IR 05000445/1990013
| ML20043B954 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 05/22/1990 |
| From: | Bitter S, Bundy H, Howell A, Johnson W, Latta R, Murphy M, Runyan M, Joel Wiebe NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV), Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20043B951 | List: |
| References | |
| RTR-REGGD-01.058, TASK-2.E.4.2, TASK-2.K.3.10, TASK-TM 50-445-90-13, 50-446-90-13, NUDOCS 9006010098 | |
| Download: ML20043B954 (29) | |
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I APPENDIX B I
U.-:S.cNUCLEAR REGULATORY l COMMISSION OFFICE OF NUCLEAR-REACTOR REGULATION
NRC Inspection Report:' 50-445/90-13
50-446/90-13'-
1 Dockets: 50-445-Unit l' Operating 1 License:.
NPF-87~
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50-446 Unit,2 Construction Permit:'CPPR-127:
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Expires:' August l, 1992,.
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Licensee:
TU Electric'-
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Skyway Tower
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400 North Olive Street Lock Box:81
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Dallas,. Texas 75201 (
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l Facility Name:. Comanche' Peak Steam Electric' Station-(CPSES),.
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l Units 1'and 2 l
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Inspection At:
Comanche Peak Site, Glen' Rose,l Texas.
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L Inspection Conducted: -April.4,-:1990..,Jthrough'May?2,'<1990'
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Inspectors:
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/ '70 R. M. Latta, Resident Inspector Date
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unya6, Resident'Inpector:
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a M. Mur y, Reactor Insp66 tor, Region IV Date /-
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9006010098 900523 O
PDR ADOCK 05000445
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H. Bt4dy,. Reactof' 1(spector, Region IV D' ate'
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D. Bitter,' Resident Inspector.
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M A. T.
owell, III, Resident Inspector Dhter j
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W. ;D.
Jo on, Senior Resident Inspector
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Reviewed ~by:
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.-S.-Wiebe, Senior Project Inspector _
- / D$es Inspection S ary.
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Inspection Conducted:- April 4, 1990, through May 2,-1990-(Report-
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50-44S/90-13; 50-446/90-13)
Areas Inspectedr Unannounced resident safety inspection including ~
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sustained control room' coverage and general plant observations;
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operational safetye veri'fication; maintenance;isurveillance testing;
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- startup test witnessing; independent'. measurement of~ reactor (coolant
system leak rates; startup test procedure and results' review;Jonsite-r
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events' followup;-initial criticality witnessing; followup on"TMI-
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y action items.(Safety Issue' Management System ItemsoII.E.472.6', closed; i.
II.K.3.10, closed); followup on previous' inspection <. findings'and;
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. violations; Regulatory GuideJ1".58 (quality. organization: minimum
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educational requirements);. followup on-allegations; and Unit 12<
'walkdowns.
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Results:
Within the areasLinspected[ one deviation was identified ~-
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involving the licensee's' failure to properly implement the.
~ requirements of Regulatory Guide 1.58'in that'a:former Operations-QC
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- manager did not meet the specified minimum educational requirements.
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Strengths were identified within the operations area relative to startup test activity control and coordination and operator responses to. plant. transients.
Both of these' areas were considered to be excellent.
General plant housekeeping and plant material conditions were judged to be very good; however, minor steam leaks and housekeeping discrepancies in the turbine building continue.to.be identified.
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DETAILS
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Persons Contacted
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L. Barker, Manager, ISEG, TU Electric J.
W.' Beck,.Vice President, Nuclear. Engineering, TU Electric
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Bhatty, Issue Interface Coordinator, TU Electric.
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R. Blevins, Manager of Nuclear' Operations Support,
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TU Electric D.-M..Bozeman, Chemistry and-Environmental Manager,-
TU Electric
H. D. Bruner,. Senior'Vice. President, TU Electric l
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C. Byrd,. Manager,. Quality Control (QC), TU Electric
- W.:J.
Cahill, Executive.Vice President,. Nuclear, TU Electric
- C..B.
Corbin, Licensing-Engineer, TU Electric J. W. Donahue, Operations Manager,-TU Electric.
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S.. L.. Ellis, Manager of Performance and Test,1 TU Electric:
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G. Guldemond,. Manager of Site Licensingb.TU Electric'
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L. Heatherly, Licensing Compliance Engineer,
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TU Electric
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C. Hicks,. Licensing compliance Manager,1TU Electric
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B..Hogg, Chief Engineer, TU Electric
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A. Hope, Site Licensing,.TU Electric
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R. T. Jenkins, Manager, Unit"1 Cperations Support Engineering,E TU-Electric J. J. Kelley, Plant Manager, TU-Electric J..E.
Krechting,- DirectorLof, Technical. Interface, TU/ Electric
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J. LaMarca, Unit 2? Project' Manager, TU Electric--
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- F. W. Madden, Mechanical. Engineering Manager,'TU Electric'
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M. McAfee, Manager, Quality Assurance.(QA),!TU Electric J. F.-McMahon, Manager Nuclear Training,,TU. Electric
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W. Muffett, Manager of Project: Engineering, TU Electric-j
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F. Ottney, Project Manager,TCASE
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W. Rau, Unit 2 Project ~ Manager,,TUmElectric
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M. J. Riggs,. Plant Evaluation Manager,: Operations, ;TU: Electric
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C.-Schmidt,' Director of Nuclear, Services, GeneraliDivision,.
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TU-Electric
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B. Scott, Vice: President,.Nuclearf0perations,.TU Electric
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C.
Smith,-Plant Operations Staff,sTU Electric:
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B. Stevens, Manager of Operations SupportzEngineering'
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F. Streeter,JDirector,.QA, TU Electric y
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L. Terry, Manager of Projects,-TU, Electric l
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G. Tyler, Director, Management l Services, TU Electric
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- D.R.
Woodlan, Unit 2 Licensing: Manager, TU. Electric The inspectors also interviewed other. licensee employeesiduring.
this inspection period'.
- Denotes personnel present at the May'2,'1990, exit interview.
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L NRC personnel present at May 2 exit meeting..
H. F. Bundy,. Reactor' Inspector, Region IV i
S. D. Bitter, Resident Inspector C. I. Grimes, Director, Comanche-Peak Project = Division, NRR:
A. T. Howell, Resident Inspector W.
D._ Johnson, Senior-Resident Inspector R. M. Latta, Resident' Inspector J. E.,Lyons, Assistant' Director for Technical Programs,
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Comanche Peak Project Division,.NRR M. E. Murphy,. Reactor Inspection, Region IV.
li M. F. Runyan, Resident-Inspector
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J. S..Wiebe, Senior Project Inspector-for Inspection Programs, CPPD, NRR R. F. Warnick, Assistant Director forLInspection Programs,
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CPPD, NRR
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C. C.-Williams, Technical Assistant,_ Comanche Peak Director's Office i
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2.
Operational Safety Verification'(71707', 71715)'
The inspectors routinely toured the facility 1during-normal and backshift hours to.evaluste general: plant'andLequipment i
conditions, housekeeping, Land-adherence'to fire protection, security, and radiological control measures. ~ Longoing work-
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p activities were monitored to verify that:they.were being;
-3 conducted in accordance with. approved-administrative'and-technical procedures and that proper communications with the-t control room staff had'been established.
The; inspectors observed valve, instrument, and electrical equipmentLlineupsLin the field
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to ensure that they were consistent'with system operability
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requirements and operating procedures.
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During tours of.the control room,.the inspectors: verified proper staffing, access' control, and operatorfattentiveness.e Adherence to_ procedures and limiting conditions for operations were'
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The inspectors examined equipment lineupiand-
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operability, instrument traces, and" status-of:controlfroom i
Various control. room. logs and other.available licensee documentation were reviewed.
The inspectors' observed and reviewed maintenance and problem investigation: activities to verify compliance with~ regulations and procedures. ' Involvement i
of QA/QC, safety tag use, personnel: qualifications, fire protection precautions, retest requirements,'and'reportability were assessed.
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Checks were made to determine whether security. conditions met.
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regulatory requirements, the physical security. plank and approved.
procedures.
These checks' included 1 security staffing, protected
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and vital area barriers, personnel identification, access control badging, and compensatory measures.
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The inspector witnessed major-portions of a fire: drill.
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drill scenario involved-a postulated' fire :in _ the B Train safety
injection pump room (fan cooler)'. -The inspectorJobservedLthat
- the response of both the security force and the' health physics
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personnel were timely and effective.
The response of the fire.
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brigade was genera 11y' adequate in that the personnel involved
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were properly equipped with turnout gear:and self-contained l
breathing apparatus and that good fire fighting-techniques were q
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L exhibited.
The. actual response. time:of the fire brigade-L personnel was somewhat-inhibited by minor equipment staging-q l
deficiencies; additionally, it was. determined that operations I
personnel.in th0' control: room-responded correctly utilizing.
t Procedure FIR-101'and that1 appropriate action._was1 initiated to simulate-the securing.of the affected: equipment.3.Norsignificant v
weaknesses were observed and-the licensee has<made provisions for i
correcting the minor deficiencies.'
n On April 18, 1990, the inspector attendedLa meeting:of the-Senior
Management QA Overview Committee.
This committee meets monthly, to review plant performance from a'qualityJperspective, discuss-corrective action request st'atus, discuss, quality indicators for:
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various organizational; groups, review items of_ interest from
previous _ meetings, and. discuss' general quality! improvement
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proposals.
The~ inspector found;thatLthis. meeting was efficiently:
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conducted andlincluded'a, free: exchange of.information-onimatters-affecting' quality.
The high leveltof? management: interest
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indicated-by the memburshipEof, andzattendance'at,sthis. meeting.
i is a' positive factorttoward maintaining and improvingzthe overall quality program at-the site.
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During this inspectionLperiod, the inspectors _ observed?manyi plant ol evolutions. including lpowerichanges, main'! eedwaterepump;startup f
and shutdown,. main turbine startup and shutdown,. main generator-
synchronization to the grid, and operator responseito'a reactor u
trip, inverter failure, heater. drain. pump trip, and various-control valve malfunctions.
Operator: performance during these
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planned and unplanned evolutions was very good and-the procedures-
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used were adequate.
Plant housekeepit conditions ~were very-good, butcsteam. leaks-were a problem inLthe turbine ~ building.
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overall,.this area was considered to be excellent during this
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No violations or deviations were. identified.
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3.
Monthly Maintenance observation (62703)
Station maintenance activities for the safety-related systems.and components listed below were observed to ascertain that they were j
conducted in accordance with approved procedures, regulatory
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guides, and industry codes or standards, and in conformance with
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the Technical Specifications.
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The following items.were considered during;this review: -the
-limiting conditions for operationLwere met while; components or
, systems were. removed from service, approvals were obtained prior to' initiating the work,. activities ~were accomplished using-approved. procedures and.were; inspected as applicable,_ functional l1-testing and/or. calibrations were performed prior to returning-
components-or' systems to. services quality' control-records were-
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i maintained, activities were accomplished by! qualified' personnel, parts and materials usedfwere-properly. certified,iand:
i radiological and' fire' prevention controls'were~ implemented.-_
ti Prior to initial + Mode 1. operations,vthe inspector; reviewed the
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complete list of outstanding work requests and work: orders for'
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potential-negative impact: on Mode J1 operations..The resulting questions-were adequatelyfanswered by licensee _. personnel. lit.-was
determined that none oftthe.1195-outstanding: work' items adversely
af fected the operability. of systems needed. for-Mode :1. operations; o
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Maintenance activities ~ observed included:
Calibration of diesel" generator = jacket waterLheater.:
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thermostat switch (Work Requestl2113, Procedure:INC-2050).
t-Changing: diesel' fire pump oilifilter (Work Request 21174).
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Diesel fire pump instrumentation determinationf(Work Order-
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C90-2349)'.
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Post maintenanceL testingfof Valve 1-FV-45371(Work. Order
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C89-17779)..
3q Main feedwater pump flow 1 control-valvetrepair (Work Order
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-C90-2788).
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L Main feedwater pump coupling alignment;(Workforder'C90-2938,
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' Procedure MSM-GO-0201).
Inverter-IV1PC4 repair (Work' Order C90-24664, Procedure-t
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MSE-GO-1210, Specification;2323-ES-100).
t Installation.of Temporary Modification 90-01-019 (Work Order
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C90-2894).
Inverter IV1PC4 tuning (Procedure EGT-320A).
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Repair blowdown isolation Valve 1-HV-2400A (Work order
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C90-2959, Procedure MSM-CO-6613).
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Hydraulic jack assisted opening of. main'feedwater isolation
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-valve--(Work Order C90-3227).
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During this' inspection periodi the(licensee completed the development of a, preventive maintenance program for. lubricated-pump couplings.
The program was. developed considering vendor
p-recommendations,Emaintenance history, TU Electric commitments, i
and Nuclear Plant Reliability Data System (NPRDS).information..
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The preventive maintenance database was revised to: incorporate
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the new coupling 11ubrication' requirements. -Implementation-of
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l this program will'be reviewed duringLroutine monthly maintenance l
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I The maintenance activities observed'were performed in accordance with' applicable. licensee and regulatory requirements.,: indicating
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that the licensee's maintenance. program was fulfilling.its
. objectives.- No violations or deviations were identified.
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Monthly surveillance observation'(61726)'
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The inspector observed;the surveillance testing required byL
. Technical Specifications onithe various components listed below'
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- and verified thatttestings was performed ini-accordance with-adequate, procedures,-test: instrumentation was; calibrated,.
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l-limiting conditions for operation:were met,Lremoval:and
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restoration of the;affected components"werefaccomplished, test.
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l results ' conformed with Technical: Specifications and procedure '
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the individual' directing the' test, and any' deficiencies
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identified during the testing were' properly reviewed:and resolved
by appropriate-management" personnel.
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l The: inspector witnessed portions of4the following. surveillance'
test activities:
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. Diesel generatornstarting air. receiver checkcyalve-N
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operability test (Procedure OPT-517A).
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Emergency diese17 generator operabilityJtesti(Procedure-
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OPT-214A).
Emergency. diesel, generator inspections-(Procedure
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MSM-PO-3374).
- Diesel-fire pump test (Procedure-OPT-220)'.
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Reactor coolant: system leak rate-(Procedure OPT-303)..
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Measurement of reactor' coolant system 1 controlled l leakage l
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(Procedure OPT-110).--
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Sampling diesel fuel oil tank for water (Work Order
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S90-0961).
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_ Component cooling water operability verification-(Procedure
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OPT-208A-4).
Residual heat removal system' testing (Procedure OPT-203A,.
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PTR.C90-2369).
Slave. relay actuation' test (Procedure OPT-490A).
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l SlaveErelay actuation test (Procedure OPT-488A).-
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Slave relay ' actuation test 1(Procedure OPT-493A),
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s SlaveErelay actuationitest1(Procedure OPT-465A).
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. Main feedwater--pump' testing-(Procedure EGT-322A).-
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Main turbine stop'and control valve tcstingL(Procedure-
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OPT-217A).
Main turbine overspeedLtest1(Procedure' OPT-217A).
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Auxiliary feedwaterfsystem-test (Procedure OPT-206A).-
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During the performance of OPT-203A,JOPT-490A,cand. OPT-488A, the j
'NRC' inspector observed'that several~proceduret revisions were i
necessary to correct' component identificationLinaccuracies and to
correct procedural errors?in order.to permit completion 1of the i
test.
Subsequent to the. identification ~of theseLdiscrepancies,.
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the-licensee performed a review of theE200 andf400 series OPTL surveillance test procedures to identifyfand correct similar
errors.
However,-in general,Lthe1 observed surveillance.
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activities and their associatedLprocedures: appeared toibe'
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adequatefand. personnel performance.was excellent.
NoLviolations-or deviations were identified..
5.
Startup Test Witnessino (72302, 71715)
i The inspectors witnessed selected startup testsLin order-to verify conformance of'the licensee to testing commitments and proce: dural requirements, observe staff performance, and.to verify
that adequate test program records were maintained..'In particular, the following items were considered'during: test witnessing:
Availability of current revision of test procedure.
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Minimum crew requirements..
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Test prerequisites and. initial conditions.
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Calibration status of test equipment.
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Test coordination an'd crew performance.
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-Preliminaryresukkssatisfactoryordeviations l
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. documented for<further. evaluation.
- Adherence.to Technical Specifications during testing..
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In addition,-the; inspectors'rev,atred various logs and reports and
attended meetings and crew:brielings-related tolthe test program.
During-this(inspectionLperiod, the-following:startup: tests were i
observed:
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ISU-101A-Initial Criticality and: Low-Power' Test Sequence.
ISU-204A operational Alignment of(Nuclear Instrumentation
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ISU-205A
' Dynamic Automatic: Steam. Dump Control-
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ISU-220A Turbine Generator. Initial 1 Synchronization and Overspeed Test ISU-022A Reactor Coolant System Lsakage Rate Test
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.NUC-207-Zero Power Isothermal and" Moderator Temperature
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Coefficient Measurementsj l
L NUC-102 Incore Flux Mapping System l
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NUC-120 Rod Swap Measurements
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OPT-308 Calculating Estimated Critical Position.
'ISU-207A Steam Generator Level Control: Test
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ISU-202A Calibration of Feedwater and Steam Flow Instrumentation at; Power
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f ISU-238A Main Feedwater' System Test ISU-240A-50% Reactor-Power Test. Sequence
Licensee coordination and control of:these-tests-were excellent.
No major procedure problems were identified.
The moderator ~
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temperature coefficient was--found to.be positive,-requiring-the.
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establishment of control rod withdrawal limits and the submittal'
of a special report-to the NRC.
This report (1-SR-90-005).was i
submitted on April 16, 1990.
No-violations or deviations were
identified.
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Independent Measurement of Reactor Coolant System (RCS) Leak
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Rates (61728)
D The inspector used NUREG-1107,;" Reactor Coolant System. Leak Rate
Determination," and thefassociated software, "RC3LK9" to'
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independently verify.that,the Comanche Peak Unit 1 leak-rates
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were within.the' limiting; conditions for operation..The use of
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"RCSLK9" also verified the adequacy;of the licensee's calculation-technique _for-determining-.theLprimary. system leak. rate.
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The inspector' reviewed =th'e pertinent design documentation and
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operational procedures"tofobtainLtank:and-system data.. This data
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was then used.to create the plant parameter. list.needed by-
"RCSLK9" to calculate the identified ~and unidentified reactor
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coolant system (RCS)Lleak rate.
The inspector used data obtained
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" Reactor Coolant ~ System; Leakage' Rate Test,". Revision 2.
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l Using ISU-022A,1the licensee calculated-leak rates'as follows:
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Total RCS Leak rate-0.187 GPM i
l Identified,RCS Leak rate
.0.027: GPM-i I
Unidentified RCS Leak rate 0.16: GPM'
Using"RCSLK9,"theinspectorcalculated'leakirahestasfollows:
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Total ~RCS Leak rate
'O.'17 GPM'
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Identified RCS Leak: rate 0.03~GPM-
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Unidentified Leak. rate-0.14 GPM
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The-inspector concluded that'the. licensee's1calcuiation?
techniques were-adequate based;onLthe-close correlation of the
two methods. HNo violationsLor deviations were-identified.
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7.
Startup Test Procedure: Review (72583)
To evaluate the licensee's compliance,with Regulatory Guides 1.68 and 1.68.2, Chapter 14 of-the FSAR, andethe Technical
Specifications, the inspector. examined Initial Startup Test
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Procedure ISU-233A, Revision 1,." Remote Shutdown capability-Test."
As part~of this examination, afreviewsof Abnormal
Conditions Procedure-ABN-905A,' Revision.2, " Loss of control: Room Habitability," was alsoireviewed.- ABN-905A -is used, : in part,-' to
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implement ISU-223A.
The inspector also walked down1the remote shutdown panel (RSP).as1part of the: review of'ISU-223A--
and ABN-905A.
The following observations-and weaknesses were-
noted by the inspector:.
l Regulatory Guide 1.68.2, Section C.2 (2),. requires, in part,.
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'that the performance of nonsafety-related activities that would not be required during an actual remote shutdown f
(e.g.,.for the protection of nonsafety-related equipment i
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from mechanical damage during the transient) be previously-
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defined and evaluatedito ensure that, if they were not-performed during an actual remote shutdown,-safe shutdown of-J the plant could_still be achieved.- However,-a review of:
ISU-223A, Step 10.9.2.1 revealed that if nonsafety-related
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activities are conducted during the test,.then such'
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activities will'be documented and evaluated subsequent to the testtrather<than being~ evaluated prior to the test.
i Discussions with licensee personnolcrevealed that:there will
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be some nonsafety-related activities that_must be performed
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to protect nonsafety-related' equipment;during'the, transient.
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Although Step 11'.2.2.'3.3 of ISU-223A specified that the
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plant-shall be maintained >in,a stable,'-hot standby condition..
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for. 30 minutes and' required. the recording of < various: plant'
parameters such.as, reactor: coolant system (RCS)' pressure-and temperature, and steam generator pressure:and level in
order to verify the acceptance: criteria,1ISU-223A did not specify any specificitest1 termination 1 requirements 11n the
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event _that-problems were encountered inistabilizing the
plantiin Mode 3.
Discussionsowith licensee personnel
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revealed that'the.testimay be terminated if an_ automatic safety injection: occurred during, the testr however,. this ;was.
not-noted-in ISU-273A.
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Step 11.1'4 of ISU-223A containsta caution. statement.. This
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caution warns of a possible' safety injection if auxiliary'
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feedwater flow is. excessive'immediatelyJfollowing>the
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This caution statement indicatesfthat-
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subsequent.information pertaining to thisl step would be
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. provided later. 'TheLinspector questioned whatLthis
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J information was*and1how it'affected,this;particular stepfin:
the procedure.
Additionally,qthe) inspector noted=that there a
D was no similar precaution or warning:that a: steam line low
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pressure safety injection _could; result"ifithe steam-I generator atmospheric;reliefEvalves are opened:too quickly.
Step 11.2.2.3 of ISU-223A notesothat the specific method for i
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establishing control of thefreactor plant and1 stabilizing it in the' hot standby' condition would be providedilater.- The.
inspector was_ concerned:by;thellack;of procedural guidance a
because of.thefcomplexity of~the test.
Similarly,
Step.11.3.2'of'ISU-223A requires.that the appropriateisteps
'in ABN-905A should be1used: to establish control of L the'
reactor plant at the RSP'
The-inspector noted that ABN-905A.
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is: a detailed Lprocedure1 governing numerous safety-related activities.
Not all of ABN-905A is related to that part of-ISU-223A that is intended to'be performed (1.e.,
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Section 11.1 through 11.3).
The inspector was concerned.
that this step:does not provide enough guidance for those.
. plant personnel who will actually conduct the. test.-
Discussions with' licensee management' personnel revealed that
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the applicable portions of.ABN-905A would be clearly specified prior to conducting the remote shutdown capability
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. test.
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Technical Specification Table 4.'4-1, REACTOR COOLANT.
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SPECIFIC ACTIVITY SAMPLE AND~ ANALYSIS PROGRAM, requires, in..-
J part, that.an isotopic. analysis for iodine be' conducted
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between 2'and'6: hours'following a thermal'powerschange; Jj exceeding'15 percent of-rated thermal power >within:a 1-hour y
period.
Discussions withflicensee personnel revealed that
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the remote shutdown test would be' initiated from :2'O percent?
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of, rated thermal power.
The'inspectorEnoted,.however,sthat-j
.this iodine analysis ~ requirement was not. contained in j
.ISU-223A.
The inspectorLalso observedLthat other plant J
sampling ~ requirements 1that are found in Integrated. Plant-
Operating Procedure IP0-004A, Revision 4, " Plant: Shutdown i
From Minimum Level to Hot Standby,"
(e.g.,. sampling the-
steam generators.to determine if a' release permit.isi
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required prior:to opening thecateam-generatorLatmospheric-
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relief valves or performing a plantivent-grab sample) were-
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not'specified~in ISU-223ALevenothoughtsomejof the:same" conditions necessitating such activities could be
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encountered during~the.conductief the-remote shutdownstest..
l TheSinspectors did note that thc1steamLgenerator activity.
sample is required per Step 2.4.k.7 of'ABN-905A;'however, it was not clear that this step of ABN-905A.would be performed l
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during thestest.
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The' inspector reviewed Attachment.14.1, " Instrumentation and
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Controls Available at1the RSP & Junction-BoxesLVerification
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of Functional Check List," andecompared it'with the controls d
and. indications on"the RSP.
The inspector,found-some' minor i
nomenclature / device labeling differences between the RSP and
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the corresponding' device on Attachment 14.1'.~-'For example,-
the main' steam line numbers: (No.' 1 eor 4').swere'.not indicated
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on Attachment 14.1 for hand 1 switches ~1'-HS-2452C and ci i
1-HS-2452E ("AFW PT MSL'l[4L SPLY VLV".)..
The observations and weaknesses noted above were discussed with J
licensee. management' personnel.- Licensee personnel 1 stated that
they were aware of some of these procedural weaknesses,Jand that1
such. weaknesses would:be addressed'andfresolved prior to
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'I conducting the remote shutdown capability: test.'.The observations-J and weaknesses associated with ISU-223A will be tracked as an open item pending resolution oftthese items prior.to the d
commencement of the remote shutdown capability test:
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No violations-or deviations were identified.
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i 8.
Startup Test Results Review (72596, 72592, 72572, 72301)
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Results of selected startup tests were reviewed by the inspector i
to determine that each had been properly conducted, reviewed, and
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approved by_the licensee.
Among the characteristics checked by
,
the inspector were entry of all required data, appropriate disposition and retesting for all deficiencies,.and documentation
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of appropriate approvals.
Test results reviewed were as follows:
ISU-022A, Revision 2, "RCS_ Leakage Rate Test," approved by
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Test Review Group (TRG) on April 1, 1990.
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ISU-015A, Revision 5, " Reactor Trip System Tests," approved:
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April 2, 1990.
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l ISU-101A, Revision 3, " Initial Criticality and Low Power f
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Test Sequence," approved April 13, 1990.
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NUC-102, Revision 3, "Incore Flux Mapping System Operating
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Instructions," approved April-11, 1990.
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NUC-104, Revision 5, " Boron Endpoint Determination and
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Differential Boron Worth," approved April 11, 1990.
i NUC-106, Revision 2, " Initial Criticality," approved
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April 12, 1990.
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NUC-107, Revision 4, " Calibration of_the Reactivity.
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Computer," approved April 11, 1990.
NUC-109, Revision 3, " Determination of Core Power Range for
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Physics Testing," approved April 11,-1990.
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- r NUC-108,-Revision 4, " Reactivity Computer' Check-Out (Physics
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Testing)," approved April 11, 1990.-
NUC-111, Revision 2, " Inverse Count Rate Ratio Monitoring,"
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approved April 12, 1990.
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'NUC-116, Revision 3,." Determination.of: Operating Limits to
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Ensure a Negative MTC," approved April 11, 1990.
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NUC-120, Revision 0, " Rod Swap Measurements," approved 1
.
April 11, 1990.
NUC-205, Revision 4, " Core Reactivity Balance," approved
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April 11, 1990.
NUC-207, Revision 3, "Zero Power Isothermal and Moderator
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Temperance Coefficient Measurements," approved April 11, l
1990.
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-15-The completed test packages reflected satisfactory completion of
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the associated tests including disposition of' test deficiencies
and appropriate retesting.
The inspectors discussed with.the licensee the following areas related to potential documentation
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and procedure improvements
The test results for Procedure ISU-101A had been approved prior
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to disposition of Technical Evaluation (TE) PT-90-1174, which
.l referred to failure to meet the review criteria for differential
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boron worth.
The test-summary provided justification for not-a meeting the review criteria, but it was not clear that acceptance was recommended. irrespective of the disposition for the.TE.
However, the test supervisor stated that the TRG and the Plant Manager approved the test results irrespective of the disposition
of TE PT-90-1174.
The inspector suggested that the test summary
'
should be specific when approval is recommended with open TEs.
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In Procedure NUC-111,: Step 11.2.1.5.2 states, " Transfer the reference value for each source range (SR) channel in Table A to the space provided in Table B (hot count rate)."
The' licensee should correct this step to refer to transfer of the count rate
'
associated with the reference value, which is computed by i
dividing the'ruference value by 100.
During the review of Procedure NUC-109, the inspectors noted that
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in paragraph 11.11 thg temperagure control band' upper limit had
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been changed from 557 F to 558.F.
The. applicable procedure
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change notice (PCN) that made other changes to this paragraph did r
not indicate the temperature control band change.
This was
considered by the licensee to be operator guidance but the licensee agreed that the change should have been included in the PCN.
During the evaluation of the procedure review and commei,t sheet i
for Procedure NUC-108, the. inspectors found'that-the resolution to comment 5(c) should have been more clear and provided more
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detail.
The comment.noted that the recommended wait time for insuring plant stability was 1 minute 50 seconds whereas the actual wait time was approximately 1 minute 20 seconds.
This was followed by a recommendation that "an evaluation should be performed and included in the test package to address this."
The l
resolution stated that " Comment noted, trace was evaluated, l
results were acceptable."
This resolution does not fully address the comment.
The licensee agreed that the response should have been clearer.
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l No violations or deviations were identified.
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9.
Onsite Events Followup (93702)
a.
Inadvertent Actuation of Train A of the Control Room
HVAC System and Subsequent Inoperability of Both Trains.
At 12:28 a.m. (CDT)'on April 16, 1990, with Unit 1 in
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Mode 2, an inadvertent actuation of Train A of the control
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room emergency heating, ventilation, and air-conditioning (HVAC) system occurred when control room HVAC intake
radiation monitor X-RE-5895B was deenergized in preparation i
to troubleshoot and repair X-RE-5895B.
At the time of the
event, the auxiliary operator who was hanging the clearance tagottt for the radiation monitor thought that radiation.
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monitor X-RE-5895B was already deenergized.
It appears that the operator believed this to be true because of an unclear Unit 1 reactor operator log entry of the previous day (8:09 a.m. (CDT)) which noted that X-RE-5895B was "being
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taken out of service."
j For each train of the control room HVAC system, there are two intake radiation monitors.
Deenergizing any one of-the
four radiation monitors, activates both trains of the
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control room emergency HVAC system.
Since Train B was already operating in the emergency recirculation mode at the i
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time of the event, only train.A of the control room HVAC
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system shifted to the emergency recirculation mode.
At 12:36 a.m. on April 15, +.he licensee stopped the. control room HVAC emergency pressurization fan for Train A.
At 2:58 a.m.,
Train B of the control room HVAC system was returned to its normal lineup since radiation monitor
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X-RE-5895B is in Train A of the system.
At the same time, I
the Train A supply fan was secured in accordance with
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Technical Specification 3.3.3.1 and Table 3.3-4, Action 28,
However, at 4:55 p.m. that same day, the licensee determined
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l that both trains of the control room HVAC system were inoperable because both trains were not capable of shifting to the emergency recirculation mode on an automatic l
engineered safety feature (ESF) actuation. signal.
This i
condition existed since 12:28 a.m. that day.
At the time of the discovery, the licensee was still performing corrective
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maintenance on X-RE-5895B.
A-licensee review of the control
l room HVAC wiring diagrafas revealed that with X-RE-5895B
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deenergized, the ESF actuation signal that occurred at 12:28
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a.m. was still locked in even though the control room HVAC
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system had been restored to its normal lineup (with the exception of the Train A supply. fan).
As a result, the system was not espable of shif ting tx) the emergency recirculation mode upon any further ESF actuation signals.
The 12:28 a.m. ESF actuation signal was subsequently cleared
at 5:01 p.m.,
thereby restoring both trains to operable
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-17-l status.
The inadvertent actuation of the control room HVAC system, and the subsequent inoperability of both trains of i
the control room HVAC system will be the subject of further
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o inspection followup pending the issuance of licensee event
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report (LER) 50-445/90-007-00 which will document.these two
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events.
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h.
Spent Resin Spill Durina Transfer Because of Failed l
Transfer Hose
On April 17, 1990, at approximately 3:30 p.m. {cDT),
approximately one-half cubic feet of spent resin spilled on
I to the fuel building floor when the' transfer hose ruptured.
t At the time of the spill, the licensee was transferring i
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approximately 80 cubic feet of spent resin-that was used
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t during hot functional testing.
This spent resin was being
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transferred from the spent resin storage tank to' disposable containers via a fire hose.-
The resin spill was contained i
within the fuel building, sampled (no activity present), and subsequently cleaned'up.
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The inspector was concerned that a fire hose was being used t
in this application.
Discussion ~with licensee personnel revealed that fire hoses were used during previous transfers
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of nonradioactive resin'.
The. hose that ruptured on I
April 17, 1990, was a 2 1/2-inch, 300 psig rated hose.- The A
licensee attributed the' hose failure to degradation because
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maximum resin handling system pressure iss125=psig, which is significantly below the 300 psig~ rating of the hose.
The
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inspector questioned whether the spent resin handling system
procedure specified transfer hose _typeland, usage, as well as
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hose inspection requirements (e.g., hydrostatic testing or
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visual inspection).
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Licensee personnel indicated that ib did'not.. The inspector i
t subsequently reviewed Radwaste Systems' Procedure RWS-302,
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Revision 3, " Spent Resin Handling' System," Section 5.3.2
(resin transfer from the NSSS spent resin storage tank to
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mobile system), and found that the type of home.to be used
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was not specified, nor: was _the-hose installation discussed.-
Additionally, the procedure prerequisites did not require-
l hose inspections prior _to resin transfer.
The inspector
considered these weaknesses to be contributors to the I
April 17, 1990, resin spill.
These weaknesses were discussed with licensee management personnel.
The licensee t
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l indicated that for future resin transfers,.a vendor would be
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utilized, and as such, vendor procedures requiring 1 transfer hose hydrostatic testing would be used.
However, a review of Operations Notification and: Evaluation (One) Form
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FX 90-1440, which documents the resin spill, revealed that
the spill was attributable to-an isolated hose failure and that no further action was-required.
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Subsequent discussions with licensee personnel revealed, however, that the licensee did have controls in place for i
future vendor conducted spent resin transfer operations even though this was not documented in the initial disposition of
One Form FX 90-1440.
The inspector reviewed NRC's e
acceptance of licensing topical report CNSI-DW-11118-01-P l
"CNSI Dewatering Control Process Containers Topical Report."
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A review of this topical report revealed the vendor would i
use hoses that are hydrostatically tested up to 225 psig,
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and that these activities would be governed by a Station
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Operations Review Committee approved procedure.
The
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inspector concluded that the. likelihood of future resin spills because of hose rupture would be significantly
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reduced if such hoses are used.
This issue will remain open pending inspection of future resin transfer operations (445/9013-0-02),
c.
Reactor Trip from High Source Rance Neutron Flux
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on April 21, 1990, at 5:15 p.m. (CDT) with Unit _1 operating at approximately 6 percent power, a reactor trip occurred
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when one SR Channel (N31) was inadvertently reenergized i
thereby causing a reactor trip on high SR neutron flux.
A reactor operator was dusting off the main control board with-i l
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l a foxtail-type brush.
Apparently, the brush came in contact
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with the N31 channel SR reactor trip reset / block handswitch
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causing a reset of-that channel of the source range.
Upon resetting the channel, the source range became reenergized
!
and the reactor immediately tripped (one out of two
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coincidence logic) because reactor power was above the source range high neutron flux trip setpoint. -All1 safety-systems functioned as designed, and the plant was stabilized.
- in Mode 3.
y An inspector was in the-Unit 1 control' room at the time of
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the reactor trip. -The inspector observed that Procedures EOP-0.0, Revision 5,." Reactor Trip or Safety Injection," and-EOS-0.1, Revision 5,." Reactor Trip Response," were properly implemented.
Licensed operator response to the reactor: trip
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and subsequent stabilization of the plant in Mode 3 was considered to be excellent.-
A post-reactor protection
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system actuation evaluation was conducted in accordance with
Operations Department Administrative Proceduro'ODA-108, Revision 3, " Post RPS/ESF. Actuation Evaluation."
Future inspection followup of: the licensee's corrective action will-l be conducted after the issuance of the licensee event report
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for this reactor trip.
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e.
Followup on Source Rance Flux Doublina Actuation Event of April 12, 1990
On April 12, 1990, at 5:26 p.m., with Unit 1 critical in the
source range, a charging pump suction swap over from.the volume control tank (VCT) to the refueling water storage tank (RWST) occurred due to a source range flux doubling
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actuation signal.
Although the swap over occurred at 5:26 p.m.,
the control room operators were not aware of it
.;
until 5: 45 p.m., when the reactor operator noticed that
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reactor power was deegeasing even though'it had been
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stabilized at 1 x 10 amps.' Simultaneously, a VCT high
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level alarm was received.
The operators then immediately blocked the source range flux doubling circuit and realigned the charging pump suction to the RWST.
i The licensee's investigation revealed that two factors
!
contributed to this incident.
First, simultaneous with the I
startup, ISU-204A, " Operational Alignment of nuclear j
Instrumentation," was being performed.
The purpose of this
test was to verify proper overlap between the source and
intermediate range nuclear instruments.
To facilitate this test, the unit supervisor and reactor operator made a
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conscious decision to proceed chrough the source /
intermediate range overlap region at a slower startup rate
than normal.
Second, the two. annunciator windows, one to e
indicate flux doubling, and the other to indicate flux doubling actuation, are located next to one another.
Based
,
on these two factors and the-intermediate range, instrument
traces, the licensee concluded that although-the flux doubling circuit had been blocked early.in the startup (per procedure), it appears.that by proceeding too slowly through
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the overlap region, an imperceptible power reduction at the
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P-6 setpoint could have reset the flux' doubling circuit.
Then, because the annunciators that indicate-flux doubling and flux doubling actuation.are located so close together,
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the operator's glance at the actuation alarm convinced him
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that merely another flux doubling had. occurred, and not an actuation.
The licensee quickly performed several corrective actions to
'
prevent future occurrences.
Specifically,'the licensee
modified the flux doubling actuation annunciator window by, shading it red.
This enhances the contrast between it and the yellow-shaded flux doubling window located next to'it.
Furthermore, the licensee revised the reactor startup procedure, IPO-002A, " Plant Startup from Hot Standby to Minimum Load," to provide for continuous blocking of both trains of flux doubling circuitry by manually holding the l
blocking switches in the BLOCK position, while simultan-l eously increasing power through the source range /
intermediate range overlap region.
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-20-i The resident inspectors will followup on this event subsequent to the issuance of LER 50-445/90-006-00.
j f.
Inverter Failure l
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on April 17, 1990, at approximately 2:35 p.m., with Unit 1 i
in Mode 2 and reactor power at approximately 20 percent
'
Inverter IV1PC-4 failed.
The shift crew response to this l
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event was well coordinated and the. appropriate actions were
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completed in accordance with Operations Procedures ABN-603A
and SOP-311A to. stabilize the' plant and establish the
required bypass power.
As determined by the licensee,
several loose connections were identified at the subject i
inverter and the ferro-resonant transformer output voltage
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was unacceptably low (9 volts).
A similar failure-occurred on March 5, 1990, which involved Inverter IVIPC-1.
The ferro-resonant transformer for Inverter IV1PC-4 was replaced.
with a unit provided from the utilities onsite. spares and
was declared operable on April 18, 1990.
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Subsequently, the licensee determined.that the transformer which was used for a replacement unit for Inverter IV1PC-4 along with the transformers which were. installed as
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replacements in Inverter IV1PC-l'and IV1PC-2 were part of,.a
purchase order of five transformers (P.O. N61-00175) which
had not been evaluated in accordance with Westinghouse i'
Technical Bulletin 84-11.
This Westinghouse technical bulletin addressed the previous' failures.of three
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Westinghouse 7.5 kva static inverters at. comanche. Peak.in l
late 1984.
In particular, these three ferro-resonant
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transformers were returned to the manufacturer for a fault
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analysis, and the nature of the failure was determined to be
shorting between the coil and core of one of two reactors
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connected to thu secondary of the ferro-resonant
transformer.
The manufacturer determined that all three units failed because the laminations making up.the_ center
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log of the G40 reactor coreLshifted and vibrated due to insufficient securing.
This vibration abraded the coil l
insulation and, with operating time,1 wore through the coil
insulation.
The manufacturer also determined that the
L problem becomes progressively worse as the unit.is operated,
rapidly deteriorating the insulation,:resulting.in the core to coil short.
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At the conclusion of this reporting period,.theflicensee had-
not completed their evaluation of this event in-that the definitive reason for not using refurbished ferro-resonant
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transformers as. replacements for Inverter IV1PC-1,
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and -4 had not been established.
Additionally, several TUGCO ctock numbered.(TSNs) items were identified late in the reporting period including one pump-
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assembly motor and three Limitorque motor operated valves which did not appear to be properly incorporated into the i
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licensee's preventive maintenance program as defined in i
Station Procedure STA-677.
Therefore, pending further j
inspection activities in the area of replacement component
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control and preventive maintenance program concerns, this
issue is-identified as an open item (445/9013-0-03;
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446/9013-0-03).
g.
Auxiliary Feedwater System Check Valve Backleakage
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i on April 24, 1990, with the main turbine on line at' low
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power, plant operators observed that auxiliary feedwater (AFW) system discharge piping temperatures indicated in the
,
control room increased above ambient.- This was believed to
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be caused by backleakage into the APW system from main feedwater.
The licensee-took' action to-seat the'AFW system check valves using Procedure ABN-305A, " Auxiliary Feedwater
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Malfunction."
The licensee promptly established a task team to evaluate this instance of check valve backleakage.
The AFW system
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was deter;ained to be operable even with-the minor I
backleakage and pipe and pipe-support stress levels were
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found to be acceptable.1 TheJ11censee determined that the-AFW check valves-were not" stuck ~open as'some of them were in
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1989 but that the. valves allowed reverse flow after minor leakage eliminated the differential pressure across the
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valves.
Without'a' differential pressure,'the Borg-Warner.
t 4-inch pressure seal. check 1 valves'do not make full contact between their disks and seats.. This allowed main feedwater i
to flow back through an-AFWfcheck valvefand:back to another l
main feedwater line with-slightly lower? pressure.
Various
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short term options were-considered to< prevent this back
flow.
The ce: ion selected. involved installation of additional temperature and' pressure instrumentation on the
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AFW lines and venting the AFW lines upstream of the check valves to maintain a differential pressuresto keep the i
valves seated.
One of the longer term; options considered
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was' modification of the: valves to assure that the valves
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seat under low differential pressure conditions.
,
i subsequent to opening the main feedwater. isolation valves l
and closing the prehenter bypass valves, the licensee found
'
that two of the preheater bypass valves leaked by, allowing backleakage into the AFW system.
However, after the
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preheater bypass valve isolation valves were closed, the leakage stopped and AFW lineLtemperatures returned to
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ambient.
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To discuss the AFW system further, a meeting of licensee and NRC site, region, and headquarters personnel was scheduled i
for May 9, 1990.
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The AFW system's problems with backleakage through check
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valves will be reviewed further by both the licensee and the
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NRC.
This is an open item (445/9013-0-04).-
l 10.
Initial Criticality Witnessino-(72592)'
I The inspectors provided around-the-clock inspection coverage of the licensee's approach to and attainment-of Unit 1 initial
o criticality.
This evolution was conducted in accordance with Procedure NUC-106, Revision 2) " Initial Criticality."
On
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April 2, 1990, at 6:03 p.m.,
after verifying the prerequisites-
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for Procedure NUC-106, the licensee commenced reactor startup by withdrawing shutdown Bank A control rods.
Unit 1 entered Mode 2
at 9:01 p.m. upon the withdrawal of:all shutdown banks.
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The startup continued with the withdrawal!of-the_ control bank-control rods.
While pulling Control Bank C,:the Rod Insertion.
Limit (RIL) cleared 10 steps higher than expected.
The licensee
determined that this discrepancy had no safety significance and i'
issued a procedure change notice (PCN) to ProcedureLNUC-106 to eliminate the RIL acceptance criteria.
After withdrawing control banks to a predetermined' level,-the reactor startup continued l
with the dilution of the boron concentration in the reactor
coolant system.
During the rod withdrawal and boron dilution process, the I
licensee maintained a continuous monitoring effort.to determine
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the reactivity margin to criticality.
.This activity was performed in accordance with Procedure NUC-111,'" Increase Count
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Rate Ratio (ICRR) Monitoring."
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Criticality was achieved on April'3, 1990, at 5:52 p.m., with Control Bank D at 141 steps and a. boron < concentration of approximately 1155 ppm in,the reactor coolant system and 1166 ppm in the pressurizer.
The estimated critical concentration was
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1146 ppm Boron with Control Bank'D at 160 steps.- The deviation from estimated critical conditions-was well within the limit of 500 pcm which Procedure NUC-106 delineated as the threshold of a core performance anomaly.
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The inspector observed the nuclear instrumentation overlap
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licensee nuclear engineers that the overlap was successful.
The j
inspector observed no procedural deviations or operator errors during the reactor startup and noted that communication amongst control room operstors was excellent.. The overall effort showed excellent crew training and preparation.
The inspector verified
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i the accuracy of the estimated critical concentration calculation and concluded that the core had performed as expected.
No violations or deviations were identified.
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11.
TMI Action Items (SIMS)* (25565)
- The Safety Issue Management System (SIMS) tracking number is the-i same as the TMI Action Item number.
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a.
(Closed) TMI Action Item II.E.4.2.6 Containment Purge.
l Valves.
This item was addressed in NRC Inspection Reports
50-445/89-17; 50-446/89-17 and 50-445/90-028 50-446/90-02, and had remained open pending-inspector verification that the 18-inch valves are limited to a maximum opening of 65.
The inspector reviewed Test' Data Sheet XCP-EE-11, l
Revision S, page 8 of.8, for each valve and verified ghat i
the valves were limited to an opening of less than 65.
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During the review of this system, the inspector became i
concerned that the system piping inside containment and the
system duct outside containment may not be strong enough to withstand the transient pressures resulting from a Loss of
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Coolant Accident during the time the valves are closing.
l The licensee performed a review and determined that the piping and ducting was adequate.
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This TMI Action Item is considered closed.
l b.
(Closed) TMI Action Item II.K.3.10:
Proposed anticipatory trip modification.
This item was previously addressed in NRC Inspection Report 50-445/89-24; 50-446/89-24 and was-closed based upon the inspector's verification that the anticipatory reactor trip is not blocked above 10% power.
The licensee has since modified this trip such that the trip
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is blocked up to 50% power.
The TKILAction Item indicated
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that such modification should not be made until it has been shown on a plant specific basis that the probability of a i
small-break loss of_ coolant accident (SBLOCA) resulting from i
a stuck open pcwer operated relief valve (PORV) is unaffected by this modification.
I The inspector reviewed the Westinghouse evaluation of this subject, " Evaluation of the Potential for Increased
Pressurizer PORV Opening Resulting from Turbine Trip'Without Reactor Trip Below 50% Power (P-9 Setpoint Study) for
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Comanche' Peak," which was transmitted to TU Electric by-
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Westinghouse letter WPT-ll810 dated August 10, 1989.
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This evaluation concluded'the following:'
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(1)
For normal plant operation with all normal control systems assumed operational, the implementation of a
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system (P-9 permissive) that permits a turbine trip j
without actuating a direct r6 actor trip below 50% power
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will not result in opening the pressurizer power-operated relief valves.
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I (2)
For any single failure in the control system that was
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considered in the analysis, the implementation-of a system (P-9 permissive) that permits a turbine trip
without a direct reactor trip below 50% power will not l
result in opening of the pressurizer power-operated s
relief valves.
(3)
The P-9 interlock function can be implemented on the Comanche Peak Units with a setpoint of 50%'pcwer.
A turbine trip without' reactor trip at or below 50% power does not pose any undue or additional challenges to the i
pressurizer PORVs.
Assuming all control systems are l'
operable, neither the RCS PORVs nor the steam generator PORVs reached their. respective-pressure setpoints.
Even when single credible failures in the control l
systems are considered, the pressurizer PORVs do not i
reach their setpointe; this satisfies the intent of the concerns addressed in NUREG-0737, Item.II-K.3.10.
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The inspector determined that the evaluation showed adequate I
margin to the PORV setpoints.
Therefore, this TMI item-remains closed.
l 12.
Action on Previous Inspection Findings (92701)
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(closed) Open Item (445/8921-0-05):
Post-accident sampling
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system (PASS).
This. item remained open pending the following:
Verification of system performance by: collecting
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samples of reactor coolant and containment atmosphere under simulated accident conditions and performing required comparative analyses with routine analyses of
the reactor coolant and containment atmosphere to verify representative sampling.
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Testing and calibration.of the in-line analytical-
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instrumentation-and the development and-implementation of a preventive raaintenance. and QC program on the PASS.
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Resolution of internal QA audit deficiencies.
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t on April 10 and 11, 1990, the inspector observed' portions of the PASS (reactor coolant system and containment air)
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procedure performance including selected sample analysis.
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The results of the PASS sample analysis were compared with-routine samples of the Reactor Coolant. System (RCS) and
containment air.
Although some parameters were too low to
provide a positive comparison, only one discrepancy was
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noted, The RCS dissolved oxygen results were lauch highgr
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than actual concentrations.- The licenseo suspects the
syringe needle used for this analysis. allowed introduction i
of outside air.
Procedural changes are being evaluated to
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correct this problem.
Since dissolved oxygen concentration t
is not a required parameter, the inspector considers the PASS demonstration successful.
During the demonstration, the inspector verified that the instruments used during this process'had been calibrated and that periodic preventive maintenance is performed to ensure
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the operability of the PASS.
The inspector reviewed the QA audit deficiencies and
verified that they were appropriately resolved.
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This item is. considered closed.-
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b.
(Closed) Open Item (445/8990-0-01):
Licensee to provide
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analysis of use of detentioned reactor vessel head as hot leg vent path.
The inspector. reviewed Procedure-Change l
Notice (PCN) IPO-010A-R2-2,-dated January 16,'1990, to Procedure.IPO-010a, " Reactor Coolant System (RCS) Mid-Loop i
operations."
This change: deleted authorization.to install
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steam generator nozzle dams and thereby the need for hot leg i
vents.
Therefore, this. issue is considered closed.-
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However, it should be reconsidered if the licensee should reestablish the option of using steam generator. nozzle dams
in the future.
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(closed) Open Item 445/8990-0-02):- Licensee should complete
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Attachment 7 to Procedure'IPO-010A,: "Available. Time for Containment Closure vs. Decay Heat Generation Rate."
The-
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inspector reviewed PCN IPO-010A-R2-5 dated April-12, 1990, l
to Procedure IPO-010A which supplemented Attachment 7 with
two curvas
'I Available Time for containment. Closure Versus Decay i
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Heat Generation Rate.-
l Available Time for Containment Closure Versus Time
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After Shutdown.
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The inspector also reviewed supporting Calculation-ME-CA-0250-2155, dated April 6, 1990.
The assumptions-used appeared reasonable.
For containment closure within the j
time-limits provided by the curves,.offsite dose consequences for a loss of decay heat removal event would be i
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negligible.
The time limits were based on quarterly i
radionuclide inhalation limits for personnel in containment H
at the time of the event and involvea in containment closure
activities.
Tnis item is consioeted closed.
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d.
(Closed) Open Item (445/8990-0-03):
Licensee should include appropriate requirements in Procedure IPO-010A for
monitoring residual heat removal (RHR) pump motor-current
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l during draining to nud-loop and draining of steam generator tubes.
The licensee established a requirement in.
Step 5.1.12A) of Procedure IPO-010A, Revision 2,.for continuous monitoring of RHR pump motor current during the RCS draining evolution.
This resolves the inspector's concern.
e.
(Closed) Open Item (445/8990-0-04):
This open item involved the licensee's commitment to provide proceduralized
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i refresher training and briefings for maintenance,. planning,
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work control, and test. personnel prior to entry into reduced s
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inventory operation..The' inspector determined that Procedure IPO-010A, Revision 2, Attachment 1,
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-paragraph 1.0.a, appropriately incorporated the above requirements.
Therefore, this item is closed.
13.
Followup on Violations / Deviations (92702)
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(Closed) Violation-(445/9003-V-01):
This violation involved the.
licensee's failure to analyze:the service water intake structure (SWIS) for a groundwater level consistent with the maximum level-expected over the service lifetime of-this building.
In response to an NRC open item,-the licensee reanalyzed the~SWIS for a
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groundwater level of 783 feet, but this assumed level was still below actual. groundwater' level readings.taken in 1988 (maximum level recorded was 783.2. feet).
In response to the subject s
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violation, the' licensee reanalyzed the SWIS for_a3 groundwater-level of 793 feet (Calculation CS-CA-0000-2183,: Revision 0).which represents the probable maxim'um flood level"of the safe shutdown impoundment (SSI) including wave runup at the SWIS.
It is extremely unlikely that the groundwater level at the SWIS would exceed'the maximum flood level of the SSIt therefore, the assumed
level'of 793 feet is conservative.- The licensee revised Design Basis Documents DBD-CS-084, Revision 2, "Other Seismic Category I Concrete Structures," and DBD-CS-091, Revision 1, " Foundation i
Material' Properties,"'to reflect the higher assumed SWIS groundwater level.
The' inspector reviewed' Calculation CS-CA-000-2183, Revision'0, and concurred that this calculation proved that the SWIS is~
adequately constructed for a 793-foot groundwater level.
The manager of Civil / Structural Engineering' issued Office Memorandum CPSES-9006065 to emphasize the need to sufficiently justify i
variables ~ assumed as design input.
The inspector verified the
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associated revisions to DBD-CS-084 and DBD-CS-091, and concluded that the licensee had taken adequate action to resolve this.
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issue.
This violation is closed.
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14.
Regulatory Guide 1.58 Educational Requirements (35502)
The NRC received an anonymous concern regarding a-QC manager who had recently been disciplined for falsification of employment application records.
The inspector reviewed the licensee's information concerning this issue and determined that the i
individual held NDE certifications while not meeting the educational commitment of RG 1.58-(must be a high school. graduate or have earned the General Education Development equivalent) for
the period 1981-1987.
This is a deviation from the CPSES FSAR (445/9013-D-05; 446/9013-D-05).
CPSES FSAR Table 17.2-2,'" Regulatory Guides and Standards,"
states that TU Electric will comply with NRC Regulatory Guide 1.58, " Qualification of Nuclear Power Plant Inspection, Examination, and Testing' Personnel," which endorses ANSI N45.2.6-1978, " Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants.'"=
ANSI N45.2.6-1978, Section'3.5, recommends that Level I, II, and III personnel must be high school graduates.- NRC Regulatory i
Guide 1.58 upgrados.this recommendation to a requirement and
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states, in effect, that Level I, II, and III personnel must be
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high school graduates or have earned the General Education Development equivalent of a high school diploma.
The licensee initiated deficiency report (DR)-89-1981 to evaluate the technical impact of the individual.not meeting RG 1.58 educational requirements.
The DR concluded that there was no impact from the deviation and that procedures had been in place
for some time to preclude recurrence-of a similar incident.
i The NRC inspector reviewed DR-89-1981 and concluded that no i
safety or quality degradation was associated with this incident.
I Furthermore, the measures taken by the licensee appeared adequate
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throughout-the history of-the case, recognizing that standards
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and requirements had become increasingly stringent with time, The licensee has fully implemented effective corrective and
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preventive actions; consequently, this deviation (445/9013-D-05; 446/9013-D-05) is closed.
15.
Followup on Allegations (55100)
(Closed) Allegation (OSP-90-A-0014):
This allegation involved-worker concerns associated with the licensee's permanently-installed plant welding. system.
Specifically, CPSES utilizes a locally mounted system which was originally manufactured and supplied by Neoweld~ Corporation.
This-system currently consists
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l of a combination of Neoweld,. Big 4, and Westinghouse units which typically incorporate a 1500 amp power-supply with a 1000 amp and a 500 amp input to a dual polarity frame.
These components are installed in various locations throughout Unit'l and. Unit 2 and l
provide an established shielded metal arc welding system.
In
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response to a list of concerns involving inadequate electrical grounding of the installed welding. equipment which is generally characterized as the Neoweld system, the inspector reviewed the-design configuration and installation characteristics of these units.
This review included an examination of both the SAFETEAM response and the corporate' security investigation of this issue.
Additionally, the inspector evaluated several reference nonconformance reports concerning. welding discrepancies / damage and examined selected' sections of the manufacturer's equipment description and operational information.
Subsequent to the above review and documentation evaluations, the inspector determined-that the licensee had initiated a design.
modification (DM-90-79) to the installed welding system.' This design modification will alter the existing Neoweld grounding system to provide a-direct return path to the-welding machine rather than utilizing;the installed plant ground; system.=
This modification is currently scheduled for approval and milestone, incorporation for Unit 1 and common.
However,2the. corresponding work for Unit 2 has not yet been scheduled.
Based on the above noted, inspection activities, it was determined that the-licensee's corrective actions appeared to be technically adequate and responsive to the subject' concerns...Therefore, this allegation is closed for Unit 1.
However,:pending the I
implementation of similar corrective actions, this' item will I
remain open for Unit 2.
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16.
Unit 2 Walkdowns-(71302)
During this inspection period, routine tours of the Unit 2
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facility were conducted in order to assess equipment conditions, l
security, and adherence.to regulatory requirements.
In particular, plant' areas were examined for evidence of fire hazards, installed-instrumentation < damage, and to determine the acceptability of system cleanliness controls and general housekeeping.
Additionally, the inspector conducted' evaluations of existing plant programs for the preservation and maintenance-of installed systems and components as well as the utility's preparations for the resumption of construction' activities for, Unit 2.
During the conduct of routine Unit 2 tours, itLwas' determined
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that identifiable improvements in general plant housekeeping and the control and storage of temporary equipment have~been implemented by the Unit 2 construction organization.- These improvements were evident both inside the containment structure
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and in the auxiliary and safeguards buildings.
These l
improvements have enhanced the accessibility of-plant equipment
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and have improved the control of stored Q-listed and non-Q-listed components.
Within the areas inspected, no violations or deviations were i
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identified.
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i 17.
Open Items i
Open items are matters which have been discussed with,the licensee, which will be reviewed further by the inspector, and which involvo some action on the part of the NRC or licensee or both.
Four open items disclosed during the inspection are
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discussed in paragraph 7 and 9.
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18.
Exit Meetina (30703)
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P An exit meeting was conducted:on May 2,.1990, with the licensee's representatives identified in paragraph 1 of this report.
No
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written material was provided to the licensee by the inspectors
during this reporting period.
The licensee did not identify as
I proprietary any of the materials provided to or reviewed by the
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inspectors during this inspection.
During'this meeting, the NRC~
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inspectors summarized the scope and findings of,the inspection.
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