IR 05000334/1979017
| ML19262A684 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 09/21/1979 |
| From: | Beckman D, Keimig R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19262A674 | List: |
| References | |
| 50-334-79-17, NUDOCS 7912100253 | |
| Download: ML19262A684 (20) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region T Report No. 50-334/79-17 Docket No. 50-334 License No. DPR-66 Priority
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Category r
Licensee:
Duauesne Licht Comoany 435 Sixth Avenue Pittsburah, Pennsylvania 15219 Facility Name:
Beaver Valley Power Statinn Unit 1 Inspection at:
Shippingport, Pennsylvania r
Inspection condu te :
ust 20-24, 1979 Inspectors:
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A t t cm
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k-26-79 D.
. 'B ekman, Reactor Inspector date signed i S.
Wlach; 9-7 /- 77
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R.
S.. Markowski, Reactor Inspecter date signed date sign d
/-)/ 7I Approved by:
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41. R. Ke'imig,' Chief, Reactor Projects Section date Aigned No. 1, RO&NS Branch Inspection Summary:
Inspection on August 20-24,1979 (Report No. 50-334/79-17)
Areas Inspected:
Routine, unannounced inspection of licensee action on previous inspection findings, review of plant startup documentation, verification of valve / breaker / switch alignments for ESF components, review of surveillarce test i
results for ESF components, and review of a plant transient.
The instection involved 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> onsite by two NRC regional based inspectors.
Results:
Of the five areas inspected, no items of noncompliance were identified in three areas, three items of noncompliance were identified in the remaining two areas (Infraction - Failure to follow procedures, Paragraphs 3 and 5; Infrac-cion - Use of heating torch withcut approved procedure, Paragraph 4; and, Infrac-tion - Use of vibration measurement equipment with expired calibration, Paragraph 4).
1527 167 Region I Form 12 (Rev. April 77)
7912100 h
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I DETAILS, 1.
Persons Contacted
- F. Arnold, Construction Specialist
- G. Beatty, QA Engineer
- R. Balcerek, Maintenance Supervisor
- J. Carey, Technical Assistant - Nuclear
- R. Conrad, Senior Engineer D. Crouch, Shift Supervisor
- C. Ewing, QA Supervisor K. Grada, Shift Supervisor
- R. Hansen, NSQC Engineer
- L. Hutchinson, Station QA
- F. Lipchick, Station QA
- R. Mafrice, Supervisor - Onsite Engineering Group
- A. Mazukna, QC Supervisor
- G. Moore, General Superintendent, Power Stations Department
- R. Prokopovich, Reactor Engineer
- L. Schad, Operations Supervisor D. Schultz, Shift Supervisor
- J. Starr, Station Engineer
- H. Van Wassen, Project Manager (Part time attendance)
- D.
Williams, Results Coordinator
- H. Williams, Chief Engineer
- E. Woolever, Vice President, Engineering and Construction (Part time attendance)
The inspectors also interviewed other licensee representatives during the inspection including members of the operations, maintenance, engineering, and general office staffs.
- denotes those present at the exit interview.
2.
Licensee Action on Previous Inspection Findings (. Closed) Unresolved Item (79-04-03):
Maintenance of suitable environmental conditions in Auxiliary Feed Pump Room.
Since identification by the inspec-tor of the steam in-leakage to the room causing adverse environmental condf + ions, the licensee has taken action as discussed in IE Inspection Report No. 50-334/79-16.
During this inspection, the inspector toured the area several times while the plant was at power and confirmed that the actions taken by the licensee were successful in eliminating the release of steam to the room.
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(Closed) Unresolved Items (79-16-05, 06, 07, and 11):
Licensee to submit supplemental reports to the following Licensee Event Reports, prior to plant startup, detailing corrective actions taken or justification for return to operation:
LER 79-08, Potential for Error in Analysis for Single Dropped Rod; LER 79-10, Potential for Failure of Inside Recirculation Spray Pump Motors; LER 79-14, Steam Generator Nozzle to Feedwater Piping Weld Cracking; LER 79-15, Possible Steam Generator Level Instrument Error from High Energy Line Break Inside Containment; and, LER 79-16, Incorrect Routing of Motor Operated Valve Power Cable.
The above supplemental reports were received and reviewed by NRC:RI prior to the unit's return to power.
(. Closed) Unresolved Item (79-16-03):
Licensee to submit supplemental report to Licensee Event Report 79-09, Failure of Diesel Generator Output Breaker to Close. The actions taken to identify and correct the malfunctions of diesel generator breakers had been reported to NRC:RI via telephone and were subsequently documented in LER 79-23/03L, of the same subject, issued on August 23, 1979. The continued acceptability of diesel generator opera-bility will be reviewed as part of Unresolved Item 79-16-04, as documented in IE Inspection Report No. 334/79-16.
3.
Review of Plant Startuo a.
During the period of March 13 through August 12, 1979, the plant was maintained in a cold shutdown condition pursuant to the NRC Show Cause Order regarding seismic piping design deficiencies.
The Order was rescinded on an interim basis on August 8,1979, and the plant was returned to power operation on August 17, 1979.
The inspectors reviewed the completed plant startup procedures listed below in order to deter-mine that:
The appropriate procedures were available and properly completed.
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Applicable Technical Specifications were satisfied (reviewed on a
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sampling basis).
Systems disturbed during the outage were returned to service and
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tested in accordance with approved procedures.
The provisions of the BVPS Operating Manual, Section 1.48.9.N,
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Station Startup After Extended Outage, Testing, and Maintenance, had been implemented.
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The following procedures of the BVPS Operating Manual (0M) were reviewed:
OM Section 1.50.3, Startup Checklist A To Be Completed for Cold
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Shutdown (Mode 5) Conditions, Revision 5, completed August 11, 1979.
0M Section 1.50.3, Startup Checklist B To Be Comp (Mode 4), Revision leted When
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Leaving Cold Shutdown (Mode 5) for Hot Shutdown 5, completed August 13, 1979.
OM Section 1.50.3, Startup Checklist C To Be Completed When
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Leaving Het Shutdown (Mode 4) Conditons for Hot Standby (Mode 3),
Revision E, completed August 16, 1979.
OM Section 1.50.3, Startup Checklist D To Be Completed When
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Leaving Hot Standby (Mode 3) To Go Critical (Mode 2), Revision 7, completed August 16, 1979.
OM Section 1.50.3, Startup Checklist F - Turbine Plant Startup
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with the Reactor Plant in the Startup Mode (Mode 2), Revision 5, completed August 17, 1979.
OM Section 1.50.4.A, Instructions Before Exceeding Cold Shutdown
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Conditions, Revision 14, completed August 11, 1979.
OM Section 1.50.4.B, Instructions to Heatup Primary 31 ant from
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Cold Shutdown (Mode 5) to Hot Shutdown (Mode 4), Revision 16, completed August 12, 1979.
OM Section 1.50.4.C, Instructions to Heatup Plant from Hot Shutdown
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(Mode 4) to Hot Standby (Mode 3), Revision 14, completed August 16, 1979.
OM Section 1.50.4.D, Reactor Startup from Hot Standby to the
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Startup Mode (Mode 2), Revision 7, completed August 17, 1979.
OM Section 1.50.4.E, Turbine Plant Startup from Ambient Conditions
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to Hot Shutdown Conditions, Revision 7, completed August 12, 1979.
OM Section 1.50.4.F, Estimated Critical Position Calculation for
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Xenon Free Condition, Revision 8, incomplete.
Following the station's initial return to power on August 17, a feed-water system transient resulted in a reactor trip on Augu t 19, 1979, as discussed in Paragraph 6 of this report. The inspectors also reviewed the following completed procedures which were associated with that trip and recovery:
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OM Section 1.51.4.A, Station Shutdown - Minimim Load to Startup
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Mode or Hot Standby Mode, Revision 8, completed August 19, 1979.
OM Section 1.50.4.F, Estimated Critical Position Calculation for
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Xenon Free Condition, Revision 8, incomplete.
OM Section 1.50.4.J, Station Startup - Recovery from Reactor
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Trip, Revision 9, completed August 19, 1979.
b.
During the reviews discussed above, the inspector detennined that the ECP-1 Forms for the estimated critical position (ECP) calculations of OM Section 1.50.4.F had not been properly completed for both reactor startups (August 17 and 19,1979).
The only portions of the forms completed were Item A (Critical Data), Item B (Reactivity Balance),
and Item C (Boron Concentration).
Item D (Rod Limits), Item E (Shutdown Margin Verification), Item F (Estimated Critical Position by Count Doubling), and the preparer's and reviewer's signature blocks were incomplete on both sets of forms.
Because Item E, Shutdown Margin Verification, had not been completed for either startup, the inspector reviewed copies of Operating Surveil-lance Test 1.49.2, Shutdown Margin Calculation, which had been completed during the respective startups.
These procedures were reviewed in order to determine that Technical Specification 4.1.1.1.1 had been satisfied for performance of a shutdown margin calculation during startup rod withdrawal. The calculation for August 17, 1979 was confirmed as satisfactory.
The calculatior. for August 19, 1979, however, had been properly completed but had not been reviewed by the Shift Supervisor as of August 24, 1979.
Failure to properly complete ECP calculations is contrary to Technical Specification 6.8.1.a Regulatory Guide 1.33, Appendix A; and, the BVPS Operating Manual Section 1.50.3, Checklist D, which requires calculation of the ECP during reactor startup in accordance with the referenced procedure.
Failure of the Shift Supervisor to review the results of OST 1.49.2 is contrary to Technical Specification 6.8.1.c and the BVPS OM Section 1.55.A.1, which requires the Shift Supervisor to review surveillance tests within twenty four hours of completion for proper performance and documentation.
These findings, in conjunc-tion with a third example discussed in Paragraph 5.b. of this report, are examples of failure to properly implement procedures and constitute n. item of noncompliance at the infraction level (79-17-01).
c.
During review of OM Section 1.50.3, Checklist B, the inspector noted that the procedure contained references to Main Steam Valve Cubicle 1527 171
rupture discs which have been removed as part of Design Change No.
139. The licensee informed the inspector that the procedure changes for Section 1.50 and Section 1.45 of the OM are in progress but not yet issued. The inspector determined that the absence of these proce-dure changes had no direct bearing on the safety of operation and could be processed on a routine basis. The licensee stated that revision of Operating Manual sections which refer to the rupture disc will be completed prior to startup from the upcoming refueling outage.
.This item will remain unresolved pending NRC:RI review of these licensee actions (79-17-02).
d.
OM Section 1.50.3, Checklist C, Step 5, requires verification of Safety Injection Accumulator water inventory and pressure and provides the associated acceptance criteria.
The inspector observed that the procedure step had been annotated by the SMft Supervisor to indicate that the procedure's acceptance criteria required revision to comply with new Technical Specification requirements for accumulator water inventory and pressure issued as part of License Amendment No. 17 on March 27, 1979. The inspector confirmed that the measured values of the parameters had complied with the current Technical Specification requirements. The inspector further confimed that the document of record for compliance was Operator Log L5 which had been revised to reflect the proper acceptance criteria. The licensee stated that the appropriate procedure revisions would be completed prior to the next planned use of OM Section 1.50.3 during recovery from the upcoming refueling outage. This item will remain unresolved pending NRC:RI review of the licensee's actions (79-17-03).
e.
OM Section 1.50.4.F, Estimated Critical Position Calculation, Revision 7, refers the use of OM Section 1.49.4.M, Reference Guide for Estimated Critical Position, Revision 8, as a source for additional guidance in completing the ECP calculation.
The reference guide information is not consistent with the tabular fomat of the form used for the ECP calculation due to a recent revision of the form.
The licensee stated that the material in OM Section 1.49.4.M would be revised by September 24, 1979, to eliminate the inconsistencies.
This matter will remain unresolved pending NRC:RI review of the licensee's actions (79-17-04).
Excepi. as noted above, the inspectors had no further cuestions concerning the review of plant startup.
4.
Review of Surveillance Tests for Engineered Safety Features (ESF)
a.
The inspectors reviewed the most recently completed Onerating Surveil-lance Test results for the ESF equipment and selected safety related
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7 equipment as noted below.
The tests were reviewed to detennine that acceptance criteria had been met, discrepancies had been identified and corrected, and that the documentation reflected test performance in accordance with procedural requirements.
Refer to IE Inspection Report No. 50-334/79-09 for discussion of the review of other surveil-lance tescs which similarly effect ESF operability.
Operating Suveillance Test Number Title Date of Performance 1.1.3 Containment Isolation Trip Test, November 25, 1978 CIA, Train A, Revision 2 1.1.4 Containment Isolation Trip Test, November 26, 1978 CIA, Train B, Revision 2 1.1.5 Containment Isolation Trip Test, November 26, 1978 CIB, Train A, Revision 11 1.1.6 Containment Isolation Trip Test, December 3, 1978 CIB, Train B, Revision 11 1.1.7 Manual Reactor Trip Test, Issue 1 August 19, 1979 1.7.1 Boric Acid Transfer Pump Opera-August 20, 1979 tional Test, Revision 7 1.7.2 Boric Acid Transfer Pump Opera-August 16, 1979 tional Test, Revision 7 1.7.4 Centrifugal Charging Pump Test August 16, 1979 (1-CH-P-1A), Revision 11 1.7.5 Centrifugal Charging Pump Test August 10, 1979 (1-CH-P-1B), Revision 11 1.7.8 BA Storage Tanks and RWST Level August 16, 1979 and Temperature Verification, Revision 10 1.7.9 Centrifugal Charging Pump Test August 7, 1979 (1-CH-P-1C), Revision 10 1.7.11 CHS and SIS Operability Test, April 5,1979 Revision 4 1527 173
1.11.1 Safety Injection Pump Test (1-SI-August 11, 1979 P-1A), Revision 18 1.11.2 Safety Injection Pump Test (1-SI-August 11, 1979 P-1B), Revision 18 1.11.3 Boron Injection Flowpath Test, July 30, 1979 Revision 18 1.11.4 Accumulator Check Valve Test, August 15, 1979 Revision 17 1.11.6 ECCS Flow Path and Valve Position August 11, 1979 Check (Loop A), Revision 16 1.11.7 ECCS Flow Path and Valve Position August 6, 1979 Check (Loop B), Revision 19 1.11.9 Accumulator Isolation Valves August 14, 1979 Breakers Alignment Verifications, Revision 5 1.11.10 Boron Injection Flow Path and August 14, 1979 ECCS Subsystem Valve Exercise, Revision 18 1.11.11 Accumulator Isolation Valves August 14, 1979 Auto Open Test, Revision 17 1.11.13 Boron Injection Surge Tank Level August 12, 1979 Verification, Revision 13 1.13.1 1A Quench Pump Flow Test, Revi-August 11, 1979 sion 11 1.13.2 1B Quench Pump Flow Test, Revi-August 4, 1979 sion 11 1.13.3 1 A Recirculation Pump Dry Test, August 6, 1979 Revision 9 1.13.4 1B Recirculation Pump Dry Test, August 18, 1979 Revision 9 1527 174
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1.13.5 2A Recirculation Pump Dry Test, August 6, 1979 Revision 12 1.13.6 2B Recirculation Pump Dry Test, August 11, 1979 Revision 12 1.13.7 Recirculation Pumps Auto Spray August 13, 1979 and Flow Test, Revision 1 1.13.8 Conthinment Depressurization August 1, 1979 System MOV's Exercise, Train A, Revision 10 1.13.9 Containment Depressurization August 16, 1979 System M0V's Exercise, Train B, Revision 12 1.13.10 Spray Additive System Valve August 16, 1979 Position and Operability Check, Revision 12 1.13.11 Quench Spray System Operability June 14,1979 Test, Revision 3 1.15.1 RP Component Cooling Water Pump August 10, 1979 1A Test, Revision 7 1.15.3 RP Component Cooling Water Pump August 13, 1979 1C Test, Revision 7 1.16.1 SLCRS Exhaust Fans and Remote August 11, 1979 Damper Com onent Test, Revision 3 (Train A 1.16.2 SLCRS Exhaust Fans and Remote August 10, 1979 Damper Com onent Test, Revision 5 (Train B 1.16.3 SLCRS Exhaust Fans and Remote March 28, 1979 Damper Component Test, Revision
1.21.4 MS Trip Valve 101A Full Closure August 15, 1979 Test, Revision 2 1527 175
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1.21.5 MS Trip Valve 101B Full Closure August 14, 1979 Test, Revision 2 1.21.6 MS Trip Valve 101C Full Closure August 15, 1979 Test, Revision 2 1.24.1 Motor Driven Auxiliary Feed August 12, 1979 Pump Discharge Valves Exercise, Revision 3 1.'24.2 Motor Driven Auxiliary Feed August 7,1979 Pump 3A Test, Revision 10 1.24.3 Motor Driven Auxiliary Feed August 18, 1979 Pump 3B Test, Revision 10 1.24.4 Steam Driven Auxiliary Feed August 14, 1979 Pump Test, Revision 9 1.24.5 S-G Auxiliary Feed Pumps Oper-August 15, 1979 ability Test, Revision 8 (Tur-bine Driven Pump Data Only)
1.30.lA Auxiliary River Water Pump 9A August 10, 1979 Test, Revision 12 1.30.lB Auxiliary River Water Pump 9B August 10, 1979 Test, Revision 12 1.30.2 River Water Pump 1A Test, Revi-August 1, 1979 sion 16 1.30.3 River Water Pump 18 Test, Revi-July 31, 1979 sion 16 1.30.4 River Water System Valve Test for August 11, 1979 A Header, Revision 14 1.30.5 River Water System Valve Test for August 3, 1979 B Header, Revision 14 1.30.6 River Water Pump 1C Test, Revi-August 13, 1979 sion 16 1527 176
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1.30.8 Auxiliary River Water System August 10, 1979 Test, Revision 5 1.36.1 Diesel Generator No.1 Monthly July 31, 1979 Test, Revision 12 1.36.2 Diesel Generator No. 2 Monthly July 25, 1979 Test, Revision 12 1.36.3 Diesel Generator No. 1 Automatic August 7, 1979 Test, Revision 12 1.36.4 Diesel Generator No. 2 Automatic August 9, 1979 Test, Revision 12 The surveillance tests not reviewed during this inspection or IE Inspection No. 50-334/79-09, will be reviewed during a future inspec-tion.
b.
During review of OST 1.24.5, Steam Generator Auxiliary Feedwater Pumps Operability Test, the inspector noted that data was available for only the Steam Driven Auxiliary Feedwater Pump.
The licensee stated that the data for the portions of the test associated with the Motor Driven Auxiliary Feedwater Pumps was in routing for review.
The data was not available for inspector review during the inspection.
The inspector noted that the test had not exceeded its due date in accordance with the Technical Specification surveillance frequency requirements and informed the licensee that this matter would remain unresolved pending NRC:RI review during a future inspection (79-17-05).
c.
During review of surveillance test documentation, the inspector noted several instances in which OST procedures, written for performance during power operation, were conducted to satisfy Technical Specification Surveillance requirements for operation in Modes 1-4 prior to entering those modes. The inspector noted that the tests had been satisfactorily accomplished with respect to their acceptance criteria but, due to the system alignments required for cold shutdown operations, the procedures had been annotated to indicate that the return to service equipment alignments specified by the OST's for power operation had not been performed.
Rather, the systems had been realigned in accordance with the applicable portions of the OM Section 1.51, Station Shutdown Procedures, at the direction of the Shift Supervisor.
The inspector confirmed, on a sampling basis, that the system realignments had met the requirements of OM Section 1.51 for cold shutdown operations and that the affected equipment had subsequently been aligned for operation in Modes 1-4 prior to entering each respective mode.
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ANSI N18.7-1972, Administrative Controls for Nuclear Power Plants, Section 5.5.2, states that, for temporary changes to procedures that may involve a change in the intent for an approved procedure, the person authorized to approve the change shall be, in most cases, at a higher level of plant management than the pers7n whose designated function includes shift supervisory responsibility for the safe operation of the plant. The inspector informed the licensee that a change or deviation to the specified return to service system conditions appaars to constitute a change to the intent of the procedure and therefore, should have been the subject of a temporary procedure change.
In that the actual realignment of the system had been controlled by a properly approved procedure other than the test procedure and all deviations had been documented, the inspector did not consider the Shift Supervisor's actions to constitute noncompliance with the aquirement stated above.
The inspector informed the licensee that additional guidance for operations personnel appeared neces.sary to ensure that deviations were not made to the return to service provisions of any safety related procedure without due consideration of the intent of the procedure and the need for temporary or permanent precedure changes.
The licensee acknowledged the inspector's comments and stated that additional guidance would be included in the Operating Manual.
This matter will remain unresolved p(ending NRC:RI review of the licensee's actions during a future inspection 79-17-06).
d.
During review of OST 1.11.1 on August 22, 1979, the inspector noted that the procedure was annotated to indicate that valve 1-SI-29, the 1A Low Head Safety Injection (LHSI) Pump Minimum Flow Line Check Valve, had been heated ar.d struck with a hamer on August 11, 1979, to free a stuck valve disc.
Discussion with the personnel involved revealed that the velve body had been heated with an oxy-acetylene torch equipped with a " rose-bud" heating tip t.ntil the valve-to-piping weld joints were tou hot for contact with bare skin.
The two inch check valve, located in the LHSI mini flow line, is constructed of austenitic stainless steel and is normally NU.ed internally with borated water from the Refueling Water Storage Tank.
Flow apparently existed through the valve during the heating process but the line was subsequently drained during valve cooling.
The valve was allowed to cool to ambient conditions, apparently without any forced cooling being provided.
Based on the possibilities of newly induced thermal stresses and/or sensitization of the valve metal which could affect valve integrity, the inspector requested the licensee to evaluate the consequences of the actions above.
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Engineering Memorandum (EM) No. 20210 was immediately issued by the station, requesting DLC Engineering to evaluate the circumstances and possible effects of the above. The evaluation documented on the EM by DLC Engineering on August 23, 1979, states that the valve and connected piping had not incurred any damage of immediate concern.
A heat transfer analysis of the valve body, internals, and connecting piping indicated that the temperature of the assembly had not exceeded 7500F during an approximate four minute heat exposure.
On that basis, the thermal transient did not generate significant residual * tresses or metal sensitization.
Since the valve was freed, the EM c m ludes that warpage of the internals does not appear to be a problem.
The EM recommends that the valve be inspected during the next refueling outage and replaced if necessary.
Discussion with station personnel indicated that the valve will be scheduled for replacement.
The inspector had no futher questions regarding potential damage to the valve.
Heating of the valve was conducted without benefit of an approved procedure.
Performance of operating and maintenance activities which affect the QA Category I (safety related) system, structures, and components without the use of a properly approved procedure is contrary to 10 CFR 50, Appendix B, Criterion V; the BVPS FSAR, Appendix A, Quality Assurance Program, Section A.22.5, Instructions, Procedures, and Drawings; ANSI N18.7-1972, Administrative Control for Nuclear Power Plants; and, Station Administrative Directive No. 8, Issue 2,
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and constitutes an item of noncompliance at the infraction level (79-17-07).
e.
During review of completed OST's, the inspector noted that a number of the tests performed to satisfy ASME Code,Section IX, requirements for inservice testing of pumps were annotated to indicate that the tests had been performed utilizing a portable vibration monitor which had exceeded its specified June 1,1979 due date for routine calibration.
Instrument No. I-D-191-2 had been identified by the licensee on or before August 6,1979, as being beyond its calibration interval as documented on OST 1.30.2, lA Reactor Plant River Water Pump test, performed on August 1,1979.
The inspector determined that, since the date of identification by the licensee, the nonconforming instrument had been used to complete at least 16 tests of ESF equipment required by the facility's 10 CFR 50.55(a) inservice testing program, although no evaluation or proposed corrective action for the nonconforming instrument had been documented or implemented. The instrument had additionally been use for that testing completed between June 1 and the time of licensee identification.
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The licensee's stated intentions were to continue use of the instrument after identification due to the unavailability of a replacement unit.
The licensee had planned to have the nonconforming unit calibrated as socn as a replacement was available and utilize the "as found" data from that calibration to evaluate the test data taken after June 1.
Upon identification of this matter by the inspector, the licensee imediate'y obtained a properly calibrated replacement instrument for future t.se.
The nonconforming instrument was shipped, on an expedited basis, to the instrument vendor for calibration and documentation of the "as found" calibration data. The inspector reviewed the data obtained using the instrument during the past sixth month period and determined that all readings taken with the instrument before and after its calibration due date appeared to be consistent, with no apparent aberrstions in its performance.
Comparison of data taken on tha same equipment with the nonconfonning instrument and a properly calibrated instrument displayed a minimal deviation which appeared to be less than that necessary to place any of the reviewed data out of specification.
On August 31, 1979, during a telephone conversation between Mr. D.
Beckman of this office and Mr. R. Balcerek of your staff, Mr. Beckman was informed that the "as found" calibration data for the instrument indicates an instrument error of + 4.5% of span versus an allowable error of + 3% of span.
Preliminary licensee review of test data obtained with the instrument has indicated that, including consideration for the instrument error, no equipment vibration is in cither the Alert or Required Action Ranges described by the ASMF Code,Section XI, or the licensee's procedures.
Mr. Balcerek stated that the review was continuing and that any test data discrepancies would be documented and~ appropriate corrective action taken.
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Using measuring and test equipment which has passed its calibration date is contrary to 10 CFR 50, Appendix B, Criterion XII; the BVPS FSAR, Appendix A, Quality Assurance Program, Section A.2.2.12; QA Procedure OP-12, Control and Measuring and Test Equipment, Revision 2; and Station Administrative Directive No. 7, Control of Measuring and Testing Equipment, Issue 1, and constitutes an item of noncompliance at the infraction level (79-17-08).
5.
Valve, ?reaker, and Switch Alignment Verification a.
At various times during this inspection, the inspectors directly observed the valve, breaker, and switch alignments for Engineering Safety Feature (ESF) systems and components in order to verify that 1527 180
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the alignments were in accordance with the licensee's alignment proce-dures and that the alignments resulted in the systems being operable for accident response.
The procedures used by the inspectors were reviewed previously for adequacy as discussed in IE Inspection Report No. 50-334/79-09. The inspectors utilized the procedures listed below, appropriate sections of Operating Surveillance Tests listed in Paragraph 4 of this report, and controlled copies of the respective systems' flow diagrams for this verification.
System alignments were verified by direct observation of valve, breaker, or switch positions, control board position indications, and/or control board process instrumentation. As a minimum, each system alignment inspected was verified to be proper and adequate for accident operation.
The BVPS Operating Manual (OM) includes chapters addressing each system's description; setpoints, limitations, and precautions; norma',
system arrangement; operating procedures; and alarm response instructions.
The inspectors utilized those portions of Section 3 of each chapter which provide the normal system arrangement valve alignment and powr.r supply and control switch alignment lists.
. nly those portions of the
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systems which affected operability of ESF equipment were verified.
The following OM Sections were utilized for the systems listed:
0M 'ection System 1.3 Reactor Control anC /rotection 7.3 Chemical and Volume Control System 11.3 Safety Injection 13.3 Containment Depressurization 16.3 Supplementary Leak Collection and Release 24.3 Steam Generator Feedwater (Auxiliary Feedwater and Feedwater Isolation Portions Only)
30.3 River Water (including Auxiliary River Water)
36.3 4KV Station Service (including Diesel Generators)
37,3 480 VAC Station Service 38.3 120 VAC Distribution and Lighting 1527 181
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38.3 125 VDC Control 45.3 Miscellaneous Safety Related Systems 46.3 Post DBA Hydrogen Control b.
The inspectors also verified that all valves in the Auxiliary Feedwater System identified by the licensee as requiring locking were actually locked. The inspectors verified, on a sampling basis, that valves in other ESF systems requiring similar control were also locked.
These systems included the Safety Injection, CVCS, River Water, Containment Depressurization, and Post DBA Hydrogen Control Systems. Valves requiring locking are identified by the normal system arrangement valve lists of each OM chapter and/or the Padlock Log (which is admini-stered in accordance with OM Section 1.48.5.C, Lockout, Revision 3).
The inspectors determined that the following valves were properly positioned for operation but were not lec' ed in those positions as r
required by the normal system arrangement valve lists or the Padlock Log:
1-CH-26, Charging Pump 1B Charging Header Isolation Valve.
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1-RW-98, Unit 1-Unit 2 River Water Pump Bearing Seal Water Cross
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Connect Valve.
1-FW-57, FW-P-3A (Motor Driven Auxiliary Feed Pump) Recirculation
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Line Isolation Valve.
Failure to implement established controls for equipment locking is contrary to Technical Specification 6.8.1.a; Regulatory Guide 1.33, Appendix A; and the BVP5 OM Sections 1.48.5.C.2. 1.7.3, 1.24.3, and 1.30.3; and, constitutes a further example of noncompliance at the infraction level as discussed in Paragraph 3 of this report (79-17-01).
c.
During the valve lineup verifications and review of Operating Surveil-lance Tetts discussed in Paragraph 4, the inspectors noted that Charging Pump 1A had been replaced shortly before plant startup with a newer model pump.
The replacement pump did not require reconnection of seal water service lines which previously served the original pump and these lines had been disconnected and blanked. The normal system arrangement valve list of OM Section 1.7.3 and the applicable Operating Surveillance Tests still contained, at the time of this inspe: tion, reference to valves on the disconnected seal water lines.
The licensee stated that refernce to these lines would be deleted from the appli-1527 182
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cable procedures in the near future.
The inspector determined that the revisions could be issued on a routine basis due to the conditions described above.
This matter will remain unresolved pending NRC:RI review of the licensee's actions (79-17-09).
Except as noted above, the inspectors had no further questions concerning ESF system alignments.
6.
Review of Plant Transient (Licensee Event Report 79-26/0lP)
A manual reactor trip followed by loss of all RCS flow occurred on August 19, 1979, as described by the subject Licensee Event Report.
The inspector reviewed the circumstances surrounding the transient in order to determine that:
The reporting requirements of Technical Specifications and applicable
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Station Administrative Directives had been met.
Corrective action has been or is being taken and is appropriate to
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correct the cause of the event.
The event has been reviewed by the licensee as required by Technical
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Specifications and applicable Station Administrative Directives.
The event did not involve operation of the facility in a manner which
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constitutes an unreviewed safety question pursuant to 10 CFR 50.59.
The event was reviewed to identify generic implementations or recurrence
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of a previous event.
The report was ciearly and accurately prepared.
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The review of this event included inspector interviews of operating personnel, review of facility records including computer logs, main control board recorder charts, operator logs, and discussion with facility management.
The results of these reviews are discussed below.
On August 19, 1979, the plant was operating at approximately 50% power.
One condensate pump was in operation with the redundant condensate pomp out of service for suction strainer cleaning.
The 1 A Main Feed Pumo was operating with the 1B Main Feed Pump available. The operating main feed pump had been returned to service following maintenance and was experiencinq a rapid increase in motor bearing temperatures.
The feed pump minimum flow recir-culation valve controls from the lA Main Feed Pump had been disabled to optimize operation at 50% power with only one condensate pump in operation.
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With normal main feed pump recirculation in service, the single operating condensate pump would have been unable to satisfy the main feed pump net position suction head (NPSH) requirements at the necessary feed rate. The 18 Main Feed Pump recirculation controls had not been disabled.
At approximately 1442 hours0.0167 days <br />0.401 hours <br />0.00238 weeks <br />5.48681e-4 months <br /> on August 19, shift supervision determined that the 1A Main Feed Pump bearing temperature increase required imediate pump shutdown to prevent pump damage and the 1B Main Feed Pump was started in parallel with the 1A Pump. Approximately 1 minute later, the 1A Pump was stopped by the operator. With the 1B Main Feed Pump operating, one of the main feed pump minimum feed recirculation valves opened, diverting approx-imately 4000 gpm from the feed pump discharge to the condenser.
The increase in total feedwater flow now necessary to maintain the operating Steam Generator levels and recirculation flow resulted in a low NPSH condition at the feed pump suction with attendant alarms.
This condition continued for approximately four minutes (until 1446 hours0.0167 days <br />0.402 hours <br />0.00239 weeks <br />5.50203e-4 months <br />). At that time, a sustained low NPSH condition satisfied the main feed pump low NPSH trip circuit and the only operating main feed pump tripped.
The operator, recognizing the condition as a nonrecoverable loss of normal feedwater, manually tripped the reactor approximately seven seconds following the loss of the main feed pump. This action was appropriate to the circum-stances and in accordance with the applicable procedures. The manual reactor trip directly initiates a turbine trip which removes the turbine's steam supply. The generator nonnally remains electrically connected to the 345KV offsite busses via the main transfonner and two parallel output breakers for approximately thirty seconds.
This allows a coastdown period during which the generator is motorized and the 345KV offsite power supplies the 4KV Unit Station Service loads by backfeeding through the main trans-former. At approximately thirty seconds following a turbine t-ip, a timer would normally open the generator output breakers and automatically initiate a fast transfer to station 4KV loads from the generator output to offsite 138KV/4KV System Station Service supplies.
The normal sequence of bus transfers described above was not allowed to occur during this transient.
The Shift Operating Foreman directing control room operations observed the normal reactor trip and turbine trip but felt that the automatic bus transfer had not occurred at 30 secor.ds as expected.
As a result of the Shift Operating Foreman's concern about extended motoriz-ation of the main generator, he directed that the generator output breakers
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be tripped manually. This occurred approximately eight seconds following the turbine trip and resulted in the main generator, which was no longer motorized and was decelerating, to assume the station's 4KV loads.
This resulted in causing all RCP's to trip on underfrequency approximately 26 seconds after the reactor and turbine trips.
The 1C RCP was restarted to reestablish RCS flow approximately four minutes later.
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Review cf plant records indicates that the plant response to the trip and loss of flow was as expected. These included:
Normal initiation of auxiliary feedwater due to post-trip low-low
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steam generator level.
Feedwater isolation on P-4 (Reactor Trip + Low T-Ave).
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Completion of the 4KV Bus Automatic fast trarc.fer (at 29 seconds post-
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trip).
Intermittent Main Steam Dump Valve actuation.
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Although 4KV frequency apparently dropped low enough to result in RCP
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underfrequency trips, no evidence exists to indicate that 4KV bus voltage degraded sufficiently to require Emergency Diesel Generator operation prior to the 4KV bus transfer.
None of several redundant computer data inputs for low voltage annunciation were observed.
Review of coolant Iodine analyses required by Technical Specification -- 4.4.8 following the trip indicate no abnormal increase in coolant Iodine activity as a result of the trip or loss of flow.
Although incore thermocouple data was unavailable for the period
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during which no RCS Flow existed, coolant pressure was maintained above 2100 psig throughout the event with normal pressurizer level and RCS Loop temperatures displayed.
While RCS Loop temperatures are nonrepresentative without RCP Flow, the plant response appeared normal upon restart of the RCP's.
The facility returned to power operation without further incident on August 20, 1979. At the close of this inspection, the licensee was considering the corrective actions to be taken. All licensed operators on shift had been briefed on the circumstances of the above incident including emphasis on the need to not override or bypass automatic plant functions.
Review of the transient with regard to the licensee's procedures for loss of feedwater and reactor trip indicated that the trip and recovery operations
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were conducted in accordance with the BVPS Operating Manual requirements.
I The only apparent deviation to those requirements involved the premature manual tripping of the main generator output breakers.
This operator error appears to be the proximate cause of the loss of RCS Flow.
The inspector's review of those circumstances indicated that the operator misjudged the time elapsed from the turbine trip and proceeded with the manual actions specified by the procedure for transferring electrical supplies on the 1527 185
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basis that the anticipated automatic actions had not occurred.
The licensee stated that all onshift operations personnel have been made aware of the specific circumstances discussed above as well as the fact that automatic bus transfer will not occur simultaneously with manual tripping of canerator output breakers.
No items of noncompliance were identified.
Completion of the licensee's corrective action and the supplemental report associated with the Licensee Event Report will be reviewed during a future inspection (79-17-10).
7.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are items of noncompliance, deviations, or acceptable items. Unresolved items resulting from this inspection are discussed in Paragraphs 3, 4, 5, and 6.
8.
Exit Interview A management meeting was held with licensee representatives (attendees noted in Paragraph 1) at the close of this inspection on August 24, 1975.
The scope and findings of the inspection as discussed in this report were presented.
During a subsequent telephone conversation between Mr. D. Beckman of this office and Mr. R. Balcerek of the licensee's staff, the information contained in Paragraph 4.d. of this report was discussed.
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