IR 05000271/1988008
| ML20150F822 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee  |
| Issue date: | 07/08/1988 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20150F818 | List: |
| References | |
| 50-271-88-08, 50-271-88-8, IEIN-88-008, IEIN-88-022, IEIN-88-22, IEIN-88-8, NUDOCS 8807190074 | |
| Download: ML20150F822 (27) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No, 50-271/88-08 Docket N License Na, DPR-28 Licensee: Vermont Yankee Nuclear Power Corporation RD 5, Box 169 Brattleboro, Vermont 05301 Facility: Vermont Yankee Nuclear Power Station Inspection At: Vernon, Vermont Inspection Conducted: May 17, 1988 - June 30, 1988 Inspectors: Geoffrey E. Grant, Senior Resident Inspector Joh B. Macdonal , Resident Inspector Approved by: th: 8[#g Don ld R. HavtrT4mp, r Chief Oate Reactor Projects Section No. 3C Inspection Summary: Inspection on May_17, 1988 - June 30, 1988 (Report No. 50-271/88-08)
Areas Inspected: Routine inspection on daytime and backshifts by two resident inspectors of: actions on previous inspection findings; operational safety; security; plant operations; maintenance and surveillance; engineering support; !
radiological controls; licensee event reports; licensee response to NRC initiatives; and, periodic report Results: General Conclusion . on Adequacy, Strength or Weakness in the Licensee's Program The licensee past practice of viewing installation of Tygon tubing on various plant systems as a "housekeeping" action vice a petential modifi-cation has been inadequate. In the case of tubing installation on the standby gas treatment (SBGT) system, this practice could have resulted in degradation / damage to the "B" train (Section 6.4).
The licensee's one-week mini outage commencing June 24, 1988 was a well-planned and executed effort. A significant maintenance effort effectively addressed many maintenance requests as well as the major outage activ-
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itie Interdepartmental communication and coordination was evident and resulted in successful accomp31shment of all planned activities as well as some issues arising after plant shutdown (Section 7.2).
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8807190074 880708 PDR ADOCK 05000271 O PDC ,
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- Inspection Summary (Continued) 2 New Unresolved Items Identified Unresolved items identified during this inspection period concerned:
licensee establishment of a fuel oil sampling program in accordance with ASTM 0975-68 Table I and TS 4.10.C.2 (Section 6.2); licensee evaluation of the fuel oil system quality assurance program (Section 6.2); defici-encies in the licensee post-trip review process (Section 6.3); licensee action to correct problems associated with installation control of tem-porary tubing (Section 6.4); licensee review of event notification methodology (Section 6.5); licensee action to prevent / mitigate future activity release via the radwaste building cask room (Section 8.2); and, licensee issuance of a revision to LER 88-05 to clarify the operability determination of "B" SBGT (Section 9.2).
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TABLE OF CONTENTS PAGE 1. Persons Contacted. . . . . . . . . . . . . . . . . . . 1 2. Summary of Facility Activities . . . . . . . . . . . . 1 2.1 Facility Activities . . . . . . . . . . . . . . . 1 2.2 Union Labor Contract Settlement . . . . . . . . . 2 3. Status of Previous Findings (IP 92701) . . . . . . . . 2 3.1 (Closed) Follow Item 83-17-09:
Review Upgrade of the Service Water System (SW)
Pipe Supports and Corrective Actions for YAEC. . . 2 3.2 (Closed) Unresolved Item 84-01-04:
Revise Procedures to Ensure Isolation of Outboard Feedwater Motor Operated Isolation Valves . . . . 2 3.3 (Closed) Follow Item 84-00-02:
Inspector Review of the Maintenance History of the Uninterruptable Power Supply (UPS) System . . 3 3.4 (Closed) Follow Item 84-21-05:
Resolve Concerns Identified with Respect to OP 3126, "Shutdown Using Alternate Shutdown Methods". . . . . . . . . . . . . . . . . . . . . 3 3.5 (Closed) Follow Item 84-21-14:
Review of Personnel Adherence to Procedures . . . 4 3.6 (Closed) Unresolved Item 85-23-06:
Disposition of 10 CFR Part 21, Evaluation of Components Supplied by Aloyco Company . . . . . . 4 3.7 (Closed) Unresolved Item 86-08-01:
Review of the Seismic Analysis for the Safety-related Cells of the West Cooling Tower . . . . . 5 3.8 (Closed) Unresolved Item 86-04-01:
Review of MOV Performance . . . . . . . . . . . . 5 3.9 (Closed) Unresolved Item 86-08-04:
Review Status of Proposed TS Change to Authorize l Single Loop Operation . . . .. . . . . . . . . . 5 3.10 (Closed) Unresolved Item 87-06-03: i Followup of Con erned Individual. . . . . . . . . 6 3.11 (Closed) Unresolved Item 87-06-04:
Improvements in Main Steamline Radiation Monitor Calibration Practices . . . . . . . . . . . . . . 6 4 3.12 (Closed) Unresolved Item 87-09-01: !
Drywell and Torus Air Temperature Instrumentation !
Upgrades. . . . . . . . . . . . . . . . . . . . . 6 1
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PAGE , Operational Safety (IP 71707, 71710) . . . ..... 6
- 4.1 Plant-Operations Review , . . . . . . . . . . . .
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- 4.2 Safety System Review. . . . . . . . , . . . . . .- 7
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4.3 Feedwater Leak. Detection System . . .' . . . . . . 7 t 4.4 Inoperable Equipment. .............. 8 l 4.5 Review of Lifted Leads, Jumpers and Mechahical Bypasses. . . . . . . . . . . . . . . . . . . . .
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, 4.6 Review of Switching and Tagging Operations. . . . 9 4.7 Operational Safety Findings . . . . . . . . . . . 9
, Security (IP 71707). . . . . . . . . ........ 9 5.1 Observations of Physical Security . . . . . . . . 9 l PlantOperations(IP 71707, 93702, 82201, 94703) . . . 9 6.1 Reactor Trip - June 18, 1988. . . . . . . . . . . 9 :
6.2 Emergency Diesel Generator Fuel Suppiy. . . . . . 10 6.3 Reactor Trip - June 24, 1988. . . . . . . . . . . 13 .
6.4 Uncontrolled Maintenance on Standby Gas Treatment System. .................... . 13 6.5 Event Noti fication. . . . . . . . . . . . . . . . 14 Maintenance / Surveillance (IP 71710, 61726, 62703, !
- 61700) . . . . . . . . . . . . . . . . . . . . . . . . 15 7.1 Emergency Diesel Generator Maintenance. . . . . . 15 ,
7.E Outage Activities . . . . . . . . . . . . . . . . 16 )
- Radiological Controls (IP 71707) . . . . . . . . . . . 17 l i 8.1 Contaminated Sewage Sludge. . . . . . . . . . . . 17
- 8.2 Contamination Outside Radwaste Building . . . . . 19 I Licensee Event Reporting (LER) (IP 90712, 92700) . . . 20 -
9.1 LER 88-04 . . . . . . . . . . . . . . . . . . . . 20
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9.2 LER 88-05 . . . . . . . . . . . . . . . . . . . . 20 i
1 Review of Licensee Response to NRC Initiatives l (IP 92703) . . . . . . . . . . . . . . . . . . . , . . 21 l l
10.1 NRC Information Notice'88-08: Potential for Loss of Post-LOCA Recirculation Capability Due to
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Insulation Debris Blockage. . . . . . . . . . . . 21
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Table of Contents (Continued)
l PAGE 1 Review of Periodic and Special Reports (IP 90713). . . 21 12. Management Meetings (IP 30703, 40700). . . . . . . . . 22
- The NRC Inspection Manual inspecticn procedure (IP) or temporary instruction (TI) or the Region I temporary instruction (R1 TI) that was used as inspection guidance is listed for each applicable report sectio I l
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I DETAILS 1. Persons Contacted Interviews and discussions were conducs a th members of the licensee staff and management during the report r J to obtain inform 6 tion per-tinent to the - areas inspecte Inspec findings were discussed per-iodically with the management and supervisory personnel listed belo M6 P. Donnelly, Maintenance Superintendent Mr. R. Grippardi, Quality Assurance Supervisor Mr. S. Jefferson, Assistant to Plant Superintendent Mr. G. Johnson, Operations Supervisor Mr. R. Lopriore, Maintenance Supervisor
- Mr. R. Pagodin, Technical Services Superintendent
- Mr. J. Polletier, Plant Manager
- Mr. R. Wanczyk, Operations Superintendent Mr. T. Watson, I & C Supervisor
- Attendee at post-inspection exit meeting conducted on July 6, 198 . Summary of Facility Activities 2.1 Facility Activities
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Vermont Yankee Nuclear Power Station (VYNPS) continued full power operations during the majority of this period with pre planned power reductions to accomplish required surveillance A reactor trip occurred on June 18, 1988 due to a high reactor water 'evel c a sed by-a failure in the feed,/atar control system (see Section 6.1). The plant returned to full power on June 20. A reactor trip ov urred i again on June 24 due to a mtin turbine crip on bigh bearing vibration ;
caused by an instrument failure (see Secion 6.2). The plant trip coincided with the scheduled start of a pre planned outage which commenced on June 24 ar.d was r. earing completion at the end of the-report period (see Mtion 7.0), j An NRC Region I specialist performed an inspection of the VYNPS d security program during the period May 23-27,1988_(Inspectior. Report !
88-07). An NRC:NRR team inspection of VYNPS Emergency Opercting ~l Procedures was conducted during the period June 1-10, 1988 (Inspec-tion Report 88-200).
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. 2 2.2 Union Labor Contract Sottlement On June 17, 1988, one day af ter rejecting the original proposal, VYNPC union employees (IBEW LOCAL 300) voted to ratify an . amended labor contrac The existing contract expired at midnight on June 17, 198 Approximately 116 of' the 227 VYNPC employees onsite 'are union members including liceised control room ' operators, licensed auxiliary control room operatws, auxiliary operators, chemistry and HP technicians, maintenance plant mechanics and utilitymen, as well as stores and clerical personne Had an agreement not been reached
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the possibilty existed that the union members may not have reported to work or may not have been permitted to work - af ter midnigh June 17, l'0 Licensee management had formulated a strike contingency plan in the event that a work action occurre The plan ensured that minimum technical specification, emergency plan and administrative procedures staffing levels would be maintained by properly trained and qualified personnel on a four shif t rotatio The plant security force is non-unionized and was unaffected by the negotiations. The inspectors had no further question . Status of Previous Inspection Findings 3.1 (Closed) Follow Item 83-17-09: Review Upgrade of the h rvice Water (SW) System Flpe Supports and Corrective Actions for YAE On June 8, 1983, YAEC informed VYNPC that it had auumed incorrect stress values for the process piping (during the 1981 modification from carbon steel to copper) when . calculating pipe support spacing such that the supports were spaced too far apart. The support spac-ing on the affected SW piping was corrected via EDCR 83-21 which was completed December 12, 198 Further, YAEC engineering - ine.truction WE-103, "Engineering Calculations and Analysis" was revised to include a checklist of criteria to be considered by the independant reviewer when mechanical calculations are involved in the audit process. This item is close .2 (Closed) Unresolved Item 84-01-04: Revise Procedures to Ensure Isolation of Outboard Feedwater Motor Operated Isolation Valve On August 19, 1983, the NRC issued an exemption from certain require-ments of 10 CFR 50 Appendix J. Included in the exemption was the exclusion of the it ocard feedwater check valves from the Type C test requirement The safety evaluation accompanying the exemption stated that the licensee should ensure that emergency procedures are in effect to close the outboard feedwater motor operated valves when-eve * containment isolation is necessary. At present, if a feedwater line rupture occurred, off normal procedure (0N) 3158, "Reactor-Building High Area Temperature / Water Level", would be entered which directs the operator to determine and isolate the rupture. This item is close _. _ _ ,,_ . , , _ _
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, 3.3 (Closed) Follow Item 84-08-02: Inspector Review of the' Maintenance History of the Uninterruptable Power Supply (UPS) Syste The inspectors reviewed.the UPS failures from 1985.to 1987 as well as the March 29 and April 8-9, 1988 failures (documented in Inspection Report- 50-271/88-06). It appears that the UPS failure rate will con-tinue to meet or exceed the upper control limit, defined by the main-tenance department, as it has the past.several years. The cause of the failure trend is random failure of inverter components as a result of equipment age and a less than optimal application for the inverter design. The inspectors will continue to track the UPS sys-tem performance during . routine inspection. This item is close .4 (Closed) Follow Item 84-21-05: Resolve Concerns Identified with Respect to OP 3126, "Shutdown Using Alternate Shutdown Methods".
31x items were identified for resolution with respect to OP 312 The concerns and corrective actions as reviewed in OP 3126, Revision 3, are:
(1) Originally OP 3126 was written to be performed by a shift super-visor and four operators for a minimum crew of' five ;aopl However, if a fire emergency was declared, a designated auxil-iary operator from the five-man crew would become a fire brigade member and therefore be unavailable to be used for shutdow ;1a) Revision 3 to OP 3126 identifies a five-man crew for a non-fire emergency remote shutdown and a four-man crew, _ with the shif t supervisor assuming the number one operator duties, for a remote shutdown with a fire emergency declare (2) A. site area emergency must be declared immediately upon entering intt OP 3126. Staffing levels assumed ,in OP 3126 would be in-adequate to support all required notification (2a) The duty call officer (OCO) is instructed by AP.0032, "Duty and Call Officers", to e 'st the shift supervisor' during emergency conditions. The sh ' ;upervisor can delegate the authority to ensure appropriate notification to the DC (3) The shift supervisor is not directed by 09 319.6' to a . specific plant station to accomplish a remote shutdown from outside the control roc (3a) This specific issue was addressed. and closed in Inspection Report 50-271/88-03 Section 3.1 The licensee has elected to provide the shif t supervisor with the latitude to assess plant conditions and then proceed to the location where his effective-ness would be maximize . . _- . . . .. -.
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4 l (4) A previous revision of OP 3'.26 incorrectly identified flow instrumentation for RCIC local flow indicatio (4a) Appendix D to OP 3126, Revision 3, correctly identifies flow instrument FI-13-61 for RCIC local flow indicatio (5) The ca fety relief valve (SRV) local operation switch was not labeled in accordance with OP 3126 instruction (Sa) The SRV local operation switch has been verified to have been properly labeled with open/ closed position indicatio (6) It was noted during a walkdown of OP 3126 that prepositioned copies of the procedures were not available at alternate shut-down panels and that labeling at minor panels could be enhance (6a) Prepositioned control copies of.0P 3126 are adminstrative1y con-trolled at each initial shutdown station. A recent Appendix R team inspection and walkdown of OP 3126 indicated that component labeling was sufficient to ensure operator performance of the alternate shutdown procedur A comprehensive Appendix R team inspection was performed by Region I specialists on February 8-11,1988 (Inspection Report 50-271/88-04).
The team performed an in-depth review of OP 3126 followed by a walk-through of an alternate shutdown scenario accomplished by a four-member operations crew (as would be available if a fire e :ergency were declared). The walkdown indicated that the licensee adaquately demonstrated the ability to achieve hot shutdown condition The inspectors had no further questions regarding the concerns abov This itern was close .5 (Closed) Follow Item 84-21-14; Review sf Personnel Adherence to
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Procedure. The licensee has taken measures to reduce the potential
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for personnel errors resulting from the fa' lure to follow approved plant procedure The procedure writers guide ' AP. 0831 "Plant Pro-cedures", RevSton 13, establishes a uniform procedure format for writing, iuplei..enting and reviewing procedure Inspector review of recent events does not indicate a disregard for. procedural com-plianc This item is close .6 (Closed' Unresolved Item 85-23-06: Disposition of 10 CFR Part 21, Evaluat'on of Components Supplied by Aloyco Compan On June 27, 1985, the licensee generated a potential reportable occur-
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rence (PRO) report detailing material and documentation deficiencies identified during che receipt inspection of valve wedges manufactured by Aloyco Compan Licensee management concluded that this occur-rence was not repertable under the requirements of 10 CFR 50.72 or 50.73. Further engineering evaluations were required to deter.mine reportability of this occurrence under the requirements of 10 CFR
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. 5 Part 21. Ultimately, on November 12, 1986, the lice m e determined, based on engineering evaluations performed by YAEC, that this ' occur-rence is not reportable under Part 21. The YAEC evaluation, docu-mented by memo VYS 134/86, dated October 3,1986, concluded that .th stress cracking of the valve wedges is limited to the _ weld overlay material and would not propogate to the wedge material. A sed on the minimal impact the cracking would have on the integrity of the wedge-and the very minor service stresses create;t by valve operation, the evaluation concludeo that gross failure of the wedge would not occur as s result of the weld overlay cracks. dasea- on this- evaluation, the licensee determined that a significant safety hazard as defined in 10 CFR Part 21 does not exis Aloyco Company was dissolved in February 1986. Crane Valves pur-chased the patents and_ now assumes present and future engineering, management and fabrication at their _ own facilitie This item-is close .7 .(Closed) Unresolved Item 86-08-01: Review of the Seismic Analysis for the Safety-related Cells of the West Cooling Towe The inspec-tor reviewed the engineering analysis to PDCR 86-02 to ensure that
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the seismic qualification of the #1 and #2 cells of the west cooling tower was restored to the scope of the current seismic analysis. The 1980 "E-fix modification" static seismic loading analysis concluded that seismic qualification of the #1 and #2 cells was not adversely affected and therefore that PRO 86-20 was not reportable. This item is close .8 (Closed) Unresolved Item 86-04-01: Review of MOVPerformailc A !
licensee review of MOV performance and failures was initiated follow- l ing the 1985 discovery of a crack on the. operator housing for the ;
HPCI full flow test valve, V23-24, actuator. Operator housing ' fail ~
ures are not an uncommon industry occurrence. Fifteen such industry failures were reported from 1983-1986. The failures' appear to have been caused by improperly set torque switches and limit svitches; component age was not a facto The licensee has estabilshed a M0 VATS testing program for all safety system motor operated valve The inspectors routinely monitor MOV surveillance as well as pre-ventive and corrective MOV maintenance. This item is close .9 (Closed) Unresolved Item 86-08-04: Review Status of Proposed TS Change to Authorize Single Loop Operatio On August 8, 1986, the NRC issued Amendment 94 to the VYNPS operating station. The amend--
ment revised TS to permit extended ~ operation with one recirculation loop out'of servic This item is close . .
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. 6 3.10 (Closed) Unresolved Item 87-06-03: Followup of Concerned Individua In April 1987 the licensee informed the resident inspector of a former YNSD QA inspector's intention to contact the NRC to: express personal concerns about the ~ onsite Operational Quality Group. The individual resigned from YNSD due to personal conflicts with another individual onsit The inspector considered the concerns to be licensee internal matters (see IR 87-06). To date, the NRC has not been contacted by this individua This item is close .11 (Closed) Unresolved Item 87-06-04: Improvements in Main Steamline Radiatica Monitor Calibration Practices. In March 1987 the inspector noted that the licensee was expsriencing problems maintaining the main steamline radiation monitors alarm setpoints within TS and administrative limits between calibrations. The setpoint drift was i inainly attributed to the recalibration process which required the ;
removal. of the instrument drawer cover, exposing the electrometer l tube to the environment (light and temperature). The licensee i installed a grommeted hole in the drawer cover to allow calibration ;
adjustments to be accomplished without removing the drawer cove ;
i Data compiled by the I & C department indicate that this fix has reduced the instrument drift problems previously identifie This item is close .12 (Closed) Unresolved Item 87-09-01: Drywell and Torus Air Temperature Instrumentation Upgrade During the 1987 refueling outage the licensee completed the installation of environmentally qualified, separate and redundant drywell and torus airspace temperature instru-mentation in accordance with the requirements of .9 The modifications were performed per PDCR 86-0 This item is close . Operational Safety 4.1 Plant Operations Review The inspector observed plant operations during regular and backshift tours of the following areas:
Control Room Cable Vault Reactor Building Fence Line (Protected Area)
Diesel Generator Rooms Intake Structure Vital Switchgear Room Turbine Building Control Room instruments were observed for correlation between chan-nels, proper functioning, and conformance with Technical Specifica-tions. Alarm conditions in effect and alarms received in the control room were reviewed and discussed with the operators. Operator aware-ness and response to these conditions were reviewed. Operators were
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. found cognizant of board and plant condition Control room and shift manning were compared with Technical Specification require-ment Posting and control of radiation, contaminated and high-radistion areas were inspected. _ Use of and compliance with-Radiation Work Permits and use of required personnel monitoring devices were checked. Plant housekeeping controls were observed including control of flammable and other hazardous materials. During plant tours, logs and records were reviewed to ensure _ compliance with station proced-ures, to determine if entries were correctly made, and to verify cor-rect communication of equipment-status. These records included var-ious operating logs, turnover ' sheets, tagout and jumper logs, and Potential Reportable Occurence Reports. -Inspections of the control room were performed on weekends and backshif ts including May 17-19, 23-26, and June 1-3, 6-10, 13-16, 20-24, 1988. Operators and shift supervisors 'were alert, attentive and responded appropriately to annunciators and plant condition .2 Safety System Review The emergency diesel generators (EDGs), EDG fuel oil, core spray, residual heat removal, standby gas treatment, residual heat removal service water, and high pressure coolant injection systems were reviewed to verify proper alignment and operational status in the standby mode. The review included verification that (i) accessible major flow path valves were correctly positioned: (ii)' power supplies were energized, (iii) lubrication and component cooling was proper, and (iv) components were operable based on a visual inspection of equipment for leakage and general conditions. No violations or safety concerns were identifie .3 Feedwater Leak Detection System Status The inspector reviewed the feedwater leakage detection system and the monthly performance summary provided by the licensee in accordance with VYNPC letter FVY 82-105. The licensee reported that,_ based on the leakage monitoring data for May 1988, there were no deviations in excess of 0.10 from the steady state value of normalized thermocouple readings, with the exception of point #12 on nozzle "C", and no fail-ures in the 16 thermocouples installed on the four feedwater nozzles.
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The increate in point #12 is under review by the licensee but may be !
caused by elevated drywell temperature. The inspector had no further ..
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4.4 Inoperable Equipment Actions taken by plant personnel during periods when equipment was inoperable were reviewed to verify: technical specification limits were met; alternate surveillance testing was completed satisfac-torily; and, equipment return to service upon completion of- repairs was- prope This review was completed for the following. items:
May 24-26, 1988 -- The "B" EDG was removed from service - to repair minor jacket water and air start' leaks. The scavenging air blower was replaced 'due to out of specification clearances and rotor lobe-to-blower casing rub indication June 25, 1988 -- The RHR-18 valve was declared inoperable when con-trol room position indication was lost. Indication was restored when the fault was ' bypassed by use of a temporary jumper (LL/J 88-0015).
4.5 Review of Lif ted Leads, Jumpers and Mechanical Bypasses lifted lead and Jumper (LL/J) requests and Mechanical Bypasses (MB)
were reviewed to verify that controls esta'lishedo by AP 0020 were met, no conflict with the technical specifications _ were. created, tho'
requests were properly approved prior to installation, and a safety evaluation in accordance with 10 CFR 50.59 was prepared 'if require Implementation of the requests was reviewed on a -sampling basi LL/J 88-0001 - implemented January 1,1988 to bypass the ADS bypass -
switch annunciator function due to an electrical fault. This is a cold shutdown repair ite Repairs were performed during the June 25-July 1,1988 mini-outage and the LL/J was restored June 29, 198 LL/J 88-0014 - implemented June 22, 1988 to support cable pulls for RHR instrumentation. Unqualified Lewis cable was eplaced with Rockbestos cable. The LL/J was restored June 30, 198 LL/J 88-0015 - implemented June 25, 1988 to utilize an alternate penetration to reestablish RHR-18' valve position.indi-cation. This LL/J remains ope LL/J 88-0016 - implemented and restored June 29, 1988 to support the replacement of HPCI pressure switch PS-23-84- ._ . . - _ . - .
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4.6 Review of Switching & Tagging Operations The switching and' tagging log was reviewed and tagging activities
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were irspected to verify plant equipment was controlled in accordance with th) requirements of AP 0140, Vermont Local ' Control Switchin Rules. The following switching and tagging orders were ' reviewed:
88-471, 480 -- issued to support- the May 24-26, 1988 "B" EDG maintenance 88-612 -- issued to support the repair of HPCI-15 88-618 -- issued to support the June 25-29,1988 "B" EDG electrical ^
maintenanc issued to support the repair of the ADS Bypass switch annunciator ground 4.7 Operational Safety Findings Licensee administrative control of off-normal system configurations by the use LL/J, mechanical bypass, and switching and tagging proced-ures, as reviewed in Sections 4.5 and 4.6, was in compliance with procedural instructions and was consistent with plant safety. Licen-see efforts to minimize active lifted leads, jumpers and mechanical bypasses is noteworth . Security 5.1 Observations of Physical Security Selected aspects of plant physical security were reviewed during regular and backshift hours to verify that :ontrols were in accord-ance with the security plan and approved p,*ocedure This' review included the following security measures: guard staffing; vital and protected area barrier integrity; maintenance of isolation . zones; and, implementation of accass controls, including authorization, badging, escorting, and sear che No inadequacies- were identifie .6. Plant Operations 6.1 Reactor Trip - June 18, 1988 -
The plant experienced a reactor trip on June 18, 1988 due to a high l reactor water level trip of the main tu-bin The plant was opera- l ting at 100% full power at the time of the trip with no surveil-lances, evolutions or other plant perturbations in progress. Opera-tors had only a few seconds in which to react to high feedwater flow and low condensate pressure alarms (indicative of an overfeeding situation) prior to reactor water level reaching the main turbine
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trip level. Although operators were able to react to this condition by placing feedwater control in manual and decreasing the flowrate, system response was unable to prevent the trip. Operators followed post-trip procedures and all safety systems operated normally. Due to normal post-trip shrinkage in conjunction with operator pre-trip actions to reduce feedwater flow, reactor water level reached the low level scram setpoint subsequent to the reactor tri This intiated expected groups II, III, and V primary containment isolation system (PCIS) isolations which alen operated satisfactorily. Normal reactor water level control was r. ,ained within a minute of the tri Licensee investigation of the root cause of the trip identified a failed component in the feedwater flow sensing portion of the reactor vessel water level control system which caused a large feed flow /
steam flow mismatch error to be created. This error caused the feed-water regulating valves to open creating the overfeed conditio Subsequent to troubleshooting, component replacement and testing, the licensee performed a reactor startup on June 19, 1988 reach'ag full power on June 20, 198 Inspector review of the event determined that operators had reacted quickly in an attempt to remedy the overfeed condition but that the speed of. the transient prevented these actions from having any appreciable effect on the level increase. Licensee post-trip actions appeared to effectively address plant conditions including a thorough root cause investigatio During discussions with the operations supervisor, the inspector indicated that the post-trip review report generated in accordance with AP 0154, "Post-Trip Review" contained acceptable but minimal information and had some minor error Be-cause this report forms the documented basis for a licensee managa-ment restart decision, it must contain sufficient correct information to adequately support this decision. Report errors were corrected and items clarified based upon inspector comments. The inspector had no further questions in this are .2 Emergency Diesel Generator Fuel Supply The inspector reviewed the emergency diesel generator (EDG) fuel oil supply system. Inspection emphasis was placed on system design, licensee programs, and actions that ensure availability and relia-bility of the EDG's. Two major functional areas were investigated:
engineering design and mainterance of the fuel oil supply. system; and, fuel oil supply quality assuranc The engineering design review traced the fuel oil supply path from the bulk storage tank to the engine mounted fuel pump The maintenance review examined pro- l cedural preventive maintenance actions that ensure free flow of fuel i
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oil to- the EDG's. The fuel oil review cover $d licensee controls and '
analyses intended to assure required qualit Documents reviewed included: surveillance, operation, and maintenance- procedures; pip-ing and instrumentation diagrams; the Fins 1 Safety Analysis Repor (FSAR); system descriptions; technical specifications; maintenance data; and, associated standards and Regulatory Guides. .The intent ofc
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the inspection,was.to ascertain what programs.and controls..the licen-see had implemented to assure high quality fuel oil reached the EDG's in a reliable manne The EDG fuel oil supply system consists of a main header from the 75,000 gallon storage tank. branching to parallel independent headers each supplying an 800 gallon ' day tank which supplies an associated ED A combination of level control valve and transfer pump auto -
matica11y maintains level in each of the day tank During the review, the inspector. questioned the current maintenance requirements for strainers located. at the fuel oil' transfer pump suction (basket type) and between the day tank and engine ("Y" type).
Blockage of these strainers could cause engine fuel starvation and eventual shutdown. The "Y" strainers are incorporated into a planned preventive maintenance. program and are' routinely inspected and cleaned. The basket strainers are not specifically identified in the licensee niaintenance program' and are not- routinely inspected as part of a preventive maintenance program. Plant operating procedure (0P)
5223, "Emergency Diesel Generator Maintenance", which is performed on a scheduled basis, contains requirements for strainer cleaning with-out identifying which strainers should be included. . Maintenance records for both EDG's' indicated that, during the last maintenance cycle, maintenance requests (MR's)-were' processed for cleaning strainers, again without specific identification of the strainer It appears that the transfer pump suction strainers would only be inspected if an MR was initiated due. to low indicated pump suction pressure. The importance of cleaning and - inspecting these. strainers on a periodic basis was discussed with maintenance' department per-sonnel who-subsequently agreed to review this are The inspector also noted during the maintenance review that the main fuel oil storage tank and the day tanks had never been emptied, inspected, and cleaned. The main storage tank was partially emptied ( 50%) and inspected in December, 1986. Regulatory Guide (RG) 1.137,
"Fuel Oil Systems for Standby Diesel Generators" recommends that supply tanks be emptied, accumulated sediment removed, and cleaned at ten year intervals. Additionally, RG 1.137 recommends that day tanks be checked for water monthly, as a minimum, and after each operation of the diesel for periods of one hour or more. Tne licensee cur-rently performs no checks of the condition or contents of the day tanks. Although the licensee is not committed to RG 1.137, these measures represent potential improvements to fuel oil qualit .. . - - , - . - - . - - - - - . - . - . - . . - . - . - - - . - - . , - -.-
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During the quality assurance review, the inspector noted that TS 4.10.C.2 requires the fuel oil quality to meet ASTM 0975-68 Table I criteria. The inspector could find no indication that the licensee had ever. verified that fuel oil delivered for use by the EDG's met all of the criteria in this standard. The open purchase order used to procure the fuel does' so as commercial grade with criteria spec-ified for viscosity, water and sediment, whereas the ASTM D975-68 Table I criteria additionally specifies other quality. verification parameters, e.g. , ash weight, carbon residue, sulphur, etc. . The con-tents of the delivery truck are sampled in accordance with OP 4613,
"Sampling and Testing of Diesel Fuel Oil" but only viscosity, water and sediment values are determined. Additionally,.the monthly sample of the main storage tank, taken -in accordance with OP 4613 and TS 4.10.C.2, is also checked only for viscosity, water and sediment vice the full limits of ASTM D975-68 Table I. The licensee maintained that notes contained in the bases section of the TS indicate that only viscosity, water, and sediment measurements are required. Sub-sequent to discussions with the inspector, the licensee committed to a sampling program that-covered all of the ASTM D975-68 Table I cri-teri Pending licensee execution of this commitment, this issue remains unresolved (50-271/88-08-01).
In summary, the inspector found that the licensee did not have a unified program to assure the quality of fuel oil reaching.the EDG' The sum of the pai ts of various existing licensee activities in this area falls short of a fully adequate program that would assure con-formance with TS 4.10.C.2 requirements and ASTM D975-68 criteria, as well as expected preventive maintenance quality chech. Although not specifically committed to RG 1.137, the licensee is required by 10 CFR Part 50 Appendix B to establish and maintain a quality assurance program that provides "control over activities affecting the quality of the identified structures, systems, and components, to an extent consistent with their importance to safety." Quality assurance in this context encompasses all "actions necessary to provide adequate confidence that a structure, system, or component will perform satis-factorily." Failure to implement strainer preventive maf ntenance actions, failure to adequately ascertain the condition of fuel oil supply tanks, and failure to perform adequate fuel oil analyses are indicative of a less than fully comprehensive and successful EDG fuel oil system quality assurance program. Licensee evaluation to improve the program will be reviewed by the inspector during routine inspec-tions a-d remains an unresolved item (50-271/88-08-02).
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6.3 Reactor Trip - June 24, 1988 The plant experienced a reactor trip' on June 24, 1988 due to a'high baaring vibration trip.of the main turbine. The plant was operating at 100% full power at the time -of the trip with no surveillances. or other plant perturbations in progress. The drywell was in the pro-cess of being deinerted to support a planned outage scheduled to begin late on June 24. The vibration increase was sudden and unan-ticipate Operator and system' response to the trip was satisfac-to ry . All safety systems operated satisfactoril A normal post-scram reactor water level oecrease due .to shrinkage. caused a low level actuation of PCIS groups II, III, and Sub;equent excessive feedwater flow caused an increase in reactor water level up to the feedwater pump trip setpoint. Normal level control was established within a few minutes of the tri Licensee investigation of the root cause of the trip identified a failed vibration sensor probe for the #10 turbine bearing. Failure of the probe caused a spurious high vibration signal and subsequent turbine trip. As a precautionary measure, the licensee disassembled the #10 bearing for examinatio No damage or unusual conditions were identifie During review of this event, the inspector once again observed that the post-trip. review report contained minimal information. The report was inadequate as a stand-alone document. Scme aspects of the j trip were not discussed in the report. For three days the-licensee 1 was unable to provide the inspector with several ;of the report attachments including computer alarm and trip logs. These are examples of a less than fully effective post-trip documentation and review process. The deficiencies noted in the post-trip review pro-cess for this event, the event identified in paragraph 6.1 above, and !
previously identified in IR 50-271/87-21 section 9.1 indicate the !
need for licensee attentio This item remains unresolved pending j review of licensee corrective actions -(50-271/88-f;8 03). ;
6.4 Uncontrolled Maintenance on Standby Gas' Treatment Sy s cem On April 17, 1988, an operator identified that tre existing Tygon tubing had been replaced with tubing that had increased the vertical height of the drain loop seals for both standby (,as treatment (SBGT)
trains. The original tubing increased the vertical -height of the manufacturer's loop seal just enough.to allow visible indication of water level in the hard piped loop seal. The original tubing had been in place since early plant operation. The tubing ended approxi-mately 20" of f the floo Installation was necessary because the original manufacturer's design did not provide the operators with
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, 14 loop seal lescel indication. .During the 1987 outage, the tubing was replaced because it had become dirty causing difficulty in determin-ing loop seal level. The tubing was replaced by two operators with-out use of a maintenance request. The ond of the new drain tubing was found to be 30"'of f the f W 'or the "A" train and ~ 36" for the
"B" train. . The additional height of the drain ' loop seal. would not have affected the operation of the "A" SBGT train. The additional height; could have af fected the "B" train but only during operation where the influent air had a high relative humidit The system moisture separator is designed to . remove entrained water particles that are 1 to 5 microns in size. Thus, during normal operation, . the
"B" train moisture separator would nm remove enough water to over-flow the drain tra The only time the "B" train could have been affected was after a design ' basis accident if the influent was humid primary containment air. If, during long term post-LOCA operation, the "B" SBGT train was used to . vent primary containment, it could have slowly filled with water. The additional water would - have increased the "B" SBGT train effluent humidity as well as decreased the charcoal tray effectiveness to remove iodine. This scenario is beyond the SBGT system design basi Licensee review of this event determined that Tygon tubing is most commonly used as a temporary drain, to contain leakage, to dra n equipment during maintenance and to assist in housekeeping. It i not normally considered to be plant equipment or have the capability of impacting plant equipment. When it was replaced on the SBGT trains, this human factor bias caused it to be treated as a "house-keeping item" instead of "plant equipment".
Licensee corrective actions include:
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Designation of the Tygon tubing configuration as plant equipment and initiation of a mechanical bypass (MB). reques A full plant review . will be ' performed to- identify other instances of Tygon tubing being used for operating purpose Specific training of plant personnel on this. even Licensee completion of these actions remains an unresolved item (50-271/88-08-04).
6.5 Event Notification During review of the events surrounding the contaminated sewage sludge issue (see Section 8.1), the inspector noted that, although the State of Vermont had been notified by the licensee of a potential problem on May 31, 1988 and a subsequent press release was made on June 6,-1988, the licensee failed to formally notify the NRC in accordance with 10 CFR Part 50 Section 72 (b)(2)(vi). Even after
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. 15 discussing this . omission with various levels of management including:
the Plant Manager, it took the licensee over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> more to make a belated notification on June 14, 198 Although reportability. of this event was originally addressed by the licensee on June .7, the final decision was lef t . to the shift superviso No . feedback to management of the shift supervisor's decision to not report the event occurred. 'No followup by management occurred either. The reporting requirements of 10 CFR 50.72 - (b)(2)(vi) are not as . definitive. as others in 10 CFR 50.72 and the licensee practice of having the shif t supervisor make an unreviewed determination - may not be appropriate when reporting under this paragrap Although the' inspector . con-sidered this an anomalous occurrence, licensee review of reporting-methodology is ' necessary and remains an unresolved i ten. (50-271/
88-08-05).
7. Maintenance / Surveillance 7.1 Emergency Diesel Generator Maintenance On May 24, 1988, the "B" EDG was removed from service to facilitate inspection of the scavenging' air blower rotor . clearances in accord-ance with the recommendations of Fairbanks Morse Service Information letter, dated November-15, 1984. The inspection revealed .out-of-specification clearances as well as indications of rubbing between rotor lobes and the blower casin The blower was subsequently replace Failure of the blower had been identified by Fairbanks Morse as a generic concer Post maintenance and operability runs were completed satisfactorily and the "B" EDG was returned to service May 26, 198 The "B" EDG was removed from service June 25-29, 1988 to complete the remainder of the vendor-recommended maintenance activities not accom-plished during or since the 1987 refueling outage. The maintenance was performed in accordance with procedures OP 5223, "Emergency -
Diesel Generator Maintenance", .and OP 5225, "Emergency Diesel Gener-ator Electrical Maintenance".
Six fuel oil injection pumps (1-6 opposite control side (0CS)) were replaced due to normal wear. Nine fuel oil injectors (2-5, 7, 12 i control side (CS) and 3-5 0CS) were replaced due to irregular spray pattern Three more injectors (2,4,6 0CS) were replaced following the operational run due to minor leaks.
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No_ abnormal conditions were identified by the remainder of the inspections. The . post maintenance and operability runs were com-pleted satisfactorily and the "B" EDG was _ returned to service on the morning of June 29, 1988. The "B" EOG was removed from service for a short period of time on ' June 29,1988 to replace the .three fuel injectors that were observed to have minor leaks. The maintenance on the "B" EDG was performed in a well planned, efficient manner mini-mizing diesel generator unavailabilit No inadaquacies were'
identifie .2 Outage Activities Major maintenance activities accomplished during a scheduled one-week mini-outage commencing June 24,_1988 included:
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identification and repair of the source of drywell leakage HPCI-15;
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repair of steam leak on the "B" low pressure (LP) feedwater heater and identification of similar wall thinning and subse-quent repair of the "A". LP feedwater heater;
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mechanical cleaning of main condenser tubes;
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completion of the yearly "B" EOG overhaul;
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completion of routine "A":EDG maintenance;
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inspection of the #10 main turbine bearing high. vibration alarm and turbine trip (no abnormal indications were identified);
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repair of RHR-18 position indication;
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overhaul of drywell RRU #1 and #2;
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investigation of main turbine thrust bearing wear detector alarm and secondary turbine trip signal;
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RWCU A and B pump seal overhaul; and,
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clearing of LL/J for the ADS switch bypass alarm / annunciato i i
The licensee accomplished a number of significant maintenance activ-
'l ities during the mini-outage including many activities which required '
cold shutdown conditions. This effort was _a result of proper plan- I ning and scheduling. The daily outage meetings were informative, l concise and efficient. Interdepartmental communication and coordina- l tion resulted in proper prioritization and support of all work activitie The inspectors had no further question i l
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. 17 Radiological Controls 8.1 Contaminated Sewage Sludge Recent public controversy surrounding - the purchase of a piece of-
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property (the Whitaker Farm) by the town of Vernon, Vermont, involved-one point of contention that sewage had been dumped on the farm by the Vermont Yankee. Nuclear Power Station. In fact, although VYNPS was the likely source of the sewage, a contractor hauler (A-1 Sani-tary) had been dumping the sewage on the farm by agreement with the owners to aid in fertilization. . The practice of spreading the sewage on fields was subsequently changed to dumping into-a- pit on the far This practice existed for several months in the summer / fall of 198 In January 1986, the hauler began taking VYNPS sewage to the-town o Brattleboro, Vermont sewage treatment facility by direction of the licensee. Site . sewage has been sent to- that facility since that time. The sewage is primarily . from a 10,000 ' gallon holding tank which collects the effluent from the licensee Construction Outage Office Building (COB). This building is outside of the Radiological Control Area and sewage is primarily- from lavoratories. This holding tank is pumped on average twice per week. Sludge from the main septic system is pumped and transported on average twice per yea In response to NRC Information Notice 88-22, "Disposal of Sludge from i Onsite Sewage Treatment Facilities at Nuclear Power Stations" dated May 12, 1988 and State of Vermont Department of Health inquiries,'the licensee sampled the pit on the Whitaker Farm on May 23, 1988. Re-sults obtained on May 25 and 27~were:
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7 samples taken, two showed a small amount - of activity above -
background
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Isotopes and concentrations:
Co-60 -
134 pico curies / kilogram Cs-137 -
168 pico curies / kilogram Ac/Th-228 -
582 pico curies / kilogram
, K-40 -
7,650 pico curies / kilogram
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Cs-137 could be attributed to worldwide fallout from nuclear weapons testing; Ac/Th-228 and K-40 are naturally occurrin The licensee Ntified the State Department of Health of these find-ings on May 31. The main entities involved / interested in this case from the state have been the Department of Health, Department of Public Service, Department of Environmental Conservation and the Governor's office. Licensee management was subsequently in contact with these various state agencie . . - - - . - . - , - .
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. 18 On June 6, the -licensee halted transportation of sewage off site and '
began developing a sampling procedure and disposal program to address the issue. On June 8 samples were drawn on .the COB and main tanks with results as follows:
10 pCf/kg Ac/Th-228 - 29 pCi/kg K-40 -
87 pCi/kg Co-60 -
55 pCi/kg Main Tank Sludge: Cs-137 -
121 pCi/kg Ac/Th-228 - 39 pC1/kg K-40 -
223 pCi/kg Co-60 -
853 pCI/kg Zn-65 -
53 pCI/kg Mn-54 -
39 pCi/kg Cs-134 -
13 pCi/Lg Although these amounts of contamination do not present a health or safety hazard, the presence of licensed radioactive. material in the sludge currently prevents the licensee from conducting conventional sewage disposal operation In accordance with 10 CFR Part 20: Sec-tion 301, the licensee in this case must not dispose of licensed material except by transfer to an authorized recipient, or as may be authorized in a special application approved by the NRC, or in ac -
cordance with 10 CFR Part 20 Section 303. The licensee has formed an internal task force to address the many facets of this issue. Areas
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of interest include investigation of all possible pathways for radio- 1 nuclide entry into septic systems, current sit dgeldisposal alterna-tives, and application to the NRC for approval of alternate disposal method Licensee response to NRC IN 88-22 has been good. However, past VYNPS
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practices in the area of sludge disposal have been inadequate and demonstrate a gap existed in the total radiological control progra The contents of IN 88-22 indicate that proper disposal of sewage sludge may be an . industry problem while recent events demonstrate that it is at least a problem at VYNP Past licensee sewage disposal practices apparently did not comply with requirements of 10 CFR Part 20 Section 201 in that no surveys were performed on sewage prior to release from VYNPS. Additionally, in light of the trace amount of radie.nuclides found on the Whitaker Farm arJ in conjunction with past VYNPS disposal practices, and the
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current activity levels found in onsite septic tanks, the licensee was likely not in compliance with 10 CFR Part 20 Section 301 require-ments for waste disposa Specialist inspectors from NRC:RI are reviewing this area' and will present appropriate findings in a separate inspection repor .2 Contamisation Outside Radwaste Building On August 12, 1987, a small area of ground near the northeast corner of the Radwaste Building was identified as being - contaminated ~(see Inspection Report 87-15 Section 5.0). Subsequent licensee investiga-tion determined the circumstances surrounding the contamination including probable causes~, reasone for lack of early identification, and recommended corrective actions (see VYNPC response to IR 50-271/
87-15, letter FVY 87-113 dated December 10,1987). Corrective actions were reviewed and closed out in IR 50-271/88-02 with the exception of licensee efforts to develop a suitable technique for performing surveys in high background area While investigating alternative survey methods, the licensee discovered indications 'that a larger area outside of the. Radwaste Building may be contaminate A Health Physics Ircident Report was generated and surveys performe Results of smear survey. showed no loose contamination (all smears less than 1000 dpm/100cm2 ). Asphalt samples from the areas showed small amounts of fixed activity. The licensee subsequentiy obtained core bore samples of the ground underneath the asphalt in the area to determine the degree of leaching taking plac Eleven of thirty-seven samples showed varying amounts of Cobalt-60 (Co-60), Cesium-134 (Cs-134) and- Cesium-137 (Cs-137).. Co-60 levels ranged from undetect-able to 3050 picocuries per kilogram (pCi/kg). Cs-134 ranged from undetectable to 6290 pCi/kg. Cs-137 ranged from undetectable t ,920 pCi/kg. These small amounts of activity showed that some material had leached through the asphalt inte the substratum soi Current licensee analysis indicates that the activity probably orig-inated from trace amounts of radioactive material remaining on cask surfaces followi,g decontamination procedures. These traces would probably have gone undetected by normal survey procedures. The activity in the asphalt appears to be the result of years of accumu-lation via this mechanism. Licensee identification of this . situation attests to the benefits of aggressive followup programs. Licensee pursuit of problem definition has been comprehensive and demonstrates a positive approach to improved performance. Disposition of asphalt and soil in this area as well as mathods to prevent or mitigate future activity release via the cask room are under consideration by the licensee and remains an unresolved item pending coNietion (50-271/88-08-06).
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. 20 9. Licensee Event Reporting (LER)
The inspector reviewed the below licensee event reports (LERs) _to deter-mine that with respect to the ' general ' aspects of the events: (1) the report was submitted in a timely manner; (2) description of the events was accurate; (3) root cause analysis was performed; (4) safety implications were considered; and (5) corrective actions implemented or planned were
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sufficient to preclude recurrence of a similar even .1 LER 88-04 The LER 88-04, "Isolation of Radiation Monitors Due to Personnel Error" addressed the simultaneous isolation of both advanced off gas (A0G) radiation monitors. The LER fulfilled the above criteria and no deficiences were note .2 LER 88-05 The LER 88-05, "Potential Loss of SBGT Train Due to Extension of Loop Seal" addressed a potential loss of standby gas treatment (SBGT)
train "B" due to an incorrect maintenance activity. Plant management and PORC members questioned the root cause conclusion in the draft LER and required the Engineering Support Department (ES0) to re-analyze the event. Because this LER was being reviewed late in the 30-day period, this action forced the licensee to either request an extension of the submittal date or submit an incomplete LER. The request to extend the submittal date was granted by the inspector in i the interest of supporting accurate and complete event reportin I Licensee efforts are required to develop and review LER's earlier in the 30-day cycle so that management review and questions can be j accomplished without the need for submittal extension '
Thc- inspect $r noted during review of this LER that the licensee basically statad that the "B" train of ' SBGT was inoperable from sometime during the 1987 outage until the discovery dat The inspector indicated to the licensee that if this was the case, then TS operability requirements for the. SBGT system had not been met, i SBGT would not have been single failure proof during that period, and therefore the plant would have been operated outside the design ]
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basis. Licensee subsequent investigation determined that the "B" !
train of SBGT in fact would have been able to fulfill its design function. The licensee concluded that only in a post-LOCA environ-
, ment and using the SBGT system in a non-design basis mode could the
"B" train have possioly been impacted. Independent review by the
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inspector confirmed the licensee revised analysis. Based upon this reanalysis, the li;ensee committed to submitting a revision to LER 88-05 to clarify the operability status - of "B" SBGT. This issue remains unresolved pending revision of LER 88-05 (50-271/88-08-07).
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. 21 10. Review of Licensee Response to NRC Initiatives 10.1 NRC Information Notice 88-08: Potential for loss of Post-LOCA Recirculation Capability Ote to Insulation Oebris Blockage
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The licensee previously addressed the post-LOCA insulation debris
. issue during the - 1985-1986 recirculation. pipe replacement. outag Mirror insulation was replaced with. NUK0N insulation on pipes .from 4-28 inches in diameter inside. the drywell . The NUKON insulation selected is a low density fiberglass blanketted insulation which is secured by stainless steel Velcro strips and is enclosed in 22 gage stainless steel jacket General Electric performed' an engineering analysis to determine the potential degradation of ECCS pump perform-ance resulting from the ' clogging of pump intake strainers 'with in-sulation . debris following several postulated LOCA scenarios. .The analysis was performed in accordance with ~ RG 1.82, Revision 1' and NUREG 0897, Rev;> ion 1. At VYNPS, a guillotine- break at the 28 inch reactor vessel nozzle of recirculation loop "A" would produce the maximum volume of shredded insulation debris, estimated to be 23 cubic feet. In this scenario it was concluded that the RHR suction strainers would become sufficiently obstructed such that minimum NPSH could not be maintained for the RHR pumps. The core spray NPSH mar-gin was determined to be adequate. Prior to the conclusion of the recirculation pipe replacement outage the. licensee implemented EDCR 85-01, ECN 7, which directed the installation of RHR suction strainers with a surface area of 36.30 square feet. Based on conser-vative analysis this surface area is sufficient to ensure that minimum NPSH margins are maintained for the most limiting debris generating LOCA. The inspectors had no further question . Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special. reports submit-ted pursuant to Technical Specifications. This review verified, as appli-cable: (1) that the reported information was valid and included the NRC-required data; (2) that test results and supporting information were con-sistent with design predictions and performance specification; and (3) i that planned corrective actions were adequate for resolution of the prob- l le The inspector also ascertained whether any reported information should be classified as an abnormal occurrence. The following report was reviewed:
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Monthly Statistical Report for plant operations for the month of May 198 l j
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. 22 12. Management Meetings At periodic intervals during this inspection, meetings were held with senior plant management to discuss the findings, A summary of findings for the report oeriod was also discussed at the conclusion of the inspec-tion and prior to report issuance. No proprietary information was iden-tified as being included in the report.