IR 05000245/1981014
| ML20038B715 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 11/16/1981 |
| From: | Elsasser T, Lipinski D, Shedlosky J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20038B702 | List: |
| References | |
| TASK-2.B.4, TASK-2.E.1.1, TASK-2.E.1.2, TASK-2.E.4.2, TASK-TM 50-245-81-14, 50-245-81-24, 50-336-81-12, NUDOCS 8112090042 | |
| Download: ML20038B715 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT 50-245/81-14 Report No. 50-336/81-12 50-245 Docket No. 50-336 DPR-21 License No. DPR-65 Priority
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Category C
Licensee:
Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06101 Facility Name:
Millstone Nuclear Power Station, Units 1 & 2 Inspection at:
Waterford, Connecticut 06385 Inspection conducted:
September 27 thru October 31, 1981 Inspectors:
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[g u /g/59 T. Shedlosky, S'. Resident Inspector
'date signed a /ju
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D. R. Lipinski, Resident Inspector date signed date signed Approved by:
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T. C. EMser, Chief da te ' signed Reactor Projects Section 1B, Division of Resident & Project Inspection Inspection Summary:
Inspection on September 27 thru October 31, 1981 (Combined Report Nos. 50-245/81-14 and 50-336/81-12.
Areas Inspected: Routine, onsite, regular and backshift inspection by two resident inspectors (104 hours0.0012 days <br />0.0289 hours <br />1.719577e-4 weeks <br />3.9572e-5 months <br />, Unit 1; 91 hours0.00105 days <br />0.0253 hours <br />1.50463e-4 weeks <br />3.46255e-5 months <br />, Unit 2). Areas inspected included the control rooms and the accessible portions of the Unit I reactor, turbine, radioactive waste, gas turbine generator, and intake buildings; the Unit 2 enclosure, auxiliary, turbine and intake buildings; the condensate polishing facility; radiation protection; physical security; fire protection; plant operating records; modifications; various plant trips, surveillance testing; calibration; maintenance; core power distribution limits; and reporting to the NRC.
Results:
Of the fourteen areas inspected, one item of noncompliance was identified (failure to follow written procedures, paragraph 4).
h2gOCK05000245 oo42 s11327 G
PDR Region I Form 12 (Rev. April 77)
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DETAILS 1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
A. Cheatham, Radiological Services Supervisor J. Crockett, Unit 3 Superintendent F. Dacimo, Quality Services Supervisor E. C. Farrell, Station Services Superintendent B. Granados, Health Physics Supervisor H. Haynes, Unit 2 Instrumentation and Control Supervisor R. J. Herbert, Unit 1 Superintendent J. Kangley, Chemistry Supervisor J. Keenan, Unit 2 Engineering Supervisor J. J. Kelley, Unit 2 Superintendent E. J. Mroczka, Station Superintendent V. Papadopoli. Quality Assurance Supervisor R. Place, Unit 2 Engineering Supervisor R. Palmieri, Unit 1 Engineering Supervisor W. Romberg, Unit 1 Operations Supervisor S. Scace, Unit 2 Operations Supervisor F. Teeple, Unit 1 Instrumentation and Control Supervisor W. Varney, Unit 1 Maintenance Supervisor P. Weekley, Security Supervisor 2.
Status of Unresolved and Open Items New Items:
Unit 1 245/81-14-01, Revision of gauge and instrument calibration program to include fuel pool cooling system instrumentation required for inservice inspection (paragraph 61 245/81-14-02, Implementation of progras to provide feedback to users of gauges and instruments when they are found in error during periodic calibration (paragraph 6 ).
3.
Review of Plant Operation - Plant Inspections (Units 1 and 2)
The inspector reviewed plant operations through direct inspection and observation of Units 1 and 2 throughout the reporting period. Activities in progress included full power operation of Unit I with the exception
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of reductions in power for surveillance testing.
Unit 2 operated at full power through the inspection period with the exception of brief outages following reactor trips on October 15 and October 27.
a.
Instrumentation-Control room process instruments were observed for correlation between channels and for conformance with Technical Specification equirements.
No unacceptable conditions were identified.
b.
Annunciator Alarms The inspector observed various alam conditions which had been received and acknowledged. These conditions were discussed with shift personnel who were knowledgeable of the alams and actions required. During plant inspections, the inspector observed the condition of equipment associated with various alarms.
No unacceptable conditions were identified.
c.
Shift Manning The operating shifts were observed to be staffed to meet the operating requirements of Technical Specifications, Section 6, both to the number and type of licenses. Control room and shift manning was observed to be in conformance with Technical Specifications and site administrative procedures.
d.
Radiation Protection Controls Radiation protection control areas were inspected. Radiation Work Permits in use were reviewed, and compliance with those documents, as to protective clothing and required monitoring instruments, was inspected.
Proper posting of radiation and high radiation areas was reviewed in addition to verifying requirements for wearing of appropriate personal monitoring devices. There were no unacceptable conditions identified.
e.
Plant Housekeeping Controls Storage of material and components was observed with respect to prevention of fire and safety hazards.
Plant housekeeping was evaluated with respect to controlling the spread of surface and airborne con-tamination. There were no unacceptable conditions identified.
f.
Fire Protection / Prevention The inspector examined the condition of selected pieces of fire fighting equipment. Combustible materials were being controlled and were not found near vital areas. Selected cable penetrations were examined and fire barriers were found intact.
Cable trays were clear of debris.
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g.
Control of Equipment During plant inspections, selected equipment under safety tag control was examined.
Equipment conditions were consistent with information in plant control logs.
h.
Instrument Channels Instrument channel checks recorded on routine logs were reviewed.
An independent comparison was made of selected instruments. No unacceptable conditions were identified.
i i. Equipment Lineups The inspector examined the breaker position on switchgear and motor control centers in accessible portions of the plant. Equipment conditions, including valve lineups, were reviewed for conformance with Technical Specifications and operating requirements.
4.
Inspection of New Fuel - Unit 2 Receipt and inspection practices were observed. The inspector reviewed these activities to verify:
compliance with regulatory requirements; compliance with applicable procedures; the procedure was adequately detailed to assure performance of a satisfactory inspection; inspection results satisfied the procedural acceptance criteria, or were properly dispositioned; proper equipment alignment and calibration; radiological controls for worker protection; and measures to prevent inadvertent cri ticality.
The following procedures were reviewed:
OP2209A " Refueling Operations", Revision 6.
OP2210A "New Fuel Assembly and Control Element Assembly Receipt and Inspection", Revision 3.
Inspection and handling of the following new fuel assemblies was observed:
Vendor Number ANSI Number G01 LM09GN G03 LM09GQ G15 LM09H2 G17 LM09H4 G18 LM09H5 G25 LM09HC
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All prerequisites for the receipt and inspection of new fuel were not met.
Specifically, weight tests for fuel handling slings, tools, and cables were not verified. No identifying marks on these items permitted correlation to weight test records. Other similar items were found in the general area of receipt and inspection operations. Records indicating that the particular slings, tools, and cables in use had been tested were not readily available.
Upon identification of this oversight, the receipt inspection activities were halted and necessary load handling gear was tested. Temporary tags were attached documenting the load test. This is identified as an item of noncompliance.
No other unacceptable conditions were observed.
5.
Unit 2 Reactor Trips a.
October 15, 1981 At 1435 on October 15, the unit sustained a scram from full power on low steam generator level in #2 steam generator.
A separate Steam Generator Water Level Control (SGWLC) system is provided for each steam gerierator. The SGWLC systems use several 10 ma to 50 ma GE/MAC current loops. One such current loop serves as a downcomer water level sensing loop which includes the level differential pressure sensor, a level recorder, and the Self-Synchronizing Controller (G.E. 547 series).
The current in this loop is proportional to downcomer level with 50 ma corresponding to 100% level and 10 ma corresponding to 0% level. Nomal operating level is 60% (loop current 30 ma). The Self-Synchronizing Controller (SSC) also receives a level setpoint signal and a signal from another 10 to 50 current loop reflecting steam flow-feedwater flow mis-match (30 ma represents a matched condition). Under nomal conditions in the automatic mode, the SSC compares actual level to the level setpoint and uses the resulting error and the stem flow-feedwater flow mismatch to generate an output current. The output current loop contains an electro-pneumatic converter which produces an air signal ultimately used to position the respective steam generator feedwater regulating valve (FRV).
The SGWLC system performs differently, however, under certain abnomal conditions. On a high steam generator level condition (at 85% downcomer level) control passes from the SSC to a dummy current generator which ultimately results in a rapid closure of the FRVs. This feature is intended to avoid a main turbine trip on high steam generator level (at 90% downcomer level). Normal control is restored by operator action to press a reset pushbutton on the control room C05 panel.
As a technician was re-installing the #2 SGWLC system level recorder following maintenance on October 15, a resistor opened in the 10 to 50 ma level sensing loop. This resulted in a maximum low level error in the S.S.C.,and the FRV to #2 steam generator was rapidly driven open. Level in #2 steam generator rapidly rose to approximately 85%. The SGWLC system shifted to its dummy current source and rapidly shut the FRV. The
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operator was unable to manually reset the SGWLC system and shift to manual mode in time to prevent #2 steam generator level from falling below 36% and causing a reactor scram at 1435. Auxiliary feed initiated automatically at 1438 and was secured at 1504 after level had been restored.
Had the operator shifted the SGWLC to manual mode prior to recorder
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At 1700, steam generator water chemistry samples indicated chloride in concentrations of.85 ppm in #1 steam generator and.69 ppm in
Steam generator blowdown was increased. At 1832, blowdown automatically isolated on high radiation level. Analysis of steam generator water indicated total activities of 7.25E-5 microcuries per milliliter and 6.09E-6 micro-curies per milliliter in #1 and #2 steam generators, respectively and chloride ion concentrations of 1.13 ppm and 1.06 ppm, respectively. After repairs were completed in
- 2 SGWLC system, the reactor was made critical at 1945 on October 15 and held in hot standby while secondary chlorides were reduced. The main turbine was placed on line at 1725 on October 16.
Based on tritium concentrations in the reactor coolant system and in the secondary system with the reactor at 50% power, steam generator leak rates were calculated to be.29 gallons per minute (gpm) and.11 gpm for #1 and #2 steam generators, respectively. With the reacter at essentially full power on October 17, an average of four leak rate detenninations yields leak rates of.09 gpm and.03 gpm for #1 and #2 steam generators, respectively.
Leak rate calculations using tritium concentration differences have been conducted daily. The leak rate detenninations made at full power since October 17 have remained steady through October 31 averaging.027 gpm (.038 max.,.016 min.) and.015 gpm (.028 max.,.009 min.) for #1 and #2 steam generators respectively. The resident inspectors are continuing to follow the steam operator leak rates under open item 336/81-10-03.
There were no unacceptable conditions identified.
b.
October 27, 1981 At 1335 on October 27, the unit sustained a reactor scram from 84% of full reactor power due to a main turbine trip caused by loss of main condenser vacuum.
Over the past several months, a pattern of main condenser tube problems began to emerge. Four adjacent tubes lying in a line near the top of the
"A" condenser tube bundle failed and required plugging. Slight tube leakage had been experienced and plans were made to conduct eddy current testing to determine the location of incipient tube failures. On October 27, power was reduced to 84% and "A" condenser water box entered for testing.
Preliminary analysis of results yielded indications of defects in several apparently randomly located tubes and in one tube in the same linear pattern immediately adjacent to the four failed and plugged tubes.
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A decision was made to unplug the four known defective tubes and conduct eddy current testing cn them to attempt to determine if the failures occurred in similar locations along the length of the tubes. As the tubes were unplugged, a rush of air was heard. Main condenser vacuum fell from approximately 27 inches Hg vacuum to approximately 22 inches Hg vacuum.
The main turbine tripped automatically on loss of vacuum as vacuum fell through 23 inches Hg vacuum. As reactor power exceeded 15%, a reactor scram was initiated upon the turbine trip.
l Condenser tubes with failure indications were plugged.
The reactor was made critical at 1735 on October 27.
Primary to secondary leakage was calculated at 0.04 gpm and 0.03 gpm for the No.1 and 2 steam generators, respectively, during power operation following the trip.
No unacceptable conditions were identified.
6. Inservice Inspection (ISI) Review - Unit 1 A review of the Inservice Inspection program at Unit 1 was conducted to verify actions taken to correct the item of noncompliance cited in Inspection Report l
50-245/81-09.
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l Documents reviewed inclucicd:
--- ASME Boiler and Pressure Vessel Code,Section XI, Subsections IWP and IWV, " Inservice Testing of Pumps and Valves in Nuclear Pcwer Plants",
1977 edition with S'ummer 1978 Addenda.
. --- Surveillance Procedure SP1060 Rev. 4 (9-1-81) "ISI Program Pump Vibration O'
and Hydraulic Test".
--- Surveillance. Procedure SP1061 Rev. 2 (6-29-81) "ISI Power Operated Valve
,3ndCheckValveOperability."
--- Surveillance Procedure SP1081 Rev. 0 (9-1-81) " Fuel Pool Cooling System Operational Readiness Test."
--- Instrumentation and Controls Procedure IC400A Rev. 3 (11-10-80) "Cali-bration of Instruments Used to Satisfy Tech. Spec. Requirements and/or Core Perfortnance Calibration Inputs."
--- Administrative Control Procedure ACP-QA-9.04 Rev. 7 (7-3-81) " Control and Calibration of Measuring and Test Equipment."
--- W.G. Counsil letter to D.M. Crutchfield, dated September 30, 1981.
--- ASME Report 78-WA/NE-5 " Suggested Improvements in the Measurement of Pump Vibration for In-Service Inspection."
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Tests witnessed:
Emergency Condensate Transfer Pump Vibration and Hydraulic Test (SP1060.7) - October 8 Core Spray Pump Vibration and Hydraulic Test (SP1060.2) - October 15 Fuel Pool Cooling System Operational Readiness Test (SP1081) - October 9 and 15 Pump surveillance procedure SP1060 has been revised to include specific corrective actions when test results are unacceptable, to delete an optional method of establishing pump baseline data, and to delete optional use of pump characteristic curves in lieu of established reference valves. Pump test procedures have either been modified to require varying the system hydraulic resistance to an established reference or have been included in a request for relief from code requirements (W.G. Counsil letter to D.M. Crutchfield of September 30,1981).
Valve surveillance procedure SP1061 has been revised to include specific corrective actions when test results are unacceptable.
Conduct of the tests witnessed was in conformance with the revised procedures.
The Fuel Pool Cooling System Readiness Test on October 9 was aborted when it was noticed that the calibration interval of the pump suction and discharge pressure gauges and of the flow instrument had expired.
These gauges and instruments had not been included in the periodic gauge calibration program (IC400A). A full review showed that all other gauges and instruments currently used in the ISI program had been included in the periodic calibration program.
This item is considered open (245/81-14-01) pending revision of IC400A to include Fuel Pool Cooling System Instrumentation.
Further review of the calibration program associated with ISI indicated that no formal method of feedback regarding gauges and instruments found out-of-tolerance during periodic calibrations to gauge and instrument users. Station Administrative Control Procedure ACP-QA-9.04 paragraph 4.1 defines " Measuring and Test Equipment: tools, gauges, instruments,... used to verify conformance to established requirements." Sub-paragraph 6.2.5 states, in part, "When a device is found to be out of calibration, previous measurements, tests, and inspections shall be identified... analyzed, and, if necessary, repeated 81-14-02)perly calibrated equipment..." This item is considered open (245/
using pro pending implementation of this aspect of the calibration progra.
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7.
Earth Tremor (Units 1 & 2)
On October 21,1981, at 1255, the Unit 2 seismic monitors alarmed. An earthquake was reported of approximately 3.7 on the Richter Scale (approximately 0.007 g) with its epicenter located at 4106' North Latitude and 72033' West Longitude.
Unit 1 seismic monitors did not alarm as this tremor was below their threshhold.
Inspections revealed no damage. Both units remained at full power.
8.
Review of Plant Operations - Logs and Records - (Units 1 and 2)
During the inspection period, the inspector reviewed operating logs and records covering the inspection time period against Technical Specifications and Administrative Procedure Requirements.
Included in the review were:
Shift Supervisor's Log
- daily during control room surveillance Plant Incident Reports
- 9/29 through 10/31/81 Jumper and Lifted Leads Log
- all active entries Veintenance Requests and Job Orders
- all active entries Construction Work Permits
- all active entries all active entries Safety Tag Log
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Plant Recorder Traces
- daily during cor.trn! ram surveillance Plant Process Com.tuter Printed
- daily during control room Output surveillence daily during control room Night Orders
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surveillance The logs and records were reviewed to verify that entries are properly made; entries involving abnormal conditions provide sufficient detail to communicate equipment status, deficiencies, corrective action restoration and terting; records are being reviewed by management; operating orders do not i
conflict with the Technical Specifications; logs and incident reports detail no violations of Technical Specification or reporting requirements; and logs and records are maintained in accordance with Technical Specification and Administrative Control Procedure requirements.
There were no unacceptable conditions identified.
9.
Review of Periodic and Special Reoorts Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 and 6.9.2 and Environmental Technical Specification 5.6.1 were reviewed by the inspector. This review included the following considerations:
the report includes the information required to be reported by NRC requirements; test results and/or supporting information are consistent with design predictions and performance specifications; planned corrective action is adequate for resolution of identified problems; detennination whether any information
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in the report should be classified as an abncrmal occurrence; and the validity of reported information. Within the scope of the above, the following periodic reports were reviewed by the insnector:
Monthly Operating Reports Unit 1 Corrections to
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August 1981 Report
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--- Monthly Operating Report Unit I and 2, September 1981 There were no unacceptable conditions identified.
10. 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 cause and adequacy of corrective action. The inspector detemined whether further information was required, and whether generic implications were involved. The inspector also verified that the reporting requirements of Technical Specifications and Station Administrative and Operating Procedures had been met, that appropriate corrective action had been taken, that the event was reviewed by the Plant Operations Review Committee, and that the continued operation of the facility was conducted within the Technical Specification limits.
Unit-1 81-26 Setpoint drift: One of four Isolation Condenser break detection differential switches.
81-27 Setpoint drift:
One of two Isolation Condenser Inlet Valve limit switches resulting in failure of one valve to shut in the maximum 24-second period allowed.
81-28 Failure of Gas Turbina Generator to accept loads due to automatic voltage regulator problems. This report was also submitted outside the required 30-day interval following the event. Gas turbine failures, including this specific event, are discussed in inspection report 50-245/81-11.
81-29 Erratic operation of one of four ECCS reactor Low-Low level switches.
One switch was found to be " sticking" during quarterly surveillance.
After cycling the switch several times, the condition cleared. The surveillance frequency has been increased to monthly.
81-30 Setpoint drift:
two of four main turbine bypass valve RPS time delay relay Failure of Gas Turbine Generator to accept loads due to automatic voltage regulator problems (open resistor). Gas turbine failures, including this event, are discussed in inspecion report 50-245/81-11.
Information letter Setpoint drift: four of four Scram Discharge Volume of October 2, 1981 Water Level Instrument channels failed following a reactor trip on August 17. This event is described in detail in inspection report 50-245/81-11.
11.
Inspector Witnessing of Surveillance Tests The inspector witnessed the performance of surveillance testing of selected components to verify that the surveillance test procedure was properly approved and in use; test instrumentation required by the procedure was calibrated and in use; technical specifications were satisfied prior to removal of the system from service; test was performed by qualified personnel; the procedure was adequately detailed to assure performance of a satisfactory surveillance; and, test results satisfied the procedural acceptance criteria, or were properly dispositioned. The inspector witnessed the performance of:
Unit 1 Suppression Chamber - Drywell Vacuum Breaker Exercise per SP632.4,
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revision 5, on October 8.
--- Emergency Condensate Transfer Pump Operational Readiness Test per SP625.4, revision 3, on October 8.
Emergency Condensate Transfer Pump Vibration and Readiness Test per
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SP1060.7, revision 1, on Oc.tober 8.
--- Fuel Pool Cooling System Operational Readiness Test per SP1081, revision 1, on October 9 and 15.
Core Spray System Operability Test per SP621.10, revision 3, on
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October 15.
Unit 2 R.P.S. Matrix Logic and Trip Path Relay Test per SP2401D, revision 3,
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on October 15.
Control Element Assembly Partial Movement per SP2620A on October 15.
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R.P.S. Turbine Loss of Load per SP2401C, revision 3, on October 27.
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12. Review of Radioactive Material Shipments ~ ~(Unit 1)
The inspector reviewed the activities concerning the shipment of radioactive waste to the Barnwell, S.C., burial site. Those activities included receipt inspections of the shipping cask and liner, solidification of material, g
radiation surveys and the completion of administrative and quality control
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requirements prior to shipment. These-inspectials concerned:
Dewatered Purification Media on October 29, 1981.
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13. Verification of TMI - Task Action Plan Requirements (Units 1 and 2)
The inspector reviewed the licensee's responses and the implementation of commitments made to satisfy the below listed Task Action Plan requirements.
Those requirements are stated in NUREG-0737, Clarification of TMI Action Plan Requirements. The licensee's responses to these and other require-ments are contained in the referenced documents.
II.B.4.2.B Training for Mitigating Core Damage The licensee has completed the initial training program as committed in their December 31, 1980, response to NUREG-0737. This program has been included in the station training program for future training of individuals in the specified job categories. Several Unit I SR0's enrolled in an STA upgrade training program;and Unit II plant equipment operators who were unable to attend because of shift schedules,are scheduled to receive this training.
The station training department is tracking this training require-ment for those individuals.
There were no unacceptable conditions identified.
II.E.1.1.1 Auxiliary Feedwater System (AFW) Evaluation -
Short Tem Modifications (Unit 2)
The NRC identified system design and procedural requirements for the Unit II Auxiliary Feedwater system by letter dated October 22, 1979. The licensee responded to the stated requirements and recommendations with comitments in letters dated November 28, 1979, and December 15, 1980.
Recommendation GS-4, Emergency procedures to transfer pump suction to alternate sources of supply. OP2521, Loss of Feedwater/ Steam Generators addresses the loss of main feedwater with a concurrent unavailability of the condensate storage tank (CST) water inventory. Also, OP2322, Auxiliary Feedwater System, includes paragraph 7.5, Shifting Auxiliary Feedwater Pump Suction to Emergency Fire Water Supply. Minimum CST volume is a stated procedural precautio.
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Recomendation GS-5, Emergency procedures to provide Auxiliary Feedwater Flow independent of any alternating power source. OP2521, Loss of Feedwater/ Steam Generator addresses the condition of a less of all off-site and on-site power (station blackout).
Recommendation GS-6, Confirmed flow path availability of an Auxiliary Feed-water Subsystem flow train. OP2322, Forms 2322-1 and -2 Auxiliary Feedwater valve checkoff lists, require that different operators perform the lineup of each subsystem. This was in agreement to the licensee's response to Item I.C.6, Verifying correct performance of operating activities. License Amendment No. 63 includes additional requirements for completion of an AFW flow verification test before entering Mode 3 after a Cold Shutdown of 30 days.
Recommendation GS-8, Automatic initiation of AFW. This is addressed in Item II.E.1.2.1.A.
Additional Short Term Recomendations Redundant level indications and low level alarms in control room for AFW system primary water supply. Level l
instrumentation and alarms fulfill this requirement.
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pump run verification - This data has been supplied to the Office of Nuclear Reactor Regulation.
Safety-grade indication of auxiliary feedwater flow. This is addressed in Item II.E.1.2.2.
Dedicated individual to realign AFW system manual valves from test mode to provide inspection. This is not applicable, local manual valve realignment is not required for periodic testing.
There were no unacceptable conditions identified.
II.E.1.1.2 Auxiliary Feedwater System Evaluation - Long Term Modifications -
(Unit 2)
By letter dated November 28, 1979, the licensee responded to an NRC long-term modification recommendation.
Recomendation GL-1, Safety Grade Automatic Initiation of Auxiliary Feedwater.
This is addressed in Item II.E.1.2.1.B.
Recomendation GL-3, One AFW pump be capable of being independent of any AC power source for at least two (2) hours. The licensee's November 28, l'J79, response was updated on December 15, 1980. The licensee intends to install air operators on the Auxiliary Feedwater control valves and Auxiliary Feedwater pump turbine steam admission valves. This modifict. tion is scheduled for completion by January 1,1982.
There were no unacceptable conditions identified.
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II.E.1.2.2.C Safety Grade Auxiliary Feedwater' Flow Indication ~(Unit 2)
The Auxiliary Feedwater flow indication instruments have been replaced with a qualified safety grade system. Power supplies have been shifted to Class IE safeguards supply.
There were no unacceptable conditions identified.
II.E.4.2.5.B Containment Isolation Dependability - Containment Pressure Set Point By letters dated December 31,1980, May 20, and July 1,1981, the licensee demonstrated that no modifications to the containment isolation system, containment pressure set point was required. This position was accepted by the NRC in Safety Evaluations dated July 20 and September 18, 1981, for Units 1 and 2, respectively.
There were no unacceptable conditions identified.
II.E.4.2.7 Containment Isolation Dependability - Closure of Purge Valves on High Radiation Signal By letter dated July 1,1981, the licensee presented an analysis to justify a position of not isolating the containment purge valves on a high radiation signal. The licensee concluded that the addition of a high radiation signal was not necessary to ensure safe operation of Unit 1 or 2.
Overall, there are no modifications planned to the containment isolation logic at either unit.
14. Nuclear Review Boards The licenset has published draft revisions to the Nuclear Review Board's Charter and supporting documents, Nuclear Engineering and Operations Procedures NE0 2.01, Reporting of Defects and Noncompliances per 10CFR 21, NE0 2.02, Charter for Nuclear Review Boards and NE0 3.01, Conduct and Format of Nuclear Review Board Audits. These documents were reviewed by the inspector against the requirements of Technical Specification Section 6.
Discussion of these changes was held with licensee representatives. The inspector found that the proposed changes to the Board's standard operating procedures to be a significant improvement in the Board's efficiency of safety review and audits. These changes are scheduled for implementation in November,1981.
There were no unacceptable conditions identified.
15. Exit Interview
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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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