IR 05000334/1979009
| ML19209B457 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 08/09/1979 |
| From: | Beckman D, Keimig R, Markowski R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19209B445 | List: |
| References | |
| 50-334-79-09, 50-334-79-9, NUDOCS 7910090754 | |
| Download: ML19209B457 (26) | |
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U.S. NUCLEAR REGULATORY C0ffilSSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 50-334/79-09 Docket No. 50-334 License No. DPR-66 Priority:
Category:
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Licensee:
Duquesne Light Company 435 Sixth Avenue Pittsburgh, Pennsylvania 15219 Facility Name:
Beaver Valley Power Station, Unit 1 Inspection at: Shippingport, Pennsylvania Inspectionconduted:ppri lb-24,1979 Inspectors:
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W Ai kckma~n, Reactor Inspector date signed b
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R. S. Markowski, Reactor Inspector date signed ON LU -
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C. d. Co gih 1, Reactor Inspector date signe~d Approved by:
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. R.'Keim
' Chief dpesigned Reactor Pr cts S ion No. 1, RO&NS Branch Inspection Summary:
Inspection on April 16-24,1979 (Recort No. 50-334/79-09 Areas Inspected: Routine announced inspection by regional based inspectors of actions taken by the licensee in response to the nuclear incident at Three Mile Island; to verify compliance with facility technical specifications for the existing plant conditions; and, to assure that factors contributing to the incident at Three Mile Island do not exist at the Beaver Valley Power Station, Unit 1.
The inspection involved 181 hours0.00209 days <br />0.0503 hours <br />2.992725e-4 weeks <br />6.88705e-5 months <br />.on site by three regional based inspectors.
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Results:
No items of noncompliance were identified in two of the three creas inspected. One item of noncompliance was identified in the third area (Infraction, failure to perform surveillance testing, Detail 7)
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Persons Contacted Principal Licensee Representatives R. Balcerek, Maintenance Supervisor
- G. Beatty, QA Engineer
- J. Carey, Technical Assistant-Nuclear R. Conrad, Senior Engineer D. Crouch, Shift Supervisor R. Druga, Nuclear, Shift Operating Foreman
- K. Grada, Shift Supervisor R. Hanson, QC Engineer
- L. Hutchinson, Station QA
- L. Xorak, Personnel Records Assistant E. Kurtz, Sr. QA Engineer
- F. Lipchick, Station QA J. Maracek, Reactor Engineer
- W. Marquardt, Administrative Supervisor
- S. Prokopovich, Reactor Engineer
- L. Schad, Operations Supervisor
- J. Werling, Station Superintedent D. Williams, Results Coordinator
- H. Williams, Chief Engineer The inspectors also held discussions with and interviewed other members of the plant staff during the inspection.
- denotes those present at the exit interview held on April 24, 1979
- denotes those present at an exit interview on April 23, 1979
- denotes those present at both meetings above.
2.
Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (78-33-02):
Revise OST 1.30.10, Intake Bay Silting, to delete use of reactor plant heat exchangers and equipment as a desilting flow path. The Licensee has issued Operating Manual Change Notice No. 79-36 to delete the above and provide for the use of portable equipment for the desilting opera-tion.
(Closed) Inspector Follow-up Item (77-18-06):
Submit follow-up to LER 77-06 on Feedwater System piping support deficiencies. The licensee submitted the subject report on March 14, 1979. The re-port was reviewed in-office by the inspector and this item is closed.
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Plant Status During Conduct of Inspection e..
General Description of Existing Plant Status During this inspection, April 16-24, 1979, the plant was main-tained in cold shutdown (Mode 5).
Primary temperature as measured by a core centerline thermocouple (T0014A) was 108 F.
The Reactor Coolant System was at atmospheric pressure with primary baron concentration at 827 ppm (7.2% calculated shut-down margin with2 1% required).
Reactor Coolant Pumps were secured in preparation for seal replacement, and flow through the core was being maintained at 1700 gallons per minute by the Residual Heat Removal system.
Reactor Vessel f.evel had been lowered and was being controlled to maintain a level at approximately the centerline of the cold leg piping to sup-port reactor coolant pump seal replacement.
Hydrazine hac; been added to the reactor coolant system for oxygen control and total gas concentration had been reduced to 3.9 cc/kg.
Offsite electrical power was available and one diesel generator and four DC battery banks were operable as required by Tech-nical Specifications.
Boric Acid Transfer Pump 2A, Charging Pump B, Boric Acid Storage Tank A and the Refueling Water Storage Tank were operable as defined by the Technical Speci-fications.
The plant status described above was determined by direct ob-servations in tb control room, review of surveillance test records retained in the control room, and review of shift supervisor,
shift foreman and reactor control operator logs.
During this inspection. the plant conditions,as indicated in the control room,and operator staffing were periodically monitored by the inspectors.
No items of noncompliance were identified.
b.
Review of Surveillance Test Records Associated with Technical Specification Requirements for Mode 5.
The inspector selected and reviewed the following records to verify that required Mode 5 surveillances had been performed and that the acceptance criteria had been met.
The operating Surveillance Tests (OST) reviewed and the dates last performed were:
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-5-OST 1.2.3, Nuclear Source Range Channel Functional Test,
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March 6, 1979;
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0'iT 1.7.1, Boric Acid Transfer Pump (ICH-P-2A) Opera-
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tional Test, April 16, 1979; OST 1.7.5, Centrifugal Charging Pump Test (ICH-P-1B),
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March 21, 1979 OST 1.7.8, Boric Acid Storage Tanks and RWST Level and
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Temperature Verification, April 15, 1979; OST 1.10.1, Residual Heat Removal Pump Perfonnance Test,
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December 8,1978; OST 1.10.2 Residual Heat Removal Automatic Isolation
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and Operating Interlock Test, August 25, 1977; OST 1.10.3, Residual Heat Removal System Monthly Valve
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Exercise and Position Verification, March 19, 1979; OST 1.10.4, Residual Heat Removal System Refueling Valve
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Exercise, December 11, 1978; OST 1.11.10, Boron Injection Flow Path and ECCS Subsystem
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Valve Exercise, April 10, 1979; OST 1.36.2, Diesel Generator No. 2 Monthly Test, April 13,
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1979; OoT 1.36.4, Diesel Generator No. 2 Automatic Test,
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October 20, 1977; OST 1.36,7, Offsite to Onsite Power Distribution System
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Breaker Alignment Verification, April 14, 1979; OST 1.36.9, AC Power Source Breaker Alignment Verification
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During Shutdown, April 14, 1979; OST 1.39.1, Weekly Station Battery check, April 11, 1979;
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OST 1.49.2, Shutdown Margin Calculation, April 17, 1979;
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and, Surveillance Testing of Fire Protection systems
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(discussed in Paragraph 7).
No items of noncompliance were identified.
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4.
Licensee Response to IE Bulletin (IEB)79-06A, Review of Operational Errors and System Misalionments Identified Durina the Three Mile Island Incident, Revision 1
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During the course of this inspection the licensee was evaluating the information contained in the subject Bulletin and formulating
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the actions to be taken in response to that information.
Station
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personnel were maintaining close liaison with the station's NSSS
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vendor and industry developed information regarding the Three Mile Island event and its implications for the plant.
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l In order to coordinate the activities above, the licensee has J
established a BVPS Task Force, consisting of station supervisory and operating personnel, which is developing the licensee's course
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of action. The. inspectors reviewed and discussed the status of the
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Task Force efforts at various times during this inspection.
At the close of the inspection the Task Force had identified approxi-
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mately 50 key tasks for additional review or implementation. These tasks address the actions required by the subject IEB as well as
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other improvements in operation, administrative controls, and
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emergency operations not specifically discussed in the IEB.
The
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Task Force is periodically reporting to station management and the
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Onsite Safety Committee (OSC) with its output. The inspector reviewed the minutes of Special OSC Meetinq No. BV-0SC-19-17, con-
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ducted on April 19 and 20, 1979 and determined that the licensee is A,
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providing a high level of management attention and dedicated man-
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power to the efforts of the Task Force and associated activities.
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The formal licensee response to IEB 79-06A, Revision 1 will be
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reviewed by NRC:RI, when issued. Additional onsite inspection will be conducted to confirm the accomplishment of action (s) specified
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in that response.
(334/79-BU-06)
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5.
Operator Training
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a.
Trailina Conducted In Respone to Three Mile Islai.d Incident
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The licensee has routinely and repeatedly conducted on-shift
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briefings of shift crew personnel at various times since the
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beginning of the incident at Three Mile Island.
These shift
crew briefings, documented in the Shift Supervisor's logbook,
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were conducted on an informal basis by the respective Shift
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Supervisors and included the specific details of the TMI-2
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incident to the extent of available information including
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IE Bulletins and Preliminary Notifications.
Interviews
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conductod by the inspectors with on-shift licensed and un-
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licensed personnel confirmed the performance of the briefings
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and determined that they were meanin[ful and were directed c
toward understanding the incident anc its implications for
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the operation of the Beaver Valley ftcility.
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The licensee commenced formal training, administered by the station Training Coordinator, on April 20, 1979 which addressed
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the specific areas listed below.
This training will be attended by all NRC licensed personnel and their attendance
documented as required by the quality assurance program. The
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training is scheduled for completion prior to the plant's
return to power operation.
The inspectors reviewed the
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schedule and lesson plans for the training and determined that it is directed toward:
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(1) Providing operators an awareness of the details of the Three Mile Island incident to the extent of information
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(2) Reinstruction on specific measure:. which provide assurance that engineered safety features are available
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when required;
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(3)
Instructions on specific and detailed measures to assure that automatic actuations of emergency safety features e
are not overridden.
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(4) Review of plant automatic actions initiated by reset of
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engineered safety features that could affect the control
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of radioactive liquids and gases;
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(5) Additional subject matter identified as appropriate in
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IE Bulletin 79-06A and its associated revisions.
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The completion of licensee administered training will be I
reviewed by NRC:RI during a future inspection to confirm that
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all required personnel received the training, that all required
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to those attending.
(334/79-09-01)
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Inspector Discussions with Licensed Operators In addition to training conducted by the licensee the inspectors
l and a special NRC TMI-2 incident briefing team held direct
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discussions with licensed and unlicensed operations and staff personnel and trainees on April 2,
1979, with respect to
details surrounding the events at TMI-2.
Licensed personnel
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-8-from the corporate office were also in attendance. The follow-ing topical areas were discussed:
(1) An update of TMI-2 status including the chronology of events associated with the incident; (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 feedwater trains; (4) The need for prompt reporting of serious events to the NRC; (5) The necessity to avoid premature resetting of Engineered Safety Feature Systems, including core cooling systems and containment isolation systems.
These discussions also encompassed resetting from spurious signals; (6) The need to avoid premature tripping of Engineered Safety Feature Systems during any transients requiring flow; (7) The material contained in IE Bulletin 79-06A, Revision 1.
The licensee maintained documentation regarding attendance at NRC discussions. The NRC personnel held discussions with licensee personnel including 31 licensed operators and senior operators covering the above areas.
Staff, supervisory, and nonlicensed individuals were also in attendance. All NRC licensed personnel and all principal members of the station operations staff and management were present.
c.
Review of Licensed Operator Requalification Training Proaram The inspectors conducted a review of licensed operator requali-fication program training administered through the previous twelve months.
The review was directed at establishing the extent of training routinely provided to licensed operators which related to the contributory factors of the TMI-2 event.
The inspectors reviewed the licensee's detailed lesson plans, detailed training course manual material and sampled attendance records to detennine the scope of training administered and attendance by licensed personnel.
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-g-The inspectors detennined that the following training program lectures, attended by licensed operators, addressed a number of the TMI-2 contributory factors on a routine training basis prior to the TMI-2 event:
Lesson Plan II-19, Transient Analysis;
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Lesson Plan II-21, Accident / Transient Analysis;
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Lesson Plan IV-9, Solid State Protection System, Prevention
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of ESF Override, and Specific Measures to Ensure ESF Avail-ability; Lesson Plan VI-13, Administrative Controls, Incident Report-
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ing, Technical Specification Administration Requirements, Control of Interlock Defeats, Bypasses, Blocks, Jumpers, and Equipment Status Control; Lesson Plan VII-11, Normal / Abnormal Emergency Procedure
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Drills; Lesson Plan VII-14, Emergency Procedure Drill;
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Lesson Plan VIII-13, Response to Auxiliary Feed System
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Alams; Lesson Plan VIII-16, Review of Administrative Controls
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for Valve Alignment Control and related Licensee Event Reports.
The licensee's Training Coordinator stated that all licensed operators and senior operators on the plant staff had attended each of the above lectures or had received appropriate makeup instruction.
A review of licensee records, on a sampling basis, by the inspectors confimed this statement.
No items of noncompliance were identified.
6.
Review of Valve / Breaker / Switch Alianment Procedures, C$eckoff Lists, and Piping and Instrument Drawings The inspectors perfonned a comparison of the valve lists incorporated as Section 3 of the indicated Beaver Valley Power Station Operating Manual (0M) chapters for Engineered Safety Feature (ESF) and safe shutdown systems against current piping and instrument drawings directly referenced within the valve lists to verify the accuracy 1117 136
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of the valve lists with respect to establishing valid system operating lineups.
The ESF and safe shutdown systems and/or flowpaths reviewed were:
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High Pressure Safety Injection; Cold Leg Recirculation; Hot Leg Recirculation;
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Low Pressure Safety Injection; and, Accumulator Injection; Residual Heat Removal System;
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Quench Spray (including NaOH Chemical Addition Subsystem);
and, Outside and Inside Recirculation Spray;
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Supplementary Leak Collection and Release; and,
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Auxiliary Feedwater System.
The OM chapter end piping and instrument diagrams (identified by OM Figure No. and S&W drawing No.) utilized were:
7-1, 11700-P.M-159A-6, Chemical and Volume Control System,
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Sheet 1, OM Chapter 7; 7-2, 1170-RM-159B-7, Chemical and Volume Control System,
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Sheet 2, OM Chapter 7; 10-1, 11700-RM-156A-6, Residual Heat Removal System,
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OM Chapter 10; 11-1, 11700-RM-167A-4, Safety Injection. System, Sheet 1,
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OM Chapter 11; 11-2, 11700-RM-167B-4, Safety Injection System, Shert 2,
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OM Chapter 11; 13-1, 11700-RM-165A-6, Containment Depressurization System,
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OM Chapter 13; 16-1, ll700-RB-2B, Supplementary Leak Collection and Release
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System, OM Chapter 13; 16-2, (none assigned), Supplementary Leak Collection and
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Release System, OM Chapter 13; 21-1, 11700-RM-120A-5, Main Steam System (auxiliary feed
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system steam supply portion), OM Chapter 21; and, 1117
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24-1, 11700-RM-124A-6, Feed Water System (auxiliary feed
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system portion).
No items of noncompliance were identified.
However, the below listed items remain to be inspected prior to plant startup:
comparison of switch and breaker lineup lists against
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current one line diagrams and/or elementary drawings (334/79-09-02);
verification by direct observation of actual valve / switch /
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breakeralignment(334/79-09-03),and.
verification of the condition / position of auxiliary feed-
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water system valves required by the licensee to be subject to positive position control (locking). (334/79-09-04)
7.
Review of Surveillance Records Associated with ESF and Safe Shutdown Systems The inspectors selected and reviewed the below listed records to verify that surveillances had been performed when required and that the acceptance criteria of the procedures and Technical Specifications had been satisfied.
The Operating Surveillance Tests (OSTs) reviewed and the dates last performed were:
OST 1.1.5, Containment Isolation Trip Test, CIB Train A,
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October 17, 1978; OST 1.1.6, Containment Isolation Trip Test, CIB Train B,
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October 19, 1978;
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OST 1.11.1, Safety Injection Pump Test (ISI-P-1A), February 26, 1979; OST 1.11.2, Safety Injection Pump Test (ISI-P-1B), March 12,
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1979;
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OST 1.11.3, Boron Injection Flow Path Valve Position Verifica-tion, April 2, 1979;
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OST 1.11.4, Accumulator Check Valve Test, October 23, 1977; 1117 138
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OST 1.11.6, ECCS Flow Pat _h and Valve Position Check (L.H.S.I.
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Loop A), March 5, 1979; OST 1.11.9, Accumulator Injection Valves Auto Open Test,
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March 7,1979; OST 1.11.10, Baron Injection Flow Path and ECCS Subsystem Valve
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Exercise, April 10, 1979; OST 1.11.11, Accumulator Valves Auto Open Test, October 24, 1977;
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OST 1.11.13, Baron Injection Surge Tank Level Verification,
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March 20,1979; OST 1.13.1,1A Quench Pump Flow Test, March 30, 1979;
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OST 1.13.2,1B Quench Pump Flow Test, March 19, 1979;
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OST 1.13.3, IA Recirculation Pump (IRS-P-1A) Dry Test, March 19,
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1979; OST 1.13.4,1B Recirculation Pump (IRS-P-18) Dry Test, April 2,
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1979; OST 1.13.5, 2A Recirculation Pump (IRS-P-2A) Dry Test, March 19,
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1979; OST 1.13.6, 2B Recirculation Pump (IRS-P-2B) Dry Test, April 2,
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1979; OST 1.13.7, Recirculation Pumps Auto Spray and clow Test,
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October 15, 1977; OST 1.13.8, Containment Depressurization System M0V's Exercise -
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Train A, March 4,1979; OST 1.13.9, Containment Depressurization System M0V's Exercise -
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Train B, March 31, 1979; OST 1.13.10, Spray Additive System Position and Operability
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Check, March 30, 1979; OST 1.13.11, Quench Spray System Operability Test, October 6,
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1977; OST 1.16.1, Supplementary Leak Collection and Release Exhaust
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Fans and Remote Damper Component Test (Train A), April 9,1979; 1117 139
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OST 1.16.2, Supplementary Leak Collection and Release Exhaust
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Fan and Remote Damper Component Test (Train B), April 20, 1979; OST 1.,16.3, Supplementary Leak Collection and Release Exhaust
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Fans and Remote Damper Component Test, March 28, 1979; OST 1.24.1, S/G Auxiliary Feed Pump Di:: charge Valves Exercise,
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April 6,1979; OST 1.24.2, Motor Driven Auxiliary Feed Pump Test (IFW-P-3A),
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March 23, 1979; OST 1.24.3, Motor Driven Auxiliary Feed Pump Test (IFW-P-3B),
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March 23, 1979; OST 1.24.4, Steam Turbine D:iven Auxiliary Feed Pump Test,
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March 8,1979; OST 1.30.2, River Water Pump 1A Test, March 2,1979;
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OST 1.30.3, River Water Pump 1B Test, February 16, 1979;
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OST 1.30.4, River Water System Valve Test for A Header,
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March 2, 1979; OST 1.30.5, River Water System Valve Test for B Header,
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February 16, 1979; OST 1.30.6, River Water Pump 1C Test, February 6,1979;
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OST 1.33.1, Fire Protection Monthly Inspection, March 25, 1979;
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OST 1.33.2, Fire Protection System Hose Stations Test, March 25,
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1979; 03T 1.33.3, Fire Protection System Drain Test, April 19, 1979;
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OST 1.33.4, Fire Protection System tionthly Hydrant Test,
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March 18, 1979; OST 1.33.5, Fire Protection System Inspection Te'st, April 17,
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1979; OST 1.33.7, Weekly Motor Driven Fire Pump Operation Test,
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April 16,1979; OST 1.33.8, Weekly Diesel Engine Driven Fire Pump Operations
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Test, April 16, 1979; 1]]7 140
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Fire Protection System Inspection Test, April 14, OST 1.33.9, CO2
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1979; OST 1.33.11, Foam Fire Protection Equipment Test, September 17,
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1978; OST 1.33.12, Fire Protection System Pumps Flow Test, August 12,
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1978;
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OST 1.33.13, Fire Protection System Detection Instrumentation
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Test, October 10, 1978; OST 1.33.15, Fire Extinguisher Inspection, April 1,1979;
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OST 1.33.16, Smoke Detection Instrumentation Test, December 20,
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1978; OST 1.36.1, Diesel Generator No.1 Monthly Test, April 11, 1979;
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OST 1.36.2, Diesel Generator No. 2 Monthly Test, April 13, 1979;
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OST 1.36.3, Diesel Generator No.1 Automatic Test, October 20,
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1977; OST 1.36.4, Diesel Generator No. 2 Automatic Test, October 20,
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1977; OST 1.36.5, Emergency Switchgear Operation Test - Unit to System
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Transfomer, August 21, 1977; OST 1.46.1, Post-DBA Hydrogen Control System A, February 28,
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1979; OST 1.46.2, Post-DBA Hydrogen Control System B, February 26,
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1979; OST 1.46.3, Six Month Hydrogen Recombiner - 1A Test, November 6,
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1978; OST 1.46.4, Six Month Hydrogen Recombiner - IB Test, November 6,
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1978; and, OST 1.46.5, Hydrogen Post Accident Purge System Test, April 13,
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1979.
The findings in this area are as discussed below.
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a.
The above Operating Surveillance Test Procedures and their associated data were reviewed to ensure that specific Technical Specification (TS) surveillance requirements were addressed in appropriate procedures and that the testing had been satisfac-torily accomplished when required.
During this review, the inspectors were unable to identify a test procedure or records of completion which substantiated performance of the testing requirements of TS 4.7.8.1.c.2 for the Supplementary Leakage Collection and Release System (SLCRS) Filter Banks.
This TS requires that the air flow distribution to each HEPA filter and charcoal adsorber in the SLCRS filter banks be verified to be within + 20% of the averaged flow per unit at least once per 18 months. The last documented performance of such testing was accomplished in accordance with a pre-operational test procedure reported by a Nuclear Consulting Services, Inc. (NUCON) "Radiciodine Removal Efficiency Test Report" for testing performed on August 11, 1975. The station has not issued other procedures to accomplish this testing.
Failure to conduct testing in accordance with TS 4.7.8.1.c.2 and failure to establish and implement surveillance testing procedures in accordance with TS 6.8.1.c constitute an item of nonccmpliance at the Infraction level (334/79-09-05).
Additional inspector review of this matter determined that the provisions for conducting the above testing had been inadvert-antly deleted from an approvod NUCON Procedure No. 040, "Speci-fication for Testing of HEPA Fiiters, Iodine Adsorbers, Holding Frames, Duct Heaters, and Housings", Revision 4 during licensee review and approval prior to testing conducted by NUCON in November 1978.
Informal telephone discussions between the inspector onsite and the NRC:NRR Standard Technical Specif.ca-tions Group indicated that, based on current regulatory posi-tions in Regulatory Guide 1.52, Design, Testing and Maintenance Criteria for Engineered Safety Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light Water Cooled Nuclear Power Plants, Revision 2, March 1978, the testing required by TS 4.7.8.1.c.3 could be reviewed for possible deletion from the facility's TS should the licensee conclude that to be consistent with the Regulatory Guide and make the appropriate submittals to NRC. The licensee was informed of the above and intends to evaluate the matter as part of their corrective action.
Operating Surveillance Test, OST 1.33.3, Fire Protection System Drain Test, Revision 10, includes preoperational test base line 1i17
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data for system pressure under static and flow cenditions on the data sheets for test performance.
This data is not clearly identified as being either acceptance criteria or thresholds for evaluation or corrective action.
Discussions with licensee personnel indicated that this data was intended to define an envelope of expected test results but acknowledged that the procedure did not define the values at which further action should be initiated.
The licensee comitted to provide this procedural guidance via revision of the above procedure prior to its next performance. This item is unresolved pending review of the subject revisions by NRC:RI.
(334/79-09-06)
8.
Return to Service Provisions Subsequent to Performance of Sur-veillance Tests on Engineered Safety Feature Systems During the review of the surveillance records listed in Paragraphs 6 and 7, the inspectors verified that if the performance of the sur-veillance test required placine a valve, switch, or breaker in a position or state other than the normal system alignment, as defined by the appropriate valve / switch / breaker list, then procedural steps were incorporated within that surveillance test to assure the return of the component to the normal (or required) system alignment.
Documentary evidence of the return to normal system alignment con-sisted of a performing individual's iro :ials and date.
No items of noncompliance were identified.
9.
System Operability Following Maintenance / Test Activities and Extended Outages The inspectors reviewed the administrative controls imposed by the licensee for adequate assurance of proper return to service of Engineered Safety Feature (ESF) components following test, mainte-nance and outage activities. The administrative contre.ls were reviewed to ensure that they provida, as a minimum:
continuing compliance with Technical Specifications when equipment is taken out of service for any reason; that a mechanism exists for plant operators to track the status, on a shift basis, of equipment removed from service; and, that sufficient controls exist to ensure that equipment is properly and promptly returned to service at the completion of work.
The administrative controls established for control of equipment and equipment status are promulgated through the BVPS Operating Manual, 1117 143
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Section 1.48, Conduct of Operations. The inspectors reviewed the following subsections of that document:
1.48.2, Personnel Responsibilities
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1.48.5.A, Interlcck Defeats
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1.48.5.B, Bypasses and Blocks
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1.48.5.C, Lockouts
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1.48.5.D, Jumpers, Lifted Leads, and Papered Contacts
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1.48.6.B. c':arances
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1.48.6.0, Valve Operating Diagram Status Boards
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1.48.9.H Station Startup After Extended Outage, Testing,
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and Maintenance The inspectors also reviewed all Operating Surveillance Tests (OST's)
for ESF Systems to confirm that each test provided sufficiently detailed instructions for restoring the system / equipment to operable status at the conclusion of each test. The OST's reviewed are listed in Paragraphs 6 and 7, and are discussed in Paragraph 8.
Following an extended outage, the BVPS Operating Manual, Section 1.50, Station Startup and Startup Checklists, provides the detailed instructions and procedures for plant restart. These procedures, in conjunction with the controls established by BVPS OM Section 1.48.9.H above provide for restoring disturbed systems to operable status and confirmation of their operability through surveillance testing.
Sections 1.00 and 1.48.9.H were reviewed to ensure that they addressed all the ESF systems and major considerations for confirming them to be operable.
The licensee does not utilize
" independent verification" (multi-party) of valve, breaker, or switch alignments during performance of any of the above evolutions.
No items of noncompliance were identified.
Except as noted below, the inspectors had no additional questions or comments on the administrative controls discussed above.
a.
During review of BVPS OM Section 1.48.6, Clearances, the inspectors noted that the detailed changes in system align-ment which result from clearance tagouts are not required to be reviewed by an NRC licensed operator. As presently esta-blished, the procedure requires a Shift Supervisor (licensed lil7 144
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Senior Operator) to review and approve only the " scope" and
" equipment to be remos ed from service" items of each clearance permit prior to authorizing its issuance. Any licensed or unlicensed operator may then, by procedure, authorize the detailed system alignment for safety tagging.
Should an un-licensed operator authorize an improper alignment, such practice could result in the detailed system alignment causing an unan-ticipated or unidentified entry into a degraded mode of oper-ation with respect to the facility's Technical Specifications.
While no procedural prohibition exists which would prevent unlicensed personnel from authorizing such alignment; for ESF or other Technical Specificiation related systems, existing station practice requires that a Nuclear Shift Operating Foreman (NSOF), holding an NRC Senior Operator's license, review and authorize each detailed clearance alignment prior to its implementation. When advised of the inspectors'
concerns, the licensee stated that an internal memorandum would be issued by May 1, 1979 detailing a requirement for the NSOF to review and authorize each detailed tagout for such systems prior to their implementation.
A routine revision will be made to the BVPS Operating Manual within 60 days of the end of this inspection. This itam is unre-solved pendin review of the licensee's action by NRC:RI (334/79-09-07.
b.
The BVPS Operating Manual, Section 1.48.3.E, Review, Revi-sion, and Approval Procedures, provides for using Operating Manual Change Notices (OMCN's) as a method of making interim, on the spot, changes to procedures via a form which details the procedure changes.
These forms are attached to the front matter of each affected procedure, similar to an errata sheet, until such time as a formally typed procedure revision is issued.
During their review of the various Operating Manual procedures listed in this report, the inspectors noted that a number of OMCN's had been repeatedly reissued, including repetition of all required reviews and 3pprovals, and that the total number of OMCN's in effect for operating and test procedures appeared to be a factor which might lead to opera-tional errors through their misuse.
This concern is similar to that raised in the Duquesne Light Quality Assurance Depart-ment Audit No. BV-1-79-3, Fire Protection Program.
Observa-tion No.1 of that audit identified no noncompliance with license requirements but concluded that the number of OMCN's in effect presented problems of docurrent control and the potential for operational errors.
The licensee stated that the backlog in OMCN incorporation was due to a large number of procedure changes being processed while the station's
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operating manual was being input into a computer based typing and revision system. This resulted in delays in incorporation due to unusually large clerical work loads and the inability to make individual procedure revisions while the major task of input typing was in progress.
Station management acknowledged the inspectors' concerns and stated that all OMCN's which have been outstanding for more than ninety days (the specified, nonnal term for interim use) would be incorporated in the body of their respective procedures prior to June 1, 1979. This matter is unresolved pending completion of the above licensee action and its reinspection by NRC:RI.
(334/79-09-08)
c.
The BVPS Operating Manual, Section 1.48.5.C, Lockouts, does not require clearing an entry from the locked valve log if the valve is unlocked, repositioned, and eventually returned to normal in accordance with another approved procedure or administrative control. The inspectors identified several cases during this inspection in which valves normally locked in a position to support power operation had been repositioned to support cold shutdown operation but had not been cleared from the log as di". cussed above. This aspect of the licensee's locked valve control appears to provide the potential for valve position accountability errors if improperly implemented.
The restoration of locked valves which have been disturbed but not cleared from the appropriate log will be reviewed during future inspections.
(334/79-09-09)
10.
Review of Instrument and Control Air Systems The inspectors reviewed plant procedures, air system configuration, maintenance records, and operating histories in order to assess the adequacy of the systems to provide reliable, moisture free air to reactor plant air loads; that procedures to switch to alternate (backup) -
air systems are available; and, that plant operators are familiar with that information and are aware of the importance of air systems for proper equipment operation. The inspectors reviewed the following documents:
BVPS Operating Manual, Chapter 34, Compressed Air Systems, Sections
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1-5; Emergency Operating Procedure E-16, Loss of Instrument Air;
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Computerized Maintenance History for the Compressed Air System,
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CY 1976-1978; and,
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Station Incident Report Files, CY 1976-1978.
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These reviews and discussion with plant operating personnel confirmed that Compressed Air System service is required for nonnal operation but is not essential to safe shutdown of the plant and is not required for operation of Engineered Safety Feature equipment. The only Engineered Safety Feature equipment identified as utilizing Compressed Air were containment isoiation valves. These valves utilize air for non-accident positioning and fail to the post-accident positions on loss of air.
The inspectors confirmed that the station has procedures for aligning, startup, shutdown and cross connecting station and containment compressed air systems.
Station design incorporates use of a subatmospheric containment. This feature requires that the compressed air supply for equipment use within containment be supplied from a discrete system inside containment having its own compressors and accessories. Should this system malfunction, provisions exist for cross connection with station air supplies in accordance with the procedures referenced above. Should this be necessary, containment integrity would be compro-mised requiring the reactor to be shut down.
.
Although the Compressed Air System does not service Engineered Safety Features during accident conditions, the inspectors reviewed the system's adequacy for providing reliable, moisture free air to support normal reactor operation.
Review of the maintenance records and incident reports referenced above and discussion with plant personnel identified a continuing history of problems with the station air system including repetitive failures of instrument air dryers and air compressor outages requiring the installation of a semi-permanent portable compressor.
A review of the Station Incident Report file indicated that Compressed Air System outages or air quality problems have contributed to several incidents through the past three years.
The station management is aware of the problem histories discussed above and is planning and implementing modifications which include installation of a third station air compressor, replacement of instrument air dryers with improved models, and continued availability /use of a portable unit compressor as a standby source of air.
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11.
Plant Tours At various times during this inspection, on both day and night shifts, the inspectors toured areas within the Control Room, Reactor Containment Building and the Auxiliary Building including: Reactor Coolant Pump and Steam Generator; Quench Spray; Outside Recirculation Spray; Low Head Safety Injection, and Auxiliary Feed Pump; Pressurizer and Pressurizer Relief Tank, Cubicles; Cable Vaults; Switchgear Rooms; the Main Steam Valve Room; and, other miscellaneous areas.
During these tours, the inspectors performed the following.
Residual Heat Removal, Reactor Plant Closed Cooling Water, and
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River Water systems equipment, piping and instrumentation were inspected for general condition, monitoring instrumentation recording / indicating as required, and system parameters maintained within appropriate ranges for core heat removal.
Valve and switch lineups were verified on a sampling basis.
Radiation controls in the areas inspected were observed for
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proper posting, maintenance of step off pads, adequate provisions for disposal of protective clothing, and access control to High Radiation Areas. The inspectors performed confirmatory general area radiation surveys using a properly calibrated instrument.
Plant housekeeping conditions including genecal cleanliness
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conditions and storage conditions to prevent fire hazards were observed.
Systems and equipment in all areas toured were observed for the
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existence of fluid leaks and ab".ormal piping vibration.
Mechanical snubbers and hangers installed on the Quench Spray,
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Recirculation Spray, Safety Injection, Auxiliary Feedwater, Reactor Coolant, and Chemical and Volume Control Systems were observed for proper settings and/or oil levels.
Component supports for Steam Generators and Reactor Coolant Pumps were similarly observed.
Selected system lineups on the Charging and Boration flowpaths
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were checked for proper system alignment consistent with Technical Specification requirements for the existing mode of operation.
Valve positions were confirmed through direct observation and use of control room status indication.
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Implementation of administrative controls for equipment safety
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tagouts was directly observed and proper posting and posi-tioning of tagged components was verified. These observations included active Equipment Clearance Tags on the Solid State Protection System, Reactor Coolant System, Charging System, and Reactor Plant Component Cooling Water System valves, switches, and breakers.
The control board was reviewed for annunciato'rs that should
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not be lighted during existing plant conditions.
The reasons for lighted annunciators were adequately described by the on duty control room operator.
Implementation of administration controls for electrical
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jumpers, lifted leads and papered contacts was directly ob-served; proper system configuration and posting were verified.
These observations included jumpers and lifted leads in the control circuits for Charging and Safety Injection System Components.
Implementation of administrative controls for padlocked
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equipment was directly observed and proper posting and posi-tioning of locked components was verified.
Current plant conditions require that a number of locked valves in Emergency Core Cooling Systems be in abnomal positions.
These valves have been unlocked and repositioned in accordance with sta-tion shutdown procedures. The inspectors reviewed the admin-strative controls for restoration of these valves to their nomal operating conditions and detemined that the controls appear adequate to accomplish the necessary realignment. The administrative controls for restoration of these valves to their nomal operating positions will be inspected for ade-quacy during a future inspecticn as discussed in paragraph 8 of this report.
Control room manning was observed on several occasions during
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the inspection, including shift turnovers on April 16,17, 18, and 20 to verify that proper manning levels were main-tained and that continuity of plant status infomation was maintained.
Selected fire extinguishers and fire alam stations were
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observed in the Auxiliary Building, Turbine Building, and normally occupied plant areas to confim that access was unobstructed, that locations were clearly identified, and that extinguisher pressures were satisfactory.
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Selected no smoking areas were observed for evidence of smoking.
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No items of noncompliance were identified.
12.
Radioactive Liquid and Gas Vent and Drain Syst.em Review The inspectors reviewed the below listed ciawings in conjunction with licensee shift supervisory personnel to determine if inadvertent transfer of radicactive gas or liquid from the containment could result from the resetting of engineered safety features protection channels.
The drawings review (S&W Nos.) were:
11700-RM-169A-6, Vent and Drain System, Sheet 1;
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ll700-RE-21GG-1, Elementary Diagram, Aerated Drains, Sheet 1;
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ll700-RE-21GH-1. Elementary Diagram, Aerated Drain, Sheet 2;
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and, 11700-RE-21JG-1, Elementary Diagram, Primary Grade Water, Sheet
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1.
The contact and relay arrangement associated with' control board control switch positions and contacts associated with automatic containment isolation signals were reviewed for the following components:
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Reactor Containment Sump Pumps DA-P-4A and DA-P-4B; and solenoid valves associated with trip discharge valves, TV-DA-100A and TV-DA-100B; Primary Drains Transfer Tank (D0G-TK-1) Transfer Pumps DG-P-1A
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and DG-P-1B; and, solenoid valves associated with trip discharge valves, TV-DG-108A and TV-DG-108B; and, Solenoid valves associated with Pressurizer Relief Tank Vent
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Header trip valves TV-DG-109Al and TV-DG-109A2.
The inspectors determined that if the control switch positions were maintained consistent with the elementary diagrams and a containment isolation signal was generated (associated trip valves will close, de-energizing the pumps), the resetting of the containment isolation channel will not cause, by itself, the automatic re-opening of the trip valves.
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The inspectors reviewed the procedures of OM Chapter 17 Liquid Waste Disposal System and Chapter 18 Gaseous Waste Disposal System which affect the operation of the above equipment and deter-mined that they are consistent with the information discussed above.
Additionally Emergency Operating Procedures are being reviewed by the licensee and will be revised to require additional operator action (e.g. securing pumps, etc.) to ensure inadvertent dis-charges from the containment will not take place during the existence of a containment isolation condition.
This activity will be reviewed during a future inspection as part of the actions taken in response to IE Bulletin 79-06A, Revision 1.
(334/79-BU-06)
13.
Prompt Reporting Requirements
,
,
The inspectors reviewed the BVPS Operating Manual, 3ection 1.48.9.D, Miscellaneous Reports, Revision 6 and Section 1.57, Emergency Preparedness Plan, Issue 4, to ascertain the time frames for NRC notification during significant events.
The inspectors noted that the guidance given in the two documents above is consistent with the requirements of the facility's Technical Specifications for reporting licensee events and with 10CFR20.403 for reporting in-cidents involving by-product, source, or special nuclear material.
At the time of this inspection, the licensee's procedures had not been revised to reflect the guidance provided by NRC in IE Bulle-tin 79-06A for notification within one hour of the time that the reactor is in an uncontrolled or unexpected condition of operation.
Licensee action in this regard will be reviewed as part of their repsonse to the IE Bulletin and will be followed during future inspections. The Licensee's stated intentions in-clude compliance with the notification requirements of the bulle-tin. (334/79-BU-06)
14. Onsite Assessment of Operating Procedures The inspector reviewed appropriate sections of the BVPS Operating Manual and conducted interviews with on shift licensed personnel in regard to the following subjects. The reviews and interviews were directed at determining the type and adequacy of guidance available in station procedures for the items listed below.
a.
Partial Actuation of Safety Injection (One Train) to Assist in Pressurizer Level Control Durina Routine Operational Events.
The inspector reviewed the procedures for Emergency 1117
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Operations in the BVPS Operating Manual, Chapter 1.53 and procedures for Correcting Safety Related Alarm Conditions associated with key nuclear steam supply systems and deter-mined that, as presently constituted, the licensee's proce-dures do not require or recommend partial actuation of Safety Injection (SI) for such events. The licensee's internal Task Force and Onsite Safety Committee were considering recommen-dations during the inspection which could result in partial, manual initiation of SI to provide additional assurance that routine transients are brought under rapid, positive control.
b.
Operator Guidance / Procedure Recuirements for Securing Reactor Coolant Pumps During Safety Injection. As currently esta-blished, the facility's Emergency Operations Procedures pro-vide for securing Reactor Coolant Pumps immediately after confirmation that a Loss Of Coolant Accident leading to Reac-tor Coolant System blowdown has taken place.
The licensee's Task Force and Onsite Safety Committee have recommended changes to the applicable procedures which will require that Reactor Coolant Pump (s) remain in operation during events which require initiation of Safety Injection. The licensee's intentions will be formally provided to the NRC in their response to IE Bulletin 79-06A and the affected procedures will be revised appropriately prior to the facility's return to power operation.
Interviews and discussions with operators indicated their understanding of both existing and proposed requirements for operation of Reactor Coolant Pumps.
c.
Availability of Procedures for Providing Feedwater to Dry Steam Generators.
The facility's Technical Specifications, Amendment 4, the BVPS OM, Sections 1.24.2, 1.24.4.K, 1.24.4.P, and 1.53, E-4 provide requirements for limiting the feedwater addition rate and Steam Generator Level rise rate on LOW-LOW Steam Generator Level Conditions. As presently established, the procedures do not specifically address addition of feed-water to Steam Generators which have. completely dried out due to loss of feedwater. The licensee is evaluating this matter as part of the Task Force activities.
d.
Taqqing Practices Providing Potential for Obscuration o_f_ l Control Board Indicators. The inspectors reviewea Concro Board tagging practices to determine whether they provide the potential for obscuring status indicators, meter indi-cators, or alarms. While licensee policy requires that such tags be installed, to the extent possible, to prevent such obscuration, the inspector determined that the potential does 1117
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exist for an obscured view of indication.
Licensee management has placed greater emphasis on careful installation of the tags in order to minimize the potential for problems.
The station is also reviewing improved methods of tagging (e.g. high visibility tape with repeating identification blocks) which may be implemented to remove the potential for obscuration.
This matter is being pursued for long term solution. following the unit's return to power operation.
The matters above will be further reviewed by NRC during review of the licensee's response to IE Bulletin 79-06A, Revision 1, and during facure inspections (334/79-BU-06).
At the close of this inspection, the licensee anticipated completing his evaluation and implementation of the actions described in items a, b and c above prior to the facility's return to power operation.
15.
Unresolved Items Unresolved items are matters about which more information is required to determine whether they are acceptable, items of noncompliance or deviations.
Unresolved items are discussed in paragraphs Sa, 7a and 9 of this report.
16.
Exit Interview Management meetings were held with licensee personnel (denoted in Paragraph 1) at the conclusion of this inspection.
The purpose, scope and findings of the inspection were discussed as they appear in the details of this report.
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