IR 05000424/1990017
| ML20059M788 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 09/18/1990 |
| From: | Aiello R, Brian Bonser, Brockman K, Starkey R, Trocine R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059M787 | List: |
| References | |
| 50-424-90-17, 50-425-90-17, NUDOCS 9010050276 | |
| Download: ML20059M788 (15) | |
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- UNIVED STATES
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'o NUCLEAR REGULATORY COMMIS$10N
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1101 MARIETTA STREET,N.W.
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. ATLANTA, GEORGI A 30323
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Report Nos.: "50-424/90-17cand'50-425/90-17 Licensee:' Georgia Power Company L
- P.O. Box 1295
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Birmingham.AL 35201
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Docket Nos.:
50-424 and 50-425 License Nos.: NPF-58 and NPF-81-
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Facility Name:. Vogtle 1 and 2
.'Inspec+1on Conducted: June 30 - August 24, 1990
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Inspectors:
NdIMn/dd d 8 -/ 8 '90 j
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B. R. Bonseff Senior ResidgJit Inspector Date Signed W
f6k/b h 0-/S&O R
F. AieHo,gesident Inspector Date Signed
}h hinlr.rd) &
V-49-90 R. D. Starkey, Sesident Inspector
__Date Signed r
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h 7b p thw d & 982
- 9-/'). 90 t
L.Trocine,.P@fectEngineer Date Signed
. Approved By:
e..[ M urd en /
8"/8"90'
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.. Brockprft.. }pdtion Chief-Date Signed ision of Reador Projects sq SUMMARY
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Scope:
-This routine inspection entailed resident' inspection in the following
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' areas: plant operations, radiological -controls, maintenance, surveillance.. security, and - quality programs and administrative controls 'affecting quality.
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'Results: One ' unresolved item was identified during this inspection.
The URI was in the area of inadequate corrective actions following DG start
7-failures on April 12, 1990 and July 5, 1990.
No specific strengths or weakness were identified during this-n inspection period.
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9010050276 900920.<
PDR ADOCK 05000424
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i DETAILS
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Persons Contacted
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Licensee' Employees
- J. Aufdenkampe, Manager Technical Support-
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~*G. Bockhold, Jr., General Manager Nuclear Plant I'
- C. Coursey, Maintenance Superintendent
- G. Frederick, Safety Audit and Engineering Group Supervisor l
H. Handfinger, Manager Maintenance
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W. Kitchens, Assistant General Manager Plant 0perations R. LeGrand, Manager Health Physics and Chemistry o
. G. McCarley, Independent Safety Engineering Group Supervisor l:
- A. Mosbaugh, Assistant General Manager Plant Support
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- R.'0 dom, Nuclear Safety and Compliance Manager
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J. Swartzwelder, Manager Operations j
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OtherJ11censee employees contacted included technicians,. supervisors,
' engineers, operators, maintenance personnel, quality control inspectors,'
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and office personnel.
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- Attended Exit Interview
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An alphabetical list of acronyms and initialisms is located in the last-paragraph.of the inspection report.
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Operational Safety Verification - (71707)(93702)
The facility began this inspection period with Unit 1 at 100% full power and Unit 2 in Mode 3 (Hot Standby).=
Unit 1:
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s On July 13, 1990, the unit reduced power to 70% to repair a steam leak on b
MFP "A".
The unit returned to 100% power on July 15.
On July 23,.the
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unit was manually tripped from 100% power when speed control of the MFPs
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was lost due to an electrical fault in a non-safety related 480: VAC:
switchgear.
On July 25, the unit achieved criticality.
On July 26, the s
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unit entered Mode 1 (Power Operation) and tied to the grid, The unit remained at full power, with the exception of minor power reductions-for maintenance, through the end of the inspection period.
Unit 2:
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On June 30, 1990, the unit achieved criticality and entered Mode 1 following a manual unit trip which'had occurred on June 28 due to a MSIV hydraulic.0-ring f ailure.
Prior to this trip, the unit had been in a
coastdown from 96% power in preparation for the unit's first' refueling outage which begins September 14, 1990.
On June 30, several problems -were
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the' grid.
With the unit at 18% power, a feedwater isol_ation and'a turbine.
Ltrip occurred when a SG reached its high-high level. setpoint.. A manual:
reactor trip was initiated with; the unit at approximately 8% power.
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July 1 the unit entered Mode 1 and tied to the grid. Q1 July 2, the unit-
reached 86% power and resumed the coastdown.
The unit continued-the
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coastdown through the end of this inspection period with minor power-i L
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l-reductions for maintenance activities.
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Control Room Activities
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Control Room tours and observations were performed to verify that facility operations were being safely conducted within regulatory requirements.
These inspections consisted of one or more of the following attributes, as appropriate, at the time of the inspecti_on.
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- Proper Control Room staffing
- Control Room access and operator behavior L
- Adherence to approved procedures for activities in progress
- Adherence to Technical-Specification Limiting Conditions for Operations-
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- Observance of instruments and recorder traces of safety related and'
important to safety systems for abnormalities
- Review of annunciators alarmed and action in progress to correct them
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- Control. Board walkdowns
- Safety parameter display and the plant safety monitoring system operability status
- Discussions and interviews with the On-Shift Operations Supervisor,
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Shift Super' visor, Reactor Operators, and the Shift Technical Advisor (when stationed) to determine the plant status, plans, and-l i
to assess operator knowledge
- Review of the operator logs, unit logs and shift turnover sheets No violations or deviations were identified.
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Facility Activ1 ties
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Facility tours and observations were performed to assess the l
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effectiveness of the administrative controls established by direct observation of plant activities, interviews and discussior.s with
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licensee personnel, independent verification of safety systems status
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and LCOs, licensee meetings and facility. records.
During these-inspections the following objectives were achieved:
(1)
Safety System. Status (71710) - The inspector verified that flowpath valve alignment, control and power supply alignments, component conditions, and support systems for the accessible portions of the ESF trains were proper.
The inaccessible portions were verified as availability permitted. An additional
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l indepth inspection of the Unit 2 RHR train'"B" was performed to-
- compare the system lineup procedure with the plant drawings and as-built configurations and to compare valve remote and local
indications.
Walkdowns were expanded to-include hangers and supports, and electrical equipment interiors..
The inspector
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verified that the lineup was in. accordance with license requirements for system operability.
The' inspector used procedure 11011-2,. Residual Heat Removal
System Alignment, Rev 6 and P & ID 2X4DB122 Rev. 23, to verify
. correct system alignment.
All valves observed during the-walkthrough were. determined to be correctly aligned; however, several examples were noted of errors in component nomenclature.
I Specifically, on 480V AC MCCs. 2ABD, 2BBD, 2ABB, and 2BBB, the component word descriptions as stated on the breaker ID tag' did
not match the wording in procedure 11011-2.
However, in each
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case, the proper breaker number and component ID number were
correctly _ stated in the procedure.
In some cases, the word -
description on the breaker ID was comple+.ely in error and '
potentially confusing to plant personnel wi o would be using the
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component.
All procedure discrepancies and-inspector
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walkthrough observations were discussed with the RHR system j
engineer who stated-that corrective action would be-taken.
The inspector has no further comments..
(2) Plant Housekeeping Conditions -
Storage of. material and components and cleanliness conditions of various areas throughout th.e - facility were observed to determine whether safety ~and/or fire hazard:; existed.
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~(3)
Fire Protection - Fire protection activities, staffing and equipment were observed to' verify that fire brigade: staffing was-appropriate and-that. fire alarms, ' extinguishing equipment,
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actuating controls, fire fighting equipment, emergency-equipment, and fire barriers were operable.
(4) Radiation Protection - Radiation protection activities, staffing and equipment 'were observed to verify prcper program implementation.
The inspection included a review of the. plant b
program effectiveness.
Radiation Work Permits and personnel compliance were reviewed during the daily plant tours.
Radiation Control Areas were observed to verify proper.
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identification and implementation.
(5) Security - Security controls were observed to verify that
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security barriers were intact, guard forces were on duty, and access to the Protected Area was controlled in accordance with the facility security plan.
Personnel were observed. to verify
.I proper display of badges and that personnel requiring escort were properly escorted.
Personnel within Vital Areas were
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_.erved to ensure proper authorization for the area.
Equipment
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cperability or. proper compensatory activities were verified on a m
periodic basis.
(6) Surveillance (61726)(61700) - Surveillance tests were. observed.
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to ' verify that approved procedures-were being used. qualified
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personnel were conducting the tests, tests were-adequate to.
verify equipment operability, calibrated equipment was utilized,.'
and TS requirements were followed.
The. inspectors observed a
portions of the-following surveillances and/or reviewed completed data against acceptance criteria:
-Surveillance No.
Title-14514-1, Rev.' 3 FHB Post Accident Exhaust System.
Operability Test
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14553-2, Rev. 1 Train "A" ESF Room Cooler And Safety Related Chiller Flow Path Verification L'
14802-2, Rev. 3 NSCW-Pumps And Discharger Check Valves IST
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14803-1/2,'Rev. 6/2 CCW Pumps And Discharge Check
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Valves IST l
14806-1, Rev. 7 Containment Spray Pump And Check Valves IST l
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14807-1/2, "ev. 6/2 MDAFW Pumps Train A" IST
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14825-1, Rev. 15 Monthly SI System Train "A"~-IST s
'14830-2, Rev. 2 Quarterly "B" Train NSCW Check
Valves IST l 0n July.11,1990, DG 2A was undergoing a routine surveillance.
using. procedure 14980-2, Diesel Generatt,e Operability Test. The right air start bank was-isolated to allow. testing of the '1 eft air start bank.
The engine' start button-was pushed by the control room operator and the engine. began to roll-with starting air..The licensee reported: that the engine rolled twice and stopped.
The DG'was declared inoperable and an investigation
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into the cause'of the event was begun.
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During the review of the July 11 start failure, the licensee determined that similar events had -occurred on April 12 and s
July 5, 1990.
These previous similar events had not been recognized as failures and, therefore, had not been reported as such.
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i U-On April. 12, 1990,-- the licensee conducted a TS surveillance test of DG 2A.
The manual start button was-pushed, but' no start '
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occurred.-
The operators attributed' the start failure to personnel error, incorrectly assuming that the start button was not held long' enough, to satisfy the necessary start logic.
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Another start attempt resulted in a successful start.
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. July 5, a similar incident occurred on DG 18.
As before, the _
operators assumed that the start button was not held long-enough
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on the first start attempt. Another attempt again resulted in a
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successful start.
- For. the April 12 'DG 2A start, the : operators documented their
incorrect 'assumpt'on tnat the start button was released too
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soont'however, this first start attempt was not. recognized as a
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valid failure.
This matter was not pursued and.no corrective.
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The July 5 DG.1B start failure again was attributed to an operator error and was not identified as a
start failure.
The operator neither logged the event as at failure nor'followed up to determine the cause'of the failure.
- Therefore, : nt_ corrective action was taken.
The licensee's failure to esta211sh measures to ensure prompt identification and correction of significant conditions adverse.to quality following the April 12 and July 5 DG start failures prolonged the period in which DGs 2A and IB remained in a degraded o
condition.. Pending = resolution of this and other enforcement issues associated with corrective actions this issue has been
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_ identified as the1following Unresolved Item.
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URI 50-424/90-17-01 and 50-425/90-17-01 "Pending resolution of the enforcement issues associated with the corrective actions following D/G start failures on 4/12/90 and 07/05/90."
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The licensee's investigation into, the July 11 event determined that the starting air valve pistons could stick in their: cap:
assemblies'due to inadequate manufacturing tolerances. 'The air start system provides the means to start the DG.on receipt of a-start signal by-injecting: stored compressed air into the engine.
cylinders causing the engine,to roll.and start.
The' air start j
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valves are air-to-open, spring-to-close valves, y
This condition of the air' start valves-was apparently the result
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. of' the manufacturing process which left insufficient clearance
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between some'of the pistons and caps. A failure to start would-occur only after the engine had been shut down on a previous run and the engine stopped with a particubr aiignment of faulty air start valves and crankshaf t position, q
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On a non-emergency manual start with the air; start valves-malfunctioning, the initial burst of air was. not adequate to'
change the alignment of the crankshaf t with respect to the
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faulty air start pilot valves so that any subsequent attempt ~ to start the engine could be successful.
The licensee now believes this problem may have been the cause-of-DG failures on January
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24, 1990 and January _25,1990. - Both; of these failures were, reported ~via special reports required by TS.
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On July-19, 1990, the manufacturer, Cooper Industries,-submitted a 10 CFR 21 report as a result of the finding on the air start q
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system.
The manufacturer's report. confirmed that the sticking
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of the air start pistons could result in slower engine start t'les orla failure to start.
The licensee's corrective actions have included testing of all sixteen starting air valves on each of the four DGs and increasing the clearances on the valves that stuck.and advising-operators that the DG should start when the manual-pushbutton.is-depressed.
Long term corrective action has not yet been--
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determined by the vendor.
(7) Maintenance Activities- (62703)
The inspector observed:
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maintenance activities to verify that correct equipment'
clearances were in effect; work requests' and fire prevention work permits,.as required, were issued and being followed;
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-quality control personnel were available for inspection activities as required; -retesting and return of systems to service was prompt and cor ect and TS requirements were being followed.
The Maintena.e Work Order backlog was reviewed.
Maintenance was observe and/or work packages were reviewed for the following maintenan.4-activities:
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j 28906504 Repair Leaking Flange On HDT Pump "B" l
Suction Valve.
29001026 Replace Heater Drain Pump "B" According i
To DCP-V2E0083.
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29002686 Install Vent Valves On-Spent Fuel-Pool
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Cooling Lines In Accordance With DCP
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90-V2N0087.-
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Diesel Generator 1A Pop Test.
l 190 Diesel Generator 1A Left Bank a
Intercooler Leaking Water From Test Valve.
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19003505 Repair HDT "B" High Level Dump Valve t
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No violations or deviations were identified.
3.
Review of Licensee Reports (90712)(90713)(92700)
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In-Office Review of Periodic and Special Reports This -inspection consisted of reviewing the below listed reports 4to
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determine whether the information reported by the licensee' was technically adequate and consistent with the. inspector knowledge of the material contained within the report.
Selected material within the report was-questioned randomly to verify accuracy' and to provide.
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a reasonable assurance that other NRC personnel have an appropriate document for their activities.
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Monthly 0perating Report - The reports dated July 10 and August 9,
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1990 were reviewed. The inspector had no comments.
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. Deficiency Cards and Licensee Event Reports Deficiency Cards ard Licensee Event Reports were. reviewed - for
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. potential generic impact, to detect trends, and to determine whether
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' corrective actions appeared appropriate.
Events which were reported.
pursuant to.10 ' CFR 50.72, were reviewed following occurrence to
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determine if the technical specifications and other regulatory l,
requirements were satisfied.
In-office review of LERs could result i
j in further followup to verify that the stated corrective actions were
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completed, or to identify violations in addition to those described a
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Each LER = was-reviewed for enforcement action in
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accordance with 10 CFR Part 2 Appendix-C, and where the violation
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was not cited;the criteria specified in Section V.G.1 or_V.A of the.
t NRC Enforcement Policy were satisfied.
Review of;DCs was performed
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to maintain a realtime status of deficiencies, determine regulatory
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s compliance, follow the licensee corrective -actions, and assist-as a -
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basis for closure of the LER when reviewed.
Due to the' numerous-DCs processed only those DCs which resulted in enforcement -action or.
i further inspector followup with the licenseeLat' the end of the inspection are listed below.
The DCs and LERs denoted with ~ an
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asterisk indicate that reactive inspection occurred ' following the event and prior to receipt of the written report.
(1) The following Deficiency Cards'were reviewed:
DC 1-90-303 " Unit 1 Manual Reactor Trip Due To Lowering SG r
Levels."
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The unit one reactor..
manually tripped due to SG. levels
. lowering uncontrollably. - The reactor was manually. tripped to.
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prevent an automatic reactor trip on low steam generator levels.
The cause of the loss of level control was a loss of' power to INB01 (non IE 480 VAC switchgear) which is under investigation.
This event will be further followed up when submitted as an LER..
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F (2) The following LER was reviewed and closed.
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50-424/89-02, Rev. O, " Improper' Fuses May Have Prevented Fulfillment Of A Safety Function."
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As a result'of improper fuses found in equipment during the construction phase.of Unit 2, plant personnel initiated a-
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fuse verification walkdown program on Unit I to confirm
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that proper fuses were installed.
On January 6,1989,:
' personnel performing the walkdown found improperly sized
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fuses ~ installed in the control circuit for a. NSCW fan -
motor.- The control circuit had a 6 amp fuse installed:
where the design called for a 30 amp fuse and a 30 amp fuse-
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installed in a location designed for a 6 amp fuse. The fan was removed from service and a LC0 was initiated.
The-cause of this event could not.be specifically determined..
Either the fuse was originally installed by the vendor or (
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it was installed as result of maintenance or other-
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operational' activities which did not= provide for confir-mation of proper fuse installation.
The :following
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corrective actions were initiated:
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The improper fuses were replaced and thec LC0 was exited.
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Procedure 00304-C. Equipment Clearance And Tagging",
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-paragraph 4'1.1, was revised to require that fuses be
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individua11y, bagged. and tagged unless contained:in
assemblies.-
The fuses must now be-removable o identified by panel number and fuse _ location whenever_
removed'for clearances.
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Procedure 00306-C, " Temporary Jumper And Lifted Wire -
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Control", paragraph 4.9, was revised to require that a
fuses be individually bagged and tagged. unless
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contained in removable assemblies.
The fuses must also be identified by panel number and fusa location 1'
whenever removed.
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Design engineering, in conjunction with plant personnel, analyzed fuses in fire event safe shutdown
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circuits and electrical penetration protection l
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circuits and walked down and o inspected c those -
accessible fuses necessary for performance of the circuit's safety related functions.-
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Training to familiarize appropriate plant' personnel with fuse installation, removal, -and replacement-
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H requirements was conducted.
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Procedures to verify that fuses on printed circuits
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boards are correct prior to board 3 replacement, were revised.
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Design reviews were performed by the architect engineer and NSSS vendor to -identity-those fuses utilized for accident scenarios cr required to~ satisfy-m specific design requirements.
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For those fuses identified in corrective action #7,-an.
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inspection was performed.- The_ inspection identified differences between the "as installed" and the' "as
' designed" configuration. Deficiencies identified were replaced or an engineering evaluation 'was: performed to,
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demonstrate the adequacy of the "as installed"
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condition.-
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The inspector has no further comments.
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Meeting With Local Officials - (94600)
W On July 2,1990, a public meeting was held by the NRC with local officials
of Waynesboro and the County Boards;of Commissioners for, all counties
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within a ten mile radius of the site..The meeting presented the mission of the NRC, ' introduction of key NRC personnel..' discussion of f linestof communications, and the-' loss of vital 1 AC power event that-occurred-on
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March 20, 1990.
The meeting was open for questions:during-the presenta-stion.
The following Region II NRC personnel attended the. meeting. -
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i A. R. Herdt, Branch Chief, Division of Reactor Projects
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- x K. E. Brockman, Chief, Reactor Projects Section 3B, Division of i
- Reactor Projects
.l K. M._ Clark, Public Affairs 0 cer d
R. Trojanowski, State and Local Government Liaison
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B. R. Bonser,-Senior ~ Resident Inspector
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'R. F. Aiello, Acting Senior Resident Inspector R..D.' Starkey, Resident Inspector J
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.P..A. Balmain, Resident Inspector
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Installation and Testing of Modification - (37828)
The objective of this review was to inspect onsite activities and hardware i
associated with tte installation of plant modifications and to ascertain
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that related modifications activities which are not submitted for approval r
to the NRC, are in conformance with the requirements of the TS, t
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10 CFR 50.59, and 10 CFR 50, Appendix B, Criterion III, " Design Control."
i The specific design change reviewed was the adding of two vents to the
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spent fuel pool cooling system return lines so that maintenance can be performed on either the heat exchanges, or the gate valves and the butterfly valves which are located in the return lines downstream of the heat exchangers.
Prior to the modification, draining the return lines i
required lowering the spent fuel pool water level to permit uncovering of the siphon breaker holes.
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The inspector obcerved work being performed, reviewed the design change documents and discussed the modification with the system engineer.
The inspector toured the work area with the system engineer and the responsible maintenance foreman.
The work package, MWO 29002686, was
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inspected for thoroughness including verification that QC hold points had been signed off.
The inspector determined that the modification had been
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performed according to the DCP and at-built drawings and in accordance with procedure 00400-C, Plant Design Control, Rev. 11.
No violations or deviations were identified, j
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Midloop/ Reduced Inventory Activities The inspector reviewed the licensee's preparation for midloop/ activities
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for the upcoming Unit 2 refucHng outage (2RI).
The inspector verified that appropriate procedures are in place which address the concerns of Generic Letter 88-17 (Loss of Decay Heat Removal) dated October 17, 1988.
Procedures are active and in use for the following requirements.
Containment Closure Capability For Mitigation Of Radioactive Releases
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- Procedure 14210-1, Containment Building Penetration Verification (Refueling), Rev.
5, is used to verify containment building penetrations status prior to and during refueling er core alterations or movements of irradiated fuel within the containment.
Procedure 18019-C, Loss of Residual Heat Removal, Rev. 8, step A8, states that when RHR cooling can not be restored in a timely manner, and when RCS level is less than the 191 foot elevation then initiate containment closure using procedure 14210-1.
Additionally, procedure 12007-C, Refueling Entry, Rev.15, requires that if it is intended to drain
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doin to less than 3 feet below the Reactor Vessel Flange then determine the closure status of Containment Equipment Hatch and ensure the hatch is capable of being closed within 57 minutes.
However, if it is intended to reduce RCS level more than 3 feet below
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the reactor vessel flange, then ensure the hatch is closed prior to exceeding 3 feet below the flange.
Maintenance procedure, 27505-C, Opening and Closing Containment Equipment Hatch, Rev. 3 gives iirection for the actual closing of the equipment hatch.
I Cf Temperature Indications - Procedure 120'"i-C, Unit Cooldown to
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Cold Shutdown, Rev.16. states that if it u intended to operate below the 191 foot elevation then a minimum of two incore.
thermocouples shall be available during periods where the reactor head is installed.
RCS Level Indication - Procedure 12007-C, Refueling Entry, Rev.15,
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requires that when RCS level is belcw 17% pressurizer level that temporary RCS level indication must be installed.
There are two control room indicators and a local tygon tube indicator which are used to meet this requirement.
Two out of the three level monitors must agree before the RCS is drained below the top of the hot leg.
Procedure 23985-1, RCS Temporary Water Level System, Rev. 1, provides instruction for the installation, channel calibration and removal of the RCS Temporary Water Level System.
RCS Perturbations Avoidance - Procedure 12007-C, Refueling Entry,
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Rev. 15 step 2.1.4 (Precautions and Limitations), states that during periods of operation with the RCS level below the Reactor Vessel Flange elevation, ongoing work activities should be closely scrutinized and any work activii.y that has the potential for reducing RHRS capability should be limited.
A similar statement can be found in procedure 12006-C, Unit Cooldown to Co'd Shutdown, Rev.16, Step 2.1.17.
RCS Inventory Addition - Procedure 18019-C, Loss of Residual Heat
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Removal, Rev. 8 Attachment 8, provides instructions to operators on how to gravity drain the RWST to the RCS, Procedure 12007-C, Refueling Entry, Rev.15, step 2.2.9 describes two boron injection flow paths, one of which must be available while in Mode 5 or 6.
One of these. flow paths is from the Boric Acid Storage Tank via a Boric Acid Transfer Pump and a Charging Pump to the RCS, The second floupath is from the RWST via a charging pump to the RCS.
The licensee has drafted a TS change request which would allow the SI pumps to be available during a reduced inventory condition.
The TS change request is expected to be approved by the GPC corporate office on August 31. 1990.
Nozzle Dams / Loop Stop Valves - Procedure 12007-C, Refueling Entry,
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Rev.15, and procedure 12006-C, Unit Cooldown to Cold Shutdown, Rev. 16. have similar steps concerning nozzle dams. These procedures state that if SG nozzle dams are to be installed and no cold leg opening is to be established, a vent path is required from the reactor vessel upper plenum.
This vent path can be satisfied by:-
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f (a) removing a pressurizer manway, or (b) removing a SG manway on a hot leg that will not be damed, or (c) removing three pressurizer code safeties.
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Repower to Vital Busses From Alternate Source if Primary Source Is
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Lost - Procedure 13427-1, 4160V AC IE Electrical Distribution System, Rev.12, step 4.4.2, provides instructions on powering the 4160V IE Switchgear through the emergency incoming breaker.
7.
Allegations Allegation Ril-90-A-0121, Potential Security Compromise due to Missing Security Grating.
Concerni A concerned was identified that between the cooling towere and the water discharge there was a cover over an opening, possibly a pipe, which had some form of security grating or bars that were not locked and apparently should have been locked.
The inspector was concerned that some storm drains did not have proper security barriers, thus permitting unauthorized access into either the PA or VA.
Discussion:
The concern involved security barriers (presumably on storm drains) that were not locked down, thus permitting possible unauthorized access to either the PA or VA.
Due to the vagueness of the original concern the inspector was not able to determine if referrence was being made to the circulating water cooling towers outside the PA or the NSCW cooling towers inside the PA.
Therefore, the inspector conducted an inside as well as outside PA walkdown to examine all storm drains that could provide possible unauthorized access.
Conclusion:
The-inspector was able to confirm that some storm drains outside the PA did not have security barriers. However, all storm drains /manways outside the PA which were not secure posed no threat or compromise to the PA. Tha inspector conducted a similar walk down inside the PA to examine the-potential for a security breach from the PA to the VA.
The inspector discovered one ventilation duct leading from the PA (outside) to the VA (inside) that appeared unsecured.
A further investigation with the Manager-Security revealed that an internal security barrier existed between the vent duct s9ction and the VA precluding any unauthorized entry.
The inspector has no further comments regarding this concern end it is, therefore, considered closed.
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8.
ExitInterviews-(30703)
The inspection scope and findings were summarized on August 28, 1990, with those persons indicated in paragraph 1 above. The inspector described the areas inspected and discussed in detail the inspection results.
No dissenting comments were received from the licensee. The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspector during this inspection.
Region based NRC exit interviews were attended during the inspection period by a resident-inspector.
This inspection closed one Licensee Event Report and one allegation. One item was identified during this inspection period:
URI 50-424/90-17-01 and 50-425/90-17-01 "Pending resolution of the enforcement issues associated with the corrective actions following D/G start failures on 4/12/90 and 07/05/90" - paragraph 2.b.(6).
9.
Acronyms And Initialisme AC Alternating Current CCW Component Cooling Water System CFR Code of Federal Regulations DC Deficiency Cards DCP Design Change Package DG Diesel Generator ESF Engineered Safety Features FHB Fuel Handling Building GPC Georgia Power Company HDT Heater Drain Tank IST Inservice 'esting LC0 Limiting Conditions for Operations LER Licensee Event Reports MCC Motor Cc..+.rol Center MDAFW Motor Driven Auxiliary Feedwater Pumps MFP Main Feed Pump MSIV Main Steam Isolrtion Valve MWO Maintenance Work Order NPF-Nuclear Power Facility NRC Nuclear Regulatory Commission
.NSCW Nuclear Service Cooling Water System NSSS Nuclear Steam Supply System PA Protected Area P&lD Piping and Instrumentation Diagram QC Quality Control
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RCS Reactor Coolant System Rev Revision RHR Residual Heat Removal System RWST Refueling Water Storage Tank SG Steam Generator
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SI Safety Injection System TS Technical Specification URI Unresolved Item VA Vital Area VAC Volts Alternating Current l
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