IR 05000259/1982013
| ML20054K270 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 05/14/1982 |
| From: | Cantrell F, Chase J, Paulk G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20054K246 | List: |
| References | |
| TASK-2.B.1, TASK-2.B.2, TASK-2.B.3, TASK-2.B.4, TASK-2.F.1, TASK-2.F.2, TASK-2.K.3.22, TASK-2.K.3.28, TASK-TM 50-259-82-13, 50-260-82-13, 50-296-82-13, NUDOCS 8207010358 | |
| Download: ML20054K270 (12) | |
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NUCLEAR REGULATORY COMMISSION
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o REGION 11 ITs E
101 MARIETTA ST., N.W., SulTE 3100 ATLANTA, CEORGIA 30303
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Report Nos. 50-259/82-13, 50-260/82-13 and 50-296/82-13 Licensee: Tennessee Valley Authority 500A Chestnut Street Tower II Chattanooga, Tennessee 37401 Facility flame:
Browns Ferry Nuclear Plant Docket Nos. 50-259, 50-260 and 50-296 License Nos. DPR-33, DPR-52 and DPR-68 Inspection at Browns Ferry site.near Athens, Alabama b
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7/FL Inspectors:
J. W. Chase
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Date Signed f$b Sb3/PL
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D'te Signed G. L. Paulk a
Approved by:
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F'.' S. Cantrell, 'Sdef t6rythief, Division of Date Signed Projects and Resident Programs Sultf1ARY Inspection on March 26 to April 25, 1982 Areas Inspected This routine inspection involved 225 resident inspector-hours in the areas of operational safety, licensee action on previous inspection findings, maintenance, surveillance testing, independent inspection efforts, reportable occurences, THI action items, Unit 3 startup, organization changes, plant physical protection and reactor trips.
Results Of the eleven areas inspected, no violations or deviations were identified in nine areas. Three violations were found in two areas.
[ Violation of Technical Specification 3.5.F (Unit 2_), paragraph 8; violation of Technical Specification 6.3.A.6 (Unit 3), paragraph 8; violation of Technical Specification 6.3.D.2 (Unit 1), paragraph 5.]
8207010358 820624 PDR ADOCK 05000259
PDR L
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DETAILS 1.
Persons Contacted G. T. Jones, Power Plant Superintendent J. R. Bynum, Assistant Power Plant Superintendent J. R. Pittman, Assistant Power Plant Superintendent L. W. Jones, Quality Assurance Supervisor W. C. Thomison, Engineering Section Supervisor A. L. Clement, Chemical Unit Supervisor D. C. !!ims, Engineering and Test Unit Supervisor A. L. Burnette, Operations Supervisor R. Hunkapillar, Operations Section Supervisor T. L. Chinn, Plant Compliance Supervisor M. W. Haney, Mechanical flaintenance Section Supervisor T. D. Cosby, Electrical flaintenance Section Supervisor R. E. Burns, Instrument itaintenance Section Supervisor J. E. Swindell, Field Services Supervisor A. W. Sorrell, Supervisor, Radiation Control Unit R. E. Jackson, Chief Public Safety R. Cole, QA Site Representative, Office of Power Other licensee employees contacted included licensed reactor operators and senior reactor operators, auxiliary operators, craftmen, technicians, public safety officers, quality assurance, quality control and engineering person-nel.
2.
flanagement Interviews Management interviews were conducted on March 26, April 2, 9 and 23,1982, with the Power Plant Superintendent and/or the Assistant Power Plant Superintendents and other members of his staff. The licensee was informed of three violations identified during this report period. The licensee did not object to the three violations identified.
3.
Licensee Action on Previous Inspection Findings (Closed) Open Item (259/80-47-02) Celcon Contact Arm Retainer Fire. The licensee updated the response to IE Bulletin 78-01 and revised Electrical Maintenance Instruction 53.
The inspector. had no further questions.
(Closed) Open Item (296/78-30-05)
Conflict between BFA 45 and BF 6.2.
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licensee has updated the Standard Practice 7.6 used to detail Trouble Report Implementa tion. The inspector had no further questions.
(Closed) Violation (259/82-32-01)
Failure to submit a prompt report required by 10 CFR 50.72. The inspector verified that corrective action taken by the licensee was adequate to prevent future recurrence.
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(Closed) Unresolved Item (259/81-32-06) Unreviewed maintenance records requiring QA supervisor review.
The inspector reviewed current backlog of records requiring QA supervisor review.
The unreviewed records have been significantly reduced and, therefore, the inspector has no further ques-tions.
(Closed) Violation (259, 260/81-32-04, 296/81-32-02)
Failure of Quality Control (QC) to do required surveys. The inspector reviewed the current tracking system for surveys and reviewed several surveys to ensure timely completion.
The inspector also discussed the status of the survey program with the QC Supervisor that is charged with the responsibility for the survey program.
The inspector had no further questions.
(Closed) Violation (259/82-32-02, 260/81-32-03, 296/81-32-01)
Failure _to have training or instructions for the Shift Technical Advisor, STA, on how to perform a QC review of Trouble Reports (TRs). As of this time QC person-nel are reviewing TRs prior to work on safety-related equipment.
In addi-tion, Standard Practice BF 7.6 has been issued which implements the N-0QAM TR review program.
The inspector had no further questions.
(Closed) Violation (260/81-18-02)
Failure to have an approved procedure during a feed water hydrostatic test.
The inspector reviewed numerous TRs and found that all had been reviewed by the plant QA staff prior to work.
The inspector had no further questions.
(Closed) Violation (260/81-35-02)
Failure to maintain drywell to suppres-sion chamber differential pressure at greater than 1.3 psid. The inspector verified that the procedure, SI 4.2 F-17, which sets the low alarm setpoint had been changed on all units to alann prior to the pressure decreasing below the technical specification limit.
4.
Unresolved items There were no unresolved items identified during this report period.
5.
Operational Safety The inspectors kept informed on a daily basis of the overall plant status of any significant safety matters related to plant operations.
Daily discus-sions were held each morning with plant management and various members of the plant operating staff.
The inspectors made frequent visits to the control room such that each was visited at least daily when an inspector was on site.
Observations included instrument readings, setpoints and recordings; status of operating systems; status and alignments of emergency standby systems; purpose of temporary tags on equipment controls and switches; annunciator alarms; adherence to procedures; adherence to limiting conditions for operations; temporary
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alterations in effect; daily journals and data sheet entries; and control room manning.
This inspection activity also included numerous informal discussions with operators and their supervisors.
General plant tours were conducted on at least a weekly basis.
Portions of the turbine building, each reactor building and outside areas were visited.
Observations included valve positions and system alignment; snubber and hanger conditions; instrument readings; housekeeping; radiation area con-trols; tag controls on equipment; work activities in progress; vital area controls, personnel badging, personnel search and escort; and vehicle search and escort.
Infomal discussions were held with selected plant personnel in their functional areas during these tours.
In addition a complete walkdown which included valve alignment, instrument alignment, and switch positions was performed on the standby liquid control system and the containment atmo-sphere dilution system (Unit 3).
During a routine tour of Unit I reactor building on April 21, 1982, the inspector noticed that the doors to the Unit 1 "A" and B" reactor water cleanup (RWCU) rooms were open. These areas are both classified as high radiation areas where the intensity of radiation is >1000 mrem /hr.
The inspector questioned two TVA personnel who were arouH~d the "B" RWCU room as to who was guarding the "A" RWCU room door.
Both personnel stated that they were not charged with observing that door.
In addition, they were both in a position which prevented them ft x directly observing the
"A" RWCU room door.
Based on plant layout, it was possible for personnel to enter the
"A" RWCU room unobserved.
The inspector's investigation into this incident showed that operations personnel had unlocked both doors to allow maintenance personnel to enter the rooms to change the oil in the RWCU pumps. After the doors were unlocked, no one was directly charged with or designated to guard the door to prevent unauthorized entry.
On April 23, 1982, the Assistant Plant Superintendent was informed that failure to maintain positive control over the entrance to the
"A" RWCU pump room was a violation of Technical Specification 6.3.D.2 which requires that areas with intensity of radiation >1000 mrem shall be locked.
(259/82-13-01)
6.
Maintenance Observation During the report period, the inspectors observed the below listed main-tenance activities for procedure adequacy, adherence to procedure, proper tagouts, adherence to technical specifications, radiological controls, and adherence to quality control hold points.
1.
Troubleshooting Unit I generator ground 2.
Repair Unit 3 EHC control system 3.
Troubleshooting Unit 3 reactor core isolation cooling electical over-speed trip.
4.
Change out of block valve on Unit 3 instrument rack.
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In the above area, no violaitions or deviations were identified.
7.
Surveillance Testing Observation The inspectors observed the performance of the below listed surveillance procedures. The inspection consisted of a review of the procedure for technical adequacy, conformance to technical specifications, verification of test instrument calibration, observation on the conduct of the test, removal from service and return to service of the system and a review of test data.
1.
Scram Discharge Volume Level Instruments SI 4.1.A.8 2.
Reactor Building Static Pressure SI 4.2.A.18 3.
Reactor Vessel Head Bolting Studs SI 4.6.A.5 4.
Functional Test Reactor Water Level SI 4.2.A.3 In the above area, no violations or deviations were identified.
8.
Independent Inspection Effort During this report period, the inspector reviewed the Unit 3 hydrostatic test procedure (SI 3.3.1.A) perfonned on March 26-28, 1982.
This procedure pressurizes the reactor vessel to normal operating pressure while main-taining temperature in the reactor from 187 to 210 F.
The procedure review consisted of ensuring that the pressure-temperature limits were maintained as required by the technical specifications. The minimum loading tempera-ture for the head bolts, vessel flange and head flange were maintained and the procedure was followed.
Procedure SI3.3.1.A requires the primary coolant temperature to be main-tained <210 F if primary containment is not established. Technical Speci-ficatioii 3.7. A.2 requires primary containment to be established if reactor water temperature is above 212 F.
The review of SI 4.6. A.5, Reactor Vessel Head Bolting Studs, showed that on March 27,1982, the temperature, as read on the strip chart recorder for the discharge of recirculation pump A, was recorded as 211 F for 10:00 p.m. and 11:00 p.m.
The thermocouple readings for the metal temperature on the feedwater nozzle, vessel top head flange and vessel head, obtained from SI 4.6.A.2, Reactor Vessel Shell Temperature and Reactor Coolant Pressure Monitoring during Hydrostatic or Leak Tests, showed the temperature to be 211 F to 210 F starting at 11:00 p.m. to 12:00 a.m. on March 27, 1982.
The inspector determined that with the temperature > 210 F., primary con-tainment was not established in that the airlock doors entering the primary containment were open. The licensee identified that in addition to the airlock doors being open, the drywell head was not installed, thereby negating primary containment integrit.
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On April 9,1982, the Assistant Plant Superintendent (Operations) was informed that not establishing primary containment as required by SI 3.3.1.A prior to exceeding 210 F coolant temperature, was a violation of Technical Specification 6.3.A.6 which requires that surveillance and testing pro-cedures be followed.
The licensee did not refute the violation.
(296/82-13-01)
During a backshift tour of the Unit 2 control room at 7:50 p.m. on April 21, 1982, the inspector noted the reactor core isolation cooling system con-troller was in the manual position.
The system, thus would not perform its intended automatic function during accident conditions.
Additionally, the inspector noted that the high pressure coolant injection system was inoper-able due to maintenance (tag out No.82-373). The HPCI system was declared inoperable at 2:35 p.m. on April 21, 1982. Operability surveillance instructions on redundant safety equipment were conducted as required by technical specifications and completed at 7:00 p.m. on April 21, 1982.
The operator placed the RCIC controller in automatic as required at the completion of the RCIC operability surveillance (SI 4.5.F).
It was the common practice to check for steam leaks in the vicinity of the RCIC about 30 minutes after the operability surveillance was completed.
During the steam leak inspection, the opertor placed the RCIC controller in manual to ensure the RCIC did not start during the steam leak inspection. The steam leak inspection is not addressed in the RCIC surveillance instruction or any other plant procedure.
The operator said that the controller was in manual for only a short time (10 minutes) before the inspector's tour. When questioned about the manual position of the controller by the inspector, the operator immediately returned the controller to automatic.
The inspector immediately notified the shift engineer of this observance.
The inspector infomed the Assistant Plant Superintendent on April 23, 1982, that failure to have the Unit 2 reactor core Isolation cooling system operable as required by Technical Specification 3.5.F was a violation.
(260/82-13-01)
During a document review of the high pressure fire protection system control diagram (47W610-26-1), the inspector noted that the print referenced a cutout to prevent the fire pumps from starting for the first ten minutes af ter a loss of coolant accident (Note 6). This action prevents potential diesel overloading during emergency cooling initiation and sequencing.
The 10 minute period would allow for a stabilization period after the LOCA.
The inspector reviewed various diagrams, logic circuits, and surveillance instructions and found that the 10 minute time delay does not exist and apparently was never used in the plant fire pump starting control circuits.
Instead, the currently configured circuitry maintains a constant block signal to prevent the electric fire pumps from starting, unless manually overriden, during an accident condition.
Note 6 was apparently initially added in error. The Plant fianager was informed on April 23, 1982, that this item will remain an open item until the control diagram is corrected to reflect plant operation and configuration.
(259,260,296/82-13-02)
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9.
Reportable Occurrences The below listed licensee event reports (LERs) were reviewed to determine if the information provided met NRC reporting requirements. The determination included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of each event. Additional in-plant reviews and discussions with plant personnel as appropriate were conducted for those indicated by an asterick:
LER NO.
Date EVENT
- 259/81-71 11/11/81 Level switch LIS-3-203B calibration drift.
- 259/81-72 11/12/81 Pressure transmitter PT-74-65 out of calibration.
- 259/81-28 11/23/81 Failure to - take required air samples.
259/82-16 2/17/82 Level switch LIS-3-203C calibration dri f t.
- 259/82-17 3/8/82 Reactor water level Yarway LI-3-46A inoperable.
- 260/82-10 10/21/81 SI 4.1.B.2 not completed at required frequency.
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260/82-11 2/15/82 Level transmitter LI-64-66 drif t.
- 260/82-12 3/15/82 HPCI Valve 73-18 would not stay open on test.
- 296/81-60 10/12/81 RHR Valve 74-75-failed to open in required time limit.
- 296/81-66 11/7/81 CAli Ril-90-250 inoperable.
- 296/81-74 12/30/81 Target Rock relief valve failure. to lift.
296/82-05 3/5/82 Reactor water level switches LIS-3-203A and LIS-3-203D out of calibration.
The inspector reviewed the file of Licensee Reportable Event Determination (LRED) records for January - itarch,1982 on Units 1, 2,' and 3.
The inspec-tor noted that a LRED dated January 21, 1982 addresses concerns related to a non-conservative Unit 3 diesel load analysis in the case of a LOCA with concurrent loss of offsite power. The FSAR (Section 8) diesel load analysis does not assume an auto-start of.a raw cooling water pump (300 HP) on loss of offsite power. Additionally, FSAR Section 10.7 specifically states that raw cooling water pumps are not started automatically in either loss of power mode or design basis accident mode since they are not required for a safe shutdown. The start of RCW pump 3D on the 3EC diesel generator pro-vides extra loading such that the residual heat removal pump powered from the diesel will have an extended acceleration time. The engineering design analysis calculations done by the licensee to account for the RCW pump start provides a safety margin of 2 seconds for the RHR pump to be at full speed before LPCI full injection.
The analysis further states that the " diesel generator loading after the addition of the RCW pump will be within the short
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term rating of the diesel generators, and the unit operator can adjust this loading if he feels it is necessary before any diesel generator ratings are exceeded." The inspector is concerned about the auto-start teature of the RCW pump and its affect on other safety-related equipment and the statement that operator action nay be required during accident conditions to assure diesel availability for LPCI injection.
This item will remain an open item for further evaluation by the inspector.
(296/82-13-03)
10. THI Action Items The following action items were reviewed by the inspectors during this report period:
a.
II.B.1.2 and II.B.1.3 Reactor Coolant System Vents. TVA responded to this item in a letter to NRR on December 23, 1980. TVA concurs in the consensus of the BWR Owner's Group that the existing reactor venting capability and procedures are fully satisfactory.
This item will remain open.
b.
II.B.2.2.8 Plant
' 'iing Design Review and Environmental Qualifica-
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tion of Equipme'
. paces / Systems used in Post-Accident Operations.
TVA in a letter nKR on December 23, 1980 addressed the review of vital area access in a post-accident situation as being completed.
The electrical equipment qualification is addressed by TVA response to IE Bulletin 79-018.
This item will remain open for tracking purposes.
c.
II.B.3.2.B Post-Accident Sampling. The post-accident sampling facility (PASF) is currently under construction in the turbine building.
On October 28, 1981, the licensee submitted to NRR a proposed completion
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date for the PASF in the 1982/83 timeframe.
This item will remain open.
d.
II.F.1.1.B.2 and II.F.1.2.B.2 Accident Monitoring for Iodine /Partic-ulate and Noble Gases.
The licensee has reported to the NRC on June 1, July 2, and August 10,-1981, that difficulty existed in the procure-ment of equipment to adequately implement these items and that no instrumentation is currently available that will fully meet the NRC requirements for sampling and analysis of plant effluents.
This item will remain open, e.
II.F.1.4 Containment Pressure Monitor. The licensee submitted its revised completion schedule of this item in a letter to NRR on October 28, 1981. The current schedule calls for installation in 1983 and 1984. This item will remain open.
f.
I I. F.-l. 5 Containment Level.
TVA submitted to NRR on October 28, 1981 the current completion schedule for this item.
The item is scheduled for canpletion in 1983 and 1984.
This item will remain open.
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II.F.2.3.B Instrumentation for Detection of Inadequate Core Cooling.
TVA is participating in the BWR Owner's Group. activities in this area.
TVA does not intend to proceed any further in design until final approval of Regul,atory Guide 1.97.
This item will remain open.
h II.K.3.22.8 Automatic Switchover of Reactor Core Isolation Cooling System Suction.#The licensee believes that the addition of automatic switchover of RCIC suction from the condensate storage tank to the suppression pool is not required.
Adequate time to perfonn the swtichover manually exists for events where RCIC is needed.
During large volume high pressure injection required evolutions, the HPCI system provides the necessary flow to maintain core coverage.
The RCIC System is used during low flow high pressure injection required evolutions. Current licensee procedures are adequate to manually switchover RCIC supply sources when required.
This item will remain open.
i.
II.K.3.28 Verify Qualification of Accumulators on Automatic Depress-urization System Valves.
The action item requires the licensee to address two separate concerns on short-term and long-term operability requirements for the ADS valves and accumulators. The short-tenn concern requires that ADS accumulators have sufficient capacity to cycle the valves open five times-at design pressure.
The licensee has performed field tests to verify that this requirement is satisfied.
The long-tenn concern addresses the requirement for Emergency Core Cooling Systems to withstand a hostile environment and still perfonn their function for 100 days folloWing an accident.
The licensee cannot necessarily guarantee the availability of the ADS on a 100-day basis.
The licensee had initiated internal design studies to formulate cost benefit analysis to improve the long-term ADS design performance.
The licensee is also participating in the BWR Owner's Group generic study of design improvements. The inspectors will continue to track this
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II.B.4.
Training for liitigating Core Dama'ge.
During this report period, the licensee completed the training for Health Physics person-nel.
This training completes the licensee commitment for this item.
(Reference IE inspection report 81-26 and 81-35)
11.
Unit 3 Startup During this report period, Unit 3 achieved criticality af ter a six and one-half month refueling and torus modification outage.
Prior to the startup, the inspector made a tour of Unit 3 drywell to inspect the condi-tion of equipment and area cleanliness.
During this inspection, the inspectors noted that the bolts which attach the hydraulic snubbers to the base plate for the core spray system, snubbers R-8 and R-9, did not have proper thread engagement.
The bolts lacked from one to three threads of nut engagement of being flush with the nut.
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The licensee inspected all other hydraulic snubbers in the Unit 3 drywell and found that the snubbers for the redundant core spray piping, snubbers R-1 and R-2, had a similar problem.
The bolts were replaced on all four snubbers to achieve proper thread engagement.
The licensee has committed to inspecting the core spray piping snubbers inside the drywell on Units 1 and 2 at the next shutdown requiring drywell entry.
(259,260/82-13-02)
The inspector observed Unit 3 startup testing to verify compliance with procedures and regulatory requirements.
During a review of procedural documentation on April 10, 1982, the inspector observed that the pull sheets scheduled to be used to pull rods for startup did not reflect the current procedure. The STA did not realize the pull sheet instruction (SI 4.3.B.1) had been changed on April 1,1982.
The startup rod sequence (A2) had been verified correct on the SI 4.3.B.1 data sheet on April 2, 1982.
The inspector notified the shift engineer of the out-of-date procedure.
Action was taken to update the pull sheets to be used for startup to the current procedural requirements.
(Reactor startup had not commenced at this time).
The inspectors also reviewed the valve lineup sheets performed prior to startup and found that three valves on the Reactor Core Isolation Cooling (RCIC) and eight root valves for safety instrumentation had not been verified in the correct position.
(The valves had been anotated as not requiring verification) The licensee performed a valve lineup on these valves and found them to be in the proper position.
In addition, the licensee rereviewed all safety system valve line ups to ensure all valves had had their positions verified. No further discrepancies were noted.
The Plant Manager was informed on May 6,1982, that the failure to verify the above valves were in the correct position prior to startup was another example of a violation for failure to follow procedure.
(296/82-13-01)
In the above areas, no other violations or deviations were identified.
12. Organization Changes During this report period, Mr. R. Hunkapillar, Mr. L. Jones and Mr. W.
Thomison assumed the duties of Operations Section Supervisor, Quality Assurance Staff Supervisor and Engineering Section Supervisor, respectively.
The inspector reviewed their qualifications per Technical Specification 6.1.E which commits Browns Ferry plant management to ANSI 18.1, Selection and Training of Nuclear Power Plant Personnel, dated March 8,1971. Their resumes show that Mr. Hunkapillar, Mr. Jones and Mr. Thomison are qualified to the requirements of ANSI 18.1 for their respective appointments.
In the above areas, no violations or deviations were identified.
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13.
Plant Physical Protection During the course of routine inspection activities, the inspectors made observations of certain plant physical protection activities. These included personnel badging, personnel search and escort, vehicle search and escort, communications and vital area access control.
No violations or deviations were identified within the areas inspected.
14.
Reactor Trips The inspectors reviewed activities associated with the below listed reactor trips during this report period. The review included determination of cause, safety significance, performance of personnel and systems, and corrective action. The inspectors examined instrument recordings, computer printouts, operations journal entries, scram reports and had discussions with operations, maintenance and engineering support personnel as appro-priate.
On April 12,1982, Unit 3 was manually scrammed from 20% power for turbine maintenance after excessive turbine vibration was noted on the
"C" low pressure turbine during startup after refueling outage.
Required safety systems perfomed satisfactorily. The excess turbine vibration was caused by the shroud band on the 13th stage of the 3C low pressure turbine (turbine end) coming off.
The unit remains shutdown for repairs at the conclusion of this report period.
On flarch 15,1982, Unit 1 tripped from 91% power during a surveillance on level instrumentation.
It could not be determined that this caused the scram, however, it is most likely the cause.
Required safety system perfomed as designed.
On !! arch 20, 1982, Unit I was manually scrammed from a power level of 417 ItWe to enable a drywell entry for the repair of an unidentified drywell leak rate in excess of five gallons per minute. The leak was traced to the vent line for FCV 69-1, the reactor water cleanup inboard isolation valve.
The vent line was found cracked.
A support for this line was missing and apparently not installed following modification activities during a recent refueling outage. The inadequate bracing had resulted in a vibration induced fatigue crack in the 3/4" line. The sample line was rerouted to diminish its susceptibility to vibration. All safety systems functioned as designed.
Refer to report 82-11 for further infomation information on this item.
On !! arch 25, 1982, Unit I was manually scrammed from 64% power due to an EHC hydraulic oil leak on the supply line to the servo valve for "B" turbine generator control valve.
Required safety systems performed as designed.
On reviewing the scram report, it was noted that an error existed.
The scram
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report written in accordance with Standard Practice 12.8 noted that there were no "02 position rods." A review of the 0D7-0P2 computer printout by the inspector revealed that " rod 34-43" settled at the "02 position." The Assistant Plant fianager was notified that this would be an open item and followed up on a future inspection.
(0 pen 259/82-13-04)
On April 4,1982, Unit 1 tripped due to a generator load reject due to activation of the generator field ground relay.
Investigation found no fault which could have caused the relay activation. Safety systems operated as designed. A review of the OD7-0P2 printout revealed that " rod 46-43" settled at the "02 position." The report indicated that only the "34-43 rod" was at the "02 position." The assistant plant manger was informed that the inaccurate report will remain open and followed up on a future inspec-tion.
(0 pen 259/82-13-04)
On April 8,1982, Unit 1 scrammed from 99% power due to generator load reject.
Safety systems responded as designed.
The licer.see recalibrated the field ground relay.
Four main steam relief valves actuated to control reactor pressure. The scram report indicated that no relief valves actua ted.
The Assistant Plant Manager was informed that the error in the scram report will be left as an open item and followed up on a future inspection.
(259/82-13-04)
No violations or deviations were noted in the above area.
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