valve
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April 4.8, 1988
would fully lift when test pressure reached its setpoint. Additionally
the test equipment war being improperly used. Further testing of one
of these valves proved that the valve would operate as designed.
The replacement valves were tested with the same low pressure rig, but
were heated with radiant heat in a hot box to a lower temperature more
representative of actual ambient operating temperature. Each valve was
then required to lift two consecutive times in the test range. All
three presaurizer code safety valves were replaced with successfully
tested valves.
2) WCNOC believes that t', 9.87 pound decrease per degree of
temperature is invalid bas d on the inconsistencies in test
parameters, (i.e. method of tempvature control and length of time
to reach equilibrium).
3) The test temperature of 120 - 200 F was taken from the Westinghouse
design specification. The procedure was written with thesa values, during
Start-up of 1.he plant. The spare valves were tested between 120 - 140 P.
This value was not from the technicag manual but a value @osen which
fits within the criteria of 120 - 200 F.
The three valv e s installed were installed utilizing detailed work
instructions rather than procedure, allowing more specific details.
4) If the guide rings are not adjusted during testing, verifications were not
needed. In the case of the spare valves, the guide rings were adjusted
and placed back to what the Crosby Teeting Report specified.
d. The temperature range of 70 -120 F, prov1Nd for setpoint valve testing,
is considered adequate for the folleving reaso.a
1) Containment atmospheric conditions are designed to be maintained less
than 120 F. The location of the Pressurizer Code Safety valves from
the ;,ressurizer (11 f eet) is sufficient to preclude temperatures of
the valve to be excessively greater than that of the general aren.
2) The dominant factor thst may vary the relieving pressure setpoint in
regard to temperature is the relief valve spring. The location of
the spring in respect to the process fluid makes the temperature of
the spring more closely resemble the general area temperai.ure.
3) Subsequent temperature monitoring of the Pressurtzer Code Safety
valves during power operation during March
surface and spring temperatures ranging from 77,1988 to 88gevealed
F. Thisvalve
data
confirms the temperature range provi.tod in the Engineerir g
Jisposition to EER 87-BB-21.
4) Adequate compensation should ce given to operating temperature
conditions during the set pressure tasting of safety relief valves.
The Engineering Disposition to EER 87-BB-21 addresjed ambient
temperature conditions. Inlet pipe temperature conditions should
also be considered as to its applicability or influence on the test
results and the a ceptance of the test. Engineering concluded that
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Page 69 of 70
April 28, 1988
the contribution that the inlet pipe temperature has in relation to
that the spring imposes is negligible,
f. The pressurizer safety relief valves are designed to limit primary system
pressure excursions following anticipated operational and accident
transients. Operability of the safety valves was demonstrated by
prototypical testing and appropriate analysis in accordance with
NUREG-0731 II.D.1. The type of safety valve used at Wolf Creek, Crosby
Model HB-BP-86 6H6, was tested in an EPRI test program.
The ring settings used for the Crosby 6H6 valves at Wolf Creek aprcoximate
those used in a series of EPRI tests on the Crosby 6M6 valve, where
' reference' settings were used. Results from this series of tests are
considered applicable to the plant valves.
The safety valves are required to operate over a range of full pressure
steam, steam-to-water transition, and subcooled water flufJ conditions.
The valves were tested for the range of required conditions in the EPRI
test program. The acceptance of this test program and plant specific
results by the NRC was documented in a letter fro 9 P. O'Connor to B.
Withers, dated August 6, 1987.
ACTIONS WHICH HAVE BEEN OR VILL BE TAKEN:
a.,b.,c.,e.
1) The operability test procedure for the pressurizer code safety valves was
revised January 26, 1988 to reflect the following:
The procedure now includes a statement about the lifting characteristics
of a safety valve, minimizing test pstformance error.
Heating requirements of the valve for testing have been changed to reflect
more accurate representr. tion of actual ambient temperatures. Using
radiant heat, a more evea heat soak is obtained, and lessens thermal
gradients throughout the valve.
The test procedure now requires two successful consecutive pops within
the allowed tolerance. This shoulu verify the accuracy of the set
pressure.
2) None deemed necessary
3) Procedure STS HT-005, has been changed for a heat box to be used rather
than heat blankets. The box supplies a uniform heating source for the
valve, making a consistent temperature across the entire valve. A step
was added to the procedure to record the temperature of the valve at the
time the valve is tested. -
4) Three new safety valves were installed on the pressurizer on Work
Requests 91059-87, 03999-87, and 0430' 57. The guide ring settings were
verified to be correct per Crosby T,.t Data Sheet. The three valves
removed will ts disassembled, inspected, reessembled and tested on Work
Requests 70654-87, 70705-87 and 70655-87. At that time the guide rings
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April 28, 1988
will be verified as being correct per the Crosby Test 'ata Sheets. The
only time the guide rings need to be verified as be.ng set correctly
is when the rings need changed during the course of work.
CONCLUSION:
a., b., c., e.
Procedure STS MT-005 was first used during Refuel II. Though the
procedure satisfied the requirements of the Technical Specifications, the
methodology was lacking in direction. There has been a complete procedure
rewrite, incorporated on a temporary procedure change, and a permanent
procedure change is being written.
The items of concern expressed on the testing of the pressurizer safety
valve were resolved on Work Requests 191050-87, 104300-87, and #03999-87,
with detailed work instruction. The work instructions were then used to
develop a new procedure and work instructions for performing inspection
and testing of the three removed valves on Work Requests 170654-87, 17070."-87,
and 170655-87.
Temperature data is being taken in the plant at normal operating
pressure and temperature to further define the actual ambient temperatures
that are experienced by the safety valves. This data, when completed and
evaluated, will be incorporated into the procedure.
d.,f.
Based on the above discussions, WCNOC does not consider this item to be a
deficiency.
k