IR 05000324/1986030
| ML20215E020 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 12/02/1986 |
| From: | Fredrickson P, Garner L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20215D981 | List: |
| References | |
| 50-324-86-30, 50-325-86-29, IEB-79-17, NUDOCS 8612170191 | |
| Download: ML20215E020 (16) | |
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[>A M ?
UNITE ^~) STATES o
NUCLEAR REGULATORY COMMIS$10N
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,j 101 MARIETTA STREET.N.W.
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t ATLANTA, GEORGI A 30323
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Report Nos.: 50-325/86-29 and 50-324/86-30 Licensee: Carolina Power and Light Company P. O. Box 1551
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Raleigh, NC 27602
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Docket Nos.:
50-325 and 50-324 License Nos.: OPR-71 and OPR-62 Facility Name: Brunswick 1 and 2
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Inspection Conducted:.
ctober 5-31, 1986 95 %d nli %
Inspectors:
g H. Ruland Date Signed 11 f I la (
kdL W. Garner Date Signed
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Assisting Ins c rs:
H. E.,Krug, G. 4 ejfelt
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/)d-/fd Approved By P.fE. Fre~drickson, Section Chtef_
Division of Reactor Projects- _
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SUMMARY, -
s Scope:
This routine safety inspection involved the areas of maintenance observation,. surveillance observation,. operational safety verification, onsite Licensee Event Reports (LER) review, in office LER review, followup on inspector identified and unresolved items, IE Bulletin Followup, Environmental Qualifica-tion (EQ) of components, management visit, and onsite followup of events.
Results: One violation was identified - Failure to properly perform a temporary revision.
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8612170191 861205 PDR ADOCK 05000324 G
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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 L. Jones, Director - Quality Assurance (QA)/ Quality Control (QC)
R. Helme, Director - Onsite Nuclear Safety - BSEP J. Chase, Assistant to General Manager J. O'Sullivan, Manager - Maintenance R. Eckstein, Manager - Technical Support G. Cheatham, Manager - Environmental & Radiation Control K. Enzor, Director - Regulatory Compliance R. Groover, Manager - Project Construction A. Hegler, Superintendent - Operations J. Wilcox, Principal Engineer - Operations W. Hogle, Engineering Supervisor B. Parks, 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 W. Murray, Senior Engineer - Nuclear Licensing Unit Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, office personnel, and security force members.
Bergen-Paterson Pipe Support Corp.
J. Moore, Field Applications Engineer, Services Group.
2.
Exit Interview (30703)
The inspection scope and findings were summarized on November 4, 1986, with the assistant to the general manager and on November 14, 1986, with the general manger.
One violation - failure to perform a proper temporary
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revision (paragraph 7) - was discussed in detail.
Three Unresolved Items *
were identified (paragraphs 6 and 11).
The licensee acknowledged the i
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finding' without exception ~
The licensee identified as proprietary two documents provided to or reviewed by the inspectors concerning EQ of the High Pressure Coolant Injection (HPCI) speed sensor.
No information identified as proprietary by the licensee was included in the report.
3.
Followup on Previous Enforcement Matters (92702)
Not inspected.
. 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-BPNY1 RPS Channel B1 Analog Inverter No. 1 Calibration 86-BRFBI Snubber 821-44SS138 Functional Test 86-BRSS1 Repair of 2-RPS-PS-1-81 Power Supply 86-BKCII Unit 2 Drywell Radiation Monitor, CAC-AT-1260, Repair 86-BPML1 Megger and Bridge Unit 1 HPCI F001 Valve Breaker per MI16-16 86-BPWII Replacement of Breaker Handle for 1-E41-F006 86-BGLE1 Replacement of Unit 2 Division I Backup Nitrcgen Rupture Diaphram 86-BRDF1 2A Standby Liquid Control (SLC) System Accumulator Needle Valve Replacement PM 84-195 Nitrogen Bottle Replacement for DivisionI Unit 1 Nitrogen Backup System
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PM 85-124 Replacement of Fire Damper 2-DG-FDMP-10 86-AYKZ1 Chlorine Detector Electrolyte Level Check 86-BPDIl Lexington Standard 4KV Fire Pump Breaker Maintenance No violations or deviations were identified.
5.
Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
' Specifications.
Through observation and record review, the inspectors verified that:
tests conformed to Technical Specification 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:
IMST-RHR21R RHR-LPCI, CSS, and HPCI High Drywell Pressure Instrument Channel Calibration.
01-03.3 Unit 1 Auxilary Operator (AO) Daily Surve111ence Report PT-15.4 Unit 2 Secondary Containment Integrity SBGT 01-3.1 Periodic Testing and Control Operator Daily Surveillence Report - Unit 1 01-3.2 Periodic Testing and Control Operator Daily Surveillence Report - Unit 2 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 Technical Specifications were met.
Control operator, shift foreman, clearance, and other logs were reviewed to obtain information concerning operating trends and out of service safety systems to ensure that there were no conflicts with Technical Specifications Limiting Conditions for Operations. Direct observations were conducted of control room panels, instrumentation and recorder traces important to safety to verify operability and that parameters were within Technical Specification limits.
The inspectors observed shift turnovers to verify that continuity of system
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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 Technical Specifications, 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, checked clearance 1-86-927, and verified the operability of onsite and offsite emergency power sources.
The inspectors performed walkdowns in normally inaccessible areas of Unit 2 during the short surveillence test outage. Areas inspected included the drywell, the torus and the main steam line tunnel. Minor material condition discrepancies found by the inspectors were corrected by the licensee prior to unit startup.
On October 23, 1986, the inspector observed during a tour of the Unit 2 drywell, that the manual SLC inboard injection valve, C41-F008, was open but not locked.
Operating procedure OP-05, Standby Liquid Control System, Revision 19, requires the valve to be locked open. The valve lineup sheet was last successfully completed on March 26, 1986.
The Quality Assurance (QA) group has outstanding items concerning control of locked valves.
Response to these items is due October 31, 1986.
The QA organization amended SFR-86-016 on October 30, 1986, to include C41-F008.
Corrective action will be addressed in the response to the SFR-86-016 addendum. The subject valve was locked prior to the startup on October 30, 1986. Another valve found by the inspector as being in the correct position but not locked is discussed in inspection report 325/86-1 _
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The licensee's visual inspection of snubbers in the Unit 2 drywell found 15 snubbers with low fluid level.
The inspection is required by Technical Specification (TS) 4.7.5.
As allowed by the TS, the licensee functionally tested the snubbers to demonstrate operability; all passed the test.
However, some of the snubbers with low fluid level activated during the drag test. A vendor representative in the presence of the inspector observed the testing of some of these snubbers. The vendor representative indicated that air was being drawn into the main cylinder when the shaft was fully extended for testing. When this air passes by the poppet during compression, an oil slug hammer effect occurs causing the snubber to activate and lock up.
The licensee attributed most low fluid level problems to leakage from the fill plug.
In nine cases, snubbers had loose fill plugs. Other problems included a torn accumulator seal and a pinched main cylinder seal. Snubbers which did not indicate full were either replaced or filled as necessary and the' fill plugs torqued correctly.
Thus, the snubbers now installed in Unit 2 are not identified leakers.
The licensee plans to inspect the drywell snubbers at each cold shutdown while additional investigation and testing, if necessary, is conducted.
The inspector has reviewed engineering evaluation 86-0447 concerning the low fluid level snubbers, The report concludes that the snubbers were operational in the as found condition. The inspector has several questions concerning this determination. Pending receipt of further information from the licensee clarifying the as-found operability of the snubbers, this is considered an Unresolved Item: Adequacy of Snubber Functional Test With A low Fluid Level (324/86-30-04).
On October 22, 1986, the inspector observed that the Unit 1 Average Power Range Monitor (APRM) B strip chart recorder 1-C51-R603B was showing a step increase of 5 to 10% above 100% and than a step return to 100%. The control operator had been told on turnover, approximately 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> earlier, that the APRM was being affected by surveillance activities on a radiation monitor.
However, the surveillance had been completed prior to turnover.
The inspector observed that three step increases had occurred several hours after turnover. The operator had not noticed that the changes were still occurring after completion of the surveillance.
The APRM was removed from service and work request 86-BRKX1 was issued to investigate the problem.
Low Power Range Monitor (LPRM)04-290 was found spiking.
Maintenance procedure MI-10-12, Installed Neutron Detector Testing (SRM, IRM, LPRM and TIP), was performed.
This test is a high voltage breakdown test.
The application of a high voltage can burn away the whisker which causes the spiking. A whisker is an impurity-related growth of metallic oxides on the uranium dioxide coating of the detector. The application of high voltage is the recommended method of repairing this type of spiking per GEK-83439, Operation and Maintenance Manual Model NA-200 Local Power Range Monitor.
This was successfully completed and the LPRM and APRM was returned to service.
The operator's failure to notice the problem was discussed with plant supervisio y
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On September 28, 1986, the inspector observed that the Unit 2 shift foreman, looked for the appropriate control operator (CO) to acknowledge an alarm, left his desk in the center of the "at the controls area" and responded to an annunciator. Because it was unusual that the shift foreman looked for someone before he took the action, the observation was discussed with the operations manager. A review of the matter by the licensee revealed that the CO, a licensed reactor operator (RO), had informed an extra R0 that he was going into the back area of the control room for a cup of coffee.
The extra R0 was talking on the phone to the dispatcher at the time and acknowledged the C0's statement. When he finished talking, the extra R0 also left to get a cup of coffee whithout informing the shift foreman. When the extra R0 met the CO, he immediately returned to the "at the controls area." He had been gone approximately one minute. The extra R0 stated that he forgot the unit had been turned over to him. It is the normal practice to allow the shift foreman to relieve the control operator when he must leave the control board area for a few minutes. However, the shift foreman is normally informed that he has the board.
Because the shift foreman responded to the annunciator, he demonstrated his responsibility to be the licensed operator at the controls as required by 10 CFR 50.54(k). Because the C0 and extra RO did not leave the control room area, the minimum shift crew composition of TS 6.2.2.a was met.
The operations manager met with his supervisors to review the conduct of control room turnovers. On October 9, 1986, the operations superintendent issued a policy statement to all shift operating supervisors. The policy states that:
Each unit reactor operator requiring relief for any reason shall not be relieved until a licensed operator or senior licensed operator occupies the control operator area and takes turnover of unit status from the operator being relieved.
To occupy the control operator area includes the control operator desk area and the RTGB area, near or on the dark carpet.
The shift foreman's area in the center of the control room is not an acceptable location.
No violations or deviations were identified.
7.
Onsite Review of LERs (92700)
The listed LERs were revieved 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.
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(Closed)' LER 1-83-33, Primary Containment Isolation System (PCIS) Reactor Low Level Instrument Drift. The frequency of calibration was verified to have increased'to a 6 month interval for 18 months following this event. No instrument drifting was observed. The present frequency for this instrument was 18 months.
(Closed) LER 1-83-110, Emergency Gas Treatment System Cooldown Valves Failed to Close Because Valve Was Stiff from Infrequent Use. The highest numbered Unit 1 LER that was issued in 1983 was 64. Also, this topic was not found on the licensee's Unit 1 LER summary sheet.
Therefore, this LER is administrative 1y closed.
(Closed) LER 1-85-27, Automatic Starting of Emergency Diesel Generators (DGs) Nos. 2 and 4 Resulting from Loss of Plant Emergency AC Bus E-2 During Periodic Maintenance Checkout. The licensee's corrective action included a revision of maintenance instruction MI-10-2H to include a safety precaution and, in Table 4, a list of 4KV breakers, whose 52 S devices cculd result in challenges to safety systems.
The inspector verified that the procedure changes were incorporated in Rev. 009 to MI-10-2H.
(Closed) LER 1-85-28, Design Inadequacy of Standby Gas Treatment System (SBGTS). Concerned a design error in the standby gas treatment system which would have prevented automatic initiation following a temporary loss of offsite power until the operator manually reset the system.
Before the modification, a loss of offsite power was incorrectly treated by the electrical logic as a high temperature signal.
The inspector examined modification package PM-85-74 which provided an automatic reset feature for the SBGTS following a loss of offsite power through the provision of an additional relay. The inspector examined the train A and B acceptance tests contained in the turnover package for PM-85-74 titled "SBGTS AUTO RESET."
The inspector observed that the test specifically verified that SBGTS trains A and B reset automatically following power interruption.
(Closed) LER 2-80-84, Containment Atmosphere Dilution (CAD) Tank Control Valve Inoperability from the Reactor Turbine Gauge Board (RTGB).
Dryers were visually verified in the instrument air system to prevent water accumulation in the electro pneumatic control valves. The work was done by plant modifications PM-80-260 and PM-80-261.
(Closed) LER 2-80-121, Reactor Level Instrument, 2-B21-LI-R604A, Tracking Problem. The level instrument was found to have drifted out of calibration and was recalibrated. The licensee documented that between 1982 and March 1985, that there was no drifting problem for this level instrument.
(Closed) LER 2-82-71, Total Value of Type "C" Local Leak Rate Tests (LLRTs)
Exceeded 60% of the Primary Containment Allowable Leakage (La). To provent recurrence, a specific leakage limit is applied for each LLRT by procedure EER 84-0037 and graphed per procedure ENP-16.4 to ensure that extensive degradation has not occurred. Valves are tested before and after rainte-nance to monitor performance. In 1984, primary containment was verified by
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LLRTs and an Integrated Leak Rate Test (IuRT) without the total sum of the as-found LLRTs exeeeding 0.60 La.
(0 pen) LER 2-82-83, Drywell to Torus Vacuum Breakers - X18A, C, and E -
Leakage Problem.
Dirt, rust, and silicon sealer (i.e., RTV from mainte-nance), prevented the seats of the valves to seal properly. The corrective action of performing an inservice inspection (ISI) program visual inspection, VT-2, was inappropriate. The licensee was re-evaluating this LER for a suitable inspection method.
(Closed) LER 2-82-92, Refueling High Reactor Coolant Chloride Content.
During refueling, the reactor coolant chloride content increased to 0.20 ppm.
The increase in chlorides occurred when shutdown cooling was restored after the residual heat removal (RHR) system was used to decrease the torus level. To prevent recurrence, suppression pool water chemistry controls have been established by procedure AI-81.
(Closed) LER 2-82-121, Primary Containment Isolation (PCI) Ball Valve Inoperable When a Traversing Incore Probe (TIP) Stuck in Its Guide Tube.
The guide for the TIP was found defective and replaced on October 31, 1982.
Also, contributing to the sticking was a low nitrogen purge pressure for the TIP system, which allowed moisture to accumulate in the tubing to cause the graphite lubricant to cake.
The TIP system nitrogen purge pressure has since been corrected and graphite is no longer used to lubricate the TIP guide tubes.
(0 pen) LER 2-83-01, Reactor Core Isolation Cooling Turbine Exhaust Diaphragm Pressure High Annunciator Alarm Due to Instrument Drift. Two cases were cited in this LER.
The first was due to an instrument drift of 2-E51-PS-N012 and it was recalibrated. The second case was due to water filling the switch housing of this instrument. This item will be closed after NRC inspection of the present detectors material condition.
(Closed) LER 2-83-43, Continuous Fire Watches for Inoperable Fire Detectors Not Established. The operations shift foreman failed to recognize that TS 3.7.8 was not satisfied by an hourly fire watch established for TS 3.3.5.7.
These TS requirements are currently covered in the licensee's reactor operator qualification program - limiting condition of operation (LCO)
requiring quick action, LP-07-2-32. Also, it has been the practice of the fire protection group to provide the operations shift foremen with compensatory fire protection recommendations.
(Closed) LER 2-83-47, Fire Suppression Water System Valves Were Not Covered in Test Procedure.
The inspector verified that the current procedu e, PT-35.22, Revision 12, has valves 2-MUD-V37 and 2-FP-V58 listed.
(Closed) LER 2-83-64, Diesel Generator Tripped on Generator Reverse Power Due to Sticking Contacts in the Jet Assist Time Relay (JATR). After a review of records and discussions with cognizant plant personnel who prepared the records, the inspector concluded that the sticking of the JATR of the diesel starting air system and the failed valve stem bearing in the
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1-SW-V207 valve were both isolated instances of equipment failures. After reviewing Revision 17 of operating procedure OP-50-1, the inspector concluded that the tripping of DG No.1 on generator reverse power was caused by a personnel error when the operator entered and executed the correct procedure at the wrong location.
(Closed) LER 2-83-79, A Generator Reverse Power Trip of the No. 1 Diesel. A generator reverse power trip on the No. 1 OG occurred during the performance of the monthly load test in accordance with PT-12.2a.
The involved auxiliary operator was counseled and instructed as to the proper execution of PT-12.2a, as were all plant licensed operators and auxiliary operators.
Specifically, the training addressed the need to promptly load the generator after synchronizing the generator to the load, as was required by PT-12.2a.
The inspector examined PT-12.2a and noted that the caution stating that load must be increased immediately following synchronization was clear and was placed immediately preceding the step requiring synchronization.
(Closed) LER 2-83-85, No. 4 Diesel Generator Would Not Develop Generator Output Current.
The No. 4 DG failed to start due to grounding of field shorting device No.17 which prevented generator exitation.
The licensee concluded that solenoid failure was probably an isolated event, although the licensee determined that this was the second such solenoid failure.
Based upon a recommendation of the Corporate Nuclear Safety group, the licensee prepared and issued MI-10-6A3 (Rev. 0) " Diesel Generator Field Grounding Relay (17) Inspection." The inspector examined Rev. O to MI-10-6A3. No problems were identified.
(Closed) LER 2-83-113, Primary Containment Atmospheric Control Inerting Inlet Isolation Valve Dual Open and Closed Indication Due to a Defective Limit Switch. The highest numbered Unit 2 LER that was issued in 1983 was 98. Also, this topic was not found on the licensee's Unit 2 LER summary sheet. Therefore, this LER is administratively closed.
(0 pen) LER 2-86-021, Inadvertent Deenergization af Reactor Protection System (RPS) Bus 2A. With Unit 1 shutdown and Unit 2 at 100% power, an A0 opened the Unit 2 Electrical Protection Assembly (EPA) breakers for RPS bus 2A instead of the Unit 1 EPA breakers for RPS bus 1A. This error deenergized RPS bus 2A, causing a half scram and tripping logic fur the applicable group isolations. Power was restored to the RPS bus 2A within one minute from the alternate power supply.
Several factors contributed to the event. The A0 had left the control room through the Unit 2 door, placing him in the wrong unit. The EPA breakers were not labeled with unit designations.
The A0 had operated the EPA breakers with no procedural step directing the operation.
The A0 committed the error while attempting to prepare to remove test equipment from the RPS bus.
Most of the steps performed by the A0 were contained in the Unit 1 OP-3, Revision 4, RPS Operating Procedure, sections 7.0, Shutdown, and section 8.1, Transfer RPS to Alternate Power Supply.
No step in either procedure required the A0 to open the EPA breakers. The A0
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annotated the procedure, indicating that the C0 authorized operation of the EPA breakers.
TS 6.8.2 requires that temporary changes.to procedures of specification 6.8.1, which includes OP-3, may be made provided that the change is approved by two memoers of the plant staff, at least one of whom holds a Senior Reactor Operators license on the unit affected and that the change is documented, reviewed pursuant to specification 6.5.2.1 and 6.5.2.2, and approved by the General Manager - Brunswick Plant or his designated alternate within 14 days of implementation. Contrary to this requirement, OP-3 was change on September 19, 1986, by adding a step to open the EPA breakers without the proper review, documentation, or approval. This is a Violation: Improper Temporary Revision to OP-3 When Operating EPA Breakers (325/86-29-01).
The inspector also had questions regarding the content of the LER. 10 CFR 50.73(b)(2)(ii)(J)(2)(ii) requires - that, for each personnel error, the licensee discuss whether the error was contrary to an approved procedure, was a direct result of an error in an approved procedure, or was associated with an activity or; task not covered by an approved procedure. No mention of the lack of procedural quidance was included in the LER.
Futhermore, 50.73(b)(4) requires that the LER contain a description of any corrective actions planned as a result of the event, including those to reduce the probability of similiar events occurring in the-future. The license changed the labels on the EPA breakers but did not include this information in the LER. No Notice of Violation is being issued for failure to comply with the above provisions of 10 CFR 50.73 since an NOV is being issued for the underlying event.
One violation and no deviations were identified.
8.
In Office LER Review (90712)
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 takei, or planned, existence of potential generic problems and the relative safety significance of the event.
(Closed)' LER 1-86-25, Autoisolation of the Control Building Heating Ventilating Air Conditioning System and Starting of Control Building Emergency Air Filtration Train 28.
No violations or deviations were identified.
9.
Followup on Inspector Identified and Unresolved Items (92701)
(Closed) Unresolved Item (325/82-05-10 and 324/82-05-10), Control Room Ventilation Emergency System Will Not Auto Isolate on High Chlorine. The control building emergency ventilation system would not automatically isolate to prevent the admission of chlorine into the control room if the local control switch was in the ON position.
The inspector examin91 the
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chlorine detectors in the control room air intakes and the modification package, PM-81-032, especially that portion of the turnover section used to perform. the acceptance test.
The inspector observed that the acceptance test properly tested the control building emergency ventilation system in the standby mode.
(Closed) Inspector Followup Item (325/85-22-04 and 324/85-22-04), Inclusion of Unlabeled Diesel Generator Valves in OP-39. This item concerned four valves on DG No.1, and three valves each on DGs 2, 3 and 4.
The fourth valve on DG No I was a valve installed in parallel with an air regulator valve in the starting circuit.
The inspectors observed, during engine walkdowns, that this valve was replaced by a check valve providing the same configuration as on the other three engines.
With respect to the other three valves per engine, the inspector observed that all twelve valves were properly included in Revision 27 to OP-39; and, during subsequent engine walkdowns, that all twelve valve tags matched the procedure description and were attached to the proper valves.
(Closed) Inspector Followup Item (325/86-12-01 and 324/86-13-01), Licensee to Modify Procedures to Adjust Diesel Generator Governor Oil level While Engine Is Running. The licensee modified OP-39 to provide a procedural step to verify-that the governor oil level is visible within the limits of the governor oil sight glass.
The inspector observed that the level verification was included in step B.2 of Rev. 28 to OP-30.
No violations or deviations were identified.
10.
IE Bulletin Followup (92717)
(Closed) IEB 79-17, Pipe Cracks in Stagnant Borated Water Systems at PWR Plants, 325/79-BU-17 and 324/79-8U-17.
No response was required for BWR plants.
Cracking occurred in the heat affected zones of type 304 stainless steel pipe that contained stagnant boric acid solution with some chloride contamination.
Brunswick uses boron in the SLC system.
The water is relatively stagnant and maintained at 95 degrees F to 100 degrees F.
The SLC piping is 304 stainless.
The licensee has not found a problem in this area.
Brunswick uses a buffer solution containing sodium pentaborate instead of boric acid. The recirculation ioop to the test tank is sampled for chlorine, flourine, boron, and sulfates during the monthly surveillance test; however, no acceptance criteria was applied to the results.
The licensee performs the required VT-2 visual inspection on the SLC piping every three months during the operational check of the system.
In the future, the licensee plans to only sample the test tank prior to the 18 month squib valve injection test. Acceptance criteria will be applied to future samples.
No violations or deviations were identifie...
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11.
Environmental Qualification (EQ) of Components (25576)
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HPCI Turbine Speed Sensor EQ The licensee found that the speed sensor magnetic pick-up installed in the Unit 1 and Unit 2 HPCI turbines was not environmentally qualified.
The licensee declared the turbines inoperable, installed qualified sensors, and began a review of the event.
The licensee questioned the sensor EQ during a procedure development documentation review on October 16, 1986.
Procedures were being written for any complex EQ required component replacement.
The procedure writer noticed that the EQ maintenance summary in the EQ data package-for the HPCI steam turbine required replacement of the speed sensor every 20 years.
Subsequent document review showed that the speed sensor had not been replaced during the EQ upgrade cf the HPCI turbine. However, the General Electric (GE) EQ report, NEDC-31001-1, called for replacement of the old Woodward supplied sensor with one supplied by GE and manufactured by Electro Corp. The EQ group verified that no documentation existed to support EQ of the installed Woodward sensor in the GE report or that any exception had been taken with the report regarding the sensor. The EQ group also found the qualified Electro Corp. sensors on site.
Operations declared Unit I and Unit 2 HPCI systems inoperable at 1:50 p.m.
on October 17, 1986.
Both units were at full power.
Declaring HPCI inoperable placed both units in a 14 day ACTION statement. Unit I remained at full power while Unit 2 shutdown on the evening of October 17 to replace recirculation pump seais.
The EQ group had informed operations that the sensor had not been replaced as required by the qualification documentation.
Had the speed sensor failed, no signal would be provided to the speed controller. The HPCI turbine would overspeed and trip with no speed signal.
Maintenance installed the new Electro Corp. sensors, restoring the EQ of the HPCI turbines. The Unit 1 sensor was replaced on October 18,
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1986, under Direct Replacement (OR) 86-0179 and returned HPCI to operable status. The Unit 2 speed sensor was replaced under DR 86-0180
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on October 21, 1986.
Unit 2 was restarted on October 30, after post maintenance requirements were completed satisfactorily.
The materials used in the speed sensor must withstand the Brunswick design EQ environment.
The non-metallic packing material used in the Woodward (old) speed sensor was the critical material that had not been evaluated for EQ. Initial information supplied to the licensee from GE shows that the packing material EQ threshold values are higher than the corresponding environmental values for Brunswick, i.e., that the old sensors could be qualified.
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Documentation did not support EQ for the speed sensor on November 30, 1985. Therefore, the enforcement issue relative to compliance with 10 CFR 50.49 remair.s Unresolved pending further Region II inspection and management review:
HPCI Speed Sensor Not EQ (325/86-29-02 and 324/86-30-02),
b.
Limitorque Motor-Operator Wiring On August 21, 1986, Region II's Atlanta based personnel contacted Carolina Power and Light Company (CP&L) concerning their 10 CFR 50.49 Limitorque Motor-0perated Valves (MOVs) with regard to IEN 86-03, Potential Deficiencies in Environmental Qualification of Limitorque Motor Operator Wiring. The licensee was requested to advise the Region of the action taken with regard to IEN 83-72, Environmental Qualification Notice No. 24, and the above IEN (86-03) and, if required, to provide a Justification of Continued Operation (JCO).
Subsequent telephone conversations with the licensee, and their letter NLS 86-334 dated September 19, 1986, indicated that ques,tionable wiring was found in Unit 2.
CP&L stated that Unit 2 was in a refueling outage when IEN 86-03 was received.
The licensee inspected 40 Limitorque actuators during the outage.
Thirty-three actuators had black wiring with no identifications markings, four of which were in the drywell.
The wiring in the four drywell actuators was replaced with qualified Rockbestos wire. Based on chemical analysis and review of the purchase specification, the licensee concluded that the unmarked wire was Raychem cross-linked polythylene and was therefore qualified at Brunswick for use inside and outside containment for both units.
The licensee discovered a single wire in the actuator for valve 2-E11-F024A, the Suppression Pool Cooling Isolation Valve, that had no generic qualification package to support it.
The wire markings identified the wire as VULKENE type XHHW. The wire was replaced with qualified Rockbestos wire.
The licensee plans to inspect Unit 1 Limitorque wiring during the refueling outage scheduled to start on January 31, 1987.
Since documentation did not support qualification of all wire and there is a question concerning compliance with 10 CFR 50.49 and the deadline, this is an Unresolved Item:
EQ of Limitorque Motor Operators (325/86-29-03 and 324/86-30-03).
No violations or deviations were identified.
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12. ManagementVisit(30702)
The Region II Director of Reactor Projects, the responsible section chief, and the inspectors met with the general manager and his principal staff on October 30, 1986.
Discussion items included 10 CFR 50.72 reports,
-management response to personnel errors, probabalistic risk assessements, NRC performance indicators, and EQ issuses.
13. Onsite Followup Of Events (93702)
a.
Addition of Boron Into Unit 2 Reactor On October 21, 1986, with the unit in cold shutdown during a routine sampling of the Unit 2 coolant, the conductivity was found to be 23.5 umhos.
TS 3.4.4 requires the conductivity to be less than 10.0 umhos when the reactor is in cold shutdown.
The licensee immediately began to take action to restore chemistry within the limit.
The only immediate method was to feed with the control rod drive pump
.and bleed to'radwaste. The Reactor Water Cleanup (RWCU) system was out of service for modification at the time. RWCU was returned to service at 1756 hours0.0203 days <br />0.488 hours <br />0.0029 weeks <br />6.68158e-4 months <br /> on October 22. The conductivity was measured as 6.7 umho at 0140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> on October 23.
Based on a review of a portable strip chart recorder on October 21, the licensee determined that the conductivity increase had occurred at the same time that surveillance PT-6.3.2 was being performed.
PT-6.3.2, Standby Liquid Control (SLC) System Injection Test, pumps water from a test tank into the vessel to verify the pump flow rate as required by TS 4.1.5.c.
The test tank had contained a diluted solution of boron as measured by previous samples.
The concentration of boron in the reactor coolant was measured by ion chromtography to be approximately 12 ppm.
The licensee expects no adverse reaction on the reactor internals, instrumentation or fuel assemblies since reactor coolant temperature was low and the solution injected was a buffer solution.
The concentration of boron was reduced to less than 1 ppm prior to startup of the unit. The licensee plans to revise PT-6.3.2 to provide a note similar to that contained in OP-05, Standby Liquid Control System, Revision 19. OP-05, page 26, contains the following note:
This procedure is intended to flush the SLC test tank and piping prior to SLC Injection PT-6.2.3 and periodically to reduce boron concentration buildup in SLC test tank and piping as needed.
b.
Inadvertent Core Spray Initiation The Unit 2 Core Spray systems automatically started and injected about 8000 gallons into the reactor vessel with the unit in cold shutdow,
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While conducting a routine non-TS calibration, MI-3-13A, of the Unit 2 Division II Emergency Core Cooling System power supply and inverter, a technican removed the fuses from inverter No. I and then mistakenly lifted the leads on inverter No. 2.
When the technican lifted the lead, he saw an arc and attempted to reattach the lead, blowing the inverter fuse.
All four diesels started, core spray initiated and injected, and HPCI and the Automatic Depressurization System received initiation signals.
The initiation logic was reset within five minutes.
The licensee attributed the event to personnel error. The inspector concurred with the licensee's conclusion that the procedure contained adequate-controls and cautions to direct the technican to the correct equipment. The inspectors will complete the inspection of this item for technical review and potential enforcement action during the routine LER review, after the LER has been issued.
No violations or deviations were identified.
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