ML20129H914
See also: IR 05000424/1990019
Text
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UNITED STATES
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NUCLEAR REOULATORY COMMIS$10N
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101 MARIETTA STREET,N.W.
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ATLANT A, GEORGI A 30323
NOV 2 71991
%.....
NOTICE OF SIGNIFICANT MEETING
Name of Licensee:
Georgia Power Company
Name of Facility:
Vogtle, Units 1 and 2
Docket Nos.:
50-424, 50-425
i
Date and Time of Meeting:
December 16, 1991, at 1:30 p.m.
Location of Meeting:
Region II Office, Atlanta, Georgia
Purpose of Meeting: An Enforcement Conference to discuss the circumstances
associated with failure to provide accurate information to
the NRC during the inspection as documented in 50-424,
425/90-19 and 50-424/90-19, Supplement 1.
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NRC Attendees: S. D. Ebneter, Regional Administrator
E. W. Merschoff, Acting D.irector, Division of Reactor Projects'
(DRP)
G. R. Jenkins, Director, Enforcement and Investigation
,
Coordination Staff
A. R. Herdt, Chief, Reactor Projects Branch 3, DRP
P. S. Skinner, Chief, Section 3B, DRP
J. M. Partlow, Associate Director for Projects, NRR
G. C. Lainas, Asst. Director for Region II Reactors, NRR
D. Hood, Project Manager, Division of Reactor Projects, NRR
ias Project Engineer, RP3B, DRP, RII,
S.J.kt M,e.D A
Licensee Attendees: W. G. Hairston, III, Senior Vice President - Nuclear
Operations
C. K. McCoy, Vice President - Vogtle Project
W. Shipman, General Manager - Vogtle
NOTE:
Attendance by NRC personnel at this NRC/ Licensee meeting should be
'
made known by 4:00 p.m., December 10, 1991, via telephone call to
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S. Vias, FTS: 841-5350.
4
Ba 6,& ,
/
Approved by:
Meded
P~ierce H. Skinner, Chief.
Reactor Projects Section 3B
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Division of Reactor Projects
Distribution:
(See page 2)
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9611040115 960027
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KOHN95-211
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Notice of Significant Meeting
2
goy 2 7 1991
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Distribution:
J. H. Sniezek, Deputy Executive Director for Nuclear Reactor
Regulation, Regional Operations and Research
H. L. Thompson, Jr., Deputy Executive Director for Nuclear
Materials Safety, Safeguards and Operations Support
T. E. Murley, Director, Office of Nuclear Reactor Regulation,
J. G. Partlow, Associate Director for Projects, NRR
G. C. Lainas, Associate Director for Region II Reactors, NRR
i
J. Lieberman, Director, Office of Enforcement
S. A. Varga, Director, Division of Reactor Projects - 1/II, NRR
D. Matthews, Director, Directorate 1-3, NRR
D. Hood, Project Manager, Division of Reactor Projects, NRR
J. F. Wechselberger, Regional Coordinator EDO
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J. Goldberg, Deputy Assistant General Counsel for Hearing
and Enforcement
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GEORGIA POWER COMPANY
NRC
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A.
DOMBY
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HYDR 0 GEN MONITOR ISOLATION VALVES
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ALLEGED STATEMENT:
(IR 90-19)
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"...TNE US$ INDICATED THAT THESE VALVES (CIVS) RECEIVED A
(AUTOMATIC) CONTAINMENT ISOLATION SIGNAL.
THE OPERATIONS
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MANAGER CONFIRMED THIS STATENENT IN A LATER DISCUSSION WITH THE
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INSPECTION TEAM."
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DISCUSSION:
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US$ BELIEVED THE VALVES RECEIVED dUTOMATIC CLOSURE SIGNAL.
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USS'S STATEMENT NOT SURPRISING:
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US$ WAS ON SNIFT AND UNDERSTOOD THE TEAM WOULD BE
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FAMILIARIZING THEMSELVES WITH CONTROL ROOM;
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NOT PART OF ROTE MEMORY;
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TOUR INTERRUPTED BY NRC QUESTIONS; NO PRACTICAL
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OPPORTUNITY FOR RESEARCN;
$
USS UNAWARE THAT GUESTION WAS MORE THAN INFORMATIONAL.
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UNREASONABLE FOR NRC TO RELY ON ANSWER, GIVEN CONTEXT:
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USS DIO NOT PERCEIVE QUESTION AS FORMAL;
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NRC DID NOT ASK US$ TO CONFIRM.
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HYDR 0 GEN MONITOR ISOLATION VALVES
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US$ PROVIDED CORRECT INFORMATION ON OWN INITIATIVE AT FIRST
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OPPORTUNITY (AND WNEN UNAWARE OF NRC CONCERN):
OPERATIONS MANAGER DID NOT STATE OR CONFIRN TNAT VALVES
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WERE AUTOMATIC ISOLATION VALVES.
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CONCLUSION.
ACCURATE INFORMATION WAS PROVIDED PRIOR TO TNE END OF DAY SHIFT.
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HYDR 0 GEN MONITOR ISOLATION VALVES
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$
ALLEGED STATEMENT:
(SUPPLEMENT 1)
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"DURING A UNIT 1 SURVEILLANCE PROCEDURE, THE
{
UNIT SHIFT SUPERVISOR (US$) STATED, AND THE
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OPERATIONS MANAGER LATER CONFIRMED, THAT THE
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CONTAINMENT ISOLATION VALVES FOR THE HYDROGEN
MONITOR SYSTEM WERE ALLOWED TO BE OPENED
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.WITHOUT ENTERING THE LC0 ACTION REQUIREMENTS
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FOR TS 3.6.3 BECAUSE THE' VALVES RECEIVED AN
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AUT0NATIC ISOLATION $1GNAL."
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DISCUSSION:
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UNIT 2 SURVEILLANCE, NOT UNIT 1;
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USS ExPLAINEo OPEN VALVES WERE PERMITTED BY SURVEILLANCE PROCEDURE;
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THERE WAS NO DETAILED DISCUSSION WITH USS OF THE APPLICATION OF TS
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3.6.3 ' AND WNETNER COMPLIANCE WAS ASSURED;
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UNSEASONABLE FOR NRC 70 RELY ON USS STATEMENTS ALONE FOR
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GPC POSITION, GIVEN CONTEXT *
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USS PROMPTLY AND VOLUNTARILY PROVIDED ACCURATE INFORMATION
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RE: AUTOMATIC ISOLATION.
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. OPERATIONS MANAGER DID NOT STATE THAT VALVES RECEIVE AN
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AUTOMATIC ISOLATION SIGNAL.
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OPERATIONS MANAGER STATED THAT CIVS COULD BE OPENED WITHOUT
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ENTERING THE- LC0 REQUIREMENTS OF TS 3.6.3.
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HYDR 0 GEN MONITOR ISOLATION VALVES
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CONCLUSION:
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USS ~ DID NOT DISCUS $ TS COMPLIANCE WITH THE. TEAM.
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OPERATIONS MANAGER DID NOT TELL THE TEAM THAT THE VALVES RECEIVED A
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CONTAINMENT ISOLATION SIGNAL BUT DID HAVE SUBSTANTIAL DISCUSSIONS
REGARDING TS COMPLIANCE THROUGHOUT THE DURATI0il 0F THE INSPECTION.
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STATEMENT IN SUPPLEMENTAL' REPORT APPEARS TO BE AN INACCURATE
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SYNTHESIS OF STATEMENTS TAKEN FROM THE ORIGINAL INSPECTION REPORT.
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SNUBBER REDUCTION MODIFICATIONS
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ALLEGED STATEMENTS:
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A.
(IR 90-19) ". ..THE OPERATIONS MANAGER STATED THAT THE MAJORITY
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0F THE MODIFICATIONS (T0 THE SNUBBERS) WERE PERFORMED IN
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CONJUNCTION WITH PRE-PLANNED SYSTEM OUTAGES. "
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B.
($UPPLEMENT 1) "THE OPERATIONS MANAGER STATED THAT . . .
THE MODIFICATIONS TO THE SNUBBERS (ALWAYS) WERE DONE IN
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CONJUNCTION WITH PREPLANNED SYSTEM OUTAGES WHICH WERE
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REQUIRED FOR OTHER PREVENTIVE OR CORRECTIVE MAINTENANCE OR
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TESTING."
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"INE INSPECTION IDENTIFIED THAT FEW OF THE $NUBBER
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M00!FICATI0h5 WERE DONE JOINTLY WITH PRE-PLANNED SYSTEM
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OUTAGES."
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DISCUSSION:
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A STATEHENT $1MILAR TO A WAS MADE; 8 SHOULD NOT IMPLY "ALWAYS".
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STATEMENT MADE WAS UNDERSTANDABLE:
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CONSISTENT WITH PRIOR VEGP PRACTICES;
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CONSISTENT WITH KNOWLEDCE OF INITIAL PLANNING.
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COMMUNICATORS SELIEVED THIS WAS STILL THE PRACTICE.
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VEGP ' WORK PLANNING / SCHEDULING GROUP CHANGED APPROACH.
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CHANGE IN APPROACH WAS NOT KNOWN TO COMMUNICATORS.
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SNUBBER. REDUCTION _ MODIFICATIONS
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STATEMENT WAS MADE IN INFORMAL CONTEXT.
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- ALLEGEo INACCURATE INFORMATION NOT MATERIAL.
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SOME "$NUSSER LC0" ONLY WORK WAS ACKNOWLEDGED;
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NOT A POSITION STATEMENT DEMONSTRATING COMPLIANCE.
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UNREASONABLE FOR NRC TO RELY'ON STATEMENT ALONE
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CLEARLY BASED ON UNDERSTANDING OF COMMUNICATORS;
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00ALITATIVE RESPONSE TO QUESTION;
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ALTERNATE, OBVIOUS PRIMARY SOURCE OF COMPLETE INFORMATION.
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HRC INFORMED OF CHANGE IN PRACTICE AND SUPPLIED DETAILED
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DOCUMENTATION PRIOR TO EXIT.
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SNUBBER REDUCTION MODIFICATIONS
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CONCLUSION:
A svATEMENT sIMILAR TO A WAS MADE.
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STATEMENT A WAs sAsED ON REASONABLE EXPERIENCE AND KNOWLEDGE.
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"ALWAYS" 5N00LD NOT BE IMPLIED IN STATEMENT 8.
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STATEMENT 8 Is NRC MrsPERCEPTION BASED ON INFORMAL, ORAL STATEMENT
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DURING FACT-FINDING.
CORRECT INFORMATION WAS PROVIDED TO NRC PRIOR TO THE EXIT.
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PERSONNEL ACCOUNTABILITY
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ALLEGED STATEMENT:
($UPPLEMENT 1)
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"THE OPERATIONS MANAGER STATED TMAT THE
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SHIFT SUPERINTENDCNTS ($$) REPORTED
DIRECTLT TO THE OPERATIONS MANAGER. . ."
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"THE INSPECTION REVEALED TMAT THE $$ REPORTED 70
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THE UNIT SUPERINTENDENT -(US) . . . "
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DISCUSSION:
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OPERATIONS MANAGER'S STATEMENT WAS ACCURATE.
THE $$ REPORTED
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TO OPERATIONS MANAGER AT THE TIME.
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$$ DID NOT REPORT TO THE US AT TIME OF INSPECTION (VEGP
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PROCEDURE 10000-C REVISION or MARCH 23, 1990);
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$$ DID WORK CLOSELT WITH US AT TIME OF INSPECTION;
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CONCLUSION:
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APPARENT NRC MISPERCEPTION BASED ON INFORMAL, ORAL STATEMENTS
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DURING FACT-FINDING REGARDING WORKING RELATIONSHIP BETWEEN $$
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AND US.
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PERSONNEL ACCOUNTABILITY
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ALLEGED STATEMENT:
($UPPLEMENT 1)
"THE OPERATIONS MANAGER STATED THAT...
HE PERSONALLY PREPARED THEIR ($NIFT
$UPERINTENDENTS') PERFORMANCE APPRAISALS."
"THE INSPECTION REVEALED. . .THAT THE US PERSONALLY
PREPARED THE PERFORMANCE APPRAISALS OF THE $$."
DISCUSSION:
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OPERATIONS MANAGER DOES NOT RECALL MAKING THIS STATEMENT.
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RESPONSIsILITY FOR WRITING PERFORMANCE APPRAISALS WAS DELEGATED
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TO U$ SY THE OPERATIONS MANAGER.
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OPERATIONS MANAGER REMAINED INVOLVED IN SETTING ANNUAL
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PERFORMANCE GOALS FOR $$.
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OPERATIONS MANAGER WAS PERSONALLY INVOLVED IN PERFORMANCE
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APPRAISAL DEVELOPMENT OF $$.
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DELEGATION OF RESPONSIBILITY FOR DRAFTING PERFORMANCE APPRAISALS
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DID NOT ALTER REPORTING STRUCTURE.
ALLEGED STATEMENT IS NOT MATERIAL TO REGULATORY MATTER $;
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CONCLUSION:
APPARENT MISCOMMUNICATION BASED ON INFORMAL, ORAL STATEMENTS
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DURING FACT-FINDING.
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ALLEGED INCOMPLETE STATEMENT:
($UPPLEMENT 1)
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"THE UNIT SUPERINTENDENT (MS) INDICATED THAT THERE WERE NO
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OPERATIONS DEPARTMENT ACTIONS WHICH WERE ANTICIPATED OR
REQUIRLN WITHIN THE FIRST THREE HOURS OF ENTERING THE
ACTION. STATEMENT OF TS 3.0.3."
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"THE INSPECTION IDENTIFIED THAT (VEGP POLICY AND PRACTICE) REQUIRED
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PREPARATIONS FOR A POWER REDUCTION, INCLUDING INFORMING THE
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LOAD DISPATCNER WITHIN THE FIRST HOUR."
DISCUSSION:
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ONLY ONE CONVERSATION BETWEEN U$ AND NRC INSPECTORS ON THIS ISSUE.
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FIRST DAY OF INSPECTION; US MAD COME SY TO MEET INSPECTORS, OFFER
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SUPPORT;
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US IMMEDIATELY OUESTIONED ON TS 3.0.3 COMPLIANCE BY 2 DIFFERENT
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INSPECTORS.
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AS US REMEMsERS, FOCUS WAS ON PLANT SHUTDOWN (I.E., PHYSICAL
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' INITIATION) AS REQUIRED BY TS 3.0.3
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CONVERSATION WAS INFORMAL -- NO TIME OR NEED FOR RESEARCH/ REFLECTION.
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US' MADE IWO POINTS:
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GPC'S " GOOD FAITH" APPROACH TO INITIATING SHUTDOWNS IN TS 3.0.3;
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GPC'S PRACTICE FOR REPORTING TS 3.0.3 SHUTDOWNS.
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ANTICIPATED TS 3.0.3 ACTIONS
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U$ DID NOT BELIEVE IT NECESSARY TO DISCUSS PREPARATIONS
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FOR SNUTDOWN (PRIOR TO PHYSICAL PLANT MANIPULATION) OR
NOTIFYING LOAD DISPATCHER.
NOT GERMANE TO HIS POINTS;
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NOT ASKED FOR BY INSPECTOR $.
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US WAS AND IS WELL AWARE OF REQUIRED PREPARATIONS AND NOTIFICATIONS; NO
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REASON TO CONCEAL INFORMATION.
TNESE MATTERS WERE SUBSEQUENTLY ADDRESSED:
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INFORMATION PROVIDED TO INSPECTORS SY OTHERS DURING INSPECTION;
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GPC PROVIDED DETAILED DISCUSSION IN FEBRUARY 8, 1991 RESPONSE TO
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INSPECTION REPORT 90-19.
US DISCUSSION OF TS 3.0.3 WAS ONLY A SMALL PART OF
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SUBSTANTIAL DISCUSSIONS RE TS 3.0.3 POLICIES / PRACTICES.
CONCLUSION:
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NOT A MATERIALLY INACCURATE OR INCOMPLETE STATEMENT; RATNER, A
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CASE OF MISCOMMUNICATION;
US DID NOT BELIEVE NRC WAS ASKING ABOUT REQUIRED ACTIONS SHORT OF
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PNYSICAL PLANT MANIPULATION TO INITIATE SHUTDOWN;
" MISSING" INFORMATION WAS NOT MATERIAL TO ISSUES BEING DISCUSSED.
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ENFORCEMENT CONSIDERATIONS
10 CFR 50.9 COMPLETENESS AND ACCURACY OF INFORMATION
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"(A) INFORMATION PROVIDED TO THE COMMISSION. . .BY A LICENSEE. . .$NALL BE
COMPLETE AND ACCURATE IN ALL MATERIAL RESPECTS."
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ACCURATE AND COMPLETE INFORMATION WAS PROVIDED;
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UNSWORN, ORAL STATEMENTS--PARTICULARLY IN PRELININARY FACT FINDING
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PROCESS--SHOULD NOT BE RELIED UPON SY INSPECTORS WITNOUT DUE
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CONSIDERATION OF CONTEXT;
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MATERIALITY MUST BE ASSESSED IN CONTEXT:
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MOST ISSUES NOT SIGNIFICANT
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NO INTENT
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NO BENEFIT
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RULE OF REASON SHOULD BE APPLIED REGARDING COMPLETENESS
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OBLIGATION TO SEEK ADDITIONAL INFORMATION TO CLARIFY
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UNDERSTANDING
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ENFORCEMENT CONSIDERATIONS
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PART 2, APPENDIX C, SECTION VI
POLICY PR0vIoES FACTORS TO BE CONSIDERED FOR ENFORCEMENT INVOLVING
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ORAL STATEMENTS.
1.
DEGREE OF KNOWLEDGE REGARDING MATTERS AT ISSUE:
VARIABLE;
2.
OPPORTUNITY AND TIME TO ASSURE ACCURACY:
LOW;
3.
DEGREE OF INTENT OR NEGLIGENCE:
NONE;
4.
FORMALITY:
NONE;
5.
REASONASLENESS OF NRC RELIANCE:
LOW, GIVEN FACT FINDING
CONTEXT;
6.
IMPORTANCE OF INFORMATION:
LOW TO NONE;
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REASONABLENESS OF EXPLANATION:
HIGN;
IN SUM, FOR ALL 7 STATEMENTS, FACTORS HEAVILY WEIGH TOWARD HQ
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ENFORCEMENT.
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ENFORCEMENT CONSIDERATIONS
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PART 2, APPENDIX C, SECTION VI
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" ASSENT AT LEAST CARELESS DiSPEGARD, AN INCOMPLETE OR INACCURATE ORAL
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STATEMENT NORMALLY VILL NOT GE SUBJECT TO ENFORCEMENT ACTION UNLESS IT
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INVOLVES SIGNIFICANT INFORMATION PROVIDED BY A LICENSEE OFFICIAL. "
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$1rATEMENTS AT !$$UE NOT MATERIALLY INACCURATE OR INCOMPLETE;
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MOST--IF NOT ALL--INFORMATION AT ISSUE IS NOT "SIGNIFICANT".
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POLICY FURTNER EMPNASIZES TNAT ENFORCEMENT NOT USUALLY TAKEN WHEN
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CORRECT INFORMATION WAS SUBSEOUENTLY PROVIDED.
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TNIS $NOULD APPLY;
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DURING INSPECTION, AND IN FOLLOW-UP RESPONSE TO ORIGINAL
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$
INSPECTION REPORT, COMPLETE AND CORRECT INFORMATION WAS AVAILABLE
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OR PROVIDED.
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SUMMARY
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NO ENFORCEMENT ACTION APPROPRIATE
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UNSWORN, ORAL STATEMENTS
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CONTEXT WAS INFORMAL, PRELIMINARY FACT-FINDING
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NO INTENTIONAL MISSTATENENT OR CARELESS DISREGARD FOR
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ACCURACY OR COMPLETENESS
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COMMUNICATORS ATTEMPTED TO PROVIDE RESPONSIVE, CORRECT
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INFORMATION
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SUPPLEMENTAL INFORMATION PROVIDED DURING INSPECTION
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NUCLEAR REGULATORY COMMISSION
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REGION 11
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101 W ARIETTA STRE ET. N.W.
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ATL ANT A. GEORGI A 30323
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Docket Nos. 50-424, 50-425
DEC 0 21991-
Georgia Power Company
. ATTN: - Mr. W. G. M eston, III
Senior Vice President -
,
Nuclear Operations
P. O. Box 1295
Birmingham, AL 35201
Gent 1e' men:
SUBJECT:
NRC INSPECTION REPORTS .N05. 50-424/91-30 AND 50-425/91-30
This refers to the special inspection conducted by the Nuclear Regulatory
Comission (NRC) Augmented Inspection Team (AIT) at your Vogtle Electric
Generating Plant (VEGP) during the period of October 29.- November 1,1991,
concerning a loss of Decay Feat Removal capability that occurred on October 26,
1991.
At the conclusion of the inspection, the findings were discussed with
those members of your staff identified in the enclosed inspection report.
The enclosed copy of the AIT report identifies the areas examined during this
.
inspe: tion.
Within these areas, the inspection consisted of selective
examinations of procedures and representative records, interviews with
personnel, and observation of activities in progress.
The AIT concluded that the event was caused by a combination of factors
.
including a comon mode failure to all reactor vessel level instrumentation
'
that was being used to monitor level in the reactor vessel and an inadequate
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,
control.of a temporary modification connected to the primary system.
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' A review of the inspectior findir.gs is continuing to detemine whether the
'
described activities violate NRC requirements.
You will be advised by separate
'
correspondence of the results of our review on this matter.
In accordance with Section 2.750 of the NRC's " Rule > of Fractice." a copy of
this letter and the enclosure will de placed in the NP.C Pubin: Document Ecom.
'
Should you have any questions concerning this letter, please contact us.
.
Sincerely.
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Stewart D. Ebneter
Regional Administrator
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KRC Inspection. Report
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Georgia Power Company
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cc w/ encl:
DEC 0 2199;
R. P. Mcdonald-
Executive Vice President-Nuclear
Operations
Georgia Power Company
P. O. Box 1295
Birmingham, AL 35201
C. K. McCoy
Vice President-Nuclear
Georgia Power Company
P. O. 1295
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'
Birmingham, AL 35201
W. B. Shipman
,
General Manager, Nuclear Operations
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Georgia Power Company
P. O. 1600
Waynesboro, GA 30830
J. A. Bailey
Manager-Licensing
Georgia Power Company
P. O. Box 1295
Birmingham, AL 35201
D. Kirkland, !!I, Counsel
Office of the Consumer's
Utility Council
Suite 225, .32 Peachtree Street, NE
Atlanta, GA 30302
Office of Planning and Budget
Room 615B
270 Washington Street, SW
Atlanta, GA 30334
Office of the County Commissioner
Burke County Consnission
Waynesboro, GA 30830
Joe D. Tanner, Consnissioner
Department of Natural Resources
205 Butler Street, SE, Suite 1252
_ Atlanta, GA 30334
.
Thomas Hill, Manager
Radioactive Materials Program
Department of Natural Resources
.
4244 International Parkway
--
(cc w/enci cont'd - see page 3)
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Georgia Power Company
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DEC 0 21991
cc w/ enc 1: (Continued)
Suite 114
Atlanta, GA 30354
Attorney General
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Law Department
132 J;dicial Building
Atlanta, GA 30334
Dan Smith, Program Director
of Power Production
Oglethorpe Power Corporation
2100 East Exchange Place
P. O. Box 1349
'
Tucker, GA 30085-1349
Charles A. Patrizia Esq.
Paul, Hastings, Janofsky & Walker
12th Floor
.
1050 Connecticut Avenue, NW
Washington, D. C.
20036
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NUCLEAR REGULATORY COMMISslON
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ATLANTA GEORGIA 30323
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101 MARIETT A STRE ET.N.W.
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Report Nos.:
50-424/91-30 and 50-425/91-30
Licensee: Georgia Power Company
]
Docket Nos.: 50-424 and 50-425
.
License Nos.: NPF-68 and NPF-81
Facility Name: Vogtle Electric Generating Plant Units 1 and 2
Inspection Conducted:
October 29 - November 1, 1991
' Team Members:
B. Breslau, Reactor Inspector, RIl
G. Galletti, Human Factors Specialist, NRR
C. Liang, Senior Reactor Systems Engineer, NRR
0. Star
y, Resident inspe: tor - Vogtle, Ril
4.Ach /!
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M/2/.29, /91/
Team Leader:
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P. Skinner, Section Chief, Reactor
Date Signed
Projects Section 3B, Division
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Reactor Projects, Rll
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TABLE OF CONTENTS
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P'92
1.
Introduction - AIT Fonnation and Initiation . . .. . . . . . . . . . . .
1
A.
Background ............................................ 1
8.
A I T F o rma t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
C.
AIT Charter - Inspec tion Ini tiation . . . . . . . . . . . . . . . . . . . 1
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D.
Persons Contacted ..................................... 2
E.
. A c r o nym s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
F.
Documents Reviewed ............................'........ 2
11. Ev en t Des c r i p t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
A.:
Event Overview for Vogtle Uni t 1 . . . . . . . . . . . . . . . . . . . . . . 2
B.
I n i t i a l Cond i tions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
C.
Detailed Sequence of Events as Verified
by the AIT and Licensee Personnel . . . . . . . . . . . . . . . . . . . . . 3
! ! ! . Radia ti on Pro tec tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
IV. Safety System Performance and Plant Proximity
To Sa f e ty L imi ts a s De fi ned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
V.-
Procedures Reviews..........................................
7
1
VI.
Training....................................................
8
V I I . O pe ra to r Ac t i ons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
VI!!. Reactor Control System Water Level
I n s t rume n ta t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
j
IX. " B " RHR P ump O pe ra bi l i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
X.
S i ghtgl a ss Modi fication. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
XI. Gene ri c Le t te r 88-17 Ac ti ons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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XII . Human Performance impl ica tions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
A.
I n t r o d u c t i on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
B.
Co n tri bu t ing Caus e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
1.
C ommu n i c a t i on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
2.
Des i gn Control Practi ces . . . . . . . . . . . . . . . . . . . . . . . . . 16
3.
Procedural Factors...............................
17
. X I I 1. Re p o r t a ba 1 i ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
X I V . C o nc l u s i on s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
- XV. Exit Interview with Licensee Management . . . . .. ... . . . .. . . .. . 19
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APPENDICES
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Appendix A
Persons Contacted ...........................
20
Appendix B
Acronyms ....................................
21
Appendix C
Documents Reviewed ..........................
22
FIGURES
Figure 1
RHR System Simplified Diagram
figure.2
RCS Siteglass Header Simplified Drawing
figure 3
Mid Loop Level Instrumentation Range Information
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Figure 4
Event and Causal Factors Chart
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1.
INTRODUCTION - AIT FDRMATION AND INITIATION
A..
Background-
Vogtle Electric Generating . Plant Units 1 and 2 are four reactor
coolant loop Westinghouse pressurized water reactors rated at 3411 MW
thermal. The units are located approximately 26 miles southeast of
Augusta, Georgia in Burke County.
Unit 1 received a full power
operating license in March 1987, and Unit 2 in March 1989.'
B.
AIT Formation
On the morning of Monday, October 28, 1991, the Regional
Administrator, after further briefing by the regional and resident
staff and consultation with senior NRC management, directed the
formation of an AIT with Region !! and NRR personnel.
,he Ali was to
be headed by a Region 11 Reactor Projects Section Chief. The basis
for the formation of the AIT was to gain a clearer understanding of
the event related to the degradation of Decay Heat Removal that
j
occurred at Vogtle Unit 1 on October 26, 1991.
C.
AIT Charter - Inspection Initiation
,
The Charter for the Ali was prepared on October 28, 1991.
The
special inspection consnenced at 10:30 a.m. on October 29 with an
entrance meeting and VEGP licensee management briefing of the event.
The Charter for the AIT specified that the following tasks be
completed:
1.
Develop and validate the sequence of events associated with the
October 26, 1991, degradation of decay heat removal at Vogtle.
This secuence is to begin with plant conditions inriediately
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prior to this event, including known significant deficiencies in
safety-related and balance of plant equipment, and extend until
the plant was stable.
!
2.
Evaluate the significance of this event with regard to
f
radiological consequences, safety system performance, fuel
integrity and plant proximity to safety limits as defined in TS.
3_.
Identify any human factors, training.or procedural deficiencies
related to this event.
Evaluate operator actions during the
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event ~ and subsequent equipment recovery. Specifically, evaluate
- the effectiveness of the procedures for recovery from 1058 of
decay heat removal which were used during this event, and the
requirements for monitoring
primary plant parameters such as
.
reactor coolant temperature and pressure while shutdown and
during changes to the shutdown cooling lineup.
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- Evaluate the degree to which prior work planning for the outage
could have precluded this event. Include the following aspects:
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(a) ~ independent verifications, (b) verbal comunications, (c)
outage control, and (d) system engineer involvement.
5.
Evaluate the basis for the decision that this event was not
reported to the NRC and evaluate the adequacy of the event
classification.
6.
Determine if the following played a significant role in this
event: system modifications; plant material conditions; the
quality of maintenance; or the responsiveness of engineering to
identify problems.
7.
Evaluate the effectiveness of management involvement during the
event, the post event reviews, and subsequent recovery.
8.
For each equipment malfunction or personnel error
to the extent practical, determine:
a.
Root cause.
b.
If the equipment was kr:wn to be deficient
prior to the event,
c.
If equipment history would indicate that the
equipment had either been historically unreliable or if
maintenance or modifications had been recently performed.
d.
Pre-event status of surveillance, testing
(e.g.,Section XI), and/or preventive maintenance.
.9.
Prepare a special inspection report documenting
the results of the above activities within 30 days of inspection
completion.
D.
Persons Contacted
See Appendix A
E.
Acrony:s
See Appendix B
F.
Do:uments Reviewed
See Appendix C
- !!. Event Description
A.
Event Overview
At approximately 10:30 p.m., on October 26, 1991, while Vog'tle Unit 1
was in mode 6 (refueling) with the reactor vessel head off, the
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licensee was draining the cavity and reactor vessel to just below the
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reactor vessel flange to facilitate replacing the head.
The "B"
Residual Heat Removal (RHR) pump was in use for decay heat removal,
while the "A" pump was being used to pump down the cavity and vessel.
.
As draining continued, the licensee observed indications of
cavitation on the "B"
RHR pump. ' The "B" RHR pump was_ placed on
minimum flow recirculation (miniflow) and the "A" pop was realigned
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to take a suction from the RWST and used to raise water level in the
vessel. Decay heat removal capability was restored after water level
was reestablished.
The reactor was without decay heat removal for
approximately 16 minutes. Core temperature as indicated at the RHR
pump discharge increased from approximately 87 degrees F to 107
degrees F.
There was no radiological release to the environment.
.
This event was reported by the licensee in LER 50-424,425/91-09:
Loss of Residual Heat Removal Pump Flow During Draindown of Reactor
-Cavity.
B.
Initial Conditions
The unit was in day 42 of a scheduled 52 day refueling outage.
Presently the schedule has been extended to approximately 68 days.
- C.
Detailed Sequence of Events as Verified By the AIT and
Licensee Personnel
DATE/ TIME
EVENT
10/26/91
3:32 p.m.
"A" RHR pump secured following pump down of reactor
cavity at 210'4"
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6:20 p.m.
USS comences shif t turnover process with his relief -
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topics include pending reactor cavity / vessel level
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decrease.
APO inside containment notified by RO to
monitor RCS tygon tube for level changes.
6:30 p.m.
APO in containment called control room to establish
communications for cavity draindown. Level watch was
established at the new level sightglass.
6:33 p.m.
Started
"A" RHR pump to lower reactor cavity and
vessel level from 210'4" to 192' at a flowrate of
approximately 100 gpm to the RWST.
6:48 p.m.
USS shift relief turnover completed.
Off-going USS
not aware- that drain down had comenced.
Reactor
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cavity level was at 208' at this time as indicated by
the pressurizer level indicator (cold ~ calibrated
instrument)
RCS level at 207' as read on Pressurizer cold level
7:25 p.m.
-
instrumentation 1-LI-462
Oncoming PE0 relieves APO on
station at sightglass
7:30 p.m.
and discovers that valves HIH, DIH, and DIL are shut
and valves GD and GV are open with caps installed.
The APO and PE0 notify the control room and draining
was stopped. The sightglass was then valved in and
At that time the sightglass, tygon
vented by the PEO.
tube and visual cavity indication were all reported
reading approximately 205'6".
'
8:10 p.m.
Draining was resumed at a flowrate of 1000 gpm.
8:34 p.m.
RCS level at sightglass was 204'6".
8:59 p.m.
RCS level at sightglass was 203'6".
9:14 p.m.
RCS level at sightglass was 202'6".
9:23 p.m.
RCS level at sightglass was 201'6".
9:38 p.m.
RCS level at sightglass was 198'6".
9:47 p.m.
At approximately 197' on the sightglass the drain rate
)
was decreased
from approximately 2500gpm to
approximately 800gpm.
An " Accumulator *4 Hi/Lo Level" alarm (RCS High Level)
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10:01 p.m.
annunciator was received in the control room (ALB
'06-003). The RO tapped meter indicator 1-LI-957. The
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meter reading dropped immediately from 100% to 60%.
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(1-LI-957 was the indication associated with the level
Draining was
device providing this alarm signal.)
<
The USS called I & C personnel to
'
stopped.
investigate 1-L1-957. At this time the sightglass
,
was verified to read 194'
Reactor cavity level was
also verified to be at 194' which is at the vessel
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The RO decided that the sightglass was thr:
most reliable indication.
,
Draindown continued to 192' at a rate of approximately
-10:17 p.m.
675 gpm.
10:24 p.m.
RCS level at sightglass 193'6".
'
10:31 p.m.
RCS level at sightglass.193'.
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10:33 p.m.
Control room operators observed
"B"
RHR flow
,
oscillations and decreasing pump discharge pressure
indicative of cavitation. RHR flow and pump discharge
pressure as observed by the RO decreased to O gpm and
,
'O psig. The R0 aligned the "B" RHR pump to miniflow
,
alignment.
- 1-LI-957 indicated approximately 30%(188'3")
.
- 1-LI-950 indicated approximately 60%(187'6")
,
- sightglass indicates 193'
- Reactor vessel level reported approximately
,
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l' below flange (193')
!
10:34 p.m.
Oraindown was stopped by closing
"A"
RHR pump
discharge valve placing pump in a miniflow lineup.
j
Pump was then shutdown.
j,
Entered A0P 18019-C, Loss of RHR (Mid Loop LOCA)
.
10:38 p.m.
"B"
RHR pump cavitation stopped. Pump still on
)
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miniflow.
4
10:39 p.m.
SS paged to return to the control
room.
55
instructed operators to raise level to greater than
the cavity floor level to remove any question as to
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RCS level.
"A" RHR pump was aligned to pump water
from RWST ~ to RCS at a flowrate of 400 gpm.
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10:44 p.m.
Shut
"A" RHR pump discharge valve and opened
"B"
discharge valve to establish a recirculation flowrate
i
of 350 gpm.
i
Attempted to increase flowrate to 3000 gpm
cavitation noted and flow reduced to 1800 gpm.
'
10:45 p.m.
SS determined that the event did not require emergency
classification.
.
10:56 p.m.
"A" RHR pump aligned to fill reactor vessel at a
flowrate of 400 gpm.
j
11:10 p.m.
Stopped vessel fill at an indicated level of
j
approximately 194' at sightglass.
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11:16 p.m.
"B" RHR pump flow stabilized at 3000gpm.
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11:30 p.m.
SS contacted Operations Manager to discuss event.
10/27/91
1
12:15 a.m.
Operations identifies sightglass top isolation valve.
HIL, closed and red tagged.
Also discovered that a
HEPA filter was connected to the top of the
pressurizer safety valve flange with.the attached hose
collapsed.
HEPA was turned off and a vent path for
the Pressurizer established.
2:00 a.m.
SS contacted the Operations Unit Superintendent to
discuss reportability.
It was decided that this event
was not reportable.
6:30 a.m.
Assistant General Manager infonned of event.
He
proceeded to the site to start event investigation and
organize a critique team.
8:30 a.m.
Vogtle event team established.
111. Radiation Protection
At the time of this event, personnel were performing limited
r.aintenance activities outside the bioshield. There were approximately 30
to 40 personnel in containment, the majority of whom were HP technicians
and decontamination personnel.
Decontamination was planned for the area
near the vessel flange but work had not begun. There were two continuous
air sample monitors close to the reactor cavity neither of which recorded
any activity during this event.
Following and during the event HP did
not initiate any additional surveys.
There were no personnel
contaminations or overexposures as a result of this event.
IV. Safety System Performance and Plant Proximity to Safety Limits
Unit 1 had completed refueling. The reactor vessel head was removed. The
"A"
RHR pump was operating for cavity pumpdown at a flow rate of
apprcxicately 675gpm.
The "B" RHR pump was operating for core cooling at
a flow rate. of approximately 3000gpm.
Upon indication of cavitation at
the
"B" RHR pump, the RO realigned the pump to a miniflow lineup and
aligr.ed the "A" RHR punp to raise water in the vessel and cavity area.
Af ter sufficient cavity level was regained, the "B" RHR pump was realigned
to resume it's function of core cooling by stabilizing at a flow rate of
1800;pm and then increas'ing to the TS required flow rate of 3000gpm.
Durir.g the transient, the required core cooling was interrupted for a
peri:d of approximately 16 minutes.
The RCS temperature as read at the
discr.arge of the
"B" RHR pump increased from 87 degrees F to a peak
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temperature of 107 degrees F.
The data recorded in the ERF computer
,
indicated that there was a short period of time during which the "B" RHR
pump discharge pressure was near zero psig. This indicated that the pump
may have been running without any flow during this time period.
However,
the'"8" RHR pump was later verified by the licensee to be operable without
having sustained any damage.
The RHR pumps at this facility are designed
without protection from automatic pump trip when a low suction pressure
occurs or on a low flow condition.
The pump protection for these
conditions is the operation of the pump in a miniflow alignment and
1) ERF computer
operator actions in response to the following) symptoms: abnormal pump discharge
(SPDS) alarm on RHR pump motor instability; 2
flow; and 3) unstable pump discharge pressure.
The assessment of the
.
operability of the
"B" RHR pump after the transient is addressed in
'
section IX of this report.
Except for the reactor vessel level instrumentation that is used for
I
cavity and vessel pumpdown which was not functioning properly as discussed
in section VIII of this report, all plant safety systems required for
i
these plant conditions were functional.
This included the Component
Cooling Water system, and the Nuclear Service Water Cooling system
(ultimate heat sink), RCS makeup capabilities by gravity feed from the
RWST, and the charging pumps.
Based on the plant specific data provided in figures 2 and 3 of plant
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Operations Procedure 18019-C, the staff projected that the estimated time
to RCS saturation was 75 minutes and the estimated time to uncover the
core was 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> under the loss of core cooling condition assuming
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shutdown cooling flow could not be reestablished.
Thus, a sufficient
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safety margin to any safety limit existed during the transients. No TS
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required safety limits for these plant conditions were exceeded.
Under
the plant conditions discussed above, the staff considers that the fuel
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integrity had not been affected during this event.
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V.
Procedure Reviews
Procedures and administrative controls were reviewed to verify that
l
exin ing prot.edures covered reduced inventory operations, provided
'
precautions and prerequisites for entering into a reduced inventory
condition, and
to determine whether existing procedures contributed to
<
this event.
i
.
The licensee's initial investigation revealed that a collapsed HEPA filter
duct attached to a ' pressurizer safety valve penetration prevented the
pressurizer from being vented to the atmosphere. The HEPA filter was a
fan type unit rated at 2000 to 2400 cfm with the capability of maintaining
approximately 1.2" wg pressure at 2000 cfm.
The licensee utilizes a
-
reactor coolant system sightglass manifold with attachments for a tygon
tube as an independent method of determining RCS level during reduced
inventory conditions. Operation procedures listed in Attachment C, invoke
the requirement that a tygon tube watch be established when RCS level is
to be lowered below 15'; pressurizer level (207 feet) and periodic checks
,
_
.
.
.
8
should be made every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> between the control room indication and the
tygon tube. The control roor indicators should be within 7% of scale with
the tygon tube.
-
J'
The Operations procedures provide guidance that should level be lost or
0
become suspect, to suspend draining operations and resolve problems, and
1
t
,e
if necessary, initiate injection to restore level.
However, no
\\
(
instructions were provided directing Operations to verify that a correct
" g.
tygon tube lineup existed, and to ensure an adequate vent path was
,.
established,
$-
,
,
[
Independent level indication is required when the RCS will be
~
depressurized and less than 140 degrees F.
Maintenance is directed to
connect level indication per maintenance procedure 54840-1. The procedure
provides instructions for installation, fill and leak testing of the
sightglass manifold and/or tygon tube, however, it does not include
guidance concerning establishment or verification of an adequate vent
path.
Procedure 54840-1 was not implemented prior to consnencing the RCS
draining evolution, nor was any other approved procedure utilized
-
to verify alignment of the independent RCS level indication.
.VI.
Training
The training program was reviewed to determine the extent to which the
licensee addressed potential difficulties that may occur during reduced
inventory conditions; whether related industry events involving loss of
cooling during mid-loop operations were covered prior to entering )the
current outage; and training materials were reviewed (Attachment C to
determine whether they contributed to the apparent loss of shutdown
cooling.
The inspector reviewed the licensed and non-licensed operator trainir;
programs, including the continuing training program and reviewed course
,
completion and attendance records.
The curriculum provides ample
information concerning reduced inventory operations and loss of coolir.;
during mid-loop operations.
The basic overview lesson of the RHR system, the licensed operator ar.d
non-licensed operator lesson plans for the RHR system operations (start
up, place in standby readiness, loss of RHR, cavity fill and draining
activities) were reviewed. Additionally, reviews of student handouts and
simulator guides coupled with the reviews of instructor lesson plans were
determined to adequately cover pump cavitation and vortexing phenomena.
The training material adequately covered the importance of accurate level
indication for the RCS during draining and mid-loop operation. This area
was stressed throughout the training program.
Numerous references were
made concerning the importance of preventing excessive flow rates,
preventing kinked hoses, collapsed lines due to vacuum, improper valve
.--
_ _ . _
,_ _.
_ _
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. _ _ _ _ _ _ _
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,'9,
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[*
-9-
t
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i
i
lineups, air bubbles, debris in lines, improper routing, temperature of
.
-
the. fluids, surge line uncovery, and improper syste.. flow rates which can
i
cause inaccurate level indication.
Even though the operators received extensive training concerning thi
importance of RCS level indication and all the conditions that can affect
!
-
RCS level indications, operator interviews revealed that the operators did
!
not relate the RCS level indication problems encountered on the October
26, 1991, to improper venting.
,
4-
l
VII. Operator Actions
l-
Interviews were conducted with the operators involved with the October 26,
1991 apparent loss of shutdown cooling event. Discussions involved shift
turnover information verbal directions given to individual operators,
what interpretation was given to the directed activities and the
'
j
individual's judgement involved in addressing: RHR pump cavitation, and
.
the observed RCS level discrepancies involved with the installed
i
instrumentation, the tygon tube, and the sightglass manifold.
h
Operator interviews revealed that during the day shift, on October 26,
,
'
1991 ECCS testing had been completed, RHR train B was supplying shutdown
cooling with train A being used for-reactor cavity draining and to support
'
.
!
cavity decontamination efforts.
The cavity .was drained down to 210 feet
!
from 215 feet.
The cavity level was monitored cer-tinuously by direct
l'
observation by an operator. The operator was in direct connunication with
the control room via headset.
Subsequently, operations was requested to
i
continue lowering cavity level for. further decontamination of cavity walls
.
'
!
and to support weld repairs for indications noted on reactor vessel
f
1
>
j
The day shift established a tygon tube watch about ene hour prior to shift
l
change to support draining the cavity below the 2C7 feet level.
The
operator establishing the tygon tube watch improperly assumed that the new
1
-
!
sightglass modification was turned over to Operations since there were no
j;
clearance tags hanging on' valves associated with the new sightglass. The
i
clearance tags had been removed inadvertently through other activities in
j
the area. He did not conduct a walkdown of the new installation nor did
l'
he question the control room concerning the operability of the new
(
sightglass modification.
L
The on-coming operator assigned to relieve the tygon tube watch noted that
i
the off-going watch was having difficulty observing any level within the
n
j
sight glass. Draining was in progress and RCS level was reportedly at 207
feet and decreasing. The level should have been visible at the top of the
'
sightglass.
The on-coming operator noted that the sightglass was empty
-
.and promptly : reported the condition to the control room operator. The
j(
control room operator stopped .all draining activities and directed the
tygon tube watch to investigate. The tygon tube watch determined that the
4
'
sightglass was isolated and reported this condition to the control room,
stating that the system alignment would be corrected and that the
,
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m
,
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, -
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.-
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10
'
'
Both the off-going and the
sightglass would then be filled and vented.
I
on-coming tygon tube watch performed actions which they thought corrected
o
However, this
the valve lineup. and filled and vented the gauge glass.
task was accomplished without the use of any drawings or procedures to
i
>
ensure a correct lineup was established.
The control room operator actions, when being notified that the sightglass
was empty and isolated, were appropriate in stopping all activities
!
F
associated with draining of the reactor cavity.
However, the operator's
f
actions were not appropriate since draining activities were resumed
l
without making _a determination of why the sightglass was empty and
isolated with a tygon tube watch established.
.
,.
Once the operators aligned the sightglass (one valve was later found to be
.
I
closed), filled and vented the system, draining was recommenced after
detennining that levels in the sightglass, tygon tube and reactor cavity
<
The cavity level did not
J
were -indicating the same approximate level.
appear to be decreasing as quickly as expected for the draining rate in
L
The drain rate was decreased, but the level decrease seemed to
j
i
!
A level
j
progress.
The draining was stopped to allow level to settle.
increase.
check between the tygon tube, sightglass and cavity level indicated a
i
l
level of 194 feet.
'
-
At about the same time as the level check was being conducted, the high
{
This appeared to have been a reflash-
level alarm for the RCS alarmed.
The control room operator observed that the reactor vessel
i
-condition.
wide range level gauge (1-LI-957) indicated full and tapped the gauge.
r
}
The level indication dropped from 100 percent to 60 percent. Operations
contacted I&C.
The discussion revealed that the instruments had
l
historically been unreliable in similar situations. The decision was made
I
that the sightglass was the most reliable indication.
Operations
continued draining to 192 feet.
At approximately 193 feet indicated
'
level, RHR B pemp flow became erratic, flow and pressure went to zero.
on minflow.
- .
The operator secured shutdown cooling and placed the pump
l
Operations subsequent actions were correct in recovering reactor cavity
level and reestablishing shutdown cooling.
Cooling was lost for
approximately 16 minutes.
Further investigation by operations found a .
collapsed pressurizer vent duct on the instruments' vent path (comon mode
l
failure for all instruments) and a closed valve (should have been open)
'
between the top of the sightglass and the pressurizer, both of these
discrepancies contributed to false RCS level indication on all indicators.
4
VIII'. Reactor Coolant System Water. Level Instrumentation
The inspectors reviewed the licensee's RCS water level instrumentation to
determine whether there were at least two independent, continuous
~
indications of the RCS water level available when the plant was to be
,
operated in a reduced inventory condition.
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p.
11
.
i
The licensee had established a visual level indicator (tygon tube) from
j
the bottom of the hot leg to.the top of the pressurizer. The connections
for this instrument were from the loop 1 intermediate leg to a vent valve
-
.
on .the top of the pressurizer. The tygon tube had a scale of one foot
,
l
increments.
This method of . level indication had been used during outage
conditions since initial plant operations.
,
!.
The licensee had also established an electronic level monitoring system
that indicated levels in a reduced inventory condition (lower than the
vessel flange level).
This' level indication was displayed in the control
room. The method used to implement this indication was' to disconnect the
,
nomal level instruments from the number 1 and 4 accumulators (1-LT-950
s
. and 1-LT-957) and connect temporary level transmitte.rs to this circuitry.
These temporary level instruments are connected to the RVLIS isolators and
,
1
to pressurizer level transmitter 1-LT-459.
The instruments use the
-
accumi,lator electronics' circuits to provide an alam from 1-LI-950 when
,
,
187', and an alam from
j
reactor vessel level decreases to approximately(this alam is nomally
,
1-LT-957 if level increases to a level of 192'
,
illumir.ated with levels greater than 192'in the vessel and cavity area).
'
4
she configuration of both the visual and electronic level indications
being connected to the pressurizer resulted in this being a connon point.
As a result, when the HEPA filter was placed on the pressurizer vent point
and a vacuum drawn on the pressurizer, all of the instruments were ~
- 7
affected in a nonconservative direction.
In addition, since ESF testing
. had caused level changes in the cavity and vessel, pumping down out this
. . .
- -
excess water also added to the vacuum condition since an adequate vent
path was not available.
Therefore two independent level instruments were
"
not available for this function.-
IX. Operability of "B"
RHR Pump
During this event the "B" RHR pump was observed to experience cavitation
- on two separate occasions.
The first cavitation occurred at 10:35 r m.
,
and was approximately three minutes in duration. The second was at 10:59
p.m. and lasted approximately two minutes. After the pump was restored to
!
nomal flow conditions, control room personnel monitored pump running ups
and flow for stable conditions.
The indications appeared to be nomal.
. An operator was dispatched to the "B" RHR pump room to visually inspect
the pump.. His visual inspection determined that there were no unusual
pump noises, vibrations, seal leakage or bearing damage.
Based on the
. observations at the pump and control room indications, operations
personnel determined the pump was safe to continue to operate.
. On October 28, 1991, the licensee initiated several actions to verify that
no da . age had occurred to' the pump.
Maintenance technicians took
vibration readings at two locations 90 degrees apart near the pump / motor
flange. The pump!at that time was operating at 3050gpm compared to a flow
rate cf 2000gpm which .is the normal flow rate that these vibration
readings are taken.. iThe readings were 1.3 mils ~ and 1.5 mils.
The
readings' were slightly higher than the prevtous high readings of 1.0 mils
'
and. 0.3 mils _(Westinghouse allows up to 3 mils for these values.) The
,
% .
.m.
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difference could possibly be attributed to the difference in flow rates at
l-
which the readings were taken.
Also an IST Senior Engineer, using the
,
October 26 pump operating data, calculated that the pump was operating
!
slightly below the desired point on the pump operating curve but was above
!
the minimum acceptable curve assumed in the safety analysis. Maintenance
j
Engineering personnel also took vibration data readings at six locations
j
on the pump and motor.
This data compared favorably with previous
historical data dating back to April 1988.
None of the six recorded
!
points exceeded the baseline values nor did they approach the warning or
alert limit values. Motor current readings were also taken and found to
i
i
be acceptable. On October 31, the licensee also obtained upper and lower
bearing oil samples for analysis.
The results of the analysis of these
!
samples indicated no abnormal conditions in the pump bearings.
,
I
Due to existing plant conditions the licensee was not able to estabitsh
,
the necessary system alignment to conduct a formal IST on the "B"
j
!
Procedure 14812-1, Residual Heat Removal Pump and Check Valve IST,
pump.
requires 23 feet of water above the reactor vessel flange for Mode 6
testing. Since the reactor vessel head was about to be installed and the
reactor cavity had been drained, the test was not conducted. The licensee
l
planed to conduct an IST prior to entering Mode 4 in accordance with
procedure 14805-1, Residual Heat Removal Pump and Check Valve IST - System
in Standby.
j.
The licensee consulted Westinghouse concerning potential pump damage as a
result of running the pump in the conditions existing at the time of the
event. Westinghouse advised that when a pump is operated under adverse
suction pressure conditions, the level of pump damage and the continued
,
i
pump operability is best determined by inspection and testing of the pump.
'
They advised the licensee to rotate the pump shaft by hand and to vent the
'
pump casing prior to operation.
In addition, during subsequent operation,
visual observation for leakage should be conducted to confirm that the
pump seal is not damaged.
Vibration levels, pump head and motor amperage
should be monitored during operation.
They' further stated that if these
values meet the surveillance requirements, this would confirm that the
pump suffered no internal damage that will affect the pump hydraulic
performance or operability.
On November 1, after the Unit had entered Mode 5, the licensee performed
procedure 14812-1 for the "B"
RHR pump.
The measured data from that
,
surveillance were within the accaptable range and the performance of the
"B" RHR pump was considered satisfactory.
-
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13'
X.
Sightglass Modification
The design and installation of the Unit 1 RCS level indicating sightglass
was controlled under DCP 91-V1N0150-0-1.
The purpose of the DCP was to
replace the original sightglass which had been installed during the second
refueling and which was determined to be an unacceptable design.
Operations had expressed a preference for a continuous level indication
spanning from the pressurizer heaters to the bottom of the hot leg. This
type of sightglass had been installed on Unit 2 during the last refueling
and the intent was to duplicate that design on Unit 1.
The design
incorporated a flexible, clear plastic hose as -the sightglass to measure
.
the RCS water level' during draindown and reduced inventory or mid-loop
operations in the region between the bottom of the pressurizer and the
bottom of the hot legs.
-
'
.
,
At the ' time of this event, the sightglass modification was essentially
(y
complete.
All that remained to be done was a scale adjustment and the
j
'
performance of a functional test.
Maintenance was still holding the MWO
l
e
paperwork since the scale had not been set.
The sightglass had been
tagged out by operations, however, one of the hold tags at the bottom of
the sightglass was missing.
The system engineer responsible for the
modification had not yet completed a RTS form to be placed with the
'
Modification Log located in the Control Room. Thus, the Control Room had
not been notified in writing that the modification had been completed and
that the system was ready to be used.
XI. Generic Letter 88-17 Actions
.
i
4
GPC responded to GL 88-17 in correspondence dated December 29, 1988.
In
this correspondence with respect to providing two independent, continuous
RCS water level indications whenever the RCS is in a reduced inventory
condition, the licensee responded as follows:
I
RCS water level is monitored via temporary level
!
instrumentation whenever the RCS in a reduced inventory
condition.
Operations procedures -include instructions
to notify Instrumentation and Control personnel to
install temporary level instruments prior to draining
-
the RCS. Instrumentation and Control Procedure 23985-1,
"RCS Temporary Water Level System", provides instruc-
tions for installation of two independent channels of
level indication using temporary transmitters and
- -
existing levels instrumentation in the control room.
4
'
Level is measured directly from the hot leg between the
-.RVLIS upper range lower tap and the pressurizer steam
,
' space to minimize thermodynamic and pressure errors.
,
One channel provides wide range level indication from
i
approximately one foot below mid-loop to the vessel
'
The other channel provides narrow range level
,
indication from approximately one foot below mid-loop to
the top of the hot leg. Level is continuously monitored
'
and ' alarmed in the control room.
A-low level alarm is
- set at three inches above the center of the hot leg.
'
'
.-
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_
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14
In addition to the temporary level transmitters, a tygon
tube is installed 'per Procedure 54890-1, " Installation
and Removal Instructions for the RCS Water Level Tube".
The tygon tube is used as a backup to be continuously
monitored when operating below 17% pressurizer level, if
either control room indication is lost or while reducing
RCS level.
GPC believes that this recomendation is appropriately
addressed, and no further action is planned.
The NRC reviewed the response and in correspondence to GPC dated
January 27, 1989, the NRC stated that the staff had reviewed the submittal
and found that is generally met the intentions of the generic letter with
respect to expeditious actions and is adequate for plant operation. This
letter also identified areas that were incomplete, however, the response
associated with level indications was not questioned.
NRC review of the GL 88-17 implementation is addressed in NRC Inspection
Report Nos. 50-424/89-19 and 5C-425/89-23.
Although the reactor vessel level indicating system was connected to the
RCS as stated in their correspondence for the electronic level
instrumentation, the licensee did not provide a description of the tygon
tube system which was the backup for the electronic system. Since all of
this instrumentation had a corinon reference into the pressurizer, all
level instruments would be affected by perturbations in the pressurizer.
The system installed does not meet the intent of two independent
continuous water level indications as discussed in GL 88-17.
XII. Human Performance implications
A.
Introduction
The team reviewed control room and local control instrumentation used
by the operators during the drain down evolution to determine if the
indications available to the operators may have contributed to the
event.
The team determined that the Control Room instrumentation, operator
aids, and local RCS level indications used by the operators during
the diain down evolution were readily accessible, adequately
labelled,'and adequately scaled for the activities associated with
the planned evolutions.
The temporary modification of the control
room accumulator tank level gauges and annunciator windows for RCS
level indication were understood by the reactor operators. Although
annunciator window for ALB-06-D03, " Accumulator r4 Hi/Lo level",
associated with temporary RCS level indicator 1-LI-957, had not been
modified to read "RCS High Level" prior to the event, the operators
understood that the annuniciator was associated with RCS level. The
-addition of temporary operator aid PTDB-1, "Mid-loop Level
~
. .
,
15
Instrumentation Unit 1", to control panel 1A1, provided the operators
with a useful tool for conversion of control room RCS level
indication from . level as a percentage (".) to level in feet. This
helped provide consistency with the local RCS level indications which
were scaled in feet (temporary tygon tube) and in both feet and
inches (sightglass).
The team considered additional aspects of human performance which may
have contributed to this event.
The team reviewed a sample of the
licensee's administrative controls and operating procedures,
interviewed plant Operations personnel, and walked down local RCS
level indication systens.
As a result, the team determined that the
human performance aspects which contributed most significantly to
this event include: (1) miscommunication between control room crew
and plant equipment operators in the containment; (2) weakness in
design control practices; and (3) weaknesses in procedural
implecientation.
An Event and Causal Factors Chart has been prepared to aid in the
understanding )of the human performance implications of this event
(see Figure 4 .
From the chart, it becomes evident that several
causal factors contributed to most of the events leading up to the
RHR pump cavitation.
The team has attempted to characterize the
human factor implications outlined in this chart.
l
B.
Contributing Causes
!
The. team determined that several causal factors contributed to the
failure of the operating crew to realize the actual RCS level and to
understand the factors which may have contributed to the erroneous
,
RCS level indications.
Human errors are seldom the result of a
<
single root cause, and as described below, this investigation
identified several facters which together contributed to the event.
1.
Comunications
The day-shift auxiliary operator was instructed by the control
room supervisor to monitor the tygon tube. The USS, knowing the
sightglass had not been returned to service, expected the APO to
F
monitor the tempcrary tygon tube according to his instructions.
The APO reported to the 185' level'of the containment building
and upon seeing the sightglass believed he should monitor that
system, and proceeded to do so. During shift turnover, a second
AP0 was- requested .to relieve the operator at the tygon tube.
When the second APO arrived at the sightglass, he assumed the
- s
system had1been returned to service, since the APO already at
'
the location was monitoring the device.
The second APO did
[
realize that the sightglass was empty and called the Control
Room to report the conditon.
Af ter consultation with the
-
Control Room,' the AP0s proceeded to fill and vent the system in
~'an attempt .to. place it in operation.
4
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16
These activities were characterized by a lack of explicit
.
instruction to the AP0s dispatched to monitor local RCS level
as to which indicator was to be used.
In addition, the AP0s
.
and control room operators did not fully consider or question
their supervision as to why the sightglass was isolated prior to
i
placing it into operation. . These consnunication breakdowns
l,
contributed to the use of unauthorized and inappropriate plant
i
equipment for monitoring RCS level,
j
2.
Design Control Practices
j
The team reviewed the design control process and
'
observed several weaknesses in this process and its
implementation of the sightglass modification.
Administrative controls for the implementation and closure of
Design Change Packages are ptevided in procedure 50008-C, DCP
i
Implementation and Closure.
ihe procedure specifies that a
l
Return to Service (RTS)
Checklhi, shall be completed by the
responsible engineer and presented to the USS for notification
prior to. declaring the system operable. The USS may then, at
'
his discretion, declare the system operable or wait for
i
additional activities ' to be completed, if such additional
.
j
activities are required.
,
The methods used by the USS to notify operations personnel of
.
the status of system operability may include: (1) discussion
.
during shift turnover briefings; (2) inclusion in crew required-
reading books if the modification affects procedures; (3)
general
crew discussions;
(4)
or for insignificant
,
modifications, may not warrant any discussion among the crew at
all. However, these methods are infonnal, and do not appear to
be governed by sufficient administrative control to ensure that
all plant personnel affected by modifications would be notified
3
of such changes.
I
The design control process allows for the removal of clearance
'
!
tags on equipment for functional testing prior to returning the
l
'
equipment to service. This process, as noted by the team during
~
~
1
walkdown of the sightglass modification, may create a situation
where plant personnel could mistakenly implement equipment not
i
returned to service because of a lack of clearance tags or other
1
indications on the equipment. As a result of the evaluation of
this event, the APO's dispatched to locally monitor RCS level
indication did not observe any clearance tags on the sightglass
>
.or lower boundary isolation-valve (HIH) and, therefore, assumed
'
,
that the equipment had been returned to service.
The lower
valve had been previously tagged but the tag had apparently
'
'
fallen off.
!
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17
3.
Procedural Factors
Procedural guidance on the installation and use of the
sightglass indicator is provided in procedure 54840-1, RCS
Draindown Modifications: RCS Sightglass, Tygon Tube, and Defeat
of RHR Suction Valve Auto Closure Interlock. This procedure was
not, at the time cf the event, released to operations because
the sightglass had not yet been functionally tested and returned
to service.
The operators dispatched to locally monitor RCS
level attempted to place the system in operation without the
appropriate procedure or valve lineup sheet. As a result, the
operators did not realize that an upper boundary isolation valve
J
(HIL) had been installed during the modification and therefore
failed to open this valve and align the system correctly.
Had
the operators atte. pted to open valve MIL, they would have seen
a clearance tag or. the valve and may nave questioned the use of
the sightglass for nonitoring RG 1evel.
In addition, the team determined that the operating procedures
used during the craindown (UOP-12000 C) did not require the
sightglass to be walked down prior to use to ensure proper
alignment and a ver.t path. if the operators had walked down the
entire system befcre starting to monitor RCS level, they may
have observed the clearance tag on the upper isolation valve and
questioned the use of the sightglass.
If the sightglass had
been completely walked down prior to operation, the operators
would probably have noted the HEPA filter installed on the
pressurizer and notified the Control Room operators of the
collapsed hose.
.
XIll.
Reportability
The licensee considered the reportability of this event in accordance
with 10CFR50.72 at 10:35 p.m. on October 26. Vogtle procedure 9100-C
did not identify any condition that would result in imediate
notification _ of the NRC.
At about 2:00 a.m. on October 27, the SS
contacted the Operatier.s Unit Superintendent to discuss the event.
They concluded that since the
"B"
RHR pump was not secured in
response to the cavitation problem and that the cavitation did stop
when flow was' reduced, and the "A" pump was also available and did
not cavitate when used to add water to the vessel, a complete loss of
cooling did not occur. They decided that a report in accordance with
10CFR50.73 was not required.
At 6:30 a.m. that morning the Assistant General Manager - Operations
was' notified. He contacted the General Manager and Vice President.
Since the decision was ?ade that this was not reportable, management-
decided- to establish an event review team to further review this
event, submit a voluntary LER, and notify the resident inspectors.
The team reviewed this isfue during the inspection and concluded that
the event should have been reported to the NRC in accordance with
10CFR50.72(b)(2)(lii)(5).
This conclusion was based on the
--
--
--
L
.__
_ _ _ .
_ _ .
. _ _ _ _
-
.
.
18
'
conditions that the
"B" RHR pump was removed from service due to a
cavitation problem and had the "A" RHR pump been placed in operation
under the existing conditions, it would have experienced a similar
'
problem.
The licensee contacted the Team Leader on November 6, and notified
4
him that upon further analysis indications existed that the "A"
pump was exhibiting signs of degradation. Based on that infonnation
the licensee notified the NRC in accordance with 10CFR50.72.
In
,
'
addition, the licensee identified that their analysis had shown that
water level had decreased to slightly below the nozzle centerline
(187'). This was based on the point that was predicted for vortexing
on the "A"
pump.
Their conclusion was the pump could not pump at a
>
flow rate of 3000gpm and, therefore, it could not meet the definition
'
of operability. The licensee also identified that calculations
indicated that temperature could have reached a maximum of 116
degrees coolant temperature and 117 degrees fuel temperature assuming
nc cooling was available during the transient. During the period of
time that the RHR pumps were not'available other makeup to the vessel
i
from the RWST and a charging pump was available.
Gravity feed from
,
the RWST could have been utilized if necessary at a flow rate of
i
approxinately 1000gpm to refill and cool the vessel.
'XIV. Conclusions
The Team made the following conclusions during the review of this event:
f
1.
Sufficient safety margin existed during the event. No TS safety
limits were exceeded ar.d fuel integrity was not affected.
i
'
2.
Operations staff took prompt action to quickly assess the
problem and reestablish shutdown cooling.
3.
Design and installation procedures for visual level indication
and electronic level instrumentation were inadequate in that
independency was not 1: plemented as part of these indicators.
This resulted in a corron mode failure for all level instruments
monitoring reactor vessel level.
4
The licensee did not ;erform an adequate evaluation concerning
the reportability of tnis event.
5.
The system for control of modifications in progress is weak in
that inadequate means were available to indicate the sightglass
system was not available for operator use.
6.
The system used to control temporary modifications is weak in
that there are no requirements to perform _an analysis for
connecting HEPA filters to safety related systems.
.
I
e
--
.-.
__
_
_
. _ _ .
.
__
_.,_._ _ _
_ _ _ . . . _ _
%
-
l
19
7.
Comunicatior.s were weak between the operators in the control
room and the AP0's in containment in that it was not made clear
which indication was required to be monitored.
In addition,
i
when notified of the sightglass being isolated and empty,
control room operators did not stop to question this condition.
8.
Operations procedures ~ provide adequate guidance that should
level be lost or become suspect . to suspend draining operations
and resolve the problem.
However, no directions were provided
in these procedures directing operators to verify correct tygon
tube lineup existed, and to ensure an adequate vent path for the
instrumentation.
9.
Training materials were adequate to cover the event in progress.
Although this material was provided during the training
sessions, the operators did not relate this problem to the
training they had been given.
XIV. Exit Interview With Licensee Management
>
The inspection scope and findings were summarized on November 1,
1991, with those persons indicated in Appendix A.
The NRC described
the areas inspected and discussed in detail the inspection results
delineated in this report.
No proprietary material is contained in
this report. No dissenting coments were received from the licensee.
p
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'
.
20
'
APPENDIX A - PERSONS CONTACTED
Licensee Employees
- J.' Bailey, Manager Licensing SNC
- H. Beacher, Sr. Engineer Technical Support
- J.- Beasley, Assisstant General Manager Operations
,
_
W. Brack, Auxiliary Plant Operator
G. Brenenborg Health Physics Supervisor
- J. Brown, Acting Training Manager
- W. Burmeister, Manager Engineering Support
D. Carter, Shift Superintendent
M. Chance, Sr. Plant Engineer
- S. Chesnut, Manager Technical Support
- C. Christiansen, Supervisor SAER
W. Diehl, Unit Shift Supervisor
G. Durrence, Plant Operator
B.' Evans, Plant Operator
T. Forehand, Plant Engineer
- J. Gasser. Unit Superintendent Operations
- H. Handfinger. . Manager Maintenance
T. Hargis, Shif t Superintendent
M. Henry, Auxiliary Plant Operator
M. Hickox, Sr. Engineer
- M. Hobbs, ! & C Superintendent
- K. Holmes, Manager Chemistry and Health Physics
G. Hooper, Plant Engineering Supervisor
J. Hopkins, Shift Superintendent-
P. H'.mphrey, Reactor Operator
C. Futton, Plant Equipment Operator
i
i
- W. Kitchens, Assisstant General Manager Support
- R. LeGrand. Manager Operations
M. Lewis, Reactor Operator
!
!
- G. McCarley, ISEG Supervisor
- K. McCoy, Vice President
-*C
Meyer, Operations Superintendent
K. Middlebrooks, Unit-Shift Superintendent
W. Mitchell, Auxiliary Plant Operator
A. Nix, Plant Equipment Operator
- R. 0 dom, Plant Engineering Supervisor
T. Polito, Unit Shift Superintendent
R. .Reece, Reactor Operator
- M. Sheibani, NSAC- Supervisor
- W. Shipman, General Manager
- W. Smith, Sr. Engineer Technical Support
- C. Stinespring, Manager Plant Administration
- J. Swartzwelder, Manager Outage and Planning
S.' White, Unit Shif t Superintendent
Other Personnel
- H. Dougherty, Oglethorpe Pcwer Cor.pany 'r Company
- J. Mintz, Sr. Engineer Southern Nuclea
- . ,
-
.
- - - .
.
-
- - - - - -
-
-
.-
-. - -.
-
~ . - . . . - . .
.
.
._ - -
'
\\
J
.
21
APPENDIX B
Augmented Inspection Team
AP0
Auxiliary Plant Operator
Abnormal Operating Procedure
Design Change Package
Emergency Response Facility
Instrumentation and Control
ISEG
Independent Safety Engineering Group
gpa
Gallons Per Minute
High Efficiency Particulate Absorber
Health Physics
Inservice Test
LER-
Licensee Event Report
Megawatt
MWO
Maintenance Work Order
NRC
Nuclear Regulatory Can-ission
NSAC-
Nuclear Safety and Compliance
PE0
Plant Equipment Operator
R0
Reactor Operator
Release to Service
Refueling Water Storage Tank
SAER
Safety Audit and Engineering Review
SPDS.
Safety Parameter Display System
Shift Supervisor
TS
Technical Specifications
UOP
Unit Operating Procedure
USS
Unit Shif t Supervisor
Vogtle Electric Generating Plant
wg
Water gauge
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_ _ _ ._
_ _ . _ _ _
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22
APPENDIX C
DOCUMENTS REVIEWED
- A.
Procedures
17006-1
ANNUNICIATOR RESPONSE PROCEDURE FOR.
-
'ALB-06 ON PANEL 1A2 ON MCB
,
14812-1
RESIDUAL HEAT REMOVAL PUMP AND CHECK
VALVE IST
14805-1
RESIDUAL HEAT REMOVAL PUMP AND CHECK
VALVE IST - SYSTEM IN STAND 8Y
12000-C, Rev. 18
POST REFUELING OPERATIONS (MODE 6 TO 5)
12006-C, Rev. 20,
UNIT C00LDOWN TO COLD SHUTDOWN
12007-C, Rev.'20,
REFUELING OPERATIONS (MODE 5 TO MODE 6)
3
12008-C, Rev. 2,
MID-LOOP OPERATIONS
13011-1, Rev. 25,
RESIDUAL HEAT REMOVAL SYSTEM
13005-1, Rev. 15,
REACTOR COOLANT SYSTEM DRAINING
14000-1, Rev. 31,
OPERATIONS SHIFT AND DAILY SURVEILLANCE
LOG
18019-C, Rev. 10
LOSS OF RESIDUAL HEAT REMOVAL (MID LOOP
LOCA)
23985-1, Rev. 3
RCS TEMPORARY WATER LEVEL SYSTEM
54840-1, Rev. 4,
"RCS DRAINDOWN MODIFICATIONS: RCS
SIGHTGLASS, TYGON TUBE, AND DEFEAT OF
RHR SUCTION VALVE AUTO CLOSURE
INTERLOCK"
6.
TRAINING MATERIALS REVIEWED
LO-LP-12101-24-C, Rev. 24,
RHR SYSTEM
LO-LP-60315-08-C, REY. 8
LOSS OF RESIDUAL HEAT REMOYAL
LO-LP-61212-01-C, REV. 1
M10 LOOP OPERATIONS
LO-lU-60315-001-C, REY. 4
RESPOND TO LOSS OF RESIDUAL
HEAT REMOVAL
- -
-
.
. .
.
.
_ ._.
. _ . - .
_
-
.
. _ .
_
i
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.
-
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23
.
!
LO-!U-12101-004', REY. 3
DRAIN REFUELING CAVITY
LO-!U-12101-005, REY.1
RESPOND TO RHR SYSTEM ALARMS
'
LO-H0-12101-002-C, REY. 5
LOSS OF RHR - INDUSTRY EVENTS
LO-SE-60266-00 REY. 0
INTEGRATED RESPONSE - REQUAL
NL-!U-12101-001, REY. 1
PREPARE RHR SYSTEM FOR
OPERATION
NL-!U-12101-002, REV. 2
DRAIN REACTOR REFUELING CAVITY
USING RHR SYSTEM
RQ-HO-12111-001-00, REV. O
RHR AND MID-LOOP OPERATION
RQ-H0-09001-01, REY. 2
CVCS SYSTEM
RQ-HO-37101-001-C, REY. 0
E0P REVISION 11
RQ-H0-12111-001, REV. 1
RHR AND MID-LOOP OPERATION
RQ-LP-63113-00, REV. O
RECL'AL CL'RRENT EVENTS
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FIOure 4 (Pace 1/2)
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A:L L E G A'T I O N
MANAGE-MENT
. SYSTEM
,
,
..-
. ALLEGATION NUMBER - RII-90-A-0005
RUN DATE: 12/05/91
DOCKET / FACILITY / UNIT: 05000424 / VOGTLE 1
/ 1
DOCKET / FACILITY / UNIT: 05000425 / VOGTLE 2
/ 2
,
cDOCKET/ FACILITY / UNIT:
/
/
'
, DOCKET / FACILITY / UNIT:
/
/
i
, ACTIVITY TYPES - REACTOR
,
'
I
- MATERIAL ' LICENSES -
.
OPERATIONS
OTHER
' FUNCTIONAL AREAS
-
-
4
l
'
~
WRONGDOING
, DESCRIPTION - ANONYMOUS LTR REGARDING THE PLANT OPS MANG WILLFULLY PLACED
'
i
-THE' PLANT IN A CONDITION PROHIBITED BY TECH SPEC.
,.
.
IN ADDITION, THE ACTION-PLACED THE PLNT~IN AN UNANALYZED
CONCERNS -
COND & CONSTITUED AN UNREVIEWED. SAFETY CONCERN SINCE THIS-
I
l'
j
~ ACCIDENT BY W FOR MODE 5 WITH REACTOR COOLANT LOOPS NOT FILL
j
.
.
ED VLVS WERE OPENED TO ADD CHEM. HYDROGEN PEROXIDE TO CLEAN '
q
CONFIDENT - NO-
i
'. SOURCE -' ANONYMOUS
J
'
RECEIVED--- 900116
BY - S. EBNETER
/ R2
l
!,. ACTION OFFICE CONTACT - J. VORSE
' STATUS - OPEN
'SCHED COMPLETION - 920130
DATE CLOSED -
ALLEGATION SUBSTANTIATED'-
ALLEGER NOTIFIED -
OI-ACTION - YES
OI REPORT NUMBER - Q2-90-001H
REMARKS - 1/19/90 REFERRED TO OI. 2/01/90 OI BRIEF INDICATES THE ALLEG
-
THEY ARE CONTINUING INVESTIGATION.
.IS SUBSTANT.
.
[KW:OPER, PROC, DOL
REF:RII-90-A-0092 --SAME'ALGR
(EICS)-
'
- CT:WRNG, SAFETY: .
AP:OI INVEST PNDG-
,
IR:
LCA:
A
PB3/DRP.
' ENTERED SYSTEM -L900216' CLOSED SYSTEM -
RECORD CHANGED - 911114
[U
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A.L'L E G A T ILO N.
M.A-N A G.E M E N T
SYSTEM
j
LLEGATION NUMBER'
RII-90-A-0026-
RUN DATE: 12/05/91
-
DOCKET / FACILITY / UNIT: 05000424./ VOGTLE 1
/1
DOCKET / FACILITY / UNIT:105000425 / VOGTLE 2
./2'
DOCKET / FACILITY / UNIT: _
-/
/
DOCKET / FACILITY / UNIT:
/
'/
ACTIVITY TYPES - REACTOR
'
MATERIAL' LICENSES -
'ONSITE HEALTH AND SAFETY
FUNCTIONAL AREAS
-
DESCRIPTION - DOL 210 COMPLAINT REGARDING RETALIATION FOR A SAFETY
-CONCERN ALLEGEDLY. RAISED IN 1989.
RII RCV'D A LTR FROM. LICENSEE ADVISING OF THE ALGR'S INTENT
~ CONCERNS
.
TO FILE DOL' COMPLAINT 2/27/90, EICS CONTACTED DOL & VERIFIED
h
1:
ALGR FILED A COMPLAINT.
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SOURCE - FORMER LICENSEE EMPLOYEE
CONFIDENT - NO
RECEIVED - 900223
BY - B. URYC
/ R2
ACTION OFFICE CONTACT - O.
DEMIRANDA
l
-STATUS - OPEN
SCHED COMPLETION - 920130
DATE CLOSED -
i
ALLEGATION SUBSTANTIATED -
ALLEGER NOTIFIED -
OI ACTION - NO
OI REPORT NUMBER -
l
REMARKS - MATTER BEING - APPLEALED TO ALJ BY LICENSEE. EICS TO MONITOR.
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KW: DOL
REF:NONE
(EICS)
CT: SAFETY,H&I
"AP: DOL ACTION.PNDG. TECH ISSUE CLOSED.
LIR:
LCA:
.
l
PB3/DRP
ENTERED SYSTEM
.900302
CLOSED' SYSTEM -
RECORD CHANGED - 911114
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_ _ - - - - - _ . - . ,,:,. .
_
_
._
.
A-L L E G A T I O N-
M A N'A G E M E N T
SYSTEM
~ ALLEGATION NUMBER - RII-90-A-0124
RUN DATE: 12/05/91
DOCKET / FACILITY / UNIT: 05000424 / VOGTLE 1
/1
DOCKET / FACILITY / UNIT: 0500042f / VOGTLE 2
/2
. DOCKET / FACILITY / UNIT:
/
/
' DOCKET / FACILITY / UNIT:
/
/
ACTIVITY TYPES - REACTOR
MATERIAL LICENSES
-
SAFEGUARDS
FUNCTIONAL. AREAS
-
' DESCRIPTION - ALLEGED FAILURE TO REPORT LOSS OF SAFEGUARDS INFORMATION
CONCERNS'-
- 1 ~
SOURCE - LICENSEE EMPLOYEE
CONFIDENT - YES
RECEIVEDL-l900724
BY - L. ROBINSON
/ RII
'
ACTION OFFICE CONTACT - J.
VORSE
l
I
STATUS - OPEN-
SCHED COMPLETION - 920130
DATE CLOSED -
ALLEGATION SUBSTANTIATED -
ALLEGER NOTIFIED -
1
HOI ACTION - YES
OI REPORT NUMPER - 2-91-003L
REMARKS - THE ARP MET ON 8/9/90 AND DETERMINED ADDITIONAL INFO REQ'D
FROM LICENSEE. ALLEG REFERRED TO OI.
1
i
KW: PROC,
'REF:RII-90-A-'
(EICS).
CT: SAFETY,WRNG, SAFEGUARDS
AP:OI INVEST PNDG
IR:
LCA:
PB3/DRP
[ARP 8/9/90)
= ENTERED SYSTEM
900806
CLOSED SYSTEM -
RECORD CHANGED'- 911114
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A"L L'E-G A'T-I O N-
M A N A-G E M E N T.
S Y S-T E M
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. ALLEGATION NUMBER --RII-91-A-0109.
-RUN DATE: 12/05/91
,
DOCKET / FACILITY / UNIT: 05000424 /- VOGTLE 1.
/ 1
DOCKET / FACILITY / UNIT - 05000425 /- VOGTLE 2
/ 2-
[
DOCKET / FACILITY / UNIT:
/
/
5
iDOCKET/ FACILITY / UNIT:
/
/ -
l
LACTIVITY TYPES - REACTOR
-MATERIAL LICENSES--
'
OPERATIONS
-FUNCTIONAL AREAS
-
!
!
DESCRIPTION - LICENSEE RESPONSE TO 2.206 ALLEGEDLY CONTAINS INACCURATE
INFORMATION
CONCERNS'--
,
1
.
1
SOURCE - FORMER LICENSEE EMPLOYEE.
CONFIDENT - NO
RECEIVED - 910528'
BY - L. ROBINSON
/ R2
" ACTION OFFICE' CONTACT - O.
DEMIRANDA
STATUS'- OPEN
SCHED COMPLETION - 920130
DATE CLOSED -
. ALLEGATION SUBSTANTIATED -
ALLEGER NOTIFIED -
'
'OI: ACTION - YES
OI REPORT NUMBER -
- REMARKS - THE ARP MET ON 5/31/91 AND DETERMINED THIS MATTER BE
-
REFERRED TO OI. ALGR PROVIDED ADDTIONAL EXAMPLES OF THE SAME
CONCERN ON 6/3/91 WHICH WAS PANELD ON 6/13/91 AND REFERRED
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'KW: MECH, EQUIP-
LREF::
[EICS)-
,
LCT:WRNG, SAFETY:
.
'
AP:OI ACTION PNDG
IR:
LCA: 6/03/91'- IN PERSON
PB3/DRP-
(ARP 5/31 & 6/1L/91)
c ENTERED: SYSTEM- - 910530--. CLOSED SYSTEM -
RECORD CHANGED - 911114
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A L LEE G-A.T.I O N-
MANAGEM'ENT
S'.Y S T E M
..
,
ALLEaATIONtNUMBER - RII-91-A-0178
RUN DATE: 12/05/91-
l
.
h' DOCKET / FACILITY / UNIT: 05000424 / ' VOGTLE 1
. /- 1-
I ; DOCKET / FACILITY / UNIT: -
/
/
, DOCKET / FACILITY / UNIT:
/
/
E DOCKET / FACILITY / UNIT:
/ -
/
ACTIVITY TYPES. -REACTOR
.,
- ..
'
i;
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? MATERIAL LICENSES
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FUNCTIONAL' AREAS-
-
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-DESCRIPTION 5-'A~ SWORN TESTIMONY BY GPC MANAGER ALLEGES THAT AN INV' DELAYED-
'
REPORTING OF A SECURITY BREACH
'
,
.
.
,
. -CONCERNS'--
-
.
1-
!
SOURCE - LICENSEE ' EMPIDYEE
CONFIDENT - NO
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1-RECEIVED
'910903
. BY - L. ROBINSON
/.R2
1
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' ACTION. OFFICE CONTACT,
.O.
DEMIRANDA
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STATUS ~
.OPEN
' SCHED COMPLETION - 911130
DATE CLOSED -
-
3 ALLEGATION SUBSTANTIATED?-
ALLEGER NOTIFIED -
'OILACTION1- NO
OI REPORT NUMBER -
1
REMARKS - THE'ARP MET ON 9/5/91 & DETERMINED THAT NMSS/ SAFEGUARDS
i
INTERVIEW INV TO DEVELOP INFO IDENTIFIED IN TESTIMONY.
I
NMSS CONDUCTED INTERVIEWS & INSPT WHICH DID NOT SUBSTANT
j
ALLEG. THE' SECURITY BREACH EVENT.WAS IDGGED IAW 10 CFR 70.71
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.
'AND, DOCUMENTED IN A "LER." NO FURTHER ACTION REQ'D.
-
1
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[EICS]
'
-REF:RII-91-A-0005
.SAME ALGR-
-
"
JAP:RAC ADMIN.CIDSE'
>LCA: 9/3/911 IN PERSON
-IR
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PB3/DRP
[9/5/91).
= ENTERED' SYSTEM
4910909: JCLOSED SYSTEM
'
RECORD CHANGED
- 911114
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LA'L'.L E G-A T-I O N-
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S Y S T.E M.
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ALLEGATION' NUMBER - RII-91-A-0198
RUN DATE: 12/05/91
DOCKET / FACILITY / UNIT: 05000424'/ VOGTLE 1
/1
DOCKET / FACILITY / UNIT: 050004251/- VOGTLE 2
/2
' DOCKET / FACILITY / UNIT:
'/
/
DOCKET / FACILITY / UNIT:-
/
- /-
'
'
ACTIVITY TYPES.
REACTOR
,
' MATERIAL LICENSES -'
,
1
ONSITE HEALTH AND. SAFETY
FUNCTIONAL. AREAS
--
'.
I
.
.
!
DESCRIPTION -~ ADMINISTRATIVE EXPOSURE LIMIT EXCEEDED DURING IDODINE LEAK-
. ..
1
CONCERNS;-
]
1'
1
' SOURCE - PRIVATE CITIZEN
CONFIDENT - NO
-
RECEIVED - 911018.
BY - O.
DEMIRANDA
./ R2
ACTION' OFFICE CONTACT - A. HERDT
STATUS:
OPEN-
SCHED COMPLETION - 911230
DATE CLOSED -
j
ALLEGATION SUBSTANTIATED -
ALLEGER NOTIFIED -
'OI' ACTION ~- NO
OI REPORT NUMBER -
REMARKS
ARP' REQ'D.
,
l
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- KW: SAFETY
REF:
[RPEP]
-
CT: SAFETY
~
'AP: POTTER-PROVIDE CLOSURE MEMO &:IR.-
IR:--
LCA: l'0/18- 19 PHONE
!
PB3/DRP-
.
'
ENTERED-SYSTEM-
911029 ., CLOSED SYSTEM -
RECORD CHANGED
' 911114
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i1.'L L E G.A T'I O N.
. M A'.N A G E M E N T ~
SYSTEM
~
i
'. ALLEGATION NUMBER!- RII-91-A-0216
RUN DATE: 12/05/91
-DOCKET / FACILITY / UNIT: 05000424 / VOGTLE 1
/.1
)
DOCKET / FACILITY / UNIT:-
/:
/
4
DOCKET / FACILITY / UNIT:
/
/
,
' DOCKET / FACILITY / UNIT:
/
/
!
" ACTIVITY TYPES - REACTOR
.
,
2' MATERIAL' LICENSES -
_
)
AFUNCTIONAL AREAS ":
OPERATIONS
-
-
)
!
l
!
DESCRIPTION - LICENSEE MANAGEMENT ALLEGEDLY LIED IN SWORN STATEMENTS
.ABOUT " KEY PARTICIPANTS" ROLE-IN LER 90-006
.
.
- ' CONCERNS-
4
.
1
.
SOURCE.- FORMER LICENSEE EMPLOYEE'
CONFIDENT - NO
.
RECEIVED - 911105
BY
L. ROBINSON
./ R2
4
' ACTION OFFICE-CONTACT - A. HERDT
STATUS - OPEN
-SCHED COMPLETION
- 911230
DATE CLOSED -
I
, ALLEGATION-SUBSTANTIATED -
ALLEGER NOTIFIED -
OI. ACTION - NO
-OI REPORT NUMBER -
' REMARKS -
,
. ;
.6
iKW:OPR
REF:NONE
-[EICS]
CT:FLSE.
e
-AP:EICS REFER TO.OI
'
- IR:-
LCA: 11/5/91 IN PERSON
-
'
- PB3/DRP
' ENTER.ED SYSTEM- . 911107
CLOSED SYSTEM -
RECORD CHANGED - 911114
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