IR 05000327/1981039
| ML20041F796 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 01/18/1982 |
| From: | Butler S, Ford E, Quick D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20041F754 | List: |
| References | |
| 50-327-81-39, 50-328-81-48, NUDOCS 8203170425 | |
| Download: ML20041F796 (13) | |
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UNITED STATES
NUCLEAR REGULATORY COMMISSION o
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E REGION 11
101 MARIETTA ST., N.W., SUITE 3100 ATLANTA, GEORGIA 30303 o
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Report flos. 50-327/81-39 and 50-328/81-48 Licensee: Tennessee Valley Authority 500A Chestnut Street Chattanooga, TN 37401 Facility Name:
Sequoyah Nuclear Plant Docket Nos. 50-327 and 50-328 License Nos. DPR-77 and DPR-79 Inspection at Sequo ah Nuclear P nt near Soddy Daisy, Tennessee
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8A Inspectors:
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Da'te Signed E. J.
ord f
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Sp tier Date Signed
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///#!#'h Approved by:
D. R. Qu'ick, fection Chief, Division of D6te Signed Resident and Reactor Project Inspection SultttARY Inspection on October 6 - December 5,1981 Areas Inspected This routine, unannounced inspection involved 276 inspector-hours on site in the areas of Operational ~ Safety Verification, Unit 2 Initial Criticality and Startup Testing, Licensee Event Report Review, Verification of Open Items and Licensee Conditions, Followup on Plant Incidents and Independent Inspection Effort.
i Resul ts Of the six areas inspected, no violations or deviations were identified in three areas; four violations were found in three areas (328/81-48-01 Failure to follow procedures for surveillance of safety-related equipment and 328/81-48-02 Failure to meet tech spec 3.3.1 for operable automatic trip logic in mode 2 (see l
paragraph 6); 327/81-39-01, 328/81-48-03 Failure to make properly authorized
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modification to Boric Acid Evaporator (CSSC equipment) (see paragraph 9), and 327/81-39-02 Failure to meet equipment separability requirements (see paragraph 10).
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8203170425 820309 PDR ADOCK 05000327 l
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DETAILS 1.
Persons Contacted Licensee Employees C. C. flason, Plant Superintendent J. W. Doty, Assistant Plant Superintendent (Acting)
W. T. Cottle, Assistant Plant Superintendent J. M. McGriff, Assistant Plant Superintendent D. H. Tullis, Maintenance Supervisor (ii) (Acting)
B. ft. Patterson, Itaintenance Supervisor (I)
W. A. Watson, Maintenance Supervisor (E)
L. fl. Nobles, Operations Supervisor W. H. Kinsey, Results Supervisor R. J. Kitts, Health Physics Supervisor J. T. Crittenden, Public Safety Service Supervisor R. L. Hamilton, Quality Assurance Supervisor M. R. Harding, Compliance Supervisor W. M. Halley, Preoperational Test Supervisor J. Robinson, Outage Director Other licensee employees contacted included construction craftsmen, technicians, operators, shift engineers, security force members, engineers, maintenance personnel, contractor personnel and corporate office personnel.
- Attended exit interview 2.
Exit Interview The inspection scope and findings were summarized with the Plant Superintendent and/or members of his staff on October 30, November 20 and December 8, 1981.
The violations were discussed with the Plant Superintendent and he acknowledged.
During the reporting period frequent discussions are held with the Plant Superintendent and his assistants concerning inspector findings and problems.
3.
Licensee Action on Previous Inspection Findings (Closed) Unresolved items 327/81-32-01,328/81-42-04.
The inspector has noted a marked improvement in plant housekeeping during frequent tours of the areas in question.
In addition, the matter was discussed with a Region II Quality Assurance specialist who had opened a similar item during a review of the licensee's housekeeping program. The inspector had no additional questions in this area.
These items are closed.
4.
Unresolved Items Unresnived items were not identified during this inspectio l
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5.
Operational Safety Verification The inspector toured various areas of the plant on a routine basis throughout the reporting period. The following activities were reviewed / verified:
a.
Adherence to limiting conditions for operation which were directly observable from the control room panels, b.
Control board instrumentation and recorder traces.
c.
Proper control room and shift manning.
d.
The use of approved operating procedures.
e.
Unit operator and shift engineer logs.
f.
General shift operating practices.
g.
Housekeeping practices.
h.
Posting of hold tags, caution tags and temporary alteration tags.
1.
Personnel, package, and vehicle access control for the plant protected area.
j.
General shift security practices on post manning, vital area access control and security force response to alarms.
k.
Surveillance, start-up and preoperational testing in progress.
1.
Maintenance activities in progress.
m.
Health Physics Practices.
On October 16, 1981, following the extended maintenance outage on Unit 1, the inspectors made a complete tour of the containment prior to restarting the Unit. The areas toured included the lower containment, fan and accumulator rooms, emergency recirculation sump, upper and lower plenums of the ice condenser and the upper containment.
No significant problems were noted.
On October 20, 1981, the inspector observed post maintenance testing on the IA-A motor driven auxiliary feedwater pump.
The pump had been disassembled to inspect the rotor and measure clearances.
The post maintenance test was performed in accordance with surveillance instruction SI-130.2.
The inspector reviewed the procedure for completeness and discussed the testing with the results test engineer.
The test was completed satisfactorily and the inspector had no further questions. The inspector witnessed a portion of the 1A seal injection filter replacement. The inspector verified that an approved procedure, maintenance instruction MI-81, was in use at the work
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site and that haalth physics special work permit requirements were being followed by the workers. The work was discussed with the maintenance personnel involved in measures to protect the workers from radiation and contamination were discussed with the health physics technician assigned to the job.
The inspector had no further questions.
On October 28, 1981, Unit I returned to power operation after a scheduled maintenance outage that began September 12, 1981.
The unit reached full power on fiovember 1, 1981.
On October 29, 1981, the inspector toured the entire Unit 2 containment prior to initial criticality of the unit.
Areas toured included the lower containment, including raceway, fan accumulator rooms and upper containment.
fio significant problems were noted.
On flovember 3,1981, prior to initial criticality the inspector verified the proper valve lineups for the major flow paths of the Emergency Core Cooling Systems and the containment spray system on Unit 2.
Correct position of motor operated valves was determined by position indication in the control room and position of manual locked valves was determined by local observation.
flo discrepancies were noted.
During the reporting period the inspector attended several meetings of the Plant Operations Review Committee (PORC). The meetings were held to approve various procedure changes and work plans. The inspector observed the conduct of the meetings and verified that a quorum was present as required by the technical specifications.
On riovember 18, 1981, during the performance of Surveillance Instruction SI-166.1 " Full Stroking of Category "A&B" Valves during Operation", the
licensee discovered that valve 1-FCV-63-6 was inoperable.
The Unit 1 talve indicated in the correct position but could not be opened from the main control room.
The valve serves as a cross connect from the discharge of the residual heat removal (RHR) pumps to the suction of the safety injection (SI) pumps for use during long term emergency cooling following a loss of coolantaccident(LOCA).
The valve is in parallel with a redundant valve 1-FCV-63-7 which was successfully tested earlier on flovember 18, there is no automatic function associated with the valve.
Investigation by the licensee's maintenance personnel revealed that the valve operator motor leads were disconnected from the breaker in the 480 volt switchboard. The cable was meggered prior to reconnecting the leads and a short to ground was detected.
A lead was found pinched in the valve operator cover and was determined to be the cause of the short.
The lead was repaired and the motor leads reconnected to the breaker.
The valve was declared operable after a successful functional test. The Plant Superint.tndent assigned the onsite Independent Safety Engineering Group (ISEG) the task of investigating the occurrance to determine the cause.
An inspection of all other 480 volt safety-related breaker cabinets was begun to assu.e that no other similar problems existed. fio other problems were identified.
The ISEG investigation revealed that work had been done on the
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valve which involved lifting of the leads under Work Plan WP 8806 R1 on September 30, 1981. However all work plan documentation was in order including Quality Assurance signatures that indicated that the leads were properly connected after the work was complete. The craftsmen and quality assurance inspector involved with the work were interviewed to determine if the error could have occurred during the job and they were confident that it did not. A review of other work plans, maintenance requests, opreating logs and clearance logs did not reveal any documented work that could have explained the leads being disconnected.
This occurrance was discussed with the maintenance personnel involved and other personnel responsible for related work to ensure they were aware of the problem.
Region II management was informed of the problem initially and kept informed of the licensee's findings and corrective action as they were made known to the inspector.
Due to the minor impact of the valve 1-FCV-63-6 being inoperable and the fact that the licensee identified the problem during routine surveillance testing and took prompt action to correct the situation and assure themselves that similar problems did not exist with other safety-related equipment, this occurrance will be classified as a licensee identified violation in accordance with the Interim Enforcement Policy 45 FR 66754 (10/7/80) guidelines. A notice of violation will not be issued.
On December 3,1981, the inspector observed the final preparation for and the initiation of a liquid waste release from the Cask Decontamination Tank (CDT).
The licensee's release number was 81-222-08-227.
The inspector reviewed data package SI-400.1 which contained the tank sample results and effluent monitor setpoint requirements and S01-77.1C3 which contained recirc requirements for sampling the tank and valve lineup requirements for releasing the tank.
The procedure for releasing waste water was discussed with the Auxiliary Unit Operator in charge.
The inspector accompanied him on the final valve lineup verification and observed the initiating of the release.
The release appeared to comply with regulatory and procedural requirements.
The inspector had no further questions on this matter.
As a result of several complaints regarding excessive overtime worked by licensed operators, the inspector reviewed the matter to detennine overtime limits. The matter was discussed with several operators, the Plant Superintendent, the Assistant Plant Superintendent (0perations) and the Operations Supervisor.
Plant management was aware that operators were required to work in excess of overtime limits and attributed it mainly to the fact that a number of licensed reactor operators had to be removed from shift rotation to attend classes at the licensee's operator training center in prepartaion for taking senior reactor operator examinations.
In addition they felt the problem would be alleviated when other operators that were presently in the training cycle successfully completed their reactor operator exams and received licenses from the NRC.
The Plant Superintendent felt that when overtime limits were exceeded it was necessary and properly authorized as allowed by the licensee requirement.
The inspector reviewed summaries of instances when licensed operators were required to work beyond
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overtime limits which were compiled for a period of approximately three months from August 1981 to October 1981.
The overtime appeared to be fairly well distributed among operators and did not appear excessive to.the point of jeopardizing safe operation of the plant. The inspector is of the opinion that the licensee is complying with the Unit 1 operating license overtime limits for licensed operation. The licensee was encouraged to continue efforts to provide additional licensed operators to alleviate the need for required overtime for operators.
Region II management was informed of complaints received regarding licensed operator overtime and was kept informed of the inspectors findings.
tio violations or deviations were identified.
6.
Prior to initial criticality the inspector monitored and reviewed the licensee's preparations and procedures for this evolution. Additional inspection coverage was provided by regional specialists and a detailed technical description is provided in inspection report (50-328/81-43), dated November 23, 1981.
The inspector, in conjuction with the specialists, determined that license commitments, crew requirements, technical staffing, equipment and instrument calibration, and proper procedural requirements were met. The Unit 2 reactor was declared critical at 10:25 p.m. (CST) on-November 5,1981 with approximately 2x103 counts per second on the source range. Operator actions during initial criticality were timely and correct.
The inspector witnessed portions of the following startup testing:
S/U-7.4 " Rod and boron worth measurement during boron dilution" S/U-7.3.1 " Nuclear Design Check Tests: Boron Endpoint Determination and Isolthermal Temperature Coefficient Measurement" S/U-7.7 " Minimum Shutdown Verification" S/U-7.5 " Rod and boron worth measurements during boron addition" The inspector verified that the procedures for each test were approved and available for use, prerequsites were met and properly signed off, test personnel were knowledgable of test methods and requirements, test equipment was properly installed and calibrated and test results were analyzed in a timely manner by the appropriate test personnel.
Preliminary results'for the tests appeared to be consistant with procedure acceptance criteria.
The inspector had no further questions.
During routine review of operator logs on Unit 2 the inspector noted that on November 6,1981, the licensee had discovered that a monthly functional test of the Solid State Protection System (SSPS) logic, performed on November 5, had identified a problem wi+h the "A" train logic.
The discrepancy was not brought to the Shift Engineer's attention and the Unit was taken critical with the "A" train overpower delta temperature reactor trip logic inoprable.
As soon as the licensee identified the discrepancy they declared the channel inoperable and complied with the technical specification action statement until the affected logic card was replaced and retested to demonstrate operabili ty. The inspector reviewed the circumstances surrounding the event and discussed the licensee's findings with the instrument section
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supervisor.
It was determined that on flovember 5 the instrument section was performing surveillance instruction SI-90.82 (IMI-99-SSPS) which is a routine monthly functional test of the SSPS. The procedure requires that during the conduct of the logic test, if a discrepancy is identified the shif t engineer is to be notified and the discrepancy corrected prior to proceeding with the test.
In this instance the discrepancy was identified on a maintenance request to replace the bad logic card, however, the logic test was completed without replacing and retesting the card and the protection channel was returned to service.
The instrument foreman in charge of the work stated that he was unable to locate the shift engineer to process the maintenance request (MR)
and turned it in to the engineering group before leaving work. When the Mr.
was reviewed the next morning after the Unit was taken critical and was in mode 2, the instrument engineer realized they were in violation of technical specifications and informed the appropriate management personnel.
Failure to follow SI-90.82, by not notifying the shift engineer of the bad SSPS logic test and not correcting the discrepancy before proceeding with the remainder of the logic test, is a violation of technical specification 6.8.1.7 which requires that approved procedures be implemented for surveillance activities of safety-related equipment (328/81-48-01).
Entering mode 2, startup, with an inoprable "A" train SSPS logic is a-violation of technical specification 3.3.1 which requires the automatic trip logic to be operable in mode 2 (328/81-48-02).
These violations will be identified in Appendix A - flotice of Violation.
The Instrument Supervisor stated that the occurance was discussed with the appropriate instrument personnel and the precaution regarding the action to take in the event that a bad logic test is discovered will be noted in the data sheet of SI-90.82 as well as in the precaution section.
As a result of the Unit 2 containment spray system valve misalignment identified on August 26,1981 (See IE reports 327/81-31,328/81-40),the Region II Director required in a memorandum, dated September 30, 1981, that the licensee not proceed above 5% power until they received concurrence from the flRC.
As specified in paragraph 8 of IE reports 327/81-36, 328/81-45 the concurrence would be based on a reverification of the implementation and effectiveness of the corrective measures outlined in Licensee Event Report LER SQR0-50-328/81104.
On November 12, 1981 the Chief of Reactor Projects Section 1A, Projects Branch 1, Division of Resident and Reactor Project Inspection, Region 11 came to the Sequoyah site to inspect the imple-nentation and effectiveness of the licensee's corrective action.
His inspection consisted of interviews with plant management, licensed operators and non-licensed operators and observation of plant operations in the control room and a walk through of the plant to observe general conditions and work in progress. At the conclusion of his inspection he provided verbal concurrence to the Plant Superintendent to proceed with testing beyond 5% power based on satisfactory findings.
The concurrence was documented in a memorandum from the Director, Office of Inspection and Enforcement, Region II, dated November 16, 1981. The memorandum also confirmed the licensee's commitment not to proceed beyond the 50% power
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plateau without NRC concurrence based on continued effectiveness of corrective action.
No other violations or deviations were identified.
7.
Licensee Event Report (LER) Review During the reporting period, LER's were reviewed on a routine basis as they were received from the licensee.
Each LER was reviewed to determine that:
a.
The report accurately described the event b.
The reported cause was accurate and the LER fonn reflected the proper cause code c.
The report satisfied the technical specification reporting requirements
'with respect to information provided and timing of submittal d.
Corrective action appeared appropriate to correct the cause of the event e.
Corrective acticn has been or is being taken f.
Generic implications if identified were incorporated in correctiva action
Corrective action taken or to be taken was adequate, particularly to prevent recurrence h.
The event did not involve continued operation in violation of regulatory requirements or license conditions.
The following LER's were found to be satisfactory and are closed:
81-078,81-081 thru 81-084,81-086 thru 81-089,81-091 thru 81-104,81-107, 81-109 thru 81-113 and 81-115 thru 81-118.
The following LER's have been selected for detailed review and followup or tracking of described design changes and findings will be reported when complete: 81-090,81-105, 81-106,81-108, 81-114 and 81-119.
No violations or deviations were identified.
8.
Verification of Open Items and Unit 2 License Conditions (Closed) Open item 327/81-10-06: The i'spector reviewed the changes made to the Offsite Dose Calculation fianual (0DL't) which adds additional nuclides to monthly dose assessment calculations anu provides the latitude to change the list of principle isotopes which are analyzed or modify the correction -
factor if the monthly dose estimates do not account for at least 95% of the annual dose calculation. These changes were discussed with the Region II
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11ealth Physics specialist who opened the 12m and he had no further questions. This item is closed.
Paragraph 2.c.(16) R of operating license DPR-79 requires that the licensee limit the purge valve openings to less than or equal to 50 degrees. This requirement stems from containment purge isolation valve reliability studies and was imposed in conjunction with the requirements of NUREG-0737 "Three tiile Island (Ti1I) Action Plan Requirements".
The inspector reviewed Work Plan WP 9202 which documented the work. The valve stop adjustments were replaced with elongated stops and adjusted to limit valve opening to 50 and the stem mounted position indicators were modified to indicate valve full open at the 50 position.
According to the work plan all purge system supply and exhaust containment isolation valves were modified.
The inspector also selected several of the valves and verified that the modified stop adjustments had been installed as specified.
This license condition is closed.
As required by paragraph 2.c.(16)j. of operating license DPR-79, the licensee performed endurance testing of the Unit 2 Auxiliary Feedwater (AFU)
pumps prior to exceeding 5% power. The inspector observed various portions of the testing on both the motor driven and turbine driven pumps.
The inspector verified that the testing was done in accordance with approved procedures and that properly calibrated test equipment was being used.
The results were discussed with the Preoperational Test Supervisor subsequent to the completion of the testing and it was reported that no significant deficiencies were identified. The licensee is preparing a test report to forward to the NRC as required by the licensee condition. This licensee condition is closed.
9.
Followup on Plant Incidents On November 4, 1981, Unit 2 experience an inadvertent reactor trip - safety injection.
The unit haa not yet been c 'itical, however, reactor trip breakers were shut and control rods wer. being withdrawn in preparation for initial criticality.
Following the sa'Ety injection the inspector verified that operators were recovering the pl'at in accordance with approved pro-cedures and plant parameters were stable.
Safety systems were reported to have operated properly and the NRC was notified per 10 CFR 50.72.
The inspector reviewed the circumstances surrounding the incident and determined that the licensee's instrument technicians were performing surveillance instruction SI-90.12 which is a monthly functional test of the reactor trip instrumentation. The test was being performed on channel A.
The bistable for the A channel of low pressurizer pressure safety injection was tripped as a part of the surveillance test. After approximately twenty mi'.Jtes the bistable status light for the C channel of low pressurizer pressure came on and all B train components actuated. The inspector observed a recreation of the event and during the recreation the C channel status light came on simultaneously with the tripping of the A channel bistable. Trouble shooting, by the licensee, revealed that the insulation on the input lead from the tripped pressurizer pressure bistable to the universal logic card
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had broken and was in contact with another input pin on the logic card.
This gave the B train logic a 1 out of 3 input which actuated the reactor trip - safety injection for B train components. The affected lead was repaired and a logic test perfomed satisfactorily.
Region II management was kept appraised of the situation and informed of the final results of the licensee's trouble shooting.
The licensee recommenced their approach to criticality on November 5, 1981.
On November 6,1981, Unit 1 tripped from 100% power. The trip was caused
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when the feedwater condensate demineralizer resin beds insolated and the main feed pumps tripped on low suction pressure. The isolation of the resin beds occured when an electrician working on a modification to the resin transfers portion of the control circuitry of the condensate demineralizer system allowed his screwdriver to short control power to ground and blew the fuse. With control power to the system lost, the condensate demineralizer resin bed inlet valves failed shut.
Safety systems were reported to have operated properly and the NRC was notified per 10 CFR 50.72.
Work was stopped on the condensate demineralizer syste.1 and the blown fuse replaced.
Restart of the Unit commenced on November 7, ;981.
During the restart, the unit tripped from approximately 11% power wher main feed pemp oscillation caused overfeeding of one steam generator. Systems appeared to operate properly and the NRC was notified per 10 CFR 50.72.
Recovery was une'entful and the Unit returned to power later in the day. The licensee is planning design changes to the control room circuirty of the condensate demineralizer system since loss of the single control power circuit would isolate the resin beds for both Units and cause both to trip if the resin beds were in service.
On November 10, 1981, the licensee detected high levels of radioactive xenon and rubidium in the auxiliary building.
Access to the building was immediately restricted and the necessary health physics precautions were ta ken.
Health physics and operations personnel entered the building to locate and isolate the leak.
The leak was traced to an open vent valve on the "B" Boric Acid Evaporator Package (BAEP). The valve was shut and the leak stopped.
Eleven persons received minor skin and clothing contamination which did not require any extensive decontamination effort.
No significant radiation exposure was received and there was no indication of any of the activity being released offsite. The NRC was notified per 10 CFR 50.72 even though there was no specif1c requirement to do so. The inspector reviewed the circumstances surrounding the incident and determined that the vent valve that was left open was a temporary valve that was installed on the evaporator vent condenser to aid in starting up the unit. The inspector determined that a similar valve was installed on the "A" BAEP and neither valve appeared on the system drawing (47W809-6) or in the System Operating Instruction S01-62.6 " Boron Recycle System". The valve should normally be shut and the licensee initiated a temporary change to the system valve check list in order to maintain configuration control over the valve. The inspector noted that the temporary valve on the "B" BAEP was installed April 18, 1980 under temporary alteration TACF 80-222-62. There was no TACF associated with the "A" BAEF modification.
There was no design change request associated with the modification which is a requirement of i
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Administrative Instruction AI-9, " Control of Temporary Alterations," if the modification is to remain in effe d over sixty days.
Since the BAEP's are included on the list of Critical Structures, Systems and Components (CSSC)
in the Operational Quality Assurance Manual (0QAM), modifications to the system should have been accomplished in accordance with procedures for d(isgn changes to CSSC equipment which would have included drawing and oprating instruction changes. The lack of drawing and operating instruc-tion changes resulted in a loss of configuration control and a leak of radioactive material into the auxiliary building. This is a violation of 10 CFR 50, Appendix B, Criterion III, Design Control and will be identified in Appendix A - Notice of Violation (327/81-39-01, 328/81-48-03).
On November 13, 1981, during initial testing of the Unit 2 main generator exciter, the licensee experienced damage to the exciter / generator radial leads.
The unit was shutdown on November 14 to disassemble and repair the exciter unit and is still shutdown as of the end of the reporting period.
During the shut down of Unit 2 on November 14, the licensee experienced a problem with a control rod. During the normal insertion of the control bank, rod F-2, in control bank B, stopped moving in at approximately 190 steps. All other rods were inserting normally. The reactor was already subcritical at the time of the discovery and technical specification shutdown margin requirements had been verified prior to shutdown. The rod was tripped into the core after trouble-shooting verified the problem to be in the electrical portion of the rod control system and not a mechanical sticking of the control rod itself.
The licensee appeared to satisfy all Abnormal Operating Instruction and Emergency Plan requirements and the NRC was notified per 10 CFR 50.72.
Additional troubleshooting perfonned with the Unit in cold shutdown identified the problem as a bad power connector to the F-2 control rod driven mechanism. The connector was repaired and tested satisfactorily.
On November 23, 1981, Unit 1 tripped from 100% power.
The trip occurred when #4 steam generator Main Steam Isolation Valve (MSIV) inadvertently went shut during the performance of surveillance instruction SI-618 " Safeguards protection system continuity test (monthly)".
The inspector went to the main control room after the trip and observed plant recovery operations.
The important plant parameters appeared stable and operators were recovering per approved procedures. Safety systems appeared to have operated properly and the NRC was notified per 10 CFR 50.72. The inspector reviewed the surveillance instruction and discussed its conduct with the instrument personnel involved and it appeared to have been perfonned as described.
Once plant conditions werc stable the licensee attempted to recreate the situation to determine if the inadvertent MSIV closure would repeat.
It did not. The licensee continued with further troubleshooting of the circuitry and components involved to attempt to explain the occurrence.
No other problems could be identified., The valve was tested from the main control room and the local test switch with satisfactory results.
The inspector discussed the troubleshooting done with the Instrument Supervisor and the cognizant instrument engineer and had no further questions.
The unit was returned to power operation on November 2 X
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On November 26,1981, Unit 1 tripped from approximately 45% power. The licensee was increasing power with only the "A" main feed pump (MFP). When the unit reached 40% power, the condensate to the "B" MPF isolated because the itFP turbine had not been reset. There was enough steam leakage past the
"B" 11FP turbine throttle valve to cause the itFP condenser pressure to increase. The pressure in the
"A" fiFP condenser also increased since the two are crossconnected thru a drain line and the "A" 11FP tripped causing a turbine trip and reactor trip.
Safety systems were reported to operate properly and the NRC was notified per 10 CFR 50.72. The' unit was returned to power later that day.
The licensee is modifying operating procedures to ensure that an idle MFP turbine is reset or the steam supply manually isolated prior to exceeding 40% power.
No other violations or deviations were identified.
10.
Independent Inspection Effort The inspector routinely attended the morning scheduling and staff meetings during the reporting period.
These meetings provide a daily status report
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on the operational and testing activities in progress as well as a discussion of significant problems or incidents associated with the start-up testing and operations effort.
During a tour of the Unit 1 auxiliary instrument room on November 4,1981 it was observed that temporary test leads were connected from test points in two different and redundant reactor protection channels to a common strip chart recorder.
This appeared to be a violation of the separability requirements for redundant protective channels. This condition was brought to the attention of the licensee that same afternoon.
It was determined through discussions with management and technical personnel that the recorders had been installed using Temporary Alteration Control Forms (TACF).
Later, the Plant Operations Review Committee (PORC)
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made a determination that the connection of recorders to test points was not
an alteration or modification and that the itaintenance Request (11R) system I
and an instrument maintenance log could be used to install, remove and maintain a record of recorder installation. However, PORC failed to specifically consider the case of multiple protection sets being connected into a single recorder. This created the potential for the approved safety design of the plant to be compromised due to violation of the separability requirements of 10 CFR 50, Appendix A, Criterion 22. This violation is identified in Appendix A Notice of Violation (327/81-39-02).
The licensee conducted an investigation documented by a written report which contained the following: a description of the event, the controls in effect, an evaluation of possible failure modes, and an evaluation of assumed loss of protective safety function.
During a subsequence inspection
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of the auxiliary instrument room that same evening, it was observed that all
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temporary connections between the protection channels anu strip chart recorders were removed. The licensee's response was thorough and timely in the application of immediate and long term corrective action.
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'12 On November 17, L1981, the inspector attended a meeting _ of Region II officials and the licensee at the corporate headquarters in Chattanooga, Tennessee.
The meeting was held to present the NRC's findings of the
~ Systematic Assessment of Licensee Performance for the period July 1,1980 thru June 30, 1981.
No violations or deviations were identified.
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