IR 05000293/1979009
| ML19262A607 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 09/07/1979 |
| From: | Architzel R, Markowski R, Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19262A598 | List: |
| References | |
| 50-293-79-09-01, 50-293-79-9-1, NUDOCS 7912070139 | |
| Download: ML19262A607 (20) | |
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U. S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
REGION I
Report No.
79-09 Docket No.
50-293 License No.
DPR-35 Priority Category C
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Licensee:
Boston Edison Company M/C Nuclear 800 Boylston Street Boston, Massachusetts 02199 Facility Name:
Pilgrim Nuclear Power Station, Unit 1 Inspection At:
Plymouth, Massachusetts Inspection Conducted: May 14-18, 21-25, 29-31 and June 1, 1979 Inspectors:
[
T[$3[79 R. Architzd1, Re ctor Inspector date W
dd
$
R. Karkowski, React.or Inspector date
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date Approved by:
b 0. b
.h 9. l'7 h i E. C. McCabe, Jr., Chief, Reactor Projects date Section No. 2, RO&NS Branch Inspection Summary:
Inspection on May 14-18, 21-25, 29-31 and June 1, 1979 (Report 50-293/79-09)
Areas inspected:
Routine, unannounced inspection by two NRC regional based inspectors (112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br />) of the actions taken by Boston Edison Company in res-ponse to the nuclear incident at Three Mile Island (TMI) and to assure that certain factors contributing to the incident at TMI do not exist at Pilgrim I (IE Bulletin 79-08), and certain actions relative to IE Bulletin 79-07 (Seis-mic Analysis).
Noncompliances:
Three (Procedures do not specify valve position (paragraph 2.b),
procedures do not specify valve locking (paragraph 2.f) and valve documented 1 cked in wrong position (paragraph 2.e)).
Region I Form 167 (August 1979)
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7912070
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DETAILS 1.
Persons Contacted The following technical and supervisory level personnel were contacted:
W. Armstrong, Assistant to Manager, N0D R. Atkins, Station Electrical Engineer H. Balfour, Methods Training and Compliance Group Leader E. Cobb, Chief Operating Engineer I. Crifasi, Secretary to CD Director, Plymouth Township F. Famulari, Engineer, N00 J. Fulton, Senior Plant Engineer M. Hensch, Chief Radiological Engineer C. Leonard, Senior Reactor Operator R. Machon, Plant Support Group Leader
- C. Mathis, Senior Plant Engineer
- P. McGuire, Station Manager J. Nicholson, Assistant to Station Manager P. Smith, I&C Engineer
- Denotes those present at the exit interview.
Other licensee employees were also interviewed.
2.
Inspection of Engineered Safety Features (ESF)
a.
General An onsite inspection of Engineered Safety Features was conducted which encompassed the following areas:
a review of System Operating Prc edures to determine that
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valve / breaker / switch alignment was soecified; and, was consis-tent with piping and instrument diagrams and ele:trical power distribution diagrams;
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direct observation of valves designated by the licensee as requiring locking; direct observation of breaker position associated with the
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electrical power distribution; review of procedures to determine that " return to service"
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provisions, subsequent to maintenance and testing, surveil-lance testing and extended outages, are defined, and,
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review of surveillance test results.
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Each of the above areas are discussed in the following subparagraphs.
b.
Review of System Operating Procedures (SOP) and Piping and Instru-ment Diagrams (P&ID)
The below listed procedures were reviewed against the below refer-enced P& ids' to verify, on a sampling basis, the adequacy of the procedure and/or its associated Valve Check List (Appendix A) in specifying the required valve / breaker / switch alignment.
The procedures (and/or associated drawings) reviewed were:
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2.2.8, Standby AC Power System, Revision 4 (M-223, Diesel Oil Storage and Transfer System, Revision 9)
2.2.19, Low Pressure Coolant Injection System, Revision 5
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(M-241, Residual Haat Removal System, Revision 13)
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2.2.20, Core Spray, Revision 5 (M-242, Core Spray System, Revision 9)
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2.2.21, High Pressure Coolant Injection System, Revision 5 (M-243, HPCI System, Sheet 1, Revision 15; Sheet 2, Revision 14)
2.2.22, Reactor Core Isolation Cooling, Revisica 6 (M-245,
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RCIC System, Sheet 1, Revision E2; Sheet 2, Revision 10)
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2.2.23, Automatic Depressurization System, Revision 4 2.2.24, Standby Liquid Control System, Revision 6 (M-249,
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Standby Liquid Control System, Revision 10)
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2.2.50, Standby Gas Treatment, Revision 3 (M-294, Standby Gas Treatment System, Revision 13)
2.2.70, Primary Containment Atmospheric Control System, Revi-
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sion II (M-227, Containment Atmospheric Control System, Revision E1)
S-E-155, Station Electrical Single Line Composite Diagram,
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4.16 KV and 480V AC Systems, Revision 8 E-13, Single Line Relay and Meter Diagram, 125V and 250V DC
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Systems, Revision E4
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E-14, 120V Instrument AC, Vital and Reactor Protection AC Sys-tems and 24VDC Power Systems, Revision E2 1522 W
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--8.C.13, Locked Open, Locked Closed Line Up Surveillance, Revision 2 The findings associated with above mentioned review were:
(1) During the review of the valve check list associated with pro-
,cedure 2.2.8, stan6,y AC Power System (Diesel Generators),
Revision 4, the inspector identified that the 2.5" outlet valves of the A and B Emergency Diesel Generator Oil Storage Tanks as indicated as open on P&ID, M223, Revision 9 were not incorpo-rated on the valve check list.
This is one example of failure to provide procedures which include confirmation that necessary valves are properly aligned.
(2) During the review of the valve check list associated with pro-cedure 2.2.21, High Pressure Coolant Injection System, Revi-sion 5, the inspector identified that the.75 " manual outlet valve of the Nitrogen Supply line and the 1" manual isolation valve of VRV9066 indicated as open and locked open on P&ID M-243, Revision 15 were not incorporated on the valve check off list.
This is the second example of failure to provide procedures which include confirmation that necessary valves are properly aligned.
This is an item of noncompliance (293/7S-09-01).
(3) During the review of Section VII.H of procedure 2.2.70, Primary Containment Atmospheric System, which detailed the method for nitrogen makeup to the drywell or torus, the inspector noted that the procedure does not require opening the manual block valve downstream of either 5033A or C.
The valve check list requires that these valves be closed.
The licensee acknowledged the inspector's statement and stated that the procedure would be revised.
Panding review of the revised procedure this item is unresolved (293/79-09-02).
(4) During the procedural check list reviews the inspector noted that the line up requires a check that
'E instrumentation (for each system instrument) is either.perable, inoperable, or "0K" (not known to be inoperable).
The inspector questioned the licensee concerning actual verification that instrument isolation (root) valves were in fact open to verify an available 1522 340
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sensing path during the system line up.
In a subsequent tele-phone conversation the licensee stated that VCOLs would be revised to check instruments not isolated prior to restart from the next and subsequent refueling outages.
The licensee stated that this check would encompass either a physical verificaton of open root valves, physical observation of an open sensing path (i.e., wcter flow out a drain valve), or observation of instrument response to a variation in the measured parameter.
The item is unresolved (293/79-09-03) and will be reinspected.
c.
Review of Surveillance Test Procedures and Results The below listed surveillance procedures and associated data sheets were reviewed to verify:
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return to service provisions were incorporated which assure that the system will be returned to its standby / automatic ini-tiation configuration if the test is performed during normal operation; and, the data sheet provided documentary evidence that the test was
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performed satisfactorily and the system was returned to normal.
It is noted that with respect to the data sheet review, the inspector utilized the acceptance criteria defined within the appropriate pro-cedure and verified the technical adequacy of the procedure, the frequency of performance of the surveillance and the consistency of the acceptance critaria with respect to the technical specification requireme.nts on a sampling basis only.
The surveillance tests reviewed and the date performed were:
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8.2.2, Core Spray System Performance Testing, January 30, 1976; 8.2.3, Visual and Manual Inspection of Prir.ary Containment Iso-
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lation Valves 1" and Smaller, November 14, 1977;
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8.4.1, Standby Liquid Control Pump Operability and Flow Rate Test, May 7, 1979; 8.4.2, Standby Liquid Control Pump Operability, Flow Rate and
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Relief Valve Test, April 5, 1977;
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8.4.6, Manual Initiation Test of One SLC System, September 29, 1977 and April 6, 1976, 8.5.1.1, Core Spray Pump Operability and Flow Rate Test, May 4,
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1979; 1522 341
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8.5.1.3, Core Spray Motor Operated Valve Operability Test,
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May 10, 1979;
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8.5.2.1, LPCI Subsystem Operability Surveillance Test, May 2, 1979; 8.5.2.2, L9CI Pump Flow Rate Test, May 10, 1979;
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8.5.2.3, LPCI Motor Operated Valve Operability Test, May 10,
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1979; 8.5.3.1, RBCCW Pump Operability and Capacity Test, May 17, 1979;
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8.5.3.2, Salt Service Water Pump Operability and Pump Capacity
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Test, May 17, 1979;
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8.5.3.3, Containment Cooling Valve Operability Test, May 2, 1979; 8.5.3.4, Drywell and Torus Headers and Nozzles Air Test,
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February 27, 1976; 8.5.4.1, HPCI Pump Operability and Flow Rate Test at 1000 psig,
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April 13, 1979; 8.5.4.3, HPCI Flow Rate Test at 150 psig, November 4, 1977;
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8.5.5.1, RCIC Pump Operability Test and Flow Rate at 1000 psig, May 9, 1979; 8.5.5.3, RCIC Flow Rate Test at 150 psig, November 14, 1977;
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8.5.5.4, RCIC Motor Operated Valve Operability Test, May 9, 1979; 8.5.6.1, ADS Subsystem Manual Opening of Relief Valves,
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November 15, 1977;
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8.7.2.2, Demonstration of Standby Gas Treatment Inlet Heater Capacity, February 13, 1979; 8.7.4.3, Test (Close and Reopen) Isolation Valves Except MSI'/'s,
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May 8, 1979; 8.M.2-1.5.8.3, Standby Gas Treatment Initiation and Reactor
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Building Isolation-System A Inboard, January 9,1979;
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8.M.2-1.5.8.4, Standby Gu Treatment Initiation and Reactor Building Isolation System B Outboard Drywell Isolation Valves, January 9, 1979; 1522 342
8.M.2-1.5.9, Primary Containment Isolation Valve Testing
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(Simulated Auto Actuation), October 13, 1978;
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8.M.2-2.3.1, ADS-Pump Discharge AC Interlock, March 20, 1979 and May 10, 1979; 8.M.2-2.5.7, HPCI Suppression Chamber Water Level, March 16,
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1979; 8.M.2-2.6.7, RCIC Simulated Automatic Actuation, May 29, 1976;
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8.M.2-2.10.1-1, Core Spray, Reactor Water Level, Auto Initia-
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tion Trip System "A" Logic System Functional Test, April 2.7, 1979;
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8.M.2-2.10.1-2, Core Spray, Reactor Water Level, Auto Initiation Trip System, April 27, 1979; 8.M.2-2.10.1-3, Logic System Functional Test High Drywell Pres-
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sure Core Spray System, Auto Initiation Trip System "R", April 27, 1979; 8.M.2-2.10.1-4, Core Spray System Logic System "A" Functional
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Test, April 27, 1979;
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8.M.2-2.10.1-5, Core Spray System Logic System "B" Functional Test, April 27, 1979; 8.M.2-2.10.1-6, Automatic Start Core Spray Pump 1401-A Logic
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System Functional Test, April 27, 1979;
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8.M2-2.10.1-7, Logic System Functional Test Automatic Start Core Spray Pump 1401-B, April 27, 1979; 8.M.2-2.10.1-8, Core Spray System High Drywell Pressure Auto
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Initiation Trip System "A" Logic System Functional Test, April 27, 1979;
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8.M.2-2.10.2-1, RHR System Reactor Water Level Auto Initiation Trip System "A", March 1, 1979;
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8.M.2-2.10.2-2, RHR System Reactor Water Level Switches Auto Initiation Trip System "B", March 1, 1979; 8.M.2-2.10.2-3, RHR System Auto Initiation Trip System "A"
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Functional Test, March 1, 1979;
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8.M.2-2.10.2-4, Functional Test RHR System Auto Initiation Trip System "B", March 1, 1979; 1522 343
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8.M.2-2.10.2-5, Loop Selection Logic System A, March 29, 1979; 8.M.2-2.10.2-6, Loop Selection Logic System 8, March 29, 1979;
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8.M.2-2.10.2-7, LPCI Loop Selection Logic Initiation Logic
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System Tests, February 5, 1979; 8.M.2-2.10.2-8, LPCI Logic System Tests, February 1, 1979;
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1.M.2-2.10.2-9, RHR System Reactor Pressure Permissive Loop
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3 election Permissive Logic Functional Test, February 5, 1979; 8.M.2-2.10.2-14, Automatic Start, RHR Pumps P-203A and P-203C
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Functonal Test, April 5, 1979; 8.M.2-2.10.2-15, Automatic Start, RHR Pumps P-203B and P-2030
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Functional Test, April 5, 1979; 8.M.2-2.10.2-lo, LPCI Break Detectio., Logic Functional Test,
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February 1, 1979;
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8.M.2-2.10.2-17, LPCI Break Detection Logic Functional Test, February 1, 1979; 8.M.2-2.10.2-1, RHR Logic Containment Spray "ubsystem A, March 1,
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1979;
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8.M.2-2.10.3-2, RHR Logic Containment Spray Subsystem B, March 1, 1979; 8.M.2-2.10.4-2, HPCI Initiation Logic Test, April 30, 1979;
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8.M.2-2.10.4-3, HPCI Steam Supply Isolation Valve Logic, April 30, 1979; 8.M.2-2.10.4-4, HPCI Injection Valve Logic, April 30, 1979;
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8.M.2-2.10.5, HPCI Auto Isolation System Logic, Apri' 30, 1979;
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8.M.2-2.10.7, RCIC Auto Isolation System Logic, April 30, 1979;
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8.M.2-2.10.8-1, Diesel Generator "A" Initiation by RHR Logic, November 14, 1978; 8.M.2-2.10.8-2, Diesel Generator "B" Initiation by RHR Logic,
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Ncvember 14, 1978;
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8.M.2-2.10.8-3, Diesel Generator Initiation by Core Spray Logic, November 14, 1978; 1522 344
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8.M.2-2.10.8-4, Diesel Generator "B" Initiation by Core Spray
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Logic, November 14, 1978; 8.M.2-2.10.9, Depressurization System Actuation Logic When
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Reactor Is Shutdown, November 11, 1978;
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8.M.2-2.10.9-1, Autorr.atic, Depressurization System Subsystem Logic With Reactor in Other Than Sautdown, February 14, 1979; 8.M.2-2.10.10, Trip System Bus Power Monitor, November 13, 1978;
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8.M.2-2.10.11, RCIC High Water Trip Logic, April 16, 1979; and,
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8.M.2-2.10.12, HPCI High Water Trip Logic, March 29, 1979.
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During the review of ST 8.5.3.4, Drywell and Torus Header c.ad Noz-zles air test, performed on February 27, 1976 the inspector noted that the licensee had doc.umented air flow observed through five torus spray nozzles wnen the P&ID showed six nozzles.
The individual who conducted the surveillance test stated that he was fairly certain that all nozzles (six) had been checked and that he had failed to document one.
During a subsequent plant shutdown a containment entry was made and the licensee verified that six spray nozzles are installed in the torus and that none were externally obstructed.
The inspec-i.or stated that this item, verification of air flow, is unresolved pending performance and documentation of an air flow test through all torus spray nozzles (79-09-06).
d.
Direct Observation of Locked Valve and Breaker Alignment The inspectors toured plant areas at various timas during this inspection to directly observe the status of locked valves and breakers.
The locked valve check off list, 8.C.13A-2, Revision 2 (March 7, 1979) and the electrical diagrams listed in Paragraph 2.b above were utilized.
The areas toured included the four
" quadrants" of the reactor building, reactor building elevations 23, 51 and 91; the reactor building auxiliary bay, the diesel generator rooms, the screen house and the condensate storage tank valve pit.
In addition to locked valves and breakers, the inspectors, on a sampling basis, also observed the status of major ESF flow path
.2lves as indicated in the control room; and, observed the status of valves in the diesel air start, diesel fuel oil supply and HPCI Turbine E::haust lines.
The valve check lists of the appropriate system operating procedures referenced in 2.b above were utilized.
The findings in this area are as discussed in paragraphs e and f below.
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e.
During a review of the locked valve status, the inspector noted that several valves required to be locked were in the opposite position as specified by the locked vaeve list, and locked in the opposite posi-tion.
The specific valves of concern were the Main Feed Water Pump minimum flow manual block valves (required locked open-actually locked closed) and the Drywell and Torus Nitrogen Makeup Valves (one each for torus, Drywell, requi: 2 locked open, actually locked closed).
The licensee stated that the feedwater pump minimum flow valves were closed because of recurrent problems in maintaining low differential pressure across the condensate demineralizers.
Elimination of the minimum flow path reduces total flow through the (leaking minimum flow valves) demineralizers thus reducing the differential pressure.
The nitrogen make up valves, inside the drywell access area, were closed because existing nitrogen leaks within the containment eli-minated the necessity for automatic makeup capability (i.e., con-tainment pressure routinely goes up and must be vented).
In neither case (FW minimum flow nor N2 additio.. blocks) could the licensee justify locking these valves in the opposite position.
The control room switch for A0-5033A (Drywell N2 Addition Block) was red-tagged closed on February 12, 1979 (Maintenance Request 79-262) because the valve exhibited excessive closure time during surveillance test-ing.
The inspector expressed concern about the licensee's method of locking valves in the opposite position required and noted that A0 5033A and A0 5033C had been documented as being locked open (the specified position) on May 15 and March 15, 1979 whan in fact they were locked closed and in addition A0 5033A was rc tagged closed.
The valves had been documented as locked closed on February 15, March 2, and April 18, 1979.
This in an item of noncompliance (293/79-09-04).
f.
During the review of system line ups on May 30, 1979 the inspector noted two valves in the HPCI system required to be locked open by P&ID M-243, HPCI System Revision 15 which were open but not locked.
The valves, Nos. 2301-74 (Turbine Exhaust 24" Manual Block) and a
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1" manual block to VRV (vacuum relief valve) 9066 also on the turbine exhaust line, were not incorporated in SP 8.C.13, Locked Open, Locked Closed Line Up Surveillance, Revision 2 (3/1/79).
The HPCI system was required to be operable at this time.
A. reactor startup was in progress, pressure greater than 150 psig.
The inspec-tor stated that failure to lock these valves was an item of noncom-plianca (293/79-09-05).
g.
Review of Administrative and General Operating Procedures The inspectors reviewed the below listed procedures to verify that procedural controls were specified which provide for return to service of safety systems subsequent to extended outages and perfor-mance of maintenance during normal operations.
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The procedures reviewed were:
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OPER-02, Celd Startup System Check List, Revision 2; 2.1.11, Current Valve Lineup File, Revision 0;
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1.5.3, Maintenance Requests, Revision 10.
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Specifically the inspectors observed that:
the valve lineup lists associated with each system operating
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procedure were identified as the record of the status of the system; subsequent to each extended outage, a complete new valve lineup
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was required;
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subsequent to each extended outage, pcwer supplies, switch positions and major system parameters were required to be checked; and,
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.iuring the conduct of maintenance, changes to the plant con-figuration were maintained utilizing the maintenance request procedure.
The inspector also noted that the licensee's tagging system does not incorporate provisions for independent verification (other than operator placing tags) of placement and position of tagged components.
Regarding physical placement of tags on the control toards the inspec-tor noted the licensee's practice of " curling" tags to avoid covering other indications with these tags, however, the potential for obscur-ing indications with safety tags does exist at Pilgrim Station.
h.
Operating Procedures The inspector evaluated certain aspects of the licensee's response to IEB 79-08 (BECo letter 79-79 of April 25, 1979) with regard to procedures for transferring of radioactive wastes out of the con-tainment and routine uses of the ESF feedwater (HPCI, RCIC) systems.
With regard to liquid wastes the inspector noted that even before TMI the licensee had elected to manually pump the containment sumps (WRC Inspection Report 79-01, unresolved item 79-01-04).
This mode of operation greatly reduces the chances of pumping contaminated water out of the containment (If the pumps were in automatic, and the containment isolation is reset the sumps would be pumped down).
The licensee is removing this automatic feature.
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The Standby Gas treatment system initiates upon containment isola-tion and provides a filtered, elevated release point for secondary containment atmosphere.
The primary containment atmosphere can be vented with an isolation signal present through 2" lines via key lock switch controlled valves.
None of these flow paths have isolation capability based upon effluent path radiation levels.
The inspector also reviewed routine uses of the Hi h h essure Cooi.it
Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) Systems (that is uses when they have not been initiated automatically).
The licensee has posted " Quick Start" Procedures on the Control Boards to use these systems foll1 wing a plant trip and subsequent isolation, with the RCIC being started for Reactor Vessel water level control and the HPCI being utilized in tha full flow test mode as the primary heat removal (pressure control or cooldown) mechanism.
Procedures require operation of a relief valve following a scram with isolation to provide an initial large reduction in primary system stored energy.
(The HPCI, full flow test mode is sufficient to remove approximately 2% decay heat).
No unacceptable conditions were identified, however, potential post LOCA paths for the release of radioactive materials and routine uses of ESF feedwater systems will be subject to further NRC review.
3.
Operator Training During the weeks following the accident at TMI-2 the licensee concNcted training for the licensed staff on both a reading file and formal lecture basis.
Documentation has been retained by the licensee and was reviewed by the inspector.
Additionally, a licensee training session was audited by the inspector to assure that the training provided was meaningful and direci.ed toward understanding:
(1) the seriousness and consequences of the simultaneous blocking of both trains of a safety rystem at the Three Mile Island Unit 2 (TMI-2) plant and other actions taken during the early phases of the accident; (2) the apparent operational errors which led to eventual core damage; and. (3) the necessity to systematically analyze plant conditions and parameters and take appropriate corrective action.
a.
Specific. areas addressed by the licensee included:
(1) Providing operators an awareness of the details of the Three Mile Island incident to the extent of information available at the time of this inspection.
Additionally, the licensee made available Bulletins 79-05 and 79-05A in the control room for informational purposes.
The inspectors confirmed that copies were made available to licensed personnel.
(2) Reinstruction on specific measures which provide assurance that engineered safety features are available when required.
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(3)
Instructions on specific and detailed measures to assure that automatic actuations of emergency safety features are not over-ridden.
(4) Review of plant automatic actions initiated by reset of engi-neered safety features that could affect the control of radio-active liquids and gases.
(5) Detailed review (lecture plan generated by Training Department)
on a per shift basis of all Reactor Vessel Water level sensors and indications to ensure operator knowledge of redundant level instruments.
b.
Inspector Discussions with Licensed Operators In addition to training conducted by the licensee the inspector held
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direct discussions with licensed operations personnel during day, afternoon, midnight, and training shifts (2 individuals each shift)
with respect to details surrouriding the events at TMI-2.
The follow-ing topical areas were discussed:
(1) An evaluation of training received to date relative to the events at TMI (2) A discussion of the six specific contributing factors to the incident as described on Pages 1 and 2 of IE Bulletin 79-05A (3) The seriousness and consequences of the simultaneous blocking of both auxiliary feedwa er trains (4) The need for prompt reporting of serious events to the NRC and discussion regarding the licensee's reporting procedures (5) The necessity to avoid premature resetting of Engineered Safety Feature Systems, including core cooling syste...: and containment isolation systems.
These discussions alsc encompassed resetting from spurious signals.
HPCI and RCIC initiation was used as an example.
(6) The need to avoid premature tripping of Engineered Safety Fea-ture Systems during any transients requiring flow No unacceptable conditions were identified.
c.
Prompt Reporting Requirements Plant procedures requiring prompt notification, including proposed changes to the Failure and Malfunction Reports Procedure (Revision 7 1522 349
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draft), were reviewed to ensure provisions are established incor-porating prompt (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) notification any time the reactor is not in a controlled or expected condition of operation.
The following additional procedures are being revised to require an evaluation for prompt reporting in the subsequent actions by operator:
Special Events 5.3.1 Shutdown From Outside Control Room 5.3.2 Inability to Shutdown with Control Rods
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5.3.3 Loss of all Service Water 5.3.4
. ss of all Reactor Building Cooling Water 5.3.5 Loss of A.C. Power (Use of Standby A.C. Power)
5.3.6 Loss of Vital A.C.
5.3.7 Loss of an Instrument Power Bus 5.3.8 Loss of Instrument Air 5.3.10 Loss of all Feedwater 5.3.11 Loss of Essential D.C. Bus D4 5.3.12 Loss of Essential D.C. Bus 05 5.3.13 Loss of Essential 0.C. Bus 06 5.3.14 Civil Disturbances Postulated Accidents 5.4.1 Closure of MSIV's on High Radiation 5.4.2 Pipe Break inside Primary Containment 5.4.3 Refueling Floor High Radiation 5.4.4 Pipe Break Inside Reactor Building 5.4.5 Pipe Break in Turbine Building 5.4.6 Post Accident Venting 1522 350
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The inspector noted that the licensee's proposed procedure changes did not specify that a technically knowledgeable individual must be available within one hour of such a transient and maintain a line of communications with the NRC.
A tour was made with a licensee repre-sentative and locations established for installation of a " Hot Line" directly connecting the Control Room, Emergency Control Center (ECC),
and Watch Engineer's Office with the NRC Emergency Operations Center, Bethesda, Maryland.
In addition the alternate ECC (Memg:ial Hall, Plymouth) and Health Physics Office were examined for future tele-phone installations.
The hot line was tested and operational by the completion of this inspection.
Revision of the licensee's procedtre to incorporate a technically knowledgeable individual main-taining an open line with the NRC within one hour is unresolved (293/79-09-07).
The licensee stated the procedure would be revised by July 1, 1979.
4.
Seismic Stress Analysis of Safety Related Piping (IE Bulletin 79-07)
a.
References 1.
IE Bulletin 79-07, Seismic Stress Analysis of Safety Related Piping, dated April 14, 1979 2.
Licensee Event Report (LER) 79-012/01X dated April 24, 1979, Seismic Analysis 3.
BECo Letter No. 79-78, USNRC Office of Inspection and Enforce-ment Bulletin Number 79-07, dated April 24, 1979 4.
LER 79-014/01X dated May 9, 1979, Recirculation Pipe Snubbers 5.
BECo Letter No.79-100, Actions Resulting from Boston Edison /
NRC Meeting of May 18, 1979, in Bethesda, Md., dated May 23, 1979 6.
Memorandum to T. A. Ippolito, Chief, Operating Reactors #3,00R dated May 23, 1979, Meeting O' mmary 7.
BECo Letter No.79-103, Supplementary Information Regarding Response to I&E Bulletin 79-07 and Snubber Design, dated May 25, 1979 8.
T. A. Ippolito (OR Branch 3, DOR) letter to Boston Edison Company letter dated May 25, 1979, Safety Evaluation Report, Review of Piping Reanalysis per I&E Bulletin 79-07.
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Background
--IEB 79-07 (Apri 14, 1979):
Issued as a result of NRC discovery of use of unapprosed computer load summing technique in the seismic analyses of five power reactors, which were ordered shutdown.
This bulletin required a response within ten days.
--LER 79-012 (April 24,1979, Telephone Notification, April 21, 1979):
BECo notified the NRC of the discovery by General Electric Company (during the program review required by IEB 79-07) that the DAPS com-puter program used by G.E. for the seismic analysis of the PNPS main steam and recirculation piping combir.ed directional and seismic by algebraic sum.
Reevaluation of the loads on the affected piping was per#ormed using the PISYS Program which combined directional responses in an acceptable manner.
Th'
reanalysis indicated that piping stresses for the suspect systems met the code requirements.
--BECo Letter 79-78 (April 24, 1979):
This letter was BECo's required ten day response letter for IEB 79-07.
This letter discussed the use of algebraic srmmation in the PNPS piping systems.
The licensee stated that a summary of the verification procedure for PISYS program was being prepared and would be forwarded when ccapleted.
The res-ponse also stated that the reanalysis had been performed on the pip-ing systems as originally designed, and that verification that present configurations did not affect conclusions was il progress.
--LER 79-14 (May 9, 1979) BEco reported that as an apparent result of a deficiency in the original design, four recirculation system snubbers did not satisfy T.S. operability requirements for the Design Bases Earthquake (DBE) because they were undersized.
The plant was shutdown in accordance with Technical Specification 3.6.I.2.
Planned corrective action was to modify the snubbers to withstand the required loading.
--References 5 through 8 address the results of further analyses and the May 18 meeting summaries (NRC (00R), BECo, G.E., Teledyne).
The scope of the original DAPS analyses was recognized as containing branch piping off the Main Steam and Recirculation Piping to the first anchor point.
In addition examination of supporting steel work showed that modifications were needed in addition to increas-ing snubber capacity.
All s2venty-six safety related snubbers and associated steel work were checked using the SSE loading (This includes thirty-six snubbers in the recirculation and main steam systems).
Commitments were made to verify that the analysis utilized the "as built" configurations.
Inaccessible anchor bolts were tested in accordance with IE Bulletin 79-02.
Evaluation of the licensees response to IE Bulletin 79-07 is still open, pending further NRC review.
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On Site Inspection The inspectors examined key elements of the licensee's correspondence rerarding IE Bulletin 79-07.
Discussions with licensee personnel indicated the cause for initial discovery of undersigned snubbers was that G.E. had analyzed the recirculation system with four snub-bers (SS-1 through 4) in the wrong location.
The reanalyzed loads could be handled by the installed Bergen Patterson Snubbers if the snubber s were modified by the blocking of an internal relief passage.
This action results in increasing the capacity of the snubber from 133% of rated to 200% of rated.
The passage is installed to allow piston motion when loading exceeds 133% of design.
The modification will not allow this motion, however, calculated DBE loads fall within the 200% capacity of the modified snubbers.
The inspectors performed a hands on walk through of the recircula-tion system and the "D" main steam line.
Both the main steam and recirculation systems checked by the inspec-tors are located in the Drywell.
As built verification was limited by the inspectors' radiation exposure.
The verification effort included verifying approximately accurate geometries and support orientations, including selected measurements of piping lengths, support location along those lengths, nameplate ratings on hangers, and snubbers, angles of incidence of supports and supporting steel dimensions (hanger detail drawings).
d.
Main Steam Piping The licensee had contracted Teledyne Materials Research to modify the Main Steam Piping in 1976.
The inspectors used Drawing No.
D-4076, Revision 1 (May 20, 1976) to walk down the "D" Main Steam line.
This isometric was generated in 1976 and verified as built at that time (June 4, 1976).
The three hydraulic snubbers on the D Main Steam were checked against the following Bergen-Paterson hanger details drawings:
Snubber Mark No.
Dated Checked SS-1-10-12 SD-3 September 24, 1970 September 9, 1971 SS-1-10-11 SD-2 September 22, 1970 September 21, 1971 SS-1-10-10 SD-1 September 22, 1970 September 29, 1971 Additional hangers installed on the Main Steam line and mechanical snubbers on the B and C relief lines off the main steam lines were 1522 353
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verified installed as per the isometric.
The licensee stated that these drawings were the drawings used in the seismic reanalyses.
No inconsistancies with respect to the as built configuration were iden-tified for the D Main Steam line.
e.
Recirculation System The inpectors were told by the licensee that General Electric Co.
had utilized drawing 730E822, Recirculation Loop Suspension, January 24, 1972 to reanalyze the recirculation piping.
The inspec-tors were informed that G.E. did not utilize isometric drawings.
In addition the inspectors were provided Bergen-Paterson snubber detail drawings for snubbers SS-1 through SS-26 and were informed that GE had used these drawings to perform the analysis.
The inspectors also requested details of Sway Brace No. 14 and Hangers 2, 3, and 4 to verify these types of installations on a sampling basis.
Snubbers SS-1 through 4 were not located on the recirculation pumps discharge risers (el. 36'") as indicated on the Loop Suspension drawing.
Four snubbers not indicated on this drawing, however, labeled SS-1-4, were installed on the ring header (el. 42' 8").
Eight additional snubbers (SS-19 through 26) were installed on the lower portions of the recirculation piping, but not on the drawing.
Snubbers SS-17 and 18 on the discharge value bypass line were on the drawing, however, the lines (a id snubbers) removed.
Sway Brace 14 could not be located, the inspectors subsequently determined that Sway Braces 11 through 18 were not installed as indicated.
Further discussions with the licensee determined that these errors in the seismic analysis input drawings had been the cause of the declared N strability of the snubbers.
The inspectors were pro-vided wi m ontrolled " constructions" (isometrics) of the recircu-
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lation s p.em depicting the current inputs G.E. was utilizing.
The inspectors determined that the initial G.E. reanalysis did not con-sider pipe supports installed in tie-in branch lines, for example, the RHR supply line nor the removal of the discharge bypass line nor the relocation of SS-1 through 4.
The licensee stated that these errcrs had been accounted for as demonstrated in the simplified schematics.
All snubbers installed in the system were verified by the inspectors as in the approximate location as shown in the sim-plified schematic.
The sway braces, shown on this print (dated May 23, 1979) were not installed.
In addition, three heavy steel cables were apparently rigidly attaching the recirculation pump casing to the shield wall.
This " jockey strap" is installed to hold the recirculation pump and motor in place following a line break.
The licensee contacted G.E. and informed the inspectors that elimina-tion of sway braces 11-18 would have no effection the seismic ana-lyses because they are installed with springs, therefore, discounted 1522 354
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in the analyses.
The licensee also stated that the cable arrange-ment on the pump casing had no effect on the analyses.
All of the above identified pipe support deficiencies to the as built systems (with the exception of the licensee's removal of the dis-charge valve bypass line) were traced to Field Disposition Reports (FDRs) which were generated during construction to accommodate inter-ferences, etc.
Apparently the NSSS vendor did not recalculate seis-mic loadings upon receipt of the FDR's, nor update the suspension drawing.
The licensee checked all remaining recirculation system FDR's.
A system guide was also discovered to have been eliminated through FDR's.
According to telephone input from G.E. this guide had not been used in the seismic analysis.
Based upon the licensees verbal assurances (current seismic design input documents not available on site) that these discrepancies had all been accounted for and examination of all visual examination of all restraints on the simplified schematic (sway braces previously discussed) the inspectors concluded the as built condition was now analyzed.
Further examination of this area will be performed pur-suant to IE Bulletin 79-14, Seismic Analyses for As Built Safety Related Piping Systems, issued July 2, 1979 as a result of these inaccuracies in the PNPS and other nuclear power plant seismic input documents.
5.
Diesel Generator Trips During Accidents The inspector reviewed the tripping logic for the Emergency Power Sources (Diesel Generators) which still exist during an cccident.
The schematics reviewed were E-40 Revision El (4160 Breakers 152-509 and 152-09) and E-27 Revision El (Schematic Diagram Diesel Generator).
The inspector determined'that crank case vacuum, lube oil temperature, jacket water temperature, overcrank, low oil pressure, and low oil level engine trips are all defeated when a LOCA (Loss of Coolant Accident) initiation signal exists.
The overspeed engine trip is not defeated.by the LOCA initiating device.
The inspector further noted that although the engine trips were bypassed, the salle trips discussed above exist on the diesel generator output breaker and are not bypassed during a LOCA initiating event.
In addition the output breaker trips on generator differential current and overcurrent.
This item, Diesel Gnerator breaker trips is unresolved (293/79-09-08).
Unresolved Item An item about which more information is required to determine acceptability is considered unresolved.
Paragraphs 2, 3 and 5 contain unresolved items.
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Exit Interview At the conclusion of the inspection the inspector held a meeting (see paragraph 1 for attendees) to discuss the inspection scope and findings.
The items of noncompliance and unresolved items were identified.
The licensee also discussed certain independent actions being taken to pre-clude an accident similar to TMI-2 from occurring or minimizing the con-sequences if it did occur.
Specifically, simulator training is to be geared towards emergencies rather than routine operations, licensed operators and senior operators are to be evaluated to determine areas where performance must be improved, a tape recording machine is to be installed in the control room so that events can be reconstructed, and a procedure is being developed for a metal / water reaction without a pipe break.
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