IR 05000293/1980026
| ML19351G099 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 10/02/1980 |
| From: | Jerrica Johnson, Martin T, Roberts K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML19351G078 | List: |
| References | |
| 50-293-80-26, NUDOCS 8102230118 | |
| Download: ML19351G099 (21) | |
Text
O u s "uc'e^R REcutA10av COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 50-293/80-26 Docket No. 50-293 License No. DPR-35 Priority
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Category C
Licensee:
Boston Edison Comoany 800 Boylston Street Boston, Massachusetts 02199 Facility Name:
Pilgrim Nuclear Power Station Inspection at:
Plymouth, Massachusetts Inspection conducted:
August 1-31 1980 Inspectors:
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W bnt ' M ector WWbo Reside date signed K. Robert sl
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J. Johnson,SeniorRedntInspector date signed date signed
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T. Martin, Chief, Reactor Projects Section date signed No. 3, RO&NS Branch
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Inspection Summary:
Inspection on August 1-31, 1980 (Report No. 50-293/80-26)
Areas inspected:
Routine unannounced inspection of plant operations including an operational safety verification, followup on surveillance and maintenance activities, an in-office review and followup'of licensee event reports, actions
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in response to IE Bulletins, a review of personnel and organization changes, i
and a review of process computer input data involving fuel lengths. The inspec-tion involved 96 inspector-hours onsite by two resident inspectors.
Results:
Three items of noncompliance were identified (Infraction - Failure to set APRM flux scram settings in accordance with Technical Specifications, Para-graph 2.b.(3); Deficiency - Failure to report APRM Channel 'F' 120% clamp trip setpoint outside techni' cal specification limits, Paracranh 3.b.(2); Infraction -
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Failure to properly escort visitors, Paragraph 2.b.(2)(a)).
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i Region I Form 12 (Rev. April 77)
810 2230nS
DETAILS 1.
Persons Contacted W. Armstrong, N.0.0. Staff Assistant E. Cobb, Chief Operating Engineer R. Machon, Acting Station Manager C. Mathis, Methods, Training and Compliance Group Leader J. McEachern, Security Supervisor T. McLaughlin, Senior Compliance Engineer P. Smith, Chief Technical Engineer D. Sukanek, Acting Chief Maintenance Engineer P. Willard, I&C Engineer The inspectors also interviewed other licensee personnel including members of the Health Physics, Operations, Security, Maintenance, Chemistry and Training Staffs.
2.
Opun. anal Safety Verification a.
Scope and Acceotance Criteria The inspector observed control room operations, review applicable logs and conducted discussions with control room operators during the month of August.
The inspector verified the operability of selected emergency systems, reviewed tagout records and verified proper return to service of affected components.
Tours of the site perimeter, reactor building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance.
The inspector by direct observation and interview verified that the physical secur-ity plan was being implemented in accordance with the station security plan.
The inspector observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
During the month of August, the inspector walked down the accessible portions of the High Pressure Coolant Injection system to verify operability.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under Technical Specifications,10 CFR, and Administrative Procedures.
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3.
APRM Flux Scram 'sttings During tours of the Control Room, the inspectors observed 'that the Average Power Range Monitor (APRM) Gain Adjustment Factor's (AGAF) were greater than 1.0 as indicated on the process computer printouts (P-1). The AGAF is calculated by dividing percent core thermal power by percent APRM indicated power.
Station Procedures 9.1, "ARPM Calibration," Revision 5 and 2.1.15, " Daily Surveillance Log - OPER 09," Revision 28, allow the AGAF's to fall between
.95 and 1.05 before a gain adjustment is made.
l Station Calibration Procedure 8.11.1.4, "APRM Flow Bias Signal Calibration,"
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Revision 6, specified that the APRM flow biased trip points (at 100% drive flow) be set at 118+ 1%.
The inspectors questioned the L; ensee on August 19, 1980, concerning justification for allowing the AGAF to be as high as 1.05 taking into account the specified trip setpoints and the Technical Specification Limit-ing Safety System Setting (LSSS) Section 2.1.
The inspector stated that with a combination of high AGAF and the currently allowed trup setpoint, the LSSS would be exceeded.
The following data gives examples of exceeding the Technical Specification
LSSS:
Technical Specification Limit Technical Specification 2.1.A specifies that the Nescron Flux Scram Setting, S, shall be:
S 1 65 w + 55%
w - % drive flow S - setting in % of rated thermal power t
(S 1 120% at 100% drive flow)
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Observed Data
APRM 100% Flow Biased Trip Set Point Channel AGAF*
Trio Set Point in Dercent Rated Power A
1.04 118 122.7
1.03 118 121.5 F
1.04 118.2 122.9
AGAF's from P-1 printout on July 28, 1980.
Latest flow biased trip set points from calibration 8.M.1.4 perfonned on July 1, 1980.
On August 20, 1980, the Licensee stated that due to procedural inadequacies, the settings for the APRM Flux Scram Trip and Rod Blocks may not have been in accordance with the Technical Specifications Section 2.1, that the gain of the APRM's would immediately be adjusted, that station procedures would be revised to ensure that the Technical Specifications are met.
This event was reported to the NRC in Prompt Reportable Occurrence No. LER 80-39.
The inspector verified the readjusted AGAF's and stated that failure to establish the APRM Flux Scram Settings in accordance with Technical Specif-ication 2.1 was an item of noncompliance at the infraction level (50-293/
80-26-04).
Tour of HPCI/B RHR Rooms During a tour of the B RHR and HPCI Rooms on August 27, 1980, the insnectors identified several items in the areas of housekeeping, equipment control, radiation protection and fire protection which needed increased attention.
These items included the following:
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identification of specific location on posted RWP sign-in sheets and (
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HP clothing requirement sheets; quality of lighting in B RM- -oom; j
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general cleanliness of B RHR and HPCI rooms;
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loose / illegible equipment control red tags; and,
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control / placement of spare fire extinguishers.
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The Licensee acknowledged the inspectors comments and initiated action to correct the above items. The inspector will review these areas during future routine inspections, a.
HPCI Turbine Control While conducting surveillance 8.I.6, "HPCI System Pump and Valve Oper-ability" on August 25, 1980, the HPCI turbine speed was oscillating and the operator had little control of turbine speed. HPCI was declared inoperable and a priority 'A' work request and a " Failure and Malfunction" report initiated. The electronic governor was ad-justed (was found to be within tolerance) and the control oil filter changed. The system was subsequently tested on August 25, 1980,and it.
performed satisfactorily, although the specific cause of the previous malfunction was not determined.
The Licensee called in a Terry Tur-
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bine Co. technician and the system again operated satisfactorily on August 28, 1980.
THe inspector witnessed this test run and did not note any abnormalities in turbine operation. The Terry Turbine Co.
technician did not identify any problems.
The HPCI system has malfunctioned (in different ways) due to diverse problems on numerous occasions since the end of the January-May,1980 refueling outage.
The reliability of this system will be reviewed by the NRC (50-293/80-26-05).
b.
Core Spray Valve Inocerable While conducting surveillance procedure 8.5.1.3, " Core Spray System Pump and Valve Operability," (because the HPCI system was inoperable)
the 'A' Core Spray inboard injection valve tripped its circuit breaker during an opening cycle.
The valve was found to have gone fully open but the open position switch had failed. When moving in the open (" accident") direction, the torque switch is bypassed and the motor is normally de-energized by the "open" position switch. When the
"open" switch failed, high motor current tripped the circuit breaker as the valve reached its backseat.
The valve was tagged in the open position (its' normal cosition), the motor checked, and the limit switch repaired. The valve was returned to normal and surveillance 8.5.1.3 satisfactorily completed on Auaust 27, 1980.
The inspector had no further questions, a
c.
High Reactor Water Conductivity On August 1, 1980, the Reactor Coolant System experie,nced high con-ductivity as a result of 'D' condensate denineralizer resin reten-tion elenent failure and resin break through.
This event is further described in Paragraph 6 discussing LER 80-43.
d.
Defeat of Mode Switch to " Shutdown" Scram During normal power operation at 1105 on August 18, 1980, the facility lost the 'B' Reactor Protection System (RPS) Bus due to the tripping of the 'B' Reactor Protection System Motor-Generator Set (RPSM/G).
The RPSM/G was inadvertently tripped while replacing an indication fuse.
The Bus was placed on " alternate source" and the half-scram was reset.
During a subsequent review of annunciators, the operator noted that an annunciator that indicated that the mode switch was in " shutdown" was illuminated. The mode switch was obviously not in " shutdown" and a maintenance request was initiated.
At approximately 3:30 p.m. the instrument and control technician working on the problem identified that the " Mode Switch in Shutdown" scram was bypassed. The circuit was reviewed and the relays manually reset returning the circuit to normal at 5:30 p.m. on August 18, 1980.
The Licensee submitted LER 80-38 to describe the event.
The inspectors reviewed the circuit and verified that Pilgrim's RPS logic is such that placing the mode switch in " shutdown" would cause a reactor scram.
Around the contact that opens to cause this scram is a bypassed circuit which is made up by two series contacts closing after a two second time delay, so that the scram can be reset with the mode switch in " shutdown."
If, however, the RPS bus power is lost with the mode switch in "Run",
Relay SA-K17 is de-energized (after 2 seconds) closing one of the two contacts in the Mode Switch scram bypass circuit.
When the RPS bus is then re-energized and Relay SA-K16 is energized prior to 5A-K17, this closes the second contact in the Mode Switch scram bypass circuit bypassing the mode switch to shutdown scram and keeping Relay 5A-K17 de-energized.
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If 5A-K17 is energized prior to 5A-K16, then neither bypass contacts would close (but this was not what was experienced).
With the bypass circuit made up, the Mode Switch in "Run," and if the Mode Switch were turned to the " Shutdown" position quickly, (through startup) a scram would probably not occur.
If the mode switch was turned through "Startup" slowly so that Relay 5A-K17 was energized a scram would occur.
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The Licensee issued imedate instructions to all operatina shifts to review the event, and identify the relay that must be reset, and will revise the appropriate alarm response procedure ~.
This item remains unresolved pending a review of the revised alann response procedure and a review of the circuit design to determine if a modification is required (50-293/80-26-06).
5.
Surveillance Observations a.
Scope The inspector reviewed the completed surveillance procedures 8.M.2.3.2
" Rod Block Monitor Calibration" performed on July 23, 1980, and 8.M.1-4, "APRM Flow Bias Signal Calibration" performed on July 1,1980 in order to verify that removal and restoration of the affected com-ponents was accomplished, that test results conformed with Technical Specifications and Procedure requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The inspector also witnessed portions of the following test activities:
LPRM Calibration and Computer Program 0D-1 Update.
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HPCI System Operability Test,
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b.
Findings (1) The inspector noted that Procedure 8.M.2.3.2, " Rod Block Monitor Calibration," Revision 5 did not require "as found" data be docu-mented on the data sheets for the downscale trip.
The procedure only required that a check be made to ensure that the downscale trip was readjusted so that the "as left" data was within limits.
The inspector stated that this did not provide documented assur-ance that the downscale trip setting had or would be within Technical Specification Limits between calibrations.
The Licensee acknowledged the inspectors statement and stated that Procedure 8.M.2.3.2, " Rod Block Monitor Calibration" would be revised (prior to the next calibration) to include "as found" as well as "as left" data for the downscale trip.
Pending revision of Procedure 8.M.2.3.2, " Rod Block Monitor Calibration," and review by NRC, this item is unresolved (50-293/80-26-07).
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(2) During a review of the completed surveillance procedure 8.M.I.4,
"APRM Flow Bias Signal Calibration," Revision 6, performed on July 1,1980, the inspector noted that althouc5 the "as left" value of the Channel F APRM 120% clamp trip setpoint was within limits, the "as found" setpoint was greater than 125%.
Technical Specification 2.1.A.1.a requires that the APRM Flux Scram trip settings not exceed 120% of rated thermal power for all combinations of loop flow and core power.
Technical Specification 6.9.B.2.a requires a 30 day report to the NRC whenever a reactor protection system instrument setting is found to be less conservative than those established by the Technical Specifications but which do not prevent fulfillment of the functional requirements of the system.
The inspector stated that failure to report this event in accord-ance with Technical Specification 6.9.B.2.a was considered an item of noncompliance at the deficiency level (50-293/80-26-08).
The inspector noted that the remarks section of completed APRM calibration data sheet had noted the problem with APRM Channel
'F' but that the acceptance criteria for the calibration had been signed as satisfactory.
The Licensee stated that a review of station procedures was in progress and that a change in the format of the calibration pro-cedure data sheets was proposed which would include "no adjust" limits and Technical Specification limits.
6.
Maintenance Observations a.
The inspector reviewed the completed documentation associated with Plant Design Change Request (PDCR) No. 80-48, " Installation of SDV Vacuum Breaker."
This review was performed to ascertain whether activities were con-ducted in accordance with approved procedures, and the facility Technical Specifications.
The following items were reviewed:
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welder qualification records;
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NDE records (liquid penetrant tests); and,
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material certifications / receipt inspection report.
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b.
The inspector also reviewed selected portions of activities involving the replacement of the HPCI gland exhaust fan motor on August 21, 1980.
No items of noncompliance were identified during these reviews.
7.
In-Office Review of Licensee Event Reports (LER's)
The inspector reviewed the following LER's to verify that the details of the event were clearly reported, including the accuracy of the description of the cause and adequacy of corrective action.
The inspector determined whether further information was required, and whether generic implications were involved. The inspector also verified that the reporting require-ments of the Technical Specifications had been met and that appropriate corrective action had been taken.
79-23, MSIV Closing Time
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79-26, MSIV Closing Time
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79-38, Oxygen Analyzer Valves 79-43, HPCI Isolation Valve
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79-48, Failure of Switchyard Battery Charger
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80-04, Core Spray Sparger Indications. The inspector noted that Amend-
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ment 42 to the Facility Operating License dated fiay 12, 1980, describes this event and allows operation for the next cycle. The inspector will review this area prior to startup following the next refueling outage (50-293/80-26-09).
80-07, False Fire Detection Alann
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80-10, Damaged Fire Hydrant
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80-11, Jet Pump Beam Indication.
This event is also discussed in the
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Licensee's response to IEB 80-07 and will be discussed during the followup of that Bulletin.
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80-12, Setpoint Drift LPCI Low Pressure Permissive
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80-13, Setpoint Drift Condenser Low Vacuum Trip
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80-22, Setpoint Drift RCIC High Temperature
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80-25, Fire Alarm in HPCI Quadrant due to Steam Leak
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80-26, Failure to Report Scram of May 19, 1980
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80-27, Stack Gas Sample Flow Low
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80-35, Fire Detector Inoperable in A0G Building
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80-40, SGTS Fan Unintentional Trip
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8.
Licensee Event Report (LER) Followup Through direct observations, discussionr with licensee personnel, and re-
&.' of records, the following LER's were reviewed to determine that re-portability requirements were fullfilled, immediate corrective action to prevent recurrence had been accomplished in accordance with technical specifications.
80-30, Failure of 'D' SRV to Open on Demand on July 25, 1980
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80-47, Failure of 'D' SRV to Open on Demand on August 1,1980
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The failure of 'D' SRV to open on demand on July 25, 1980 is described in LER 80-30 and Inspection Report 80-25. The cause of the failure to open on the first attempt following repairs on July 26, 1980 had not been determined and was described as unresolved item no. 50-293/80-25-02.
On August 1,1980, the licensee attempted to perform an additional test of 'D' SRV during a shutdown for high reactor conductivity.
Several attempts to open the valve remotely were unsuccessful.
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event and the licensee's subsequent actions are described in LER 80-l 47.
l With the plant shutdown over the August 1-3, 1980 weekend the licensee disassembled (with the assistance of a Target Rock Corp. representative)
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the air operator assembly, the solenoid assembly, and pilot assembly.
No defects were found and the valve was reassembled.
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During reinstallation of the solenoid, plant personnel received a mild shock.
Further investigation revealed the source of the voltage was from a test loop installed across the open indication for all relief valves. This test circuit was thought to be a possible cause for failure of 'D'
SRV to open, however, testing of the loop revealed no failed components.
On August 3,1980, 'D' SRV was tested at 150 psig with the test loop disconnected and it operated satisfactorily.
On August 5, 1980, representatives of the NRC Region I office contacted the licensee to discuss further actions to be taken regarding testing of the 'D' SRV. These actions are described in Imediate Action Letter No. 80-26 dated August 6,1980 and included the following
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commitments:
Perform surveillance testing to demonstrate the ability of 'D'
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SRV to open on demand at normal operating pressure. This test will be performed prior to 11:50 p.m., August 6,1980.
Continue troubleshooting to determine the cause of the previous
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failure.
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Perform additional testing on 'D' SRV at normal operating pres-
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sure following any work on the SRV control system.
On August 5, 1980, the licensee tested 'D' SRV at 90% power and 1000 psig with the test loop removed.
The licensee has still not determined the cause of the failure of 'D'
SRV t., open on demand on July 26, 1980 and August 1, 1980.
LER's 8030 and 80-47 and Unresolved Item No. 50293/80-25-02 remain open pending further review by the licensee and the NRC.
80-34, HPCI Exhaust Line Snubber Failures
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This LER describes repairs to two HPCI exhaust line snubbers that were observed to be severed (No. S23-3-31 on July 1, 1980 and No.
S23-3-36 on July 16,1980).
It is also noted that LER 79-50 desribed a failure of Snubber No. S-23-3-31 on December 21, 1979.
The cause of the December 21, 1979 failure has not yet been determined.
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On each occasion the damaged snubbers were replaced.
In addition, a 20 KIP snubber has been added to the line adjacent to the 3 KIP S-23-3-31 snubber.
Upon questioning by the inspector, the licensee stated that during inspections pursuant to IEB 79-14, a rigid restraint (which was not supposed to be installed per the original seismic design) was removed.
The licensee stated that seismic analysis performed by the A/E (Bechtel)
indicates that the original configuration and capacity of Snubbers S23-3-31 and S23-3-36 is adequate.
The licensee is continuing to investigate the cause rf these failures and is planning to perform a transient analysis of t'ne exhaust line which will include inputs from test instrumentation and give opera-tional loading information.
Pending a review of the seismic analysis of the HPCI exhaust line in particular, and the adequacy of not including operational loads in the seismic analyses of all systems in general, this item is unre-solved (50-293/80-EC-10).
80-36, A0G Fire Check
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While reviewing the events surrounding the inoperability of the fire detectors in the Augmented Off Gas (A0G) Building (LER 80-35), the licensee determined that hourly fire checks had not been made in accordance with Technical Specification 3.12.A.a.
The fire watch was initiated and the inoperable equipment returned to service.
The cause of this event was determined to be failure of the operations personnel to properly communicate the request for a fire watch and
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failure of the security organization (who perform these checks) to properly schedule, track and log these fire watch tours.
To prevent recurrence of this type of event, the licensee has taken the following actions:
Operations personnel have been instructed via the Watch Engineer's
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Instruction Log that following a determination of inoperable fire equipment they will do the following:
i Enter into the W.E. Log Book the faulty equipment and the
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time of failure.
Refer to the Technical Specifications.
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If a fire watch is required, the name of the securfLy
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notification and time notified will be logged in the !!.E.
Log Book.
Notify the Fire Protection Engineer.
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Security personnel !. ave instituted a new control mechanism for
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continuation of patrols whereby the security supervisor will log this activity each hour into the " Daily Security Activity Log."
The inspector questioned the licensee concerning the adequacy of these actions.
The inspector stated that the requirement for hourly fire patrols is the type of item that should go on the Watch Engineer's shift turnover form to assist the operators in ensuring that the technical specification actions are complied with.
This LER remains open pending a review of the adequacy of the licensee's actions to prevent recurrence.
80-38, Mode Switch to " Shutdown" Scram Inoperable
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This LER is described in Paragraph 2.c.(4).
80-39, APRM Flux Scram and Rod Block Settings
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This LER is desct. bed in Paragraph 2.b.(3).
80-43, High Reactor Conductivity Due to Resin Breakthrough
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At 0010, on August 1, 1980, the 'D' condensate demineralizer was placed in service.
At 0016 following observations that the conduc-tivity of the demoneralizer outlet pegged high, the demineralizer was removed from service.
At 0025 the reactor water conductivity exceeded 10 umho/cm which is the technical specification limit and a controlled shutdown was initiated. At 0730, August 1, 1980, the reactor water reached 100 umho/cm and the facility staff decided to proceed to cold shutdown at the maximum rate and conduct a bleed and l
feed flush of the reactor coolant system and conduct other mainten-l ance activities and tests.
The reactor was brought to cold shutdown, the system flushed, and the conductivity returned to normal. Chloride ion concentration remained less than 100 PPB throughout the event.
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The demineralizer was emptied of resin and opened for inspection.
The inspection revealed that a resin retention element hold down bolt had come loose and allowed the retention element to come loose; thus resin passed around retention element and into the feedwater
to the reactor.
The resin retention element was remounted, the retaining bolt tack welded, and the demineralizer returned to service.
The inspector verified compliance with the actions required by Technical Specification 3.6.B " Coolant Chemistry," aiid had no further comments on this event.
9.
Personnel and Organizational Changes The resident inspector was notified on July 31, 1980,of the following personnel changes:
Mr. G. C. Andognini (Nuclear Operations Manager) has resigned effec-
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tive August 31, 1980.
Mr. P. J. McGuire (Station Manager) has been reassigned to I.N.P.O.,
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Atlanta, Georgia, effective September 1,1980.
Mr. R. Machon (Assistant Station Manager), has been assigned as
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Acting Station Manager, effective approximately August 18, 1980.
Mr. Machon's qualifications were reviewed by the inspectors and it was de-termined that he meets or exceeds the minimum requirements of Technical Specification 6.3, " Facility Staff Qualifications" which specifies compli-ance with ANSI N18.1-1971.
A change in the Nuclear Operations Department structure is anticipated in
September, 1980.
The restructuring may include the deletion of the
" Nuclear Operations Manager" position and re-assignment of his duties to other new and existing positions.
The onsite organization is expected to change with the addition cf a second Assistant Station Manager.
The licensee is preparing a safety evaluation for these changes and will submit a change to the applicable portions of the Technical Specifications and a report to the NRC in accordance with Technical Specification 6.9.B.2.e.
The inspector will review these additional changes during a future inspec-tion.
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10.
Nonconservative Calculation of Maximum Total Peakina Factor On August 18, 1980, the inspector informed the licensee of~an event at another BWR (Brunswick).
Brunswick had been informed by General Electric Co. that the process computer had been using incorrect fuel lengths in calculating total peaking factors.
The inspector questioned the licensee concerning applicability of the prob-lem to Pilgrim even though the Technical Specifications do not specifically address maximum Total Peaking Factor.
The inspector reviewed hand calculations performed by the Reactor Enoineer which indicated that the fuel bundle and core heat transfer areas (using data from the Reload Fuel Application GE NEDO 24011-P-A-1) are in agree-ment with those values used in the process computer.
The inspector had no further questions at this time.
11.
IE Bulletin Followup
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The inspector reviewed the licensee's actions in response to the following Bulletins.
IEB 80-14, Degradation of BWR Scram Discharce Volume Caoacity
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Item 3 of the Bulletin required that facility procedures specify that the SDV vent and drain valves by periodically tested and that if these valves are not operable or are closed for more than one hour in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period that the reason be logged and the NRC notified within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Prompt Notification).
The inspector stated that the licensee's response dated July 30, 1980, did not address these concerns. The licensee representative acknow-ledged the inspectors statement and stated that a revised response would be, issued which would discuss these items.
Pending a review of the revised response and the licensee actions, this Bullet 1n remains open'.
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IEB 80-17, Failure of 76 of 185 Control Rods to Fully Insert Durina a Scram at a BWR Paragraph 2, Review of Scram Test Data.
The inspector reviewed the data from both the manual and automatic scrams. The data from strip chart recorders, computer alarm printouts, and chemistry records, was compared with the licensee's responses of August 1, 1980,and August 12, 1980.
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The reported information was in agreement with the input data with the exception of Item 2.d - time to fill the instrument volume scram limit switch from scram initiation during the automatic scram.
The time appeared to be 2 seconds off.
The licensee agreed to correct this
'
iten in a supplemental response.
Paragraph 6.a; Prompt Notification.
The licensee has revised Pro-cedure 2.2.17 to require prompt notification by the operations per-sonnel whenever one of the applicable systems is out of service and when returned to service.
Supplement 1, Paragraph 2.4; SLCS.
The inspector stated that the licensee's actions to provide clear guidance to the operators (as to when SLCS should be initiated without prior supervisory approval)
did not appear to be adequate.
The licensee's August 8, 1980, response provided an exerpt from Procedure 5.3.2, " Inability to Shutdown with Control Rods," Revision 6.
This procedure has a Caution (which was not included in the licensee's response) which states:
" Utilization of the Standby Liquid Control System shall be when:
1.
Subcriticality cannot be maintained during cooldown.
2.
If in the judgement of the Station Supervisor the hazards are of significant magnitude to warrant the use."
Also, the August 8, 1980, response did not include a reference to the SLCS normal operating procedure 2.2.24, "SLCS" Revision 6, which states in Section VII.A that:
"If in the judgement of station supervision that SLCS should be initiated... proceed as follows..."
The inspector also stated that there was no station procedure which required that the SLCS keys be readily available as reqJired by the Bulletin.
The licensee representative acknowledged the inspectors comments and stated that the appropriate procedures would be revised to address these concerns.
This Bulletin remains open pending completion of these and additional actions by the licensee and verification by the NRC.
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12.
Unresolved Items Areas for which more information is required to determine acceptability are considered unresolved.
Unresolved items are discussed in Paragraphs 2.b (2), 2.c.(4), 3.b.(1) and 6 of this report.
13.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and findings.
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