IR 05000219/1979011
| ML19209C573 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 08/07/1979 |
| From: | Briggs L, Kehoe D, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19209C555 | List: |
| References | |
| 50-219-79-11, NUDOCS 7910160163 | |
| Download: ML19209C573 (26) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
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Region I Report No. 50-219/79-11
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Docket No. 50-219 License No.
DPR-16 Priority
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Category C
Licensee:
Jersey Central Power and Licht Company Madison Avenue at Punch Bowl Road Morristown, New Jersey 07960 Facility Name:
Oyster Creek, Unit 1 Inspection at:
Forked River, New Jersey inspection conducted: May 7-11 and May 14, 1979
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Inspectors:
[
h 8/g,/79 t. Briggs, Keactgr(:Zns e or date'signso DJV/
e /7/79 D. Kehoe, Reactor Inspector date sighed date signed Approved by:
d O. b O,)u
& f '7 b T E. McCabe, Jr., Reactor Projects Section No. 2, date signed RO&NS Branch Inscection Summary:
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May 7-11 and May 14, 1979 (Report No. 50-219/79-11)
Special, onsite, announced inspection by two regional based inspectors (107.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />).
Inspection Areas:
(4):
Followup of previous inspection finding; followup of IEB 79-08; followup of May 2,1979 event; and independent inspection effort.
Noncompliances : One (Deficiency - 3 valves not locked as required, Paragraph 3.c.(7)).
1147 304 7910160163 Region I Form 12 (Rev. April 77)
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DETAILS 1.
Persons Contacted R. Baran, Engineer - Associate
- J. Carroll, Station Superintendent K. Fickeissen, Technical Engineer E. Growney, Operations Engineer T. Johnson, Instrument and Electrical Maintenance Supervisor J. Maloney, Operations Supervisor T. Quintenz, Senior Engineer
- D. Ross, Manager, Generating Stations W. Stewart, Senior Administrator - Generation Technical Training
- J. Sullivan, Chief Engineer The inspectors also contacted other members of the technical, engineering, and operating staff.
- Present at the exit interview.
2.
Followup on Previous Inspection Findings (0 pen) Deficiency (219/79-05-09):
Store Room Did Not Meet The Requirements of ANSI N45.2.2. The inspector toured the store roon and interviewed QA and store room personnel and determined that the conditions of the store room and its governing procedures had undergone significant improvement. A considerable amount of work is yet to be completed.
This item remains open pending completion of all requirements (presently scheduled for October 1, 1979).
3.
IE Bulletin 79-08 Followup Inspection of Engineered Safety Features (ESF)
a.
Gener'l_
An onsite inspection of engineered safety features was conducted as indicated in subsequent subparagraphs.
Inspection of the following systems and components were completed on the indicated dates:
Automatic Depressurization System (ADS), May 9,1979.
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1147 305
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3 Standby Liquid Control System (SBLS), May 9, 1979.
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Core Spray System (CS), May 9. 1979.
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Containment Spray System (CS), May 8,1979.
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Standby Gas Treatment System (SBGTS), May 8, 1979.
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Primary Containment Isolation System (PCIS), May 9,1979.
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Reactor Protection System (RPS), May 10, 1979.
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Shutdown Cooling System (SCS), May 9,1979.
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Diesel Generators (DG), May 10, 1979.
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Isolation Condenser System, May 8,1979.
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b.
Review of Valve / Breaker / Switch Alignment Procedures, Check-Off Lists and Piping and Instrument Diagrams To verify the adequacy of alignment procedures a comparison of the valve / breaker / switch alignment procedures and check-off lists (COL)
was performed, for the systems specified in Paragraph 3.a, against current piping and instrument diagrams (P&ID's) and single line diagrams.
The inspectors, accompanied by licensee representatives, also verified the valve / breaker / switch alignment of those systems specified in Paragraph 3.a by conducting the applicable system check-off list for all accessible components.
Check-off list completion additionally verified the status of valves requiring positive position control (locki;.gdevices).
The following procedures and drawings were used in this review:
(1)
Procedures 301, Nuclear Steam Supply System, Revision 7, September 22,
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1978 302.1, Control Rod Hydraulic System, Revision 3, March 9,
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1978 1147 306
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305, Shutdown Cooling System, Revision 4, September 22, 1978
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308, Standby Core Cooling System, Revision 7, March 7,1979
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310, Containment Spray System, Revision 5, January 16, 1979
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311, Reactor Containment Integrity and Atmospheric Control,
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Revision 10, July 14, 1978 318, Main Steam System and Reheat System, Revision 2, July
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5, 1977 330, Standby Gas Treatment System, Revision 3, July 12, 1977
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408.1, Placing Reactor Protection System MG Set 1-1 (1-2) in
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Service, Revision 1, April 19, 1979 307, Isolation Condenser System, Revision 3, October 29,
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1976 334, Instrument, Service, Breathing and Bleeder Check Trip
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Air System, Revision 5, March 7, 1979 316.1, Condensate Transfer System, Revision 2, July 5,1978
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340.1, 125 Volt D.C. Distribution Systems "A" and "B",
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Revision 4, April 9, 1979 340.3, 125 Volt D.C. Distribution System "C", Revision 0,
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April 9, 1979 108, Control of Tagging, Electrical Jumpers, Lifted Electrical
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Leads, Keys and Locked Valves, Revisicn 10, February 9,1979 304, Standby Liquid Control System, Revision 6, January 23,
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1979 201.1, Approach to Critical, Revision 11, April 25,1979
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341, Standby Diesel Generators, Revision 4, April 9, 1979
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1147 307
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(2) Drawings GE 237E566, Reactor Protection System, Revision 17
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GE 237E487, Control Rod Drive Hydraulic System, Revision 15
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GE 148F740, Containment Spray System, Revision 12
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GE 148F711, Reactor Shutdown Cooling System, Revision 7
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GE 148F712, Reactor Vessel Level / Pressure / Temperature Instru-
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ments, Revision 15 BR 2011, Flow Diagram - H&V Reactor Building, Revision 7
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BR 3013, Vital One Line Diagram, Revision 14
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GE 148F262, Emergency Condenser System, Revision 5, December
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18, 1967 BR 2013, Service, Breathing and Bleeder Check Trip Air
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GE 729E182, Sheets 1 through 3, ADS Automatic Actuation
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Logic GE 885D781, Core Spray System, August 2,1968
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c.
Findinas The inspectors conducted a hand over hand verification of all access-able valves, switches and breakers in each of the systems identified in Paragraph 3.a.
Inaccessible valves were independently verified by the licensee prior to the inspectors departure and are listed below.
Core Spray System V-20-23, Locked Open - System II Shutoff inside drywell (remote
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position indication verified by inspector).
V-20-17, Locked Open - System I Shut-off inside drywell (remote
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position indication verified by inspector).
1147 308
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2 System I manual vents - closed.
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2 System II manual vents - closed.
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Standby Liauid Control System V-19-19, Locked Open - poison pumps Discharge Shut-off inside
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drywell (remote position indication verified by the inspector).
All valves, switches and breakers were positioned in the correct position, on the dates indicated in Paragraph 3.a., except those in the Shutdown Cooling System (Paragraphs 3.c (18), (19), and (20)
refer).
The licensee had previously identified problems with valves not being identified by number, P&ID and flow diagrams not showin valves (instrument valves), and valve check off lists (g all system COL's) not identifying all valves. The following items concerning COL's and flow diagrams were compiled by the inspectors.
(1) Automatic Depressurizing System (ADS)
Review of the ADS by the inspector verified that system lineup and COL were up to date and correct.
One item was identified concerning GE print No. 729E182, ADS Automatic Actuation Logic.
The print did not in~ corporate the D.C. distribution from the new
"C" battery modification performed during the 1978 refueling out-age. This item is unresolved pending licensee revision of the sub.iect print and subsequent NRC inspection (219/79-11-01).
(2) Possible Standby Liquid Control System Degradation Several valves which could place tne Standby Liquid Control system in a degraded mode were not addressed in plant procedures and check off lists (COL's).
In addition, several system valves were not identified by permanent unique valve number tags.
The licensee acknowledged the above and stated that unique valve numbers viould be assigned to each valve and that COL's and asso-ciated procedures would be revised to identify each valve.
Valve numbering is to be completed by June 8,1979 and complete procedure revisions by September 21, 1979.
This item is unresolved pending completion and subsequent NRC inspection (219/79-11-02).
i147 309
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(3)
Standby Liquid Control System Instrumentation Several valves were not identified or shown in the Standby Liquid Control System diagram (P&ID).
The licensee acknowledged this fact ard stated that the system P&ID would be revised to identify all system valves by unique number and that action would be completed by September 21, 1979. This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-03).
(4) Standby Liquid Control System Procedure Error The inspector also identified a procedural error in the fill and vent section of Procedure No. 304.
Two valves in the vent and drain line, V-19-28 and the drain valve (no identification number)
downstream of V-19-24, provide the drain path but were not required to be opaned during the filling and venting pracedure.
The licensee stated that this problem would be corrected during the procedure and COL revision required to correct valve numbers.
This item is unresolved pending licensee action and subsequent NRC inspection (219/79 11-04).
(5) Core Spray System 19stru..ent Valves Instrument valves shich could placa +he core spray system or
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system instrumeitation in an inoi,erable u' degraded mode were not addressed in plant procedures and check-off lists (COL's).
In addition, in' trumentation and other system valves were not identi-
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fied by perm.nent tags with unique valve numbers.
The licensee acknowle ted inis condition and stated that uniaue valve numbers would be assigned to each valve and that COL's and associated procedures would be revised to identify each valve. The licenscs further stated that the valve numbering would be complete by June 8,1979 cod procedure revisions would be completed by September 21, 1979.
This item is unresolved pending completion of licensee action and subsequent NRC review (219/79-11-05).
(.6 )
Core Spray System Drawinos In addition, instrument valves were not identified or shown on the core spray system diagram (P&ID).
The licensee acknowledged this and stated that the system P&ID would be revised to identify all system valves by unique number by Septembs - 21, 1979.
This 1147 M0
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item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-06).
(7)
Unlocked Valves The inspector also identified three (3) valves required to be locked by procedure No.108, Control of Tagging, Electrical Jumpers, Lifted Electrical Leads, Keys and Locked Valves, Attach-ment No. 7.
The valves were as follows:
Valve No.
Required Position Actual Position Description LV (39)
Locked Closed Closed Core spray system supply from conden-sate storage tank drain.
V-20-75 Locked Closed Closed Pump NZOlD Discharge Check Valve Bypass.
V-20-73 Locked Open Open Pump NZ01B Discharge Check Valve Bypass and Fill Pump Suction.
The licensee took corrective action by immediately locking the above valves.
This is an item of noncompliance (219/79-11-07).
(8)
Defective Electrical Breaker Lockina Devices The inspector also identified two (2) electrical breakers for V-20-27 ard V-20-18 that were locked in the off position. However, the ni6chanical holding device was defective and the breaker position could be changed.
The licensee acknowledged the above and stated that the locking mechanisms would be repaired.
This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-08).
(9)
Possible Containment Spray System Degradation Instrument valves which could place the containment spray system or system instrumentation in an inoperable or degraded mode were not addressed in plant procedures and check-off lists (COL's).
1147 311
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In addition, the instrumentation valves and other system valves were not identified by pemanent tags with unique valve numbers.
The licensee acknowledged the above and stated that unique valve numbers would be assigned to each valve and that COL's and asso-ciated procedures would be revised to identify each valve.
The licensee further stated that the valve numbering would be completed by June 8, 1979 and procedure revisions would be complete by September 21, 1979.
This item is unresolved pending completion of licensee action and subsequent NRC review (219/79-11-09).
(10) Containment Spray System Drawings In addition, instrument valves were not identified or shown on the containment spray system diagram (P&ID).
The licensee ack-nowledged this fact and stated that the system P&ID would be revised to identify all system valves by unique nanber and that action would be complete by September 21, 1979. This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-10).
(11) Standby Gas Treatment System Instrument Tap The inspector noted that an instrument tap on the down stream side of the standby gas treatment system (SBGT) filter train was not capped, and the SBGT system was therefore open to atmosphere.
It was determined that pressure differential would prevent adverse effects from this condition.
It was also verified that the cap
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was reinstalled immediately.
The inspector had no further questions on this item.
(12) Standby Gas Treatment Drawings The inspector noted that the bypass line of the standby gas treatment (SBGT) system had been removed and replaced by a capped pipe with an isolation valve and an orifice in the cap.
The inspector further noted that the system drawing did not reflect this modification.
The licensee acknowledged this and stated that the above would be included in the drawing by a special revision.
The licensee further stated that this action would be complete by September 21, 1979.
This item is unresolved pending NRC review after completion (219/79-11-11).
1147 312
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(13) Standby Gas Treatment Eystem Valve Position Discrepancy The inspector noted that during automatic initiation, SBGT system valves V-28-21 and V-28-22 go shut.
During manual SBGT initiation these valves would remain open.
Should fan EF-5 or EF-6 be initiated under this condition some of the air flow would bypass the SDGT system altogether.
The licensee acknowledged the above and stated that the procedure for manual initiation of the SBGT system would be changed to shut V-28-21 and V-28-22.
The licensee further stated that this action wou!d be complete by September 21, 1979.
This item is unresolved pending NRC review after completion (219/79-11-12).
(la) Standby Gas Treatment System Manways and Manual Dampers The inspector noted a large number of manways and manual dampers in the standby gas treatment system whose integrity /po:ition were not addressed in plant procedures or check-off lists.
The licensee acknowledged the above and stated that procedural coverage would be developed to verify system integrity / alignment with respect to dampers and manways. The licensee further stated that the above action would be completed by September 21, 1979.
This item is unresolved pending NRC review after completion (219/79-11-13).
(15) Containment Isolation System The primary containment isolation system valve, breaker, switch and logic aligne.ent and functions were verified to be correct by the inspector. The inspector had no further questions concerning this system.
(16) Possible Reactor Protection System Degradation Instrument valves which could place the reactor protection system or system instrumentation in an inoperable or degraded mode were not addressed in plant procedures and check-off lists (COL's).
In addition, the instrumentation valves and other system valves were not identified by permanent tags with unique valve numbers.
The licensee acknowledged the above and stated that unique valve numbers would be assigned to each valve and that COL's and asso-ciated procedures would be revised to identify each valve.
The licensee further stated that the valve numbering would be complete
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1147 313'
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. 11 by June 8, 1979 and procedure revisions would be completed by September 21, 1979. This item is unresolved pending completion of licensee action and later NRC review (219/79-11-14).
(17) Reactor Protection System Drawings Instrument valves were not identified or shown on the reactor protection system diagram (P&ID).
The licensee acknowledged this fact and stated that the system P&ID would be revised to identify all system valves by unicue number by September 21, 1979. This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-15).
(18) Possible Shutdown Cooling System Degradation Instrument valves which couid place the shutdown cooling system or instrumentation in an inoperable or degraded mode were not addressed in plant procedures and check-off lists (COL's).
In addition, the instrumentation valves and other system valves were not identified by permanent tags with unique valve numbers. The licensee acknowledged the above and stated that unioue valve numbers v;ould be assigned to each valve and that COL's and asso-ciated procedures would be revised to identify each valve. The licensee further stated that the valve numbering would be complete by June 8, 1979 and procedure revisions would be completed by September 21, 1979. This item is unresolved pending co'mpletion of licensee action and subsequent NRC review (219/79-11-16).
(19) Shutdown Cooling System Drawings In addition, instrument valves were not identified or shown on the shutdown cooling system diagram (P&ID).
The licensee ack-nowledged this fact and stated that the system P&ID would be revised to identify all system valves by unique number by Sep-tember 21, 1979. This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-17).
(20) Shutdown Cooling System Valve Labels The inspector noted that a number of shutdown cooling valves were labeled with incorrect and sometimes duplicate numbers.
Time requirements and high radietion levels did not permit a hand over
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1147 314
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hand inspection to accurately identify each valve; however, the main flowpath was verified. Tha licensee acknowledged the above and stated that all incorrect valve numbers would be removed and correct valve numbers would be assigned to the valves.
The licensee also stated that a verification of the shutdown cooling valve status would be performed. The licensee further stated that this would be completed before returning to power operation.
This item is unresolved pending completion of the above stated actions and subsequent NRC review (219/79-11-18).
(21) Standby Diesel Generators Review of the standby diesel generator procedure verified that all breakers, switches, available fuel oil and fuel oil delivery lineup were correct.
The inspector noted that the proc 6 dure did not contain any specific valves to be positioned; however, the main fuel oil supply from the storage tank contained one (1)
locked open valve in the line which should be verified.
In addition, the procedural steps were not organized for efficient operator performance. The licensee acknowledged the above and stated that the procedure would be revised to correct these problems. This item is unresolved (219/79-11-19).
(22) Possible Isolation Condenser System Degradation Instrument valves which could place the isolation condenser system or system instrumentation in an inoperable or degraded mode were not addressed in plant procedures and check-off lists (. COL 's ).
In addition, the instrumentation valves and other system valves were not identified by permanent tags with unique valve numbers. The licensee acknowledged the above and stated that unique valve numbers would be assigned to each valve and that COL's and associated procedures would be revised to identify each valve.
The licensee further stated that the valve numbering would be complete by June 8, 1979 and procedure revisions would be conpleted by September 21, 1979.
This item is unresolved p(ending completion of licensee action and subsequent NRC review 219/79-11-20).
1147 M5
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(23) Isolation Condenser System Drawings Instrument valves were not identified or shown on the isolation condenser system diagram (P&ID).
The licensee acknowledged this fact and stated that the system P&ID would be revised to identify all system valves by unique number by September 21, 1979.
This item is unresolved pending licensee action and subsequent NRC inspection (219/79-11-21).
d.
Review of Plant Surveillance Procedures The inspectors reviewed current, approved surveillance tests for the systems specified in 3.a. to verify that when the surveillance test is complete, the applicable system will have been returned to an operable condition.
Each applicable surveillance test was reviewed to insure that procedural steps were included that returned the system to an automatic initiation 'ineup.
The inspector also verified that the results of the last performance of each surveillarice test were within the limits of the acceptance criteria required for system operability.
The following surveillance tests and their results were reviewed.
602.3.005, Revision 0, ADS Actuation Circuit Test and Calibra-
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tien, perfonned 11/28/78 604.3.008, Revision 0, (Revision 1 is issued), Excess Flow Check
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Valve Functional Test, performed 11/17/78 607.3.002, Revision 4, Containment Spray System Automatic Actu-
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ation Tests, performed April 26, 1979 607.4.001, Revision 6, Containment Spray and Emergency Service
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Water Pump Operational Test, performed A,nril 26, 1979 609.3.002, Revision 1, (Revision 2 is issued), Isolation Conden-
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ser Isolation Test, February 9,1979 609.3.003, Revision 6, Isolation Condenser Auto Actuation Sensor
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Calibration and Test, performed May 2,1979
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1;47 316
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609.4.001, Revision 3, Isc' tion Condenser Valve Ooerational
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Test, perfomed April 12, 1979 610.3.001, Revision 0, (Revision 1 is issued), Core Spray Pump
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Failure Pressure Switches Surveillance Calibration, performed May
? 1977 610.3.004, Revision 2, (Revision 3 is issued), Core Spray Header
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Differential Pressure Test and Calibration, performed February 27, 1979 610.3.005, Revision 2, Core Spray System Instrumentation and
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Control Calibration and Test, performed April 20, 1979 610.3.006, Revision 4, Core Spray Isolation Valve Actuation Test
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and Calibration, performed April 18, 1979 610.4.002, Revision 2, (Revision 3 is issued), Core Spray Pump
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Operational 'est, perionned April 20, 1979 610.4.007, Res 1sion 2, Core Spray System Firewater Valve Test,
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performed May t, 1979 612.4.001, Revision 1, L' quid Poison Pump Operational Test,
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performed April 29, 1979 612.4.002, Revision 1, (Revision 3 is issued), Liquid Poison
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System Functional Test, performed November 14, 1978 619.3.003, Revisicn 0, (Revision 1 is issued), High Drywell
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Pressure Isolation Functional Test, performed November 29, 1978 636.2.001, Revision 1 (Revision 2 is issued), Diesel Generator
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Auto Actuation Test, performed December 1, 1978 for Diesel Generator
- 2 and December 4, 1978 for Diesel Generator #1 636.4.003, Revision 5, Diesel Generator 20 Percent Load Test,
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performed May 7, 1979 for Both Diesels 651.3.002, Revision 0. Particulate Filter Efficiency Test, performed
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January 3, 1979 1147 3F7
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651.3.003, Revision 0, Charcoal Filter Efficiency Test, perfonned
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January 9, 1979 651.4.001, Revision 6, Standby Gas Treatment System Test, performed
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May 1, 1979 651.4.005, Revision 0, Standby Gas Treatment System HEPA Filter
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Differential Pressure Test, performed May 2,1978 665.5.001, Revision 2, Drywell To Torus Vacuum Relief Valve Leak
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Rate Test, performed November 25, 1978 665.5.002, Revision 2, Secondary Containment Leak Rate Test, last
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performed September 14, 1978 619.3.005, Revision 1, July 26,1978, High Flow in the Main Steam
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Line Test and Calibration, last performed April 24, 1979 619.3.001, Revision 1, December 9, 1977, Turbine Load Rejection
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Scram Test (> 45% load), laet perfi ned April 11, 1979 619.3.013, Revision 3, April 9,1979, Reactor Low Level Test and
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Calibration, last performed April 17, 1979 619.3.016, Revision 3, April 9,1979, High Drywell Pressure Scram
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Test and Calibration, last performed April 30, 1979 602.4.002, Revision 0, (Revision 1 is issued), September 20,
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1977, MSIV Closure Test, last perforr d April 7,1979 636.2.004, Revision 0, (Revision 1 is issued), August 25, 1978,
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Diesel Generator Battery Discharge (Load Test), last performed March 8, 1979 602.4.003, Revision 1. June 30, 1978, Electromatic Relief Valve
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Operability Test, last performed April 8,1979 619.3.004, Revision 0, September 20, 1977, Reactor lo Lo Water
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Level Functional Test, last performed November 28, 1978 619.3.004, Revision 1, (Revision 2 is issued), November 10, 1978,
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Reactor lo Lo Water Level Functional Test, last perfonced November 29, 1978
\\ \\ 41 Y S
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619.3.006, Revision 2, (Revision 3, is issued), January 30, 1979,
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Rx Triple Low Water Level Test and Calibration, last performed April 12,1979 602.3.004, Revision 2. April 2,1979, Electromatic Relief Valve
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Pressure Sensor Test, last performed May 2,1979 e.
Findings The inspector noted that the instructions contained in surveillance test procedures for returning a system to an operational lineup after completion of the test were not specific enough to verify that the system was operational. The licensee acknowledged the above and stated that specific valve by valve instructions would be included in all safety-related surveillance test procedures to return the sytems to an operational condition at the completion of the testing. The licensee further stated that this action would be complete by September 21, 1979.
This item is unresolved pending NRC review after completion (219/79-11-22).
f.
System Operability Following Maintenance The inspector reviewed the following maintena ce procedures to verify that the system was returned to an operable condition following the maintenance.
704.3.012, Revision 2, Drywell and Torus Pressure Recorder Loop
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and Gauge Calibration Procedure 709.1.003, Revision 1, Isolation Condenser Hydrostatic Test
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710.1.002, Revision 2, Core Spray Booster Pump Inspection and
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Maintenance 710.1.003, Revision 0, Core Spray Instrument Line Repair
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728.1.010, Revision 0, Feedwater System Valve V-2-10, -11, -12, -35,
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and -36 Maintenance 732.2.001, Revision 0, 4160 Volt Breaker Preventive Maintenance
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1147 319
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766.1.002, Revision 0, Off Gas Drain System Modification
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Findings The inspector noted that the instructions contained in maintenance procedures for returning a system to an operational lineup after the
- ompletion of maintenance were not specific enough to verify that the system was operational, the licensee acknowledged the above and stated that specific valve by valve instructions would be included in all maintenance procedures to return the system to an operational condition at the completion of the maintenance.
The licensee further stated that this action would be complete by September 28, 1979.
This item is unresolved pending NRC review after completion (219/79-11-23).
h.
Procedure Changes The inspector reviewed the following procedure revisions implemented by the licensee as a result of the TMI Unit 2 incident.
604.4.013, Pressure Suppression Chamber (Torus) External Inspec-
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tion, Revision 0, May 12,1979 (new procedure)
636.2.001, Diesel Generator Automatic Actuation Test, Revision 3,
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May 12,1979 502.1, Loss of Off-Site Power (new title), Revision 4, May 11,
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1979 502.6, Loss of Off-Site Power - Failure of Diesel Generators (new
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title), Revision 2, May 12,1979 503, Instrument Air Failure, Revision 5, May 12, 1979
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507.2, Turbine Building Closed Cooling Water System Failure, Revision 2, May 11, 1979 510, Turbine Trip, Revision 3, May 12. 1979
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511.1, Feedwater Pump Failure, Revision 2, May 12, 1979
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511.2, Condensate /Feedwater System Rupture, Revision 1, May 11,
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1979
- Procedure additionally revised due to May 2,1979 event, see Paragraph 4.a.(3)
for details.
1147 320
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511.3, Feedwater Flow Control Failure, Revision 2, May 12,1979
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514, Reactor Isolation Scram, Revision 3, May 12, 1979
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515.3, Small Piping Leaks in Drywell, Revision 2, May 11,1979
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516.1, Main Steam Line Rupture Outside Drywell, Revision 6, May
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11, 1979 516.2, Piping Rupture Inside Drywell, Offsite Power Available,
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Revision 5, May 11, 1979 516.3, Piping Rupture Inside Drywell With Loss of Offsite Power,
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Revision 5, May 11, 1979
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516.4, Isolation Condenser Line Break Outside Drywell, Revision 6, May 11, 1979
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516.5, Piping Rupture Inside Drywell With Loss of Offsite Power and One Diesel Generator Inoperable, Revision 5, May 12, 1979 517, Significant Increase in Off-Gas Release Rate, Revision 6,
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May 11, 1979 519, Loss of Containment Integrity, Revision 3, May 11, 1979
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525, Loss of Drywell Cooling, Revision 3, May 11, 1979 526.2, Fire in the Control Room, Revision 2, May 11, 1979
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527.1, Inadequate Relief Valve Actuation While at Power, Revision
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6, May ll, 1979 527.2, Failure of Relief Valve to Reseat - Reactor Scranimed,
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Feedwater Available, Revision 5, May 12, 1979
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527.3, (New) Loss of Feeuwater - Electromatic Relief Valve Stuck Open, Revision 0, May 12, 1979 529, Emergency Containment Purge, Revision 3, May 12, 1979
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- Procedure additionally revised due to May 2, 1979 event, see Paragraph 4.a.(3)
for details.
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532, Automatic and Manual Reactor Scram, Revision 2, May 12,1979
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534, Loss of Reactor Cooling M 'anisms During Reactor Shutdown, Revision 1, May 12,1979 The inspector reviewed the above procedures to verify that revisions made reflected lessons learned from the TMI incident.
The inspector observed a general philosophy expressed by the procedure revisions.
Primary containment isolation was not to be reset, if actuated, until all necessary samples were takan and the cause determined; verification of radioactive waste levels prior to any waste transfers; and verifi-cation of system conditions by several different sensors before over-riding any engineered safety system automatic actuations.
The inspector had no further questions in i.his area.
i.
Operator Training and Communications The inspectors verified that adequate operator training relative to the TMI 2 incident had been received by operations personnel by a review of training records of class attendance, lecture outline, and discussions with shift operating personnel.
The licensee additionally briefed the operations personnel on the procedural philosophy which resulted from the TMI incident as an interim measure until the com-mitment date of May ll, 1979 when actual procedural changes were scheduled to be accomplished and could be presented to the operations staff.
Lectures on specific changes are scheduled to commence during the week of May 14, 1979.
This item will be reinspected.
The licer.see has provided two (2) dedicated phones for a continuous comunications channel with the NRC in case of an event.
One is located in the Group Shift Supervisor's office and the other in the Conference Room located in the Administrative Building.
The inspector had no further questions in this area.
j.
Interim Control of Valve Positions The complete engineered safety system lineup checks performed by the inspectors, accompanied by licensee representatives, were a careful check of the correctness of system lineups as of the da'es of com-pletion identified in Paragraph 3.a.
Consideration of Je findings in
- Procedure additionally revised due to May 2, 1979 event, see Paragraph 4.a.(3)
for details.
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Paragraphs 3.e. and 3.g. raised the concern that surveillance or maintenance performed on the systems involved may alter the lineups without restoration being assured.
The inspectors stated that an acceptable method must be provided by)
the licensee to verify correct lineup of any system (Paragraph 3.a.
after it is disturbed from its present lineup. The licensee provided, as an interim measure until system valves are physically identified and procedures revised, a method for positive system lineup control and independent verification.
The licensee has issued Standing Order No. 27 which lists the systems of Paragraph 7.a. and requires the Group Shift Supervisor to insure independent verification is performed on any instrumentation valves that are operated during surveillance or maintenance. To insure that no valves are missed or incorrectly positioned the licensee will:
Provide instrument loop drawings that show the instrument iden-
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tification and all valves associated; Each valve on the drawing will have its position identified (open
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or closed) and its rack location; Each vclve will have a blank next to it for sinnature by the
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individual performing the operation and a sep ate blank for the verification signature; and, Each valve will be physically marked with a red (open) or green
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(closed) tape or other identifier to further assist the operator in correct positioning of the valve.
This item will be reviewed during subsequent NRC inspections.
k.
System Operability Following Extended Outages
,
The inspector reviewed, for adequacy, the administrative controls imposed by the licensee to assure proper " return to service" cf the systems specified in Paragraph 3.a. following extended outages.
A review of procedure No. 201.1, Approach to Critical, verified that, if procedural requirements are performed, in conjunction with the interim control measures, that all safety and their support systems will be properly aligned for automatic actuation.
It was also noted 1147 323
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a
that the licensee does not normally require independent verification of system lineups. The inspectors had no further questions in this area.
4.
Review of Items Directly Related to May 2,1979 Reactor Vessel Low Water Level Event a.
Licensee Comitments As a result of the May 2,1979 event the licensee made several comit-ments to the NRC.
These comitments and the licensees actions to date with respect to these comitme.ts are listed below.
(1)
Event Recorder May 2,1979, it was discovered that the event reccrder was secured approximately three (3) minutes after the event.
The licensee comitted to ensuring that this recorder would not be secured in the future.
The licensee has placed a sign on the event recorder specifically stating that this recorder is not to be secured.
This action was completed on May 14, 1979.
(2) Startup Program As a result of the May 2,1979 event, the licensee comitted to developing a startup program which would ass ae there was no fuel damage as a result of the May 2,1979 event. The licensee has developed a startup program which will detect significant changes in parameters and make a confirmatory analysis to insure fuel integrity by performing the following.
Interference checks on all control rods.
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Scram testing on 25% of the control rods to asrure no major
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deviations from previous measurements.
Analysis of reactor coolant samples during startup, heatup
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and power ascension phases.
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Analysis of off gas samples at discrete power levels up to
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full power.
Comparison of radioactivity levels to established criteria,
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with appropriate action taken if measurements fall out of specified range.
This program and the associated ' established criteria" was com-
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pleted on May 7,1979.
(3) Procedure Upgrading The licensee comitted to review / revise procedures in light of the May 2,1979 event and Bulletin 79-08.
The licensee also committed to train operations personnel on the relevant revisions made to plant procedures.
(a)
Procedures Revised as a Result of the May 2,1979 Event 317, Revision 4, May 12,1979, Feedwater System (Reactor
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Feed Pumps to Reactor Vessel)
318, Revision 3, May 11, 1979, Main Steam System and
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R1 heat System 501, Revision 26, May 12. 1979, Annunciators and Alarms
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505.2, Revision 1, May 11, 1979, Recirculation Flow
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Decrease 506.5, Revis1cn 1, May 11, 1979, Scram System Failure
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301, Revision 8, May 12,1979, Nuclear Steam Supply
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System 307, Revision 4, May 12,1979, Isolation Condenser
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System
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(b) Procedures Revised as a Result of May 2,1979 Event and Bulletin 79-08 507.2, Revision 2, May 11, 1979, Turbine Building
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Closed Cooling Water System Failure 516.5, Revision 5, May 12,1979, Piping Rupture Inside
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Drywell with Loss of Offsite Power and One Diesel Inoperable 525, Revision 3, May 11, 1979, Loss of Drywell Cooling
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527.3, Revision 0 (new procedure), May 12, 1979, Loss
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of Feedwater, Electromatic Relief Valve Stuck Open 532, Revision 2, May 12,1979, Automatic and Manual
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Reactor Scram 534, Revision 1, May 12, 1979, Loss of Reactor Cooling
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Mechanisms During Reactor Shutdown (c) Procedures Revised as a Result of Bulletin 79-08 502.1, Revision 4, May ll 1979, Loss of Offsite Power
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502.6, Revision 2, May 12,1979, Loss of Offsite Power -
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Failure of Diesel Generators 503, Revision 5, May 12,1979, Instrument Air Failure
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510, Revision 3. May 12.1979, Turbine Trip
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511.1, Revision 2, May 12, 1979, Feedwater Pump Failure
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515.3, Revision 2, May 11, 1979, Small Piping Leaks in Drywell 516.1, Revision 6, May 11, 1973, Main Steam Line
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Rupture Outside Drywell 516.2, Revision 5, May 11, 1979, Piping Rupture Inside
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Drywell - Offsite Power Available
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517, Revision 6, May 11, 1979, Significant Increase In
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Off-Gas Release Rate 526.2, Revision 2, May 11, 1979, Fire in the Control
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Room 527.1 Revision 6, May 11, 1979, Inadvertant Relief
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Valve Actuation While at Power 527.2, Revison 5, May 12,1979, Failure of Relief Valve
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to Reseat (d) Other Procedure Revisions Related To the May 2,1979 Event or Bulletin 79-08 511.2, Revision 1, May 11,1979, Co.densate/Feedwater
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System Rupture 511.3, Revision 2. May 12,1979, Feedwater Flow Control
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Failure 514, Revision 3. May 12. 1979, Reactor Isolation Scram
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516.3, Revision 5, May 11, 1979, Piping Rupture Inside
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Drywell with Loss of Offsite Power 516.4, Revision 6, May 11, 1979, Isolation Condenser
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Line Break Outside Drywell 519, Revision 3, May 11, 1979, Loss of Containment
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Integrity 529, Revision 3, May 12,1979, Emergency Containment
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Purge 604.4.013, Revision 0 (new procedure), May 12, 1979,
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Pressure Suppression Chamber (Torus) Extended Inspection 636.2.001, Revision 3, May 12, 1979, Diesel Generator
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Automatic Actuation Test
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b.
Findings The above procedure changes were found to be consistent with Bulletin 79-08 and the resolutions resulting from the May 2,1979 event.
The inspectors also verified that mandatory training sessions covering the May 2,1979 event and resultant procedural changes had been conducted.
At the time of the inspection, a Technical Specification change to require two (2) recirculation pump discharge and suction valves be open at all times was being developed.
This change would require further changes to procedure Nos. 301, 307, 317, 501, 505.2, 506.5, 514, and 532.
This item is unresolved pending submittal of the Technical Specification change, revision to the above procedures and subsequent NRC review (219/79-11-26).
5.
Review of Safety System Operations With A Degraded Voltage Condition Abnormal Occurrance 76-09 identified a safety problem at Millstone Station Nuclear plant when electrical buses were operated at a degraded voltage such that the voltage was above the setting of the undervoltage trip but below that minimum valve necessary to assure that the ECCS systems wculd fut: tion properly.
In August 1976, Oyster Creek was informed of this and requested by NRR to perform a.n analyses to determine if this situation could occur at Oyster Creek.
A report issued by Burns and Roe on August 8.1979, stated that the undervoltage setting at Oyster Creek was 2864 V and that the minimum voltage on the 4160 V bus to assure operation of the ECCS systems was 3630 V.
This left a deadband of 766 V where voltage could be above the undervoltage trip point but below the minimum required for guaranteed operation of the ECCS systems.
The Burns and Roe report suggested two actions to prevent this condition from occurring. The first action was to change the tap setting on the 480 V transformers from Tap 1 to Tap 3, providing a higher voltage to the bus.
The second was to install another undervoltage relay, to be set at 3666 V with a time delay to account for normal transients, to detect the degraded voltage condition and trip the bus, initiating diesel start and closure to affected busses.
The licensee had changed the taps on the 480 V transformers from Tap 1 to Tap 2, and is planning to perform the undervoltage modification during the
>
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next outage.
In addition, the licensee has issued a standing order to maintain voltage on the bus greater than 4000 V by adjusting the VAR's.
The inspector concluded that the Tap 2 position on the 480 V transformer was not sufficient to prevent the degraded bus condition and that the standing order did not cover the contingency of not being able to maintain voltage above 4000 V on the bus or the more probable situation of what to do if the main generator were lost and off site power was at a degraded voltage condition.
During subsequent telephone conversations the licensee acknowledged the inspectors comments and stated:
the tap position on the 480 V transformer would be changed from Tap 2 to Tap 3; the old standing order would be revoked and a new one issued which stated that voltage on the 34.5 KV bus would be maintained between 34.2 and 35.4 by using the variable tap on the 34.5 KV transformer; and, the standing order would further state that if voltage could not be maintained within this range and fell below the point corresponding to 3700 V on the 4160 bus, then the diesels would to be manually alligned to the bus.
Addition of the second undervoltage trip has been requested and is undergoing licensee engineering review.
This item is unresolved pending NRC reinspection (219/79-11-27).
6.
Unresolved Items Unresolved items are matters about which more information is required to ascertain whether they are acceptable items, items of noncompliance or deviations.
Unresolved items disclosed during this inspection are dis-cussed in Paragraphs 3.c.(1) through 3.c.(6), 3.c.(8) through 3.c.(10),
3.c.(.12) through 3.c. (14), 3.c. (16) through 3.c. (23), 3.e. (1), 3.g. (1),
4.b, and 5 of this report.
7.
Exit Interview The inspector met with licensee representatives (see Detail 1) at the conclusion of'the_inspecti6n on May 14, 1979, and summarized the scope and findings of the insrection at that time.
.
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