IR 05000277/1980032
| ML19345G327 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/05/1981 |
| From: | Blough A, Cowgill C, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19345G317 | List: |
| References | |
| 50-277-80-32, 50-278-80-24, NUDOCS 8103180186 | |
| Download: ML19345G327 (29) | |
Text
50-277-80-09-09(par.4)
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50-278-80-09-08 (par.4)
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50-278-80-08-29 (par.4)
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U.S. NUCLEAR REGULATORY COMMISSION 50-278-80-08-18 (par.4)
0FFICE OF INSPECTION AND ENFORCEMENT 50-278-80-10-20 (par.3.c.)
50-278-80-10-30 (par.3.c.)
Region I 50-277/80-32 Report No. 50-278/80-24 50-277 Docket No. 50-278 DPR-44 C
License No. DPR-56 Priority Category e
Licensee:
Philadelphia Electric Company
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2301 Market Street Philadelphia, Pennsylvania 19101 Facil k.t Name:
Peach Bottom Atomic Power Station, Units 2 and 3 Inspection at:
Delta and Philadelphia, Pennsylvania Inspection conducted:
October 1 - November 7,1980 Inspectors:
C. O. A0+A,h.. h tIr/pl C. J. Cowgill, Resident Reactor Inspector date signed e.e. < t.c o. a
,irie,
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A. R. Blough, Resident Reactor Inspector date signed date signed Approved by:
8. O. bCA*, h
- IrIei E. C. McCabe, Jr., Chief, Reactor Projects date signed Section No. 2, RO&NS Branch
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Inspection Summary:
Inspection on October 1 - November 7,1980 (Combined Inspection Report Nos.
50-277/80-32 and 50-278/80-24)
Areas Inspected: Routine, onsite regular and backshift inspection, including the corporate office, by the resident inspectors (132 hour0.00153 days <br />0.0367 hours <br />2.18254e-4 weeks <br />5.0226e-5 months <br />s-Unit 2; 132 hour0.00153 days <br />0.0367 hours <br />2.18254e-4 weeks <br />5.0226e-5 months <br />s-Unit 3). Areas inspected included accessible portions of the Unit 2 and Unit 3 facilities, radiation protection, physical security, operational safety, control room activities, maintenance, reactor chemistry, LER's, periodic reports, organi-zation and administration, TMI-2 Lessons Learned implementation, and open items.
Results :
Noncompliances - None in 11 areas, one in one area
. 't (out of date p:ocedures at the Emergency Shutdown Panels (Recurrent) Detail 3).
Region I Form 12 (Rev. April 77)
8108180\\N
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DETAILS 1.
Persons Contacted W. H. Alden, Engineer-in-Charge, Generation Division Nuclear Seccion J. H. Austin, Executive Vice President and Chief Operating Officer W. W. Bowers, Electrical Engineer, Engineering and Research W. C. Birely, Generation Division Nuclear Section M. J. Cooney, Superintendent, Generation Division (Nuclear)
J. M. Corcoran, Branch Head, Engineering and Research Quality Assurance S. L. Daltroff, Vice President, Electrical Production
- J. K. Davenport, Maintenance Engineer G. F. Dawson, I&C Engineer
- R. S. Fleischmann, Assistant Station Superintendent A. Fulvio, Results Engineer S. Gibbon, Mechanical Engineer, Engineering and Research N. Gazda, Health Physics, Radiation Protection Manager D. R. Helwig, Mechanical Engineer, Engineering and Rasearch G. R. Hutt, Branch Head, Engineering and Research Quality Assurance S. J. Kowalski, Mechanical Engineer, Engineering and Research A. J. Marie, Mechanical Engineer, Engineering and Research
i R. H. Moore, Superintendent, Electrical Production Quality Assurance R. W. Polaski, Reactor Engineer E. J. Purdy, Mechanical Engineer, Engineering and Research S. R. Roberts, Operations Engineer l
R. J. Scholz, Chemistry Supervisor l
- S. A. Spitko, Site Q.A. Engineer i
S. Q. Tharpe, Security Supervisor
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- W. T. Ullrich, Station Superintendent H. R. Walters, Manager, Engineering and Research Quality Assurance l
J. E. Winzenried, Technical Engineer Other licensee emoloyees were also contacted during the inspection.
- Present at exit interview on site and for summation of preliminary in-l spection findings.
2.
Previous Inspection Item Update (Closed) Infraction (277/79-27-01 and 278/79-30-01), procedures for use at
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the radwaste facility were not current.
The inspector reviewed Table A2-1
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of administrative procedure A-2, " Procedure for Control of Procedures,"
revision 16 dated April 2,1980, to verify that procedures are now distri-buted to the radwaste control room area.
The procedures at the radwaste
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l facility were checked and found to be stamped as controlled copies.
A sampling of these procedures was also checked against the licensee's master file
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to verify that current revisions were in place.
No unacceptable conditions l
were identified, however a recurrent item of the same nature was identified l
at a different plar.t location (See Detail 3).
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(Closed) l'nresolved Item (277/80-05-04 and 278/80-Li-04), a revision of licensee procedures for line breaks outside the drywall was required to include the use of area indications (high temperature and high radiation)
in determining successful leak isolation. The inspector reviewed the following procedures and determined that they had been revised to require
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use of the high temperature and radiation indications: E-2, " Main Steam l
Line Brcak-Outside the Drywell," revision 5 dated August 3,1980; E-3, l
"Small Line Break-Outside the Drywell," revision 3 dated August 2,1980.
l No unacceptable conditions were identified.
l (Closed) Unresolved Item (277/80-28-03 and 278/80-20-03), review of licen-see's disposition of a damaged radwaste barrel.
The licensee had planned to slice several barrels to examine cross-sectional areas for pockets of
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free-standing oil.
The licensae selected the damaged barrel as part of the sample for this test.
Barrel contents were repackaged after examir.ation.
The inspector reviewed photographs taken during the test and had no further questions regarding this matter.
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(Closed) Unresolved Item (277/78-09-02, 278/78-12-01).
A review was con-ducted by the corporate engineering staff of domestic and domineralized water systems as referenced in IE Circular 77-14 (Review of Contaminated /
Non-Contaminated System Interconnections).
The review showed that at least double check valves protect potable from non potable systems. Systems
reviewed included auxiliary steam, potable water, service water and the desineralized water storage tank supply to all domineralized water users.
Additionally, IE Bulletin 80-10, " Contamination of Nonradioactive System
i and Resulting Potential for Unmonitored, Uncontrolled Release to Environment,"
requires all licensees to sample systems considered nonradioactive but that could become radioactive through system interfaces.
3.
Plant Operations Review a.
Loos and Records (1) Documents Reviewed il -
l A sampling review of logs and records was made to:
identify significant changes and trends; assure that required entries were being made; verify that operating orders and night orders conform to Technical Specification requirements; check correctness of communications concerning equipment and lockout status; verify jumper log conformance to procedural requirements; and verify conformance to limiting conditions for cperations.
Logs and
records reviewed were:
(a) Shift Supervision Log, October 1-November 7,1980
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(b) Unit 2 Jumper Log - Current Entries
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(c) Unit 3 Jumper Log - Current Entries (d) Reactor Engineering Log - Unit 2 - Current Entries (e) Reactor Engineering Log - Unit 3 - Current Entries (f) Reactor Operators Log Unit 2 - October 1-November 7, 1980 (g) Reactor Operators Log Unit 3 - October 1 - November 7, 1980 (h) Co Log Book - October 1-November 7,1980 (i) Radiation Work Permits (RWP's) - Various in both Units 2 and 3 October, 1980 (j) Maintenance Request Forms (MRF's) - Units 2 and 3 (Sampling) October,1980 (k) Ignition Source Control Checklists (Sampling)
October, 1980 (1) Operation Work & Information Data - October and November (through November 7), 1980 Control room logs were reviewed pursuant to requirements of Administrative Proceoure A-7, " Shift Operations." Frequent initialing of entries by licensed operators, shift supervision, l
and licensee on site management constituted evidence of licensee l
review.
Official Log sign-off was verified to be correct.
Logs
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were also reviewed to assure that plant conditions including l
abnormalities and significant operations were accurately and completely racorded.
Logs were further assessed to determine
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that matters requiring reports to the NkC were being processed as suspected reportable occurrences.
No unacceptable conditions were identified.
(2) Facility Tours i
l (a) During the course of this inspection, which also l
included shift turnover, the inspector conducted daily tours and made observations of:
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Control Room
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Turbine Building - (all levels)
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Reactor Building - (Accessible areas)
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Yard area and perimeter exterior to the power
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block, including Emergency Cooling Tower and torus dewatering tank construction Security Building, including CAS, Aux SAS, and
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control point monitoring
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Lig;;cing
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Vehicular Control
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The SAS and power block control points
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Security Fencing
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Portal Monitoring
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Personnel and Badging
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Control of Radiation and High Radiation areas
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including locked door checks TV monitoring capabilities
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Off-Shift Inspections - The specific areas and
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dates examined were as follows:
Date Areas Examined October 6, 1980 Control Room observations October 7, 1980 Tour Turbine Building October 8, 1980 Control Room observations October 9,1980 Control Room observations, shift meeting October 20, 1980 Observation of a plant shutdown, drywell tour, control room tours, operational event follow-up October 21, 1980 Tour of Unit 3 Reactor Building, inspection of RWP adherence October 23, 1980 Control room observations, shift meeting October 24, 1980 Control room observations, discussions with management personnel October 28, 1980 Control room observations and inspection of Unit 2 Reactor Buf1 ding October 29, 1980 Control room observations October 30, 1980 Control room observations November 5, 1980 Control room observations, protected area lighting November 6, 1980 Control room observations and inspection of Cable Spreading Room and Unit 3 Reactor Building
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Control Room Manning.
On frequent occasions
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during this inspection, the inspectar confirmed that requirements of 10 CFR 50.54(k) and the Technical Specifications for minimum staffing requirements were satisfied.
No unacceptable conditions were identified.
Fluid Leaks.
No significant fluid leaks were
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identified which had not also been identiff r:d by the licensee nor for which necessary corrective action had not been initiated.
The inspector observed sump status, alarms, purp 'ut rates, and held discussions with licensee persoi..sel. Technical Specifications allow continued operation when total reactor coolant system leakage into primary containment is less than 25 gpm, with less than 5 gpm from unidentified sources.
Pump-out rates for the Drywell Equipment Drain Sump and the Drywell Floor Drain Sump are used to calculate identified and unidentified leakage respectively.
On October 14, 1980 the inspector observed that both Unit 3 Drywell Floor Drain Sump Pumps were out of service.
Under this condition the Floor Drain Sump overflows to the Equipment Drain Sump.
The inspector verified that the licensee was recording Equipment Drain Sump pump-out as unidentified leakage and was adhering to the 5 gpm limit.
Actual pump-out rate was about 2.5 gpm which satisfied Technical Speci-
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fication requirements.
Unit 3 was shut down on October 19, 1980 for maintenance.
During this outage the Drywell Floor Drain Sump Pumps were repaired and returned to service. After startup on October 29, 1980, the Floor Drain Suma pump outrate l
was less than 0.5 gpm and total pump-out rate was l
less than 2 gpm.
No unacceptable conditions were identified.
Off-Normal Alarms.
Selected annunciators were
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l discussed with control rrom operators and super-i visors to assure they were knowledgeable of plant
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conditions and that corrective action, if required, i
was being taken.
Examples of specific alarms discussed during the report period were: APRM
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High; Rod withdrawl Block; Liquid Nitrogen Storage Tank Level Low; Computer Room and Cable Spreading
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Room CO, System Deactivated; Standby Gas Filter Heater Failure.
The operators were knowledgeable of alarm status and plant conditions.
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i On October 7, 1980 a relief valve high temperature alarm was annunciated on Unit 3.
The inspector asked about the alarm.
A licensee representative i
stated that the alarm was caused by loose wires in the temperature recorder in the control room.
The inspector confirmed that a relief valve had not lifted by observing that the acoustic monitoring device alarm was not actuated, the local acoustic monitor panel indicated safety / relief valves were
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closed and no memory light was actuated, Suppression Pool Temperature had not increased, and that the licensee had found temperatures normal when checking relief valve exhaust line temperatures with a resistance bridge.
The temperature re-corder was repaired in a timely manner and the alarm condition cleared.
No unacceptable conditions were identified. Additionally, the inspector reviewed the licensee's ongoing progress in eliminating lit annunciators and maintaining valid alarm status.
The current Control Room Annunciator and Instrument Status indicated the following:
ANNUNCIATOR AND INSTRUMENT /
PROBLEM DESCRIPTION RESOLUTION PANEL TR-2402, Turb lube oil temp No point indicator Lab to investigate (20C088)
TR-2401, Turb bearing metal temp No point indicator Lab to investigate (20C088)
TR-2-2-184-25, Recirc MG set No point indicator Lab to investigate bearing temp (20C21)
Main steam line leakage Alarm for no apparent Calibrate (20C205L)
reason B Recirc pump motor ol'
Both alarms up at the Further investiga-hi level /B recirc pump same time tion required motor lo oil (20C204M)
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IRM-No response to neutrons Further investiga-(20C36)
tion required Cleanup non regen heat Calibrate TS 2-
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Exch. outlet hi temp 12-115 (20C204R)
G drywell cooler air hi Will not clear at 67 F Further investiga-temp tion required-(20C212R)
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ANNUNCIATOR AND INSTRUMENT /
PROBLEM DESCRIPTION RESOLUTION PANEL B drywell fan failure Fan i running but alarm Outage required (20C212R)
is up Off gas log rad monitor A Erratic Further investi-(20C10-3)
gation required Radwaste sample rack No response to radiation Further investi-Area (ARM 4-8)
gation required Conveyor Oper. Access Spikes high Further investi-Area (ARM 4-9)
gation required Plant Temperature Point 155, Bad Further investi-Readout (~(I-2100)
gation required FR-49478, 4957, Containment Does not indicate Further investi-N2 Supply gation required (2CC484-B)
Reactor Pressure Vessel Reads low Calibrate Water level (LI-85 A&B)
(20C05A)
OPI 20001, A emerg. gas RecJs "0.4" with train off Further investi-filter gation required (20C12)
OPI, 20002, B emerg, gas Reads "0.2" with train off Further investi-filter gation required (20C12)
2 Refueling floor inshore Full box glass rod Further investi-stairway (fire)
holder broken gation required (00C201L)
Off gas recombiner diff.
Will not reset Further investi-temp. hi-lo gation required l
(00C196)
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SJAE B discharge Alarm will not clear Calibrate
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pressure hi-lo (00C196)
f MG supply fan 2A-BV44 low TS-20425 will not reset Repair or replace l
air temp TS-20425 i
(00C133)
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ANNUNCIATOR AND INSTRUMENT /
PROBLEM DESCRIPTION RESOLUTION PANEL Torus Compartment ARM 5-4 Low response to radiation Further investi-(30C11)
gation required RHR pump room D ARM 5-8 No response to radiation Further investi-(30C11)
gation required
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3A heater hi level False low level alarm Material on (30C206L)
order A recirc pump-motor Alarm up level normal Further investi-oil hi level gation required (30C204M)
A, B, & C condensate pump Alarm won't clear Further investi-high vibration vib. mod not done gation required (30C207L)
Plant temperature readout Bad readouts Further investi-pts. 1, 4, 9, 165, 171 gation required (TI-3100)
(30C06A)
LR-5805 Reads high Calibrate Suppression pool level recorder (30C03-3)
F1-30260, 8 recirc pump Reads hard down Further investi-chilled water scale gation required (30C12)
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SJAE B discharge Alarm will not clear Calibrate pressure hi-10
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(Unit 3 00C196)
l MG supply fan 2A-BV 44 low TS-30425 will not reset Repair or replace air temp TS-30425 (00C133)
Piping Vibration.
No significant piping vibration
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l or unusual conditions were identified.
Monitoring Instrumentation.
The inspector fre-
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quently confirmed that selected instruments were operating and indicated values were within Technical Specification requirements.
On a l
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daily basis when the inspector was on site, ECCS switch positioning and valve lineups, based on control room indicators and plant observations
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were verified.
Examples of instrumentation observed included flow setpoints, breaker position-ing and FCIS status.* No unacceptable conditions were identified.
- radiation monitoring instruments and full-core display indications.
Unit 3 Drywell Inspection.
On October 20, 1980
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the inspector toured the Unit 3 Drywell with licensee maintenance personnel who were inspect-ing the Drywell for leaks following a reactor shutdown. The inspector verified that appro-priate Health Physics precautions were observed.
Licensee personnel identified one leak during,this inspection -- a weeping, cracked weld in a 90 elbow in the line from a between-disc drain on one of the two recirculation loop cross-tie valves. The licensee repaired the crack and in-spected the joint at 1000 psi pressure.
No abnormal conditions were identified.
A metal-lurgical analysis is being performed to determine the cause of the crack.
The inspector will review the results of the analysis.
(277/80-32-01, 278/80-24-01).
l Control of procedures.
During a facility tour
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l on October 21, 1980 the inspector inspected the i
Emergency Shutdown Panels on the 165' elevation
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of the Radwaste Building.
A folder containing procedure SE-1, " Plant Shutdown from Outside the Control Room," was posted inside the locked cage enclosure of each panel.
The procedure at the Unit 3 panel was dated May 9, 1973. After deter-mining that the effective revision of procedure
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l SE-1 was revision 6 dated August 13, 1980, the inspector informed shift supervision of this problem. The licensee confirmed that the pro-
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cedures at both Emergency Shutdown Panels were out
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of date, promptly posted the proper revisions and initiated steps to assure distribution of con-trolled copies of the procedure to those locations.
This failure to distribute procedure changes to locations where the activity is performed is contrary to criterion VI of 10 CFR 50, Appendix B l
and the licensee's accepted Quality Assurance Plan.
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This is an item of noncompliance (50-272/80-32-02 and 50-278/80-24-02).
The inspector reviewed the licensee's corrective action for this specific instance on October 23, 1980 and had no further questions. This item is recurrent in that combined report 50-277/79-27 and 50-278-79-30 and combined report 50-277/80-11 and 50-278/80-11 identified
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similar failures to control procedures at the
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radwaste panel and respirator maintenance station, respectively.
Based on this finding the inspector expressed concern that out-of-cate procedures may also be placed for use elsewhere in the facility.
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b.'
Reactor Water Chemistry The following surveillance tests for the periods indicated were r
reviewed by the inspector to assure that Technical Specification Limits were satisfied.
(1) Conductivity and Chloride Ion Content in Primary Coolant During Normal Operation and Time Conductivity and Chloride Are Above Specified Limits
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Surveillance Tests 7.2.3.A and 7.2.3.C and Peach Bottom Daily BWR Chemistry Analysis - September 29 - October 12, 1980.
Technical Specification 3.6.B requires prior to startup and wbgnoperatingatratedpressure,reactorwaterconductivityat 25 C of less than or equal to 5.0 unho/cm and chloride concentration less than or equal to 0.2 ppe.
Reactor water quality may exceed these limits for up to two weeks per year.
Maximum limits are established as 10 umho/cm conductivity and 1.0 ppa chlorides.
Inspections at Unit 2 for the report period indicated that during operation the maximum conductivity was 0.48 unho/cm and chloride concentration was less than 0.02 ppe. Through October 12, the 1980 total time above the 0.2 ppe chlorides limits and the 5.0 umho/cm conductivity
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limits are 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> respectively.
Inspections at Unit 3 for the period indicated that during operation the maximum conductivity was 1.55 unho/ca.
Chloride concentration was greater than 0.2 ppa for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> on September 29, with a maximum value of 0.28 ppe.
Through October 12 the 1980 total time above the specific "two weeks per year" limits for con-ductivity and chlorides were.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> and 45 hours5.208333e-4 days <br />0.0125 hours <br />7.440476e-5 weeks <br />1.71225e-5 months <br /> respectively.
No unacceptable conditions were identified.
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(2) Determination of Dose Equivalent Microcuries/ Gram I-131 in the Primary Coolant Surveillance Test 7.2.1.A was reviewed.
The licensee analyzes
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the following nuclides:
I-131, I-132, I-133, I-134, and I-135 and computes dose equivalent I-131 -- that amount of I-131 which alone would produce the same dose as the quantity and isotopic mixture actually present.
The Technical Specification Limit is 2.0 microcuries per gram.
Increased sampling frequency is required if any analysis exceeds 0.02 microcuries per gram. The representative sample for Unit 2, analyzed on October 7,1980, indicated a dose equivalent I-131 concentra-tion of'l.26 E-3 microcuries per gram.
The inspector also confirmed that the required surveillance frequency was being satisfied. No unacceptable conditions were identified.
c.
Inspector Follow-up on Events Occurring During this Inspection (1) Unplanned Noble Gas Release l
On October 20, 1980, between 1:00 PM and 1:45 PM, a 1.89 curie noble gas release occurred from the Unit 3 ventilation stack.
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The release began shortly after the mechanical vacuum pump, which exhausts to the main stack, was started to maintain con-denser vacuum with the unit shutdown.
The vacuum pump was i
stoppad in about 5 minutes.
No airborne radioactivity above background levels was found in the vicinity of the vacuum pump, The inspector determined that the licensee had pronptly notified the NRC via the ENS phone as required by 10 CFR so.72 l
and approved licensee procedures.
The inspector reviewed recorder traces and the licensee's calculations to confirm the i
licensee's determination that the peak release rate was about 14% of the Technical Specification allowable instantaneous release rate.
The inspector reviewed the licensee's evaluation of the cause of the event and corrective actions to prevent-recurrence. The licensee determined that the exhaust path of the vacuum pump had been blocked resulting in leakage of the noble gas through pump seals.
A normally-open valve that pro-vides for draining of moisture from the pump discharge piping was found in the shut position.
The licensee's investigation did not indicate when or why the valve had been shut, but the following inadequacies were identified.
(a) The valve, as well as three other valves important to
. draining the discharge line, had not been incorporated on a check-off list;
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(b) There were no tags on the valves identified above; and (c) The piping diagram was confusing with respect to differ-ences between Unit 2 and Unit 3.
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The inspector verified that the licensee had initiated appro-priate corrective actions, including drawing change requests, placerant of valve tags (completed prior to startup), and revis on to the system check-off lists (completed October 23, 1980).
No unacceptable conditions were identified.
(2) Unscheduled Unit 3 Shutdown The Unit 3 Reactor scrammed at about 12:08 PM on October 30, 1980, from a level of 45%.
The scram occurred when the power unbalance relay (senses mismatch between generator output
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current and steam flow) actuated causing turbine control valve fast closure.
The inspector went to the control room and verified that no Emergency Core Cooling System actuations or abnormal releases occurred, the licensee reported the scram to the NRC Headquarters Duty Officer via the Emergency Notification System (ENS) within one hour as required, and plant recovery was completed in accordance with approved station procedures.
No unacceptable conditions were identified.
4.
Review of Licensee Event Reports (LER's)
The inspector reviewed LERs submitted to the NRC:RI office to verify that the details of the events were clearly reported, including the accuracy of the description of cause and adequacy of corrective action.
The inspector determined whether further information was required from the licensee, examined generic implications and potential, and if the event warranted onsite follow-up. The following LER's wera reviewed:
LER No.
LER Date Event Date Subject 3-80-23-03L 9/30/80 9/08/80 RWCU demineralizer inlet temperature switch failed to function properly during testing 3-80-22-03L 9/19/80 8/29/80 Time delay setpoint drift caused 3B core spray pump to start 0.3 seconds too soon during testing 3-80-21-03L 9/09/80 8/18/80 During PCIS testing, venti-1ation valve A0-3506 failed to close 2-80-16-03L 9/29/80 9/09/80 During testing, one low reactor pressure relay, for
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recirculation pump discharge valve closure, failed to function No unacceptable conditions were identified.
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5.
Radiation Protection During this report period, the inspector examined work in progress in
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i accessible areas of the Unit 2 and Unit 3 facilities.
Areas examined
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included:
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Health Physics (HP) controls b.
Badging c.
Usage of protective clothing d.
Personnel adherence to RWP requirements
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Surveys
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Handling of potentially contaminated equipment and materials Additionally, inspections were conducted of usage of friskers and portal monitors by personnel exiting various RWP areas, the power block, and l
the licensee's final exit point.
More than 70 people were observed to meet frisking requirements of Health Physics procedures during the month.
A sampling of high radiation doors was verified to be locked as required.
The inspector attended General Respiratory Training (GRT) to satisfy licensee requirements and to determine that acceptable respiratory training was being provided. The inspector verified that lesson content satisfied procedure HP0/CO-9a, " Respiratory Protection Training and Fitting," and was clearly presented.
The licensee's GRT written exami-nation and fitting booth testing were completed.
The inspector noted that respiratory equipment qualifications are valid for twelve months with an additional two month grace period for requalification.
The inspector asked how qualifications are removed and personnel informed.
When an individual's respiratory qualification is 12 months old, his supervisor is informed via a " deficiency list."
Personnel who do not requality within the total 14 month period are removed from the " Current Respiratory Qualification List." Respirator use by personnel not current-ly qualified is detected by Health Physics personnel during assignment of MPC-hours on Radiation Work Permits, in which case no credit is taken for use of respiratory protection equipment in assigning exposures and the matter is discussed with the individual and his supervisor.
A licen-see representative stated that recent expirations of qualifications are now being reviewed as an additional measure although not required by the licensee's program.
This review is designed to preclude problems.
No unacceptable conditions were identified.
6.
Physical Security The inspector spot-checked compliance with the Accepted Security Plan and implementing procedures, including operations of the CAS and SAS.
Over 20 spot-checks of vehicles onsite were conducted to verify proper control.
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The inspector observed protected area access control and badging procedures on each shift, conducted inspection of physical barriers and checked control of vital area access and escort procedures.
A qualitative assessment of the adequacy of protected area lighting was made during darkness hours on November 5, 1980.
No unacceptable conditions were identified.
7.
In-Office Review of Monthly Operating Reports The following licensee reports have been reviewed in-office onsite.
Peach Bottom Atomic Power Station Monthly Operating Report for:
September,1980 dated October 10, 1980.
This report was reviewed pursuant to Technical Specifications and veri-fled to determine that operating statistics had been accurately reported and that narrative summaries of the month's operating experience were contained therein.
No unacceptable conditions were identified.
8.
Review of Short-Term Lessons Learned Requirements The inspectors reviewed the licensee's implementation of TMI-2 short-tern lessons learned requirements.
All Category A items from NUREG-0578 were examined..These items,. issued as recommendations in NUREG-0578 with an implementation date of January ~1,1980, became requirements by
an NRC letter dated-September 13, 1979, and were clarified by an
NRC letter dated October. 30,1979. The licensee provided c6mmitments l
for implementation and furnished additional information in letters to l
the NRC dated October 17, 1979, November 21, 1979, December 21, 1979 and l
January 2, 1980.
The inspectors conducted detailed reviews to verify
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that the licensee had satisfied each commitment.
In evaluating accept-ability of certain actions the inspectors considered NRR's " Evaluation of Licensee's Compliance with Category 'A'
Items of NRC Recommendations Resulting from TMI-2 Lessons Learned," Philadelphia Electric Company, Peach Bottom Atomic Power Station, dated February 26, 1980.
a.
Shift Technical Advisor The inspector verified'that a Shift Technical Advisor (STA) had been assigned to augment each operating shift effective January 1,1980.
The inspector has verified the STA's presence on shift during fre-quant checks of shift manning throughout '1980.
Procedure A-7,
" Shift Operations," was reviewed and found to clearly specify the l-STA's responsibility during routine operations, outages, transients, l
and emergencies.
The inspector reviewed the operating experience assessment function of the STA.
The inspector verified that this function is augmented by technical personnel from the corporate office and that Operating Experience Assessment Committee meetings were held as required by procedure A-7.
.The inspector reviewed committee i.
reports as contained in PORC minutes80-105 and 80-127. The inspector discussed with the committee chairman.the meeting agenda items and I
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and committee activities.
Procedure A-7 refers to a weekly meeting of the previous week's STA's.
The Operations Engineer, who is the Operating Experience Assessment Committee Vice Chairman, indicated that frequently it is not practical to have all those individuals together for a meeting, and that alternately, committee inputs are gathered from them individually or in groups of two. The licensee stated that a clarification of procedure A-7 in this area would be considered. The matter is unresolved pending results of the licensee's procedural review (277/80-32-03 and 278/80-24-03).
The l
inspector noted that the licensee plans to send two representatives to an industry meeting regarding operating experience assessment in November 1980.
b.
Shift and Relief Turnover Procedures The inspector reviewed procedure A-7 and verified that shift turn-over checklists were required for each control room and shift supervision position.
The inspector has verified completion of
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required checklists frequently during control room tours during 1980. The inspector reviewed the content of the checklists for
adequacy.
The inspector noted that the licensee uses an alternative
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-to the checklists for auxiliary operators and technicians.
This
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exception has been documented to NRR.
Auxiliary operators and technicians attend shift meetings and use a status board.
The NRR
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position is that this method satisfies the basic intent of NUREG
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0578.
The inspector observed several shift meetings, observed the
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plant operators' status board and conducted discussions with licensee personnel to verify that the alternate method is function-
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t ing acceptably.
The inspector discussed shift turnover with the Operations Engineer to verify that he routinely evaluates shift and relief turnover as required by the licensee's commitment.
No unacceptable conditions were identified.
c.
Shift Supervisor's Responsibilities NUREG - 0578 listed several actions to review and revise, as necessary, Shift Superintendent responsibilities such that he can provide direct command oversight of operations and perform management review of on-going operations important to safety without being distracted by admin-istrative details.
The-inspector reviewed a letter from the Vice-
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l President,-Electrical Production, dated December 26, 1979 which L
. emphasized the primary management responsibility of the Shift Super-intendent..The inspector verified that the letter, along with endorse-ments from the Superintendent, Generation Division (Nuclear) and
. Station Superintendent had been'provided to shif6 supervision person-nel. -The. inspector reviewed procedure A-7, " Shift Operations," and verified that it had been revised in accordance with NUREG-0578 l
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and the Vice President's directive.
The inspector noted that tha Vice President, Electric Production, had also directed a review of administrative duties of shift supervision and delegation to other operations personnel of administrative functions that distract from the management responsibility for assuring safe operation.
Through discussions eith station management and review of licensee correspon-dence, the inspector determined that a review had been conducted and administrative functions eligible for delegation had been defined.
The review resulted in the assignment of an individual to assist supervision in administrative duties during the dayshift on week-days.
Members of shift supervision interviewed stated that this administrative help could be obtained on backshifts and weekends, as needed, on a case-by-case basis.
No unacceptable conditions were identified.
d.
Shift Manning - Overtime Limits Interim criteria for shift staffing were promulgatad by NRR letter on July 31, 1980.
These included new requirements c:garding shift staffing, operator and senior operator availabilit, in the control room, and overtime limitations.
The inspector reviewed administra-tive procedure A-7, " Shift Operations," revision 14 dated October 15, 1980. The inspector verified that this procedure incorporates, effective November 1,1980, the requirements of the NRR letter.
Peach Bottom shift staffing requirements include:
(1) One senior licensed ooerator (shift supervision) on site at all times.
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(2) One senior licensed operator (shift supervision or staff SLO)
stationed in the control room complex at all times.
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(3) One licensed a-ator (Assistant Control Operator) for each reactor in tt'
1 trol room at all times -- total of two licensed operi l
(4) One licensed opei (Chief Operator) in the control room at l
all times (availat.a to serve as a rel.ief operator for one of the A.C.O.'s) in addition to the two licensed operators described above in 3.
Routine use of overtime to compensate for inadequate number of per-sonnel to meet staffing requirements is prohibited.
Overtime that must be used due to unavoidable circumstances is subject to the following restrictions:
(1) An individual shall not be permitted to work more than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> straight (not including shift turnover time).
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(2) An individual shall not be permitted to work more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period.
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(3) An individual shall not work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7 day period.
(4) An individual shall not work more than 14 consecutive days without having two consecutive days off.
Any deviations are to be approved by the Station Superintendent.
No unacceptable conditions were identified within the scope of this review. The licensee's response dated October 2, 1980 was reviewed.
l Discussions with the NRR Licensing Project Manager indicated that
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this response, including the definition of " control room complex,"
will be subject to NRR review.
e.
Control Room Access Administrative procedures were to be reviewed and revised to ensure a clear line of authority and responsibility existed in the control room during an accident.
The authority to limit control room access was to be established.
The inspector reviewed procedure A-7, " Shift Operations." This procedure establishes the Shift Superintendent as in-charge in the control room during accidents.
He is to direct
all activities to stabilize the plant and mitigate consequences of l
the occurrence unless specifically relieved by a senior plant staff
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member who holds a senior license (Senior Engineer or above).
The Shift Supervisor assumes Shift Superintendent duties if the Shift Superintendent is absent from the control room. The procedure also establishes Shift Superintendent authority and responsibility to limit control room access.
The inspector reviewed the following procedures to verify clear definition of lines of communications and authority for plant staff not in direct command of operations:
EP-46, " Class II Emergency," revision 3 dated June 26, 1980; EP-47, " Class III Emergency," revision 9 dated June 24, 1980; l
EP-48, " Class IV Emergency," revision 21, dated June 30, 1980; EP-36, " Technical Support Center Functions," revision 0 dated June 27, l WO; and EP-37, " Operational Support Center Functions," revision 0 dated June 27, 1980.
The inspector noted that the interim Technical Support Center and Operational Support Center, which were in place on January 1,1980, were not addressed in approved procedures until June, 1980.
No technical inadequacies were found in the current procedures.
No items of noncompliance were identified.
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f.
Short-Tern Accident and Procedures Review The licensee was committed to completion of the Small Break Loss of Coolant Accident (SBLOCA) analysis and Phase 1 of the Inadequate Core Cooling analysis by January 1, 1980. The required steps for each analysis included:
(1) Analyze to predict plant response during abnormal occur-rences and to identify proper and improper operator actions associated with important safety considerations; (2) Prepare guidelines for emergency procedures; (3) Impler.ent improvements in emergency procedures; and, (4) Retrain operators.
Items (1) and (2) above were undertaken by a BWR owners group.
58LOCA procedures and all operator training required by January 1, 1980 were c/amined in Combined Inspection 50-277/80-05 and 50-278/80-05.
Two unresolved items with respect to SBLOCA procedures were identified in that inspection -- one is now resolved (reference Detail 2) and one is still under review.
The inspector reviewed Emergency Procedure E-26, " Inadequate Core Cooling," Revision 2 dated August 3, 1980.
.This procedure was issued by the licensee in December, 1979 to provide guidance to the operator in coping with l
symptoms of inadequate core cooling.
No unacceptable conditions were identified.
g.
Containment Isolation Dependability The NRC position was:
(1) All containment isolation systems shall use diverse initiation parameters; (2) Each licensee should reevaluate his designation of essential and nonessential systems, describe the basis for this selection, make appropriate modifications (including provisions for auto-matic isolation of all nonessential systems), and report results to the NRC; and,
-(3) Control Systems for automatic containment isolation valves must prevent the automatic reopening of any containment isolation valve upon reset of the isolation signal.
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The inspector reviewed the licensee's responses dated November 21, l
1979 and January 2, 1980 to' verify that the study specified in (2)
above was performed and reported to the NRC. The January 2, 1980 report detailed the licensee's justification for certain exceptions to the diverse initiation signal criteria and to automatic isolation
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of non-essential lines.
Examples of the exceptions are:
use of process signals rather than containment isolation signals for reactor water cleanup system isolation; use of turbine trip signals to isolate HPCI and RCIC turbine exhaust steam line drains; indirect automatic isolation of TIP drive line isolation valves; and absence of automatic isolation for integrated leak rate test (LRT) connections that are provided with two locked-closed manual isolation valves.
The inspector verified through review of the NRR letter to the licen-see dated February 26, 1980 that NRR considers the technical justifi-cation for each exception to be adequate. The licensee's review indicated that modifications were required to provide for automatic isolations of Radioactive Gas Sample Lines and to meet the reset logic criteria.
The inspector reviewed Modification 577A, " Revision to Reset Logic in the Primary Containment Isolation System," including the safety evaluations, PORC review, Maintenance Request Forms (MRF's), pre-operational tests, and Modification Status Reports.
Satisfactory pre-operational testing was indicated for Unit 3 on December 10, 1979 and at Unit 2 on January 7, 1980.
No inadequacies in this documentation were found.
NRR's report dated February 26, 1980 indicated the need for assurance that essential systems which are initially isolated can be made available considering a single failure of the containment isolation reset logic. The inspector reviewed the licensee's single failure analysis and PORC review (PORC minutes 80-42).
No inadequa-cies were identified.
The inspector reviewed modification 577D, " Containment Isolation --
Radioactive Gas Sampler," which adds an automatic containment isola-tion feature to containment sample lines. The inspector noted that the modification is complete for Unit 2 and reviewed the safety evaluation, PORC review, MRF, and Modification Status Report.
At Unit 3, the inspector verified that the power supply fuses for the valves are removed to assure that the valves remain closed prior to imple-mentation of this modification, in accordance with the licensee's commitment.
The inspector noted that modification 577F, "TIP System Isolation l
Valve Control Circuits," has been initiated, but no actual modifica-tion is yet done.
The inspector reviewed the following documents:
(1) A Safety Evaluation for MOD 577F dated June 17, 1980, which states in part:
" Item 2.1.4 of NUREG-0578, 'THI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations,'
required the design of control systems for automatic containment isolation valves be such that resetting the isolation signal will not result in automatic reopening of containment isolation valves.
Reopening of containment isolation valves must require
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deliberate operator action.
Modification 577A revised the logic for what was believed to be all valves that could automatically reopen upon resetting the isolation signal.
However, review of l
the traversing in-core probe (TIP) system revealed that TIP
purge isolation valve 7-113 and the five TIP ball valves have
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two position, maintained-contact control switches.
If the con-trol switches for these valves are left in the "open position following a containment isolation, resetting the logic will result in automatic reopening of the valves."
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(2) The licensee's January 2,1980 submittal which states in part:
" Reset of Isolation Signals - We have completed a design review of the control systems for all automatic isolation valves to assure that resetting their isolation logic will not result in automatic reopening of the valves.
The required logic changes were completed on Unit 3 during an outage which began on December 6, 1979.
Similar modifications will be made on Unit 2 during an outage scheduled to begin on, or before, January 1, 1980."
(3) IE Bulletin 80-06, " Engineered Safety Feature (ESF) Reset Con-trols," dated March 13, 1980, which states in part:
"There have been several communications to licensees from the NRC on ESF reset action.
For example,... NUREG - 0578... However, each of these... addressed only a limited area of ESF's. We are requesting that the reviews undertaken for this Bulletin address all of the ESF's."
The inspector noted that the licensee's response to IE Bulletin 80-06 listed TIP valves as
" equipment that will not remain in the emergency mode after reset of the initiation signal," but did not identify the problem as a NUREG-0578 discrepancy and did not document the technical justification for continued operation in light of the newly-l discovered exception to January 1,1980 requirements.
The j
inspector verified that the PORC had reviewed the proposed l
modification and that administrative controls had been established i
to preclude opening of TIP valves during reset of an isolation
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signal.
The inspector asked on October 31, 1980 that the licensee formally inform NRC by letter of the new information regarding the January 2,1980 submittal and provide justification for the exception to Category 'A' requirements.
The inspector reviewed.this letter _to_NRR, dated October 31, 1980, and had no further questions.
No unacceptable conditions were identified.
h.
Onsite Technical Support Center NRC required the licensee to establish an interim Technical Support Center separate from and in close proximity to the Control Room.
The inspector toured the interim Technical Support Center, located on the second floor of the Unit 1 office complex.
During this tour the inspector verified that it was equipped with:
plant drawings; emer-
.gency procedures; two iodine radiation monitors;-direct communica-
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tions with the control room, NRC Operations center in Bethesda,
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Maryland, and the Operational Support Center; and the capability to directly monitor selected instrumentation in the Control Room via a closed circuit television network.
The inspector noted tiet the equipment provided in January, 1980 to read direct radiation was not in the center.
A licensee representative said the equipment had been recently stolen. The equipment was immediately provided and placed in a locked cabinet to prevent recurrence of the theft.
The inspector reviewed procedure EP-36, " Technical Support Center Functions,"
Revision 0, dated June 27, 1980.
The procedure contained provisions for activation, personnel assignments, areas of responsibilities, and an upper limit an the number of persons allowed in the center.
The procedure does not contain specific instructions regarding evacuation to the control room in the event the Technical Support Center becomes uninhabitable.
This area will be reviewed after clarification by the licensee.
(277/80-32-04,278/80-24-04)
i.
Onsite Operational Support Center An area designated the onsite Oper:tional Support Center was required to be established to assemble shift personnel.
The licensee has provided an office trailer just outside the control room on the 165 foot elevation in the turbine building for this purpose.
The center is equipped with direct telephone communications to the control room and the Technical Support Center.
The inspector reviewed procedure EP-37, " Operational Support Center Instructions," Revision 0, dated June 27, 1980 to verify that center activation, communications, and personnel accountability had been addressed. The inspector identified no items of noncompliance.
j.
Direct Indication of Safety / Relief Valve Position Peach Bottom Units 2 and 3 each have eleven relief valves and two
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code safety valves.
To meet the lessons learned requirements the l
licensee uses a system of acoustic monitoring channels to provide
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primary and direct indicators on the safety / relief valves and code l
safety valves. The system provides individual indication for each i
valve on an auxiliary rack located behind the Unit 3 main control
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board.
Each module provides indicator lights for " closed," "open" positions, and memory.
The memory feature is provided to show that the relief had lifted if the valve had reseated before the operator could get to.the panel.
The inspector verified that the acoustic monitoring system was calibrated, that electricai power was provided by an emergency power source and that procedure OT-35 " Inadvertent Opening of a Relief Valve," revision 17, dated October 18, 1980 used the acoustic indication as a diagnostic aid.
The licensee is committed to upgrading the seismic and environmental qualifications of this system by January 1, 1981.
The inspector will review this area after the required upgrading is completed (277/80-32-05, 278/80-24-05).
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System Integrity The licensee was to implement a prugram to reduce leakage from Engineered Safety Features (ESF) Systems that are located outside the primary containment.
The program established at Peach Bottom included:
periodic inspection of the Residual Heat Removal (RHR),
High Pressure Coolant-Inject;sn, Reactor Core Isolation Cooling, Core Spray, Scram Discharge, Reactor Water Cleanup, and Standby Gas Treatment Systems; submission of maintenance request forms when leakage was identified; and a tracking system to follow the maintenance actions.
Initial inspections were conducted in January 1980.
The initial inspections did not identify any significant leaks. The inspector reviewed the records of the inspections conducted to date and identified the following:
The RHR, Core Spray, RWCU, HPCI, and RCIC systems are to be
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inspected quarterly for leaks, and an area airborne sample is required from the RWCU backwash tank and MSIV room.
This was not performed on Unit 3 between March 1980 and October 1980.
The Standby Gas Treatment System is required to be tested with
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a tracer gas once per refueling outage.
The test was conducted during the Unit 2 refueling outage completed in August, 1980.
The test was unsuccessful because the dampers on the suction header of the Standby Gas Treatment System are not designed to be a pressure boundary and allowed the gas to escape into the Reactor Building atmosphere.
The procedures for the conduct of quarterly inspections required
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by the program are currently not approved by the Plant Operations Review Committee (PORC).
A licensee representative stated that the procedures are currently being rewritten for approval by the PORC. This area is unresolved pending licensee approval of the new procedures and reinspection (277/80-32-06, 278/80-24-06).
1.
In-Plant Radiation Monitoring (1) High Range Radiation Monitors.
The licensee was required to install instrumentation that would measure high effluent release rates.
Additionally, he was required to include procedures for quantifyjng the relgases.
The licensee installed high range (1.4x10 to 1.4x10 microcuries per cubic centimeter) noble gas effluent monitors on the sampling lines on the Unit 2 and Unit 3 Reactor Building vents and the off gas stack. The inspector verified that there was a three pen recorder in the control room and the three pens were indicating.
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The inspector reviewed procedure HP0/CO-126, " Obtaining the iodine and particulate samples from the Main Stack and Roof Vents Following Accident Conditions," Revision 0, dated January 11, 1980, and EP-48 " Class IV Emergency, Excessive Gaseous Release," Revision 21, dated June 30, 1980 to confirm that the licensee had procedures for retrieving the iodine cartridges and for calculating release rates using values obtained from the high range monitors.
The inspector identi-fied no unacceptable conditions.
The inspector reviewed RT 7.11, "High Range Monitor Source Calibration," Revision 0 dated January 18, 1980, conducted on January 25, 1980 to verify that the licensee had calibrated the high range monitors.
Licenses response dated January 2, 1980 indicated that additional calibration using Krypton-85 (Kr-85) gas would be conducted.
A licensee representative stated that the Kr-85 gas had not been used because of the potential for exceeding the maximum instantaneous release rate allowed by Technical Specifications.
(2) Improved Iodine Instrumentation.
Licensee submittal dated November 21, 1980 stated that existing portable air samplers and counting room equipment would provide the capability for analyzing iodine level.
Additionally the licensee prepared procedure HP0/CO-127, " Sample Preparation and Analysis of Highly Radioactive Particulate Filters and Iodine Cartridges,"
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Revision 0, dated January 10, 1980, to provide direction in the preparation of. particulate filters and iodine cartridges following accident conditions.
The inspector verified that the licensee had available the portable samplers and a supply of silver zeolite cartridges called for in the procedure.
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licensee representative showed the inspector the counting room l
equipment and walked through the procedure for counting various j
samples, including the iodine measurements.
The inspector l
identified no unacceptable conditions.
(3) Post-Accident Sampling Capability References:
(a) HP0/CO-121,
" Obtaining Drywell Gas Samples From Contain-ment Atmosphere Dilution Cabinets," Revision 0, dated January 11, 1980.
(b) HP0/CO-122,
" Obtaining Reactor Wa':r Samples from Sample Sinks Following Accident Conditions,"
Revision 0, dated January 11, 1980.
(c) HP0/CO-123,
" Sample Preparation and Chemical Analysis of Highly Radioactive Liquid Samples,"
Revision 0, dated January 11, 1980.
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. (d) HP0/CO-125,
" Obtaining Drywell Gas Samples from the Drywell Radiation Monitor Sampling Station,"
Revision 0, dated January 19, 1980.
(e) HP0/CO-128,
" Sample Preparation and Analysis of Highly Radioactive Gas Samples," Revision 0, dated January 11, 1980.
(f) HP0/CO-129,
" Minimization of Counting Room Background,"
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Revision 0, dated January 11, 1980.
The inspector reviewed the referenced procedures to verify that the licensee had provisions for sampling the containment air and reactor water following accident conditions and had procedures for handling, diluting and analyzing those samples.
Additionally
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a licensee representative showed the inspector the aquipment to l
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be used in diluting the reactor coolant samples and demonstrated the counting techniques that would be used.
The licensee submittal dated January 2,1980 stated that per-l sonnel exposures during the sampling and analysis operations will not meet the NRC criteria under certain accident conditions.
Additionally the licensee does not currently have the capability to obtain pressurized coolant samples.
The licensee was j
committed to upgrading the post-accident sampling capability in accordance with NRC requirements.
The inspector was shown plans for a new post-accident sample sink which will be located in the Recirculation Pump Motor Generator set rooms.
This station will provide the capability to draw all required samples without entering secondary containment.
9.
Organization and Administration a.
Audits l
Technical Specification 6.5.2.8 requires that audits of facility l
activities be performed under the cognizances of the Operation and Safety Review (OSR) Committee. The inspector reviewed a sampling of completed audits to verify that the audits were being performed at j
the required frequency. This sample included the audit of action l
taken to correct deficiencies occurring during facility operation l
which is required to be conducted every six months.
The audit was performed in December 1979 and in June 1980. Technical Specification 6.5.2.10_ requires in part that the audit reports conducted under the cognizance of the OSR Committee shall be prepared, approved, and forwarded to the Vice President, Electric Production, within 30 days following the completion of the audit. Audits as follows were reviewed:
Audit
' 80-06 Completed April 3, 1980 80-07 Completed February 26, 1980 j
80-08 Completed May 6, 1980 l
80-21 Completed June 30, 1980
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Review of Corporate logs indicated that the audits were forwarded as required within 30 days.
No unacceptable conditions were identified.
b.
Operation and Safety Review (0&SR) Committee Meetings The inspector reviewed minutes of O&SR Committec Meetings to verify that meetings are being held as required by Technical Specifications.
The inspector verified that committee members are designated in writing by the Vice President, Electrical Production and that an alternate is designated for each permanent member.
Review of meet-ing minutes indicated that a quorum existed for each meeting.
The inspector reviewed the manner in which documents are distributed to members for review and how a meeting agenda is established.
The inspector examined minutes of meeting #102 dated May 13, 1980 and meeting #104 dated June 24, 1980 to spot-check for committee review of items required by Technical Specifications.
No unacceptable conditions were identified.
10.
Maintenance a.
Completed Maintenance Review The ins 1ctor reviewed Maintenance Request Form number 2-4-M-9-4 dated 8 mber 19,1979 and Maintenance procedure M-3.7, " Control Rod Dr.
1ousing Support Inspection," Revision 2, dated December 15, 19 9.
This maintenance was completed prior to Unit 2 startup following a refueling outage. The activity performed using these documents was the removal, reinsta11ation and inspection of the support steel for the Control Rod Drive Housing.
The inspector verified by l
record review that administrative approvals had been given, Unit 2 was in cold shutdown prior to and during the activities, the latest revision of procedure M-3.7 was used in the inspection, functional testing was performed upon completion, and all required review signatures were completed.
The inspector identified no unacceptable conditions.
b.
' Procedure Review References:
(1) M9.1 Limitorque Adjustment," Revision 1, dated June 15,
l 1979
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(2) M9.2
"Asco Valve Repair," Revision 1, dated January 17, 1980 l
(3) M10.1
" Residual Heat Removal (RHR) Pump Maintenance,"
Revision 3, dated May 27, 1980
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(4) M57.1
"125 VDC Equipment Maintenance," Revision 2, dated January 18,'1979
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(5) M57.3
"125 Volt and 24 Volt Battery Corrective Maintenance,"
Revision 2, dated January 18, 1979 (6) ST2.6.07B " Calibration check of PS-3-2-3-528," Revision 4, I
dated October 27, 1978
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(7) ST2.6.080 " Calibration Check of PT/PSH/PSL 3-2-3-55D," Revision 4, dated October 27, 1978 (8) ST2.9.088 " Calibration check of LT/LS 3-2-3-838," Revision 1, dated August 6, 1974 The inspector reviewed _the referenced procedures using NUREG 1369,
" Procedures Evaluation Checklist for Maintenance, Test and Calibra-
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. tion Procedures," to determine whether each procedure contained the following elements:
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Proper identification including procedure number and title, date
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of issue, revision number, and page numbers;
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Independent Verification;
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Clear instructions;
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Quantitative acceptance criteria; and,
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The inspector noted that the approval date-had been omitted on procedure M57.3. The licensee added the date immediately.
The inspector looked at approximately 20 more procedures to ensure that there were approval dates on each.
No additional missing dates were identified.
Based on the review the inspector concluded that the
. missing date was an isolated' case.
The inspector had no further questions in this area.
c.
Test Observation On October 22, 1980 the inspector witnessed portions of ST2.9.088,
" Calibration Check of LT/LS 3-2-3-838."
The-inspector verified that:
technicians obtained shift permission to perform the test,
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calibrated equipment was used where required, the procedure was performed in the order specified, appropriate radiological controls were provided, and the steps in the procedure were signed off when accomplished.
The inspector noted that the pressure instrument selected for the test did not have the accuracy required.
The
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technicians immediately correctea this error.
The inspector discussed his concerns regarding the instrument with licensee representatives, and they stated that a training session was held for all Instrumenta-tion and Control Technicians to reemphasize the importance of selecting the proper testing equipment.
The inspector had no further questions regarding this matter.
11.
Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable items, items of noncompliance, or deviations.
Unresolved items are discussed in Detail 8.
12.
NRC/ Licensee Meeting On October 16, 1980 the inspector and an NRC Region I management representa-tive met with representatives from licensee Engineering and Research Quality Assurance and Electrical Production Quality Assurance regarding the findings of the recent Systematic Licensee Appraisal Board.
The inspectors stated that increased NRC inspection effort related to Quality Assurance would be conducted and provided licensee representatives information regarding resident inspector findings and observations.
13.
Management Meetings a.
Preliminary Inspection Findings A summary of preliminary findings was provided to the Station Super-intendent at the conclusion of the inspection.
During the period of this inspection, licensee management was periodically notified of the preliminary findings by the resident inspectors.
The dates involved, the senior licensee representative contacted, and subjects discussed were as follows:
Senior Licensee Date Subject Representative Present October 24, 1980 Control of Procedures Assistant Station Superin-(Detail 3)
tendent November 12, 1980 Summary of Findings Station Superintendent
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Attendance at Management Meetings Conducted by Region-Based Insoectors The resident inspectors attended entrance and exit interviews by region-based inspectors as follows:
Inspection Reporting Date Subject Report No.
Inspector October 29, 1980 IE Bulletin 79-01B 50-278/80-25 R. Paolino (Entrance and Exit Interviews)
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