IR 05000324/1986022
| ML20215C965 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 09/29/1986 |
| From: | Fredrickson P, Garner L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20215C949 | List: |
| References | |
| 50-324-86-22, 50-325-86-21, NUDOCS 8610100545 | |
| Download: ML20215C965 (18) | |
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UNITED STATES '
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[Sento, u
'o NUCLEAR REGULATORY COMMISSION,
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REGION 18 t
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j 101 MARIETTA STREET, N.W.
ATLANTA, GEORGI A 30323
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Report ~Nos. 50-325/86-21 and 50-324/86-22
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. Licensee: LCarolina Power and Light Company P. O. Box 1551 Raleigh, NC 27602 Docket Nos. 50-325 and 50-324 License Nos. DPR-71 and DPR-62 Facility Name: Brunswick 1 and 2 Inspection Co ed: August 1-31, 198 Inspectors:
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lan Aate' Signed p W. H N
} L. W. Garner date'31gned
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Approved By:
P. E. FredrTckson, Section Chief
'Date Signed
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Division of Reactor Projects SUMMARY Scope:
This routine safety inspection involved the areas of maintenance observation, surveillance observation, operational safety verification, onsite review committee, onsite Licensee Event Reports (LER) review, onsite followup of events, Brunswick Construction Unit (BCU) personnel evaluations, followup on unresolved items, and in-office LER review.
Results: No violations or deviations were identified.
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8610100S45 860930 PDR ADOCK 05000324
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REPORT DETAILS 1.
Persons Contacted Licensee Employees P. Howe, Vice President - Brunswick Nuclear Project C. Dietz, General Manager --Brunswick Nuclear Project T. Wyllie, Manager - Engineering and Construction E. Bishop, Manager - Operations
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L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)
l R. Helme, Director - Onsite Nuclear Safety - BSEP J. Chase,. Assistant to General Manager J. O'Sullivan, Manager - Maintenance G. Cheatham, Manager - Environmental & Radiatior. Control K. Enzor, Director - Regulatory Compliance B. Hinkley, Manager - Technical Support R. Groover, Manager - Project Construction A. Hegler, Superintendent - Operations W. Hogle, Engineering Supervisor B. Wilson, Engineering Supervisor R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)
R. Warden, I&C/ Electrical Maintenance Supervisor (Unit 1)
W. Dorman, Supervisor - QA W. Hatcher, Supervisor - Security R. Kitchen, Mechanical Maintenance Supervisor (Unit 2)
C. Treubel, Mechanical Maintenance Supervisor (Unit 1)
R. Poulk, Senior NRC Regulatory Specialist D. Novotny, Senior Regulatory Specialist W. Murray, Senior Engineer - Nuclear Licensing Unit Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force members.
2.
Exit Interview (30703)
The inspection scope and findings ware summarized on September 3, 1986, with the general manager. Three new Unrasolved Items * were discussed in detail (paragraphs 4 and 6).
The licensee acknowledged the findings without exception.
The licensee did not toonti fy as proprietary any of the materials provided to or reviewed by the inspectors during the inspection.
3.
Followup on Previous Enforcement Matters (92702)
Not inspected.
- An Unresolved Item is a matter about which more information is required to determine whether it is acceptable or may involve a violation or deviatio *
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4.
Maintenance Observation (62703)
The inspectors observed maintenance activities and reviewed records to verify that work was conducted in accordance with approved procedures, Technical Specifications, and applicable industry codes and standards. The inspectors also verified that:
redundant components were operable; administrative controls were-followed; tagouts were adequate; personnel were qualified; correct replacement parts were used; radiological controls were proper; fire protection was adequate; quality control hold points were adequate and observed; adequate post-maintenance testing was performed; and independent verification requirements were implemented.
The inspectors independently verified that selected equipment was properly returned to service.
Outstanding work requests were reviewed to ensure that the licensee gave priority to safety-related maintenance.
The inspectors observed / reviewed portions of the following maintenance activities:
86-BFZZ1 Unit 1
"A" Reactor Protection System (RPS) Motor Generator (MG) Set Electrical Protective Assembly (EPA)
Breaker 2.
Unit 1 Main Control Board Annunciator Power Supply Work.
Diesel Generator No. 4 Governor Repair.
Diesel Generator No. 3 Maintenance.
The inspector discovered a potential weakness in the licensee's post maintenance test requirements during a review of a recently completed work request on the Unit 2 High Pressure Coolant Injection (HPCI) system.
On August 25, 1986, the inspector observed that, on August 11, 1986, the licensee adjusted the packing on the steam admission valve to the HPCI turbine, E41-F001. The licensee timed the opening stroke of the valve. The recorded time was 15.6 seconds.
Review of the last system response time test, PT-45.3.4, March 8, 1985, showed that the system time was 29.63 seconds.
Review of stroke time records nearest the system response time test date revealed that, on February 27, 1985, the E41-F001 valve stroked in 15.9 seconds.
Thus it appears that the system response time was not adversely affected.
Furthermore, the licensee believes that the time to start the auxiliary oil pump, build up oil pressure and open the stop valve V8, which are evolutions in parallel to opening of E41-F001, bound the time for E41-F001 to open sufficiently to perform its function.
Data is not available to support this hypothesis, but it is based on engineers'
observations. Review of the stroke time acceptance criteria shows that the valve was allowed a stroke time up to 19 seconds. The valve may exceed this time with an increased surveillance interval. This meets the intent of the
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inservice inspection program. However, the licensee has not established any relationship between maximum allowable stroke time and effect on the system response time, if any. In general, the licensee had not considered possible effects of maintenance activities on the system response time. The inspector will review the licensee's evaluation of this issue during future inspections.
Pending review of the licensee's evaluation of stroke time effects on system response time, this is an Unresolved Item:
Maintenance Activities May Adversely Affect System Response Time (324/86-22-01).
No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical Specifications (TS). Through observation and record review, the inspectors verified that: tests conformed to TS requirements; administrative controls were followed; personnel were qualified; instrumentation was calibrated; and data was accurate and complete.
The inspectors independently verified selected test results and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following test activities:
0-PT-34.4.1.3 Control Building Fire Detection Instrumentation Operability Test.
PT-74.0 Drywell Radiation Monitor CAC-AQH-1260 Channel Calibration.
1-PT-13.1 Reactor Recirculation det Pump Operability.
1-MST-SRM11W SRM Channel Functional Test Setpoint Calibration.
1-MST-TIP41R TIP PCIS Group 2 Logic System Functional Test.
2-MST-RCIC13M RCIC Steam Leak Detection Channel Functional Test.
2-MST-RPS11W MSL Hi Rad Channel Functional Test.
No violations or deviations were identified.
6.
Operational Safety Verification (71707)
The inspectors verified conformance with regulatory requirements by direct observations of activities, facility tours, discussions with personnel, reviewing of records and independent verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the TS were met.
Control room, shift supervisor, and clearance logs were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with TS Limiting Conditions for Operations. Direct observations were conducted of
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control room panels, instrumentation and recorder traces important to safety to verify operability and that parameters were within TS limits.
The inspectors observed shift turnovers to verify that continuity of system status was maintained.
The inspectors verified the status of selected control room annunciators.
Operability of a selected Engineered Safety Feature (ESF) train was verified by insuring that: each accessible valve in the flow path was in its correct position; each power supply and breaker, including control room fuses, were aligned for components that must activate upon initiation signal; removal of power from those ESF motor-operated valves, so identified by TS, was completed; there was no leakage of major components; there was proper lubrication and cooling water available; and a condition did not exist which might prevent fulfillment of the system's functional requirements.
Instrumentation essential to system actuation or performance was verified operable by observing on-scale indication and proper instrument valve lineup, if accessible.
The inspectors verified that the licensee's health physics policies /
procedures were followed. This included a review of area surveys, radiation work permits, posting, and instrument calibration.
The inspectors verified that: the security organization was properly manned and security personnel were capable of performing their assigned functions; persons and packages were checked prior to entry into the protected area (PA); vehicles were properly authorized, searched and escorted within the PA; persons within the PA displayed photo identification badges; personnel in vital areas were authorized; and effective compensatory measures were employed when required.
The inspectors also observed plant housekeeping controls, verified position of certain containment isolation valves, and verified the operability of onsite and offsite emergency power sources, a.
Implementation of Technical Specification 3.0.5 With Unit 1 in operational condition 1, the licensee declared the 18 Standby Liquid Control (SLC) pump (Division II) inoperable with No.1 Diesel Generator (Division I) inoperable.
The licensee apparently failed to recognize, for 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, that TS 3.0.5 applied.
On August 27, 1986, at 4:00 a.m.,
the licensee declared 1B SLC pump inoperable when the pump made unusual noises during the performance of PT-6.1, the SLC system monthly operability test. Diesel Generator (OG)
No. I was also inoperable at the time.
The diesel generator had previously been declared inoperable on August 25, 1986, at 6:00 a.m.,
to perform routine maintenance.
The SLC TS 3.1.5 ACTION statement allowed the licensee 7 days to restore the IB SLC pump to operable
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status or be in hot shutdown within the next twelve hours. The DG TS 3.8.1.1.b ACTION statement allowed the licensee 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore DG No.1 to operable status or be in hot shutdown within the next twelve hours.
At 4:00 a.m., on August 27, 1986, the Unit 1 shift foreman declared the IB SLC pump inoperable, apparently creating a 7 day time limit to hot shutdown. However, TS 3.0.5 states:
When a system, subsystem, train, component, or device is determined to be inoperable solely because its emergency power source is inoperable, or solely because its normal power source is inoperable, it may be considered OPERABLE for the purpose of satisfying the requirements of its applicable Limiting Condition for Operation (LCO), provided:
(1) its corresponding normal or emergency power source is OPERABLE; and (2) all of its redundant system (s), subsystem (s), train (s), component (s), and device (s) are OPERABLE, or likewise satisfy the requirements of this specifica-tion. Unless both conditions (1) and (2) are satisfied, the unit shall be placed in at least HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in at least COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
This specification is not applicable in Conditions 4 or 5.
A system, subsystem, train, component, or device shall be OPERABLE when it is capable of performing its specified function (s).
Implicit in this definition shall be the assumption that all auxiliary equipment, ir.cluding normal and emergency electric power sources, that are required to perform its function are also capable of performing their related support function. The SLC system, per the TS bases, provides a backup capability for maintaining the reactor subtritical if control rods fail to scram. The bases states that the SLC pumps are redundant.
Thus, the function of the system is degraded with loss of redundancy, implying that an emergency power source is required for SLC to fulfill its function. Thus the licensee is required to apply TS 3.0.5 to the SLC system. When the IB pump was declared inoperable, the 1A pump should have been declared inoperable because: (1) its emergency power source was inoperable (No. 1 DG) and (2) the permissive statement of TS 3.0.5 was not satisfied, namely that the redundant pump (IB) was inoperable. Thus, per TS 3.0.5, the licensee had 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> from 4:00 a.m. to be in hot shutdown.
The licensee recognized that TS 3.0.5 applied at 7:30 a.m.
on August 26. At 8:15 a.m., the licensee verified that the IB SLC pump was operable. The original problem apparently was a testing problem due to excessive throttling of a valve during PT-6.1.
Thus, the licensee complied with the time limits of TS 3.0.5, and no violation of TS occurre *
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TS 3.0.5 does not account for any difference in systems. Regardless of
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the system, TS 3.0.5 requires 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to hot shutdown once a component is inoperable and the redundant component is inoperable solely due to an inoperable power supply. The licensee plans to explore possible TS changes to correct this problem.
Also, TS 3.0.5 does not clearly indicate, in the licensee's view, which systems or components are applicable. The licensee is developing a position regarding TS 3.0.5 applicability.
The inspectors reviewed the licensee's training concerning TS 3.0.5.
Lesson plans covering TS and bases used for Reactor Operators (RO) and Senior Reactor Operators (SRO) instruction (LP-07-2-B1, LP-07-3-B1, and H0-07-3-B1) contained material concerning TS 3.0.5.
The licensee had no record of any simulator exercises that addressed TS 3.0.5.
The licensee claimed that TS 3.0.5 training was conducted in the simulator but was not a line item in a pre planned scenario.
The licensee's failure to recognize TS 3.0.5 applied was similar to an event several months ago involving a Residual Heat Removal (RHR) pump and a DG from the opposite division. The inspectors will continue to review the licensee's resolution' of the applicability of TS 3.0.5.
This item remains unresolved pending the inspector's review of previous corrective action in this area and the licensee's final determination of TS 3.0.5 applicability.
This is an Unresolved Item:
Licensee's Implementation of TS 3.0.5 (325/86-21-01).
b.
Diesel Generator No. 4 Service Water Valve
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The inspector found DG No. 4 Jacket water cooler service water outlet valve (SW-V209), not fully open on August 26, 1986, at 11:25 a.m.
The valve, a six inch butterfly valve, was found locked in the 55 degrees position, with 90 degrees equal to full open and 0 degrees equal to shut.
The valve line-up pre-startup checklist in OP-39, Diesel Generator Operating Procedure, Rev. 28, attachment 4, page 10, requires V209 to be locked open. Unit 2 scrammed on August 23, 1986. All four diesels had started (see paragraph 9). An auxiliary operator adjusted V209, V206, and V207 for diesels 4, 1, and 2, respectively, to clear a local low service water pressure alarm. The licensee reports that the position of V209 found by the inspector would not have made No. 4 diesel generator inoperable.
This item remains unresolved pending further review of the event details by the inspectors.
This is an Unresolved Item: Diesel Generator No. 4 Jacket Water Cooler Service Water Outlet Valve Not Full Open (324/86-22-02).
c.
Poorly Inking Control Room Recorders On August 11, 1986, the inspector observed that the Unit 2 Drywell/
Suppression Chamber Temperature Recorder (TS 3.3.5.3, Accident Monitoring Instrumentation), CAC-TR-4426, was printing points which were barely, if at all, visible. Apparently the chart paper had been changed by the night shift and no action had been taken to correct the
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inking problem. The day shift control operator had not yet reviewed and initialed the chart. The same chart recorder on Unit 1 also had two points barely visible.
In this case, the operator had just initialed the chart but had failed to note the poor inking. A review of other' charts on multipoint recorders showed a similar problem. On August 18, 1986, the inspector observed that the chart recorder for 2-CAC-AQH-1264, Reactor Building Ventilation Monitor, was misprinting the points, e.g., comparison of the meters to the chart recorder showed the point designated as noble gas activity was actually the particulate filter activity. An audit conducted by corporate Quality Assurance (QA) during the period August 25 through 29, 1986, proposed a non-conformance concerning 9 out of 13 recorder charts with shifts and/or days where the charts were not initialed or time not noted. The licensee agreed to address the above centioned inspector observations as part of their corrective action to the corporate QA report, QAA/0021-86.
d.
Main Control Board Walkdown On August 26, 1986, during a control board walkdown, the inspector observed the Division II RHR heat exchange pressure indicator, E11-PIC-R606B, upscale.
Because this could be an indication of potential overpressurization of the RHR system low pressure piping, the control operator sent an auxiliary operator to investigate.
Upon venting the system, the indicator stayed full scale. A work request, 86-BJCJ1 was issued to repair the instrument.
No violations or deviations were identified.
7.
Onsite Review Committee (40700)
The inspector attended Plant Nuclear Safety Committee meeting 86-101, on August 20, 1986, concerning post scram review and restart of Unit 1.
The inspector verified that the meeting was conducted in accordance with TS requi-ements regarding membership, quorum, review process, frequency and personnel qualifications.
The inspector reviewed the list of alternates designated by the plant manager.
All alternates who attended meetings86-100, 86-101, and 86-102 were correctly designated alternates with one exception.
The Director-Onsite Nuclear Safety was listed as an alternate but was not so designated.
The quorum requirement was-met without him.
Meeting minutes were reviewed to confirm that decisions / recommendations were reflected in the minutes and followup of corrective actions was completed.
The inspector verified that the requirements in procedure AI-09, Plant Nuclear Safety Committee (PNSC) Administration, Rev. 22, was consistent with TS 6.5.3, PNSC.
No violations or deviations were identified.
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8.
Onsite Review of Licensee Event Reports (92700)
The listed LERs were reviewed to verify that the information provided met NRC reporting requirements. The verification included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of the event. Onsite inspections were performed and concluded that necessary corrective actions have been taken in accordance with existing requirements, licensee conditions and commitments. The following reports are considered closed.
Uait 1 (CLOSED)
LER 1-83-30, Pilot Cell Battery Specific Gravity Less Than TS Value.
The licensee committed to revise the surveillance procedure to ensure DC batteries are placed on equalizing charge when required.
The inspector verified that procedure MST-BATT11W, Revision 2 and 3 (Units 1 and 2, respectively), Batteries, 125 VDC, Weekly Operability Test, specifies that the corrected pilot cell specific gravity is above the TS minimum value.
During inspection of LER 1-83-30 on August 28, 1986, the inspector observed that the Engineering Subunit copy of TS, copy No. 9, had not been correctly updated per amendments No. 92 and 117 (Units 1 and 2, respectively). These amendments were issued by the NRC on September 20, 1985 and distributed by the licensee for incorporation into the various copies on October 3,1985.
Amendments No. 92 and 117 involve TS 3.8.2.3, 3.8.2.4.1, 3.8.2.4.2 and 3.8.2.5 on each unit. Amendment No.117 pages were found still attached to the transmittal sheet in the front of the book with the old pages still filed in the specification. Amendment No. 92 pages could not be located but the superseded pages were still filed in the specification. On October 9, 1985, a licensee employee signed and returned a document accountability form indicating that the amendments had been entered as required and superseded material had been destroyed or marked obsolete. The old pages had not been marked as obsolete or void in any manner. The inspector audited the Unit 1 and 2 shift foreman's copies of TS, located in the control room, on August 29, 1986. The audit verified that amendments 89 through 97 (Unit 1)
and 114 through 127 (Unit 2) had been incorporated. No other problems were found. The event has little safety significance in that the majority of the old pages were marked with "See Technical Specification Interpretation 84-09."
This document had been cancelled with the note that the new specification had been issued.
The licensee has issued on September 3, 1986, a non-conformance No. S-86-042 concerning copy No. 9 of the TS.
I Engineering Subunit personnel immediately corrected the discrepancy.
The error occurred because an inexperienced person updated the document.
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Because the error was an isolated case that involved a minor violation with little safety significance and corrective action to prevent recurrence is being taken per the non-conformance, no notice of violation is being issued.
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(CLOSED) LER 1-83-35, Main Steam Line Radiation Monitor Actuates Outside TS
Value. The licensee committed to issue a supplement after determining the cause of the event. A supplement was issued on November 11, 1983. However, no cause for failure could be determined because the removed monitor drawer
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was used for spare parts prior to evaluation.
(CLOSED)
LER 1-83-59, 1C and 1A RHR Service Water Pump Tripped After Starting. No cause was determined for the tripping. However, subsequent
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modifications have been made to improve reliability of the system.
These involve installation of separate pump suction pressure start permissive switches for each pump, a newer design pressure transmitter and relocation of the vent to the high point on the suction line.
(CLOSED)
LER 1-83-63, Erroneous Reactor Water Cleanup Differential Flow Indications Due to Entrapped Air. Supplement to the report, issued March 7, 1984, stated that PT-14.2.16 was revised to help prevent future similar occurrences. The inspector verified that PT-14.2.16, Reactor Water Cleanup High Flow Response Time, Revision 9, contains adequate instructions to vent air from the instruments after testing.
(CLOSED)
LER 1-85-01, Inadequate Calibration of Reactor Shroud Level Instrumentation.
The licensee committed to revise the appropriate procedures. The inspector verified that procedure MST-RHR24R, RHR Reactor Vessel Shroud Level Instrument Channel Calibration, Revision 1, contained the appropriate acceptance criteria.
(CLOSED)
LER 1-85-10, Reactor Building's Ventilation Exhaust Radiation Monitors Inadequate Logic Test Procedure. The licensee committed to revise the procedure.
Using General Electric (GE) elementary diagram 920D496, the licensee showed the inspector that the revised procedure PT-04.1.1, Reactor Building Vent Exhaust Monitoring System Functional Test, Revision 29, adequately addresses the stated problem.
(CLOSED)
LER 1-85-33, Safety Relief Valve Setpoint Drift.
The subject report involves the same area as LER 2-86-01.
This item is considered
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closed for administrative purposes. Further inspection will be associated with closecut of LER 2-86-01.
Also, see LER 2-84-07 closeout in this report.
(CLOSED)
LER 1-85-53, Primary Containment Group 6 and 8 Isolations Initiated by Incorrect Connection to Test Jacks. The licensee committed to revise the test procedure. The inspector verified that page E256 of plant modification 80-133 was changed as committed.
(CLOSED)
LER 1-85-66, Primary Containment Group 6 Isolation Due to an Alligator Clip Test Lead Slipping Off Screw.
The licensee committed to conduct training concerning this event and proper use of alligator clips during testing.
The training which was performed on February 5, 1986, included training on a similar event described in LER 2-85-06.
The inspector reviewed the notes utilized for the training and has no further questions.
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(CLOSED) LER 1-85-68, Technicians Fail to Inform Operations That Reactor Level Instrument Is Out of Service for Longer Than Technical Specification Allows.
The licensee committed to supply 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> timers to personnel involved in surveillance testing and counsel the involved technicians on the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> out of service allowance in Technical Specifications. The inspector reviewed the training records associated with the event and has observed use of the timers in the field.
Unit 2 (CLOSED)
LER 2-83-19, Instrument Air Tubing to Safety Relief Valves Not Adequately Supported. A supplemental report was issued July 12, 1984, which committed to revise the modification procedure to add additional controls to ensure design bases are completely defined.
Engineering Procedure ENP-03, Plant Modification Procedure, Revision 32, Section 5.3.1, requires design inputs to identify applicable regulatory commitments, code and standards.
(CLOSED)
LER 2-83-57, Condensate Storage Tank Low Level Switch Outside Technical Specifications Due to Personnel Error.
The licensee determined that specifying the setpoint tolerance in a plus-minus format contributed to the error.
The current practice in surveillance test procedures is to specify the numerical limits as bounded values instead of the plus-minus format. The inspector verified that MST-HPCI27M, HPCI and RCIC CST Low Water Level Instrument Channel Calibration, Revision 2, correctly specifies the tolerance and the setpoints are within TS table 3.3.3-2, item 3.c and TS 3.3.7-2, item c values.
(CLOSED)
LER 2-83-59, Automatic Depressurization System Switch Does Not Respond Because of Corrosion. The switch was replaced by an environmentally qualified switch as described in LER 2-83-70 closeout.
(CLOSED) LER 2-83-63, Suppression Pool Exhaust Valve Would Not Fully Close.
The licensee committed to submit a supplement to report the cause of the failure.
The supplement, issued February 19, 1985, reported that disassembly of the valve revealed no problems.
Valve was reassembled and tested satisfactorily.
(CLOSED) LER 2-83-68, Drain Sump Flow Square Root Signal Converter Out of Specification Due to Instrument Drift. The licensee committed to replace the instrument per plant modification 79-163. The inspector verified that the equipment was replaced.
(CLOSED)
LER 2-83-70, Failure of E11-N020A Micro-Switch.
The inspector verified that the subject switch and similar application (Automatic Depressurization System RHR pump running permissive), switches have been replaced on both units by environmentally qualified ASCO pressure switches.
(CLOSED)
LER 2-83-75, Drywell Floor Drain Flow Integrator Failed Solder Joint.
The licensee committed to replace the instrument per plant modification 79-163.
The inspector verified that the new equipment was installe *
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(CLOSED)
LER 2-83-78, Lack of Clarity for the Requirement Listing in the Control Operator's Daily Surveillance Report. The inspector verified that the requirement is properly stated in 01-3.1 and 01-3.2, Control Operator Daily Surveillance Report, Units 1 and 2, respectively.
The inspector verified on August 24, 1986, that the jet pump operability surveillance (PT-13.1), the subject requirement, was performed prior to exceeding 25% of full power during Unit I startup.
(CLOSED)
LER 2-83-86, Main Steam Line Radiation Monitor Instrument Drift.
The licensee committed to combine the weekly functional tests in order to better reveal instrument drift problems.
The inspector verified that MST-RPS11W, Main Steam Line High Radiation Channel Functional Test, Revision 3, meets this commitment.
(CLOSED)
LER 2-83-91, Isolation Valve E51-F043C Would Not Reopen Due to Broken Control Switch. The subject valve has been replaced by an excess flow type check valve.
(CLOSED)
LER 2-83-93, Post-Accident Monitor Giving Erratic Indications.
The subject monitor, CAC-AR-1263, has been replaced by a different system, CAC-AR-4409 and CAC-AR-4410.
(CLOSED)
LER 2-84-07, Functional Testing of the Safety Relief Valves, One Failed to Lift and 4 Lifted Out of Tolerance.
The steps taken by the licensee and the justification for continued operation is presented in the subject LER and LER 2-86-01.
Inspection of the setpoint drift problem will be performed in response to the most recent LER. Hence the previous LER's, 2-84-07 and 1-85-33, are being closed for administrative tracking purpose.
(CLOSED)
LER 2-84-11. Reactor Low Level Due to Misoperation of Residual Heat Removai Valves. The licensee provided real time training to other licensed personnel concerning this event.
The inspector reviewed the training records and materials and has no questions.
Contributing to the event was a problem with filling and venting of the suppression pool level instrumentation. The licensee committed to revise maintenance procedures to include appropriate fill and vent instructions. The inspector verified that MI-03-1BX3, CAC-LT-3342 Suppression Pool Level Transmitter Calibration, Revision 7, MI-03-1BX29, ' CAC-LT-4177 Suppression Pool Level Transmitter Calibration Narrow Range, Revision 1, MI-03-1BX35, CAC-LT-2601 Suppression Pool Level Transmitter Calibration, Revision 4,
and MI-03-1BX35A, CAC-LT-2602 Suppression Pool Level Transmitter Calibration, Revision 2, adequately address the issue.
(CLOSED)
LER 2-84-13, HPCI System Auxiliary 011 Pump Breaker Trips.
Tripping of the breaker was attributed to repeated cycling on and off of the pump while the turbine was operating at low speed. The licensee committed to review the start and stop setpoints. On March 20, 1985, the licensee issued a supplement to this LER stating that the vendor had been contacted and no change in setpoints was deemed necessary.
The licensee had added a caution note to test procedures PT-9.2, HPCI System Operability Test, and PT-9.3, HPCI System, 165 PSIG Flow Test, to warn the operators that
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operation of the system at low speeds can cause the auxiliary oil pump to cycle and possibly trip.
(CLOSED)
LER 2-84-16, Inoperability of RWCU System Primary Containment Isolation Valves.
Problem was determined to be inadequate spring tension and dirty contacts on closing torque switches. The torque switch with weak springs was replaced. The licensee committed to develop and implement a preventive maintenance program to clean contacts on selected valves. The inspector verified that MI-10-25 Torque Switch Contact Inspection of Q-List Limitorque Operators, Revision 0, adequately addresses cleaning of the contacts.
The inspector verified that selected valves are scheduled (approximately every three years) to have this MI-10-25 performed on them.
In response to an inspector's question, the licensee stated that performance of local leak rate test and inservice inspection cycling of valves is sufficient to detect inadequate spring tension due to aging and, hence, no further action is required.
(CLOSED)
LER 2-84-17, Group 3 Primary Containment Isolation Caused by Instrument Malfunction. The licensee determined that a component had failed in a temperature instrument module. The module was replaced and system was returned to service.
The licensee erroneously reported that both the inboard and outboard reactor water cleanup isolation valves had closed.
In fact, only the outboard valve closed as designed.
In a memorandum from Pastva to Poulk, dated January 24, 1985, the licensee recognized the inconsistency and determined that submission of a supplement is not warranted as outlined in NUREG 1022.
(CLOSED)
LER 2-84-18, Automatic Scram Caused by Moisture Separator High Level Switch Tripping Main Turbine. Level switch failed to reset within ten second time delay after a spurious high level due to mechanical binding.
Licensee committed to revise maintenance procedure to check for possible binding.
The inspector verified that procedure MI-03-3I, Revision 6,
contains a step to ensure no binding is encountered during calibration;
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otherwise, issue a work request to correct.
(CLOSED) LER 2-85-04, Isolation Logic Power Failure of HPCI Due to Foreign Material Causing a Ground. The subject report addressed replacement of the blown fuses and removal of the accumulation of foreign material on the barometric condenser level switch.
When questioned about the need for periodic cleaning to prevent future problems, the licensee stated that the foreign material originated from packing leaks associated with the F054 valve, Supply Drain Pot Drain Bypass Valve. This valve on both units has been replaced with one of a different type.
Hence, need for periodic cleaning is not deemed necessary.
(CLOSED) LER 2-85-05, Isolation Valves Misidentified by Operator. Improper location specification in the procedure contributed to this personnel error.
The licensee committed to revise the procedure. The inspector verified that Revision 44 of OP-46, Instrument and Service Air System Operating Procedure, contains revised locations for valves SA-V301 and SA-V302.
A notice of
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violation was issued in inspection report No. 324/85-33 concerning the event.
Corrective action concerning the personnel error will be inspected as part of the violation closecut.
(CLOSED) LER 2-85-06, Automatic Isolation of HPCI System Due to Alligator Clip Falling from Screw During Testing. The licensee committed to review the event with the periodic test crews. Also, see LER 1-85-66 closecut.
(CLOSED) LER 2-85-10, Inadequate Logic System Functional Test of 40% Main Steam Flow Primary Containment Group 1 Isolation Logic.
The licensee committed to verify appropriate testing of reactor mode switch bypass functions is incorporated into logic functional test procedures.
Plant memorandum from Dean to Musser dated January 31, 1986; concluded that procedures are written to verify each channel (reactor protection system and primary containment isolation system) is not inhibited by the mode switch from performing its function. The inspector reviewed the memorandum and has no further questions.
No additional violations or deviations were identified.
A violation (325/85-33-01), was previously issued against the event reported in LER 2-85-05.
9.
Onsite Followup of Events (93702)
a.
Unit 1 Scram on August 19, 1986 Unit 1 scrammed from 100% power following a turbine trip at 9:23 p.m.
on August 19, 1986.
The turbine tripped on a low condenser vacuum signal when a ground on the Electro-Hydraulic Control (EHC) system DC bus caused the low vacuum relays to pickup. The ground resulted from a flange steam leak wetting down the No. 1 bypass valve closed limit switch. All safety systems functioned as designed with the following anomalies:
RWCU System Outboard Isolation Valve, G31-F004, did not close. A group 3 isolation normally occurs when a Low Level 2 (LL2) signal is reached (118 plus or minus 6 inches). The NSSS post-trip log
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showed the lowest vessel level as 144.6 inches at 9:23:40 p.m.
However, the licensee received a group 1 isolation, Main Steam Isolation Valve (MSIV) closure, at 9:23:35, along with a pressure spike at that time.
The MSIVs could have shut either from a momentary high pressure signal or a resulting void collapse resulting in a momentary LL2 signal. The momentary nature of the level drop could have picked up just the group 1 isolation and the G31-F001 valve and failed to shut the G31-F004 valve and initiate HPCI and Reactor Core Isolation Cooling (RCIC).
The licensee functionally tested HPCI, RCIC and G31-F004 and verified that the equipment was operable and would respond to a LL2 signal.
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- Four Safety Relief Valves. (SRVs) lifted automatically.
The Nuclear Steam Supply Ssystem (NSSS) post-trip log overran the data buffer. Actual lift and reseat pressures of the SRVs could not be determined.
However, the SRVs did reseat and there is no indication that the SRVs failed to perform as required, b.
Unit 1 Scram on August 21, 1986 Unit 1 scrammed during a reactor start-up at 5:59:53 p.m.
Intermediate Range Monitors (IRM) channels A, D, G, F and H received upscale trips.
IRM channels B & E also went upscale but were bypassed during the start-up. IRM C showed no increase when the trip occurred. The trip occurred with the reactor still subcritical with no rod motion during the trip. The last rod had been moved at 5:58:39 p.m.
Power was in the source range at the time of the scram. The Source Range Monitors (SRM) A and B spiked from 'about 700 to 20,000 cps when the scram occurred. The main steam line C flow indicator and the core delta P recorder spiked downscale.
The inspector reviewed this post-trip review report which included IRM and SRM recorder traces, and computer post-trip logs. The cause of the scram was not determined. The licensee suspects a noise pulse caused the perturbations seen on the instruments. No source of the pulse was found. IRM C, which did not spike, had been worked on to correct noise problems several months ago. The licensee cleaned the grounds on the IRM channels, performed applicable calibration checks and re-started the reactor. Several points were connected to strip chart-recorders to help identify the problem should the problem re-occur.
c.
Unit 2 Scram on August 23, 1986 On August 23,1986, at 4:31 p.m.,
Unit 2 reactor experienced a MSIV less than 90% open scram from 99.7% of full power. The trip occurred when B21-PT-N0238, reactor high pressure transmitter, was being valved into service after being replaced. The instrumer.t isolation valve was cracked open with reactor pressure on one side and the last utilized calibration pressure (613 psig)oon the other, a pressure pulse occurred
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on the reference leg.
The low level 2 and 3 instruments momentarily actuated.
This caused the group 1 isolation (MSIV closure), which resulted in the reactor scram.
Actuation of low level 2 and 3 instruments also caused all four diesel generators to scart, contain-ment isolation groups 2, 6, 8 and inboard group 3 to isolate, starting of both standby gas treatment trains, tripping of both reactor recirculation pumps, starting of HPCI and RCIC systems (no injection),
and. starting of both core spray pumps (no injection).
The response to the transient included automatic lifting of seven SRVs, manual lifting of 4 SRVs per emergency operating procedure to further control pressure, starting RCIC and HPCI for pressure control, and placing the unit in hot standby per procedures. The maximum reactor
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pressure recorded was 1123 psig.
The maximum suppression chamber temperature obtained during the event was 114 degrees F.
All engineered safety features actuated as expected. The HPCI and RCIC systems started but did not inject because of the momentary nature of the initiation signal.
Core spray did not inject because reactor pressure did not decrease to the injection valve opening setpoint. The RHR system pumps did not start because the pressure spike did not last j
long enough to seal in the logic, e.
g., more relays have to actuate in the RHR initiation logic than in the core spray initiation logic. The inboard group 3 valves actuated because only its instruments were perturbed, e. g., outboard valve instruments are on another reference leg. Prior to restart the licensee also repaired sonic detectors on two SRV valves. Reactor operations were resumed on August 25, 1986.
The inspector reviewed the licensee's scram report and has no further
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questions. - Review of personnel actions associated with valving in the pressure transmitter are being incorporated into a maintenance experience report.
The licensee intends to finalize this report by mid-September. The inspector plans to review the report when issued.
No violations or deviations were identified.
10. Brunswick Construction Unit Personnel Evaluations The inspector reviewed the BCU personnel evaluation system to determine if workers were being discouraged from reporting non-conformances. The review consisted of interviews with selected BCU personnel, review of Non-Confor-mance Reports (NCR), and examination of a performance appraisal summary sheet.
The BCU evaluation system was supplemented last year with information concerning NCRs related to en individual's work.
The construction manager issued a memo dated November 7,1985, that required supervisors to address JCG:
field reports, and other rejected work in personnel evaluations.
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Supervisors were also told to evaluate whether they have taken prompt and appropriate actions to deal with the causes of poor work quality within their work group. BCU first used a supplemental quality evaluation form to identify the number of direct and indirect rejected work items associated with an individual. The completed form served as input to the personnel evaluation process.
The inspector interviewed selected BCU supervisors concerning the rejected work input to personnel evaluations. Licensee employees interviewed did not reveal any instance where an individual covered-up or attempted to cover-up rejected work because of the personnel evaluation system.
However, some supervisors were concerned that a worker's continued employment might be affected by the evaluation system.
The inspector relayed that non-safety concern to BCU managemen *
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The inspector found no evidence of individuals concealing defects or performing unauthorized re work to disguise or eliminate non-conforming conditions that could reflect badly on their evaluations.
No violations or deviations were identified.
11.
Followup on Unresolved Items (92701)
(OPEN)
324/86-18-04, Traversing Incore Probe (TIP) Tube Reversal.
The licensee had committed to review Unit 2 cycle 6 data for possible thermal limit violations due to the B-8 and B-10 tube swap. The licensee reported to the inspectors that:
Review of_TIP plots showed only small differences between B-8 and B-10 traces since cycle 6 operated with a deep center control rod while cycle 7 operated with a shallow center control rod.
- Comparison of average RMS error between one-eighth core symmetric TIP traces showed that the swap should have had a smaller impact on cycle 6 than on cycle 7, which was already shown to have not exceeded thermal limits.
Review of 75 statepoints throughout cycle 6 showed no thermal limits were violated as expected.
This item remains unresolved pending a drywell entry to examine the actual TIP tube reversal. The licensee plans to shutdown Unit 2 on October 24, 1986, for performance of surveillance requirements.
No violations or deviations were identified.
12.
In Office Licensee Event Report Review (90712)
The listed Licensee Event Reports (LERs) were reviewed to verify that the information provided met NRC reporting requirements.
The verification included adequacy of event description and corrective action taken or planned, existence of potential generic problems and the relative safety significance of the event.
Unit 1 (CLOSED)
LER 1-83-60, Remote Shutdown Panel Reactor Vessel Pressure Indicator Showed a Pressure of 860 PSI While Redundant Control Room Instrumentation Showed an Expected Pressure of 990 PSI.
(CLOSED)
LER 1-83-64, The Square Root Integrator Was Functioning Out of Calibration Tolerances.
(CLOSED) LER 1-85-04, Primary Containment Isolation of RWCU System, Due to Room Differential Temperature High.
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(CLOSED) LER 1-85-08, Automatic Reactor Scram Resulting from Main Condenser Low Vacuum Trip and the Decreasing Main Condenser Vacuum Resulted from Water in the Off-Gas Filter.
(CLOSED) LER 1-86-20, late Performance of Required Hourly Fire Watches.
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Unit 2 (CLOSED)
LER 2-83-67, Reactor Recirculation Pump Tripped Due to Wrong Electrical Jumper Being Accidently Removed.
(CLOSED)
LER 2-83-87, Reactor Recirculation Pump 2A Tripped Due to an Unintentional Actuation of ATWS/RPTS Instrument Caused by Personnel Error.
(CLOSED) LER 2-83-92, Control Rod Drive System Accumulator Leak Detection Instrumentation Calibration and Functional Test Revealed the Accumulator Leak Detection Instruments Did Not Respond.
(CLOSED) LER 2-84-03, Normal Power Supply Feeder to Emergency Bus E-4 Auto-Opened Due to a Bus Undervoltage.
(CLOSED) LER 2-85-07, Primary Containment Group 3 Isolation Attributed to a Weld Leak.
No violations or deviations were identified.
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