IR 05000278/1985041
| ML20136F438 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 12/27/1985 |
| From: | Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20136F434 | List: |
| References | |
| 50-278-85-41, NUDOCS 8601070378 | |
| Download: ML20136F438 (31) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-278/85-41 Docket No. 50-278 License No. DPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name: Peach Bottom Atomic Power Station Unit 3 Inspection at: Delta, Pennsylvania Inspection conducted: October 26 - December 6, 1985 Inspectors: T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector J. E. Beall, Project Engineer J. P. Rogers, Reactor Engineer H. I. Gregg Lead Reactor Engineer Reviewed by:
E. Beall, Project Engineer
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Approved by: Ikz.7'85-Robert M. Gallo, Chief date DRP, Section 2A Inspection Summary: Operational readiness assessment inspection of Unit The primary purpose of the inspection was to verify that the licensee had established and implemented programs to restore the proper configuration of the reactor plant following extensive inspections, repairs and design changes; and, to revise the reactor operating information to support safe operation. Included were a review of management oversight and corrective action tracking, pre-operational testing, RHR pump inspections and repairs, functional testing of snubbers, emergency service water piping changes, electrical modifications and restart restriction The inspection involved 245 hours0.00284 days <br />0.0681 hours <br />4.050926e-4 weeks <br />9.32225e-5 months <br /> of inspection by two resident and three region-based inspector Results: No violations were identified. Corrosion was noted on the interior of the torus, licensee inspection of the torus will be conducted prior to restart of Unit 3. Unit 3 core reload activities were performed wel The ESW and electrical modifications were well documented and the modifications were in-stalled as designed. Numerous snubbers failed functional tests; and the failure mechanism, resolution of each failure and engineering evaluation are pendin A fire occurred in the 3C RHR motor. Licensee actions to combat the fire were adequate. Generic problems apparently exist in the RHR pumps with respect to impeller wear rings. Four steam separator hold down bolts have cracked and one bolt fell into the reactor annulus area during removal. The removal of the bolt was completed on December 8, 198 Inspection of reactor vessel internals for damage is planne ~
8601070378 B51231 PDR ADOCK 05000278 e r-D9
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S DETAILS Persons Contacted J. F. Mitman, Maintenance Engineer
- R. S. Fleischmann, Manager Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist D. L. Oltmans, Senior Chemist F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Engineer
- D. C. Smith, Superintendent Operations S. A. Spitko, Administration Engineer J. E. Winzenried, Superintendent Plant Services K.- A. Hudson, Corporate Engineer P..M. Pautler, Project Engineer A. J.'Wasong, Performance Engineer Other licensee employees were also contacte *Present at exit interview on site and for summation of preliminary finding . Unit 3 Plant and Inspection Status 2.1 Unit 3 was shutdown for refueling on July 14, 1985. Major work ac-tivities that have been completed include:
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reactor core defueling and refueling
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fuel inspections, sipping and reconstitution
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control rod drive-exchange
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IRM/SRM dry tube replacements
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recirculation and RHR piping NDE inspections (reference Generic Letter 84-11)
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core spray sparger T-box repairs
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recirculation suction piping nozzle (N-1) plug sample
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10 CFR 50 Appendix R, Alternate Safe Shutdown modifications
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Emergency Service Water System modifications
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125 VDC battery replacements
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Emergency Diesel Generators' annual inspections
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RPS and PCIS HFA relay replacement
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Ofi-ss system upgrade
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Snubber inspections and testing 2.2 ' The following NRC Inspections were perfortiied dur'ng the course of the Unit 3 outage:
Report #
(50-278/85-) _Insnector(s) Scope 26 Biceiouse HP & Chemistry Team - radiation protection for Unit 3 outage 30 Cheung Maintenance Programs 32 Kucharski Fuel Reconstitution 14 Gray /McBrearty Generic Letter 84-11 NDE 35 Kucharski Local leak rate testing 36 Bicehouse Core Spray sparger repairs - HP 37 Gray /Reynolds Generic Letter 84-11 NDE, Core Spray sparger repair, and N-1 plug sample 38 Della Ratta Special nuclear material control
& accountability - Fuel Reconsti-tution 39 Pullani/Dev 10 CFR 50 Appendix R, Alternate Safe Shutdown modifications 21 Johnson / Williams Plant Shutdown 27 Johnson / Williams NDE; fuel sipping, inspection and reconstitution 33 Johnson / Williams Core Spray sparger repair NRC open issues identified in these inspections required for restart of Unit 3 are addressed in this report or will be reviewed prior to restar . Previous Inspection Item Update 3.1 (Closed) Violation (278/82-14-01). Failure to follow a pre-operational test procedure for the modificat'.ons to the backup nitrogen supply to the ADS. The licensee responded to the violation in a letter dated May 17, 198 The inspector reviewed the licensee's response and determined it to be adequate. The individual performing the test did
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not complete the final step in the test procedure which was a system check off list to return the system to normal. The licensee rein-structed and counselled the individual involved in procedural control In addition, all operations personnel were given training in adminis-trative procedures. The inspector reviewed A-50, Training Procedure, Revision 10, September 6,1984, to verify that administrative proce-dures are included in licensed and non-licensed operator training program In addition, the licensee instituted a new administrative procedure A-89, Modification Acceptance Tests, Revision 0. February 28, 1984. Procedure A-89 applies to all pre-operational tasts per-
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formed on major and minor plant modifications. The inspector reviewed this procedure A-89 and determined it to be adequate. Based on review of the licensee's formal response, procedure A-50 and procedure A-89, this item is close .2 (Closed) Inspector Follow Item (278/83-05-05). Review licensee upset report for an ECCS initiation and unplanned liquid release on Unit 3 during the 1983 refueling. On March 3, 1983, a false reactor low-low-low water level signal caused low pressure ECCE initiation and injection, and caused the emergency diesel generators to star This event was reviewed during NRC Inspection 278/83-05. The licensee reported the event via the ENS and submitted an LER #3-83-07 on March 17, 1983. In addition to the ESF actuations, 50 gallons of reactor water was released to the storm drain system. The inspector reviewed the licensee upset report #3-83-02 for this event and deter-mined the report to be adequate. In addition, the LER #3-83-07 was again reviewed and found to be adequate and consistent with the upset repor Based on initial review of this event during NRC Inspection 278/83-05, a review of LER #3-83-07 and a reyfew af the licensee upset report, this item is close .3 (Closed) Unresolved Item (278/83-20-01). Acceptability of licensee locked valve logging practices. Procedure A-8, Control of Locked Valves, Revision 5, March 14, 1983, requires that locked valves that are to be unlocked and repositioned are to be entered into the locked valve log. During the performance of a test of the Unit 3 Standby Liquid Control (SBLC) system, per ST 13.18, a general entry into the locked valve log was made stating "various SBLC valves". The licensee revised the SBLC ST 13.18 and the inspector reviewed the revision dated November 18, 1983. The revised ST 13.18 procedure delineates the specific locked SBLC valves that are to be manipulat-ed, and requires individual log entries for each valv In addition, the inspector reviewed the Unit 3 locked valve log and spot checked a number of locked valves in the plant. No abnormalities were identi-fied. Based on the above, this item is close .4 (Closed) Inspector Follow Item (278/84-03-03). Source Range Monitor (SRM) operability during control rod testing. ST 3.1.2, SRM Core Monitoring Test was performed as a prerequisite to the performance of ST 10.8, Control Rod Withdrawal Test However, there was no
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periodic retest of the SRMs during ST 1 ST 10.8 performance typ-ically may occur over a several week time frame. The licensee re-vised ST 10.8, Revision 8, December 12, 1984, to include a weekly functional test of the SRMs per ST 3.1.2. The inspector reviewed the revised ST 10.8 and determined it to be adequate. In addition, the inspector observed control rod testing per ST 10.8 and verified performance of the periodic functional testing of the SRMs per ST 3.1.2 during Unit 3 recovery from the refueling outage in November, 198 Based on the above, this item is close .5 (Closed) Violation (278/82-09-01). Failure to have appropriate in-structions for verification of the seismic restraints on the backup nitrogen gas bottles for containment isolation valves in the Contain-ment Atmosphere Control System. The inspector reviewed ST 7.9.2, Revision 3 and Revision 4, dated May 5, 1982 and August 24, 1982 re-spectively. The surveillance test ST 7.9.2, Daily Check of Contain-ment Isolation Valve N2 Bottle Pressure was revised to include verification of the seismic bottle restrain This violation is close .6 (Closed) Violation (278/84-20-01). Failure to maintain a written safety evaluation for deactivated and closed ECCS minimum flow valves. The licensee responded to the violation in a letter dated November 15, 1984. The inspector reviewed the licensee's response and determined it to be adequate. The licensee did consider the ef-fect'of the inoperable minimum flow valves, but did not perform a formal written safety evaluation. The licensee issued a letter to operations personnel on September 11, 1984, rega-ding the effects of abnormal ECCS configurations. The inspector reviewed the September 11, 1984, letter and determined it to be adequate. The licensee tested the RHR pumps with an open and deactivated minimum flow valv The result was that the RHR pumps could achieve Technical Specifi-cation required flow. The licensee intends to maintain a RHR pump operable with an open and deactivated minimum flow valve if the required flow can be achieved. In the above case, a written safety evaluation would be performed. Otherwise, the RHR pump would be declared inoperable. Based on the above, this item is close .7 (Closed) Inspector Folicw Item (278/85-07-03). Operator awareness and shift turnover documentation of inoperable equipment. The in-spector reviewed the reactor operator, shift supervisor and control operator logs and applicable shift turnover checklists for documen-tation of inoperable equipment. No unacceptable conditions nor un-documented inoperable equipment were identified. The inspector discussed current plant equipment conditions and inoperable equipment status with the operators. They were knowledgeable of all technical specification related equipment that was out of service. The inspec-tor will continue to review logs and turnover checklists, and to question operators on equipment status. This item is close p
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3.8 (Closed) Inspector Follow Item (278/85-08-01). Minor errors in P&ID M-358, Standby Liquid Control (SBLC) system. The licensee submitted a drawing change request to correct the SBLC P&ID. The inspector reviewed P&ID M-358, Revision 15, dated March 25, 1985. The missing
" locked closed (LC)" designations and incorrect valve identifications on the SBLC P&ID were corrected. This item is close .9 (Closed) Violation (278/85-12-03). Failure to conduct an adequate Shift Supervisor relie Inspection 50-278/85-12 addresses the cir-cumstances of the violation and the licensee's corrective act4;ns to avoid further violations. The inspector reviewed recent Shift Super-visor relief practices and found them to be in accordance with proce-dure A-7, " Shift Operations". The inspector will continue to review licensed operator shift relief and turnover. This item is close .10 (Closed) Inspector Follow Item (278/81-10-03). ECCS room drain com-munication. To prevent room-to-room leakage, the licensee has plugged ECCS room drains in the HPCI and RCIC room COL GP-2A, Re-actor Startup Order, Revision 62, July 1, 1985, .itep 6 has a signoff for verifying ECCS room drains are plugged. This item is close .11 (Closed) Violation (278/85-12-01). Failure to maintain the seismic qualification of nitrogen cattle 0B5538 This violation was caused bj errors in judgment of operations personnel performing ST 7.9.2,
" Daily Check of Seismic Gas Supply Bottle Pressures". The licensee instructed operations personnel on the requirements for seismic qual-ificati,n of the nitrogen bottles and posted signs near the gas bot-tie racks to describe the seismic restraint requirements. The inspector examined a sampling o; the signs in the Reactor Building and the Rad Waste Building. The inspector had no further question This item is close .12 (0 pen) Inspector Follow Item (278/85-08-04). The licensee identified a problem with the control rod drive hydraulic control unit (HCU)
scram outlet valve isolation valves (13-112) on Unit 2. This valve (13-112) is the manual isolation gate valve on the scram discharge riser pipe. The problem concerns cracking of the valve stem to valve gate (disc) connection in one of 18 valves inspected. The cracking was completely through one wall of the valve disc connection, however the other wall remained intact and no separation of the stem and disc occurre If separation were to occur, the valve disc (valve is nor-mally open and is required to be open for control rod to scram) could potentially then " float" and jeopardize the capability of the control rod to scra The Unit 2 valve supplier is Dresser, Inc. (Hancock valves) and the disc material is 420 stainless steel. The corre-sponding valves on Unit 3 are from a different manufacturer (Vogt)
and the licensee stated the valves were less susccptible to the same problem as the disc material is 410 stainless steel. The cracking was identified by tne licensee as caused by intergranular stress cor-rosion cracking (IGSCC). The licensee replaced all discs, valve L
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stems, and bonnet gaskets on the Unit 2 HCU 13-112 valves during the 1984-1985 refueling outage. The Unit 3 13-112 valves were inspected on 10 HCUs during the current 1985 refueling / outage and no indication of any cracking was found. The inspector reviewed MRFs 3-3-M8506123 through 6133 which documented the inspections. No unacceptable condi-tions were identified. The inspector also reviewed the licensee's metallurgical report dated April 12, 198 However, apparent IGSCC with the 410 stainless steel in the RHR pump wear rings discussed in detail 14.1 of this report indicate further review cf the Unit 3 HCU valves is appropriate. This item remains ope .13 (Closed) Inspector Follow Item (278/80-24-05). Replace the Unit 3 safety relief valves (SRV) acoustic monitor cables with environmen-tally qualified cables. The cables for all 11 SRVs and two code safety valves were replaced with environmentally qualified cables during the 1983 Unit 3 refueling / outage. The inspector reviewed MRF 3-1-C830215 for the SRVs (RV71A through L) and the code safety valves (SV-70 A,B). The MRF was completed on August 12, 1983, and the oper-ational verification was completed on August 16, 1983. This item is close .14 (Closed) Inspector Follow Item (278/85-12-02). ECCS actuation in-strumentation test box failure. During surveillance testing on ECCS actuation instrumentation, a test box was plugged into test jacks and an exposed wire (insulation off) shorted causing energization of ECCS actuation relays. The licensee checked all other similar test-boxes
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-and found no other abnormalities. The failed test box was repaire The licensee instituted a periodic check every six months for the associated test boxes. The inspector discussed this with licensee instrument and control enginee s. In order to track this six month inspection, the licensee attacaed a calibration sticker to the test boxes. The inspector had no farther questions at this time. This inspector follow item is close .15 (Closed) Inspector Follow Item (278/84-29-03). Licensee's disposi-tion of the ten recirculation inlet safe end (N-2) nozzles for Unit As a result of IGSCC indications on Unit 2 the licensee replaced all N-2 nozzles during the 1984-85 Unit 2 pipe replacement outage and committed to inspect the N-2 nozzles on Unit Results of the Unit 3 N-2 inspections were reported by the licensee in a letter dated October 11, 1985, and at a meeting in Bethesda, Md., on October 31, 1985. It was reported that eight inlet safe ends have thin side crack indications and nine inlet safe ends have thick side crack in-dications at a location where the thermal sleeve is welded to the inside of the safe end. The licensee determined that Unit 3 could operate another cycle before repairing the nozzles. However after discussions with NRR, the licensee committed to conduct a midcycle examination of crack growth; use improved water chemistry, operate under more restrictive reactor coolant unidentified leakage criteria
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in the drywell than provided in tne Technical Specifications and im-plement a crack growth monitoring program (see detail 15). This item is close .16 (Closed) Inspector Follow Item (278/81-10-01). Review the licensee's upset report and corrective actions regarding the Unit 3 HPCI room flooding event on April 14, 1981. The inspector reviewed the licensee upset report #3-81-3 and associated reports for the HPCI room flooding event. The basic cause of the flooding was due to inadequate blocking of the HPCI pump. This open item was reviewed in NRC Inspection 50-278/85-17 and was closed. Based on the above, this item is close .17 (Closed) Inspector Follow Item (278/84-29-02). Repair of pipe hanger 3-23-DBN-S3 which along with hanger 3-23-0BN-S4 caused HPCI to be inoperable on August 1, 1984. Hanger 3-23-DBN-S54 was repaired on August 2, 1984. Hanger 3-23-DBN-S3 was repaired as part of Plant Modification 1402. The. inspector reviewed the modification documen-tation &ssociated with the hanger. The inspector verified that the
. hanger had been modified. The inspector also reviewed the licensee's analysis of the cause of the failure and corrective actions including Modification 1268 which modified the HPCI governor control system to eliminate the large surge of steam on turbine startup. The inspector had no further questions. This item is close . Plant Operations Review 4.1 _ Station Tours The inspector observed plant operations during daily facility tour The following areas were inspected:
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Control Room
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Cable Screading Room
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Reactor Building
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Turbine Building
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Radwaste Building
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Pump House
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Diesei Generator Building
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Protected and Vital Areas
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Security Facilities (CAS, SAS, Access Control, Aux SAS)
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High Radiation and Contamination Control Areas
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Shift Turnover
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Unit 3 Drywell 4. Control Room and facility shif t staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specification Presence of a senior licensed operator in the control room was verified frequentl _
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4. The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within Technical Speci-fication requirements and normal operating limits. ECCS switch positioning and valve lineups were verified based on control room indicators and plant observations. Observa-tions included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instrument .1.3 Selected control room off-normal alarms (annunciators)
were discussed with control room operators and shift super-vision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if required, was being taken. In addition, the applicable alarm cards were checked for accuracy. The operators were knowledge-able of alarm states and plant condition .1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personne .1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compli-ance with administrative procedures and regulatory guid-anc No inadequacies were identifie .1.6 The inspector observed main stack and ventilation stack radiation monitors and recorders, and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identifie .1.7 The inspector observed control room indications of fire detection instrumentation and fire suppression systems, monitored use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment stations. No inadequacies were identifie .1.8 The inspector observed overall facility housekeeping conditions, including control of combustibles, loose trash and debris. Cleanup was spot-checked during and after maintenance. Plant housekeeping was generally acceptabl The housekeeping cor.ditions in the drywell were satisfacto-ry, with a noted improvement since the last NRC inspectio .1.9 The inspector verified operability of selected safety related equipment and systems by in plant checks of velve positioning, control of locked valves, power supply avail-ability, operating procedures, plant drawings, ,
instrumentation and breaker positioning. Selected major components were visually inspected for leakage, proper lu-brication, cooling water supply, operating air supply, and general conditions. No significant piping vibration was detected. The inspector reviewed selected blocking permits (tagouts) for conformance to licensee procedures. No inad-equacies were identifie .2 Logs and Records The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, re-quired entries, operating and night order propriety, correct equip-ment and lock-out status, jumper log validity, conformance to Limiting Conditions for Operations, and proper reporting. The fol-lowing logs and records were reviewed: Shift Supervision Log, Reac-tor Engineering Log, Reactor Operator's Log, Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits, Locked l Valve Log, Maintenance Request Forms and Ignition Source Control Checklists. Control Room logs were compared against Administrative Procedure A-7, Shift Operations. Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site manage-ment constituted evidence of licensee review. No unacceptable condi-tions were identifie .3 Unit 3 Core Reload The inspector reviewed Special Procedure (SP)-870, " Plant Conditions Necessary to Reload Fuel Unit 3", Revision 0, dated October 28, 1985, for Technical Specification requirements for loading fuel into the reactor vessel. SP-870 was reviewed in the control room while it was being implemented and after it had been completed. All steps had been completed and signed off satisfactorily. All changes to the SP-870 were handled properly and in accordance with procedures. The inspector questioned the operators on SP-870 and found them knowl-edgeable of the procedur Unit 3 core reload began on November 1, 1985. A review of the fol-lowing documentation was performed:
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FH-6C " Fuel Movement and Core Alteration Procedure During a Fuel Handling Outage," Revision 18, August 21, 198 FH-6C, Appendix 1, " Core Component Transfer Authorization Sheet."
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S-14.1-3, " Operation of the Unit 3 Refueling Platform Controls and Interlocks," Rev. 0, May 8,198 S-14.2, " Moving Fuel from the Fuel Pool to the Reactor," Revi-sion 5, May 8, 198 _
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'S-14.3, " Moving Fuel from'the Reactor to the Fuel Pool," Revi-1sion 7, May 8, 198 S-14.4, " Moving Fuel Within the Reactor," Revision 7, May 8, 198 ST-12.1-3, " Refueling Interlock Functional Test," Revision 1, October 31, 198 .
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ST-3.1.2, "SRM Core Monitoring Test," Revision 9, January 11, 198 ST-3.1.3, "SRM Functional and Calibration Check," Revision 5,
-October 29, 198 The inspector monitored the following items associated with core.re-load through direct observation of fuel handling and Control Room activities:
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The operability of refueling interlocks
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The operability of source range monitoring (SRM) instrumentation-
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Availability of direct communication between the control room and the refueling bridge
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The' presence of a senior licensed operator supervising fuel han-dling activities
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The operability of the standby gas treatment system.and secon-dary containment ,
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The radiological precautions for fuel handling including adher-ence to the RWP
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_The precautionary measures for preventing the intrusion of for-eign objects into.the reactor cavity .
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The operation of refueling bridge and associated fuel handling equipment .
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Reactor vessel and fuel pool water level and clarity requirements
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Fuel and component accountability in the spent fuel pool and in the reactor core
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Reactor mode switch locked in " refueling" position
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The operability and required full insertion of all control rods
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Unit 3 reactor operator cognizance of refueling activities and direct monitoring of SRM levels and changes (count rates and period changes).
Fuel loading was completed on November 14, 1985. Within the scope of this review of fuel loading activities, no unacceptable conditions were identifie .4 Unit 3 Torus Inspection On December 4, 1985, the inspector examined the inside of the Unit 3 toru Items checked included: drywell vent headers, suppression pool downcomers, torus to drywell vacuum breakers, torus cooling spray ring header, ECCS pumps' suction lines, overall torus integri-ty, water clarity and general area cleanliness. The inspector noted several areas of corrosion indications on the torus wall and piping inside the torus. The inspector reviewed.the following documents:
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Technical Specification 4.7.A.2.h which requires a visual in-spection for evidence of deterioration of the dryw?ll and torus interior surfaces each operating cycl ST 13.37, Drywell and Torus Inspection. The ST requires the drywell and torus surface inspection be performed per procedure ST/ISI- ST/ISI-7, Inservice Inspection - Visual Examination of Drywell and Torus Surfaces. The procedure provides the level II examin-er a check list for visual inspection of the accessible interior and exterior surfaces of the torus for evidence of cracking, peeling, delamination, undercutting, and corrosion of exposed metal. The completed examination report is forwarded to the level III nuclear coatings inspector (Mechanical Engineering Division) for review and disposition of any indication The licensee stated that ST/ISI-7 is a new procedure (PORC approved May 6, 1985) and the torus surface inspection had not yet been com-pleted during the current Unit 3 outage. The last visual inspection of the torus was conducted on July 28, 1983, by a representative of the Mechanical Engineering Division as documented in a memorandum dated August 3, 1983. At that time no indication of corrosion was noted. After completion of the torus inspection and resolution of the corrosion evidence observed by the inspector, this item will be reinspected (IFI 50-278/85-41-01).
5. Nuclear Review Board (NRB)
The inspector attended the NRB meeting #178 on December 5, 1985. The in-spector reviewed the requirements of Technical Specification (TS) section
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6.5.2, Operation and Safety Review Committee (0&SRC). The O&SRC is cur-rently called the NRB. The NRB meeting was conducted in accordance with TS 6.5.2 as verified by checking the following items:
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A quorum of the NRB was present
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The meeting composition was adequate
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Independent review and audit of required activities was performed
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Written minutes of the nesting were generated Areas discussed during the meeting included:
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Plant status
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Mechanical snubbers
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RHR pump failures
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Radiation protection
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Cable tray fire The inspector noted that the NRB members exhibited a questioning attitude with regards to the safety issues being reviewed. Within the scope of the NRB meeting review, no unacceptable conditions were identifie . - Review of Licensee Event Reports (LERs)
6.1 The inspector reviewed LERs submitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the descrip-tion and corrective action adequacy. The inspector determined wheth-er further information was required, whether generic implications were indicated, and whether the event warranted on-site followu The following LERs were reviewed:
LER N LER Date Event Date Subject
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e 6.2 On-Site-Followup For LERs selected for on-site followup and review (denoted by aster-isks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued operations of the facility was conducted in accordance with Technical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59. Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewe . LER 3-85-1 The LER concerns scram and Group I, II and III isolation signals caused by the inadvertent de-energization of the Reactor Protection System (RPS) and Primary Containment Isolation System (PCIS) logic on Octo-ber 18, 1985. Removing the jumpers required for special Procedure 716 caused trips in the "B" channels of the RPS and PCIS logics. These trips, when combined with the "A'!
channel trips present as a result of system blocking caused the full scram signal and Group I, II and III isolation signals. The inspector reviewed and discussed the event with the licensee. The LER states that Special Procedure 716, " Temporary Bypass of ECCS, PCIS, and RPS Action fro-a Low Vessel Level for Low Level Work with the Core Off-loaded", Rev. 1, dated October 7, 1985, will be revised by December 31, 1985, to provide the necessary steps to prevent the event from re-occurring. The inspector discussed the procedure-with the engineer responsible for the chang The licensee committed to revise the procedure before using it again. The inspector will review the revision when
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completed and had no further questions at this tim . LER 3-85-17. The LER concerns a scram signal generated by bumping an IRM cable while the "A" channel of RPS was out of service for maintenance on October 18, 1985. The event was reviewed and discussed with the licensee. The inspector noted that apparently similar events had occurred on Unit 3 and not reported to the NR The lack of reporting RPS actuations was an apparent viola-tion in NRC Inspection 278/85-33. Based upon the discus-sions associated with the apparent violation the licensee started reporting the events begin,ing with the event of LER 3-85-16 which also' occurred on October 18. The licensee is writing LERs to cover previous events identi-fied but not reported. The inspector believes LER 3-85-17 is adequate with the generation of reports on the previous similar event _ _ _ - - ___
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15 Disassembly and Inspection of RHR Injection Valves Due to the dimensional discrepancies encountered with Walworth replacement parts during repairs to the Unit 2 M0-2-10-154A RHR injection valve (NRC Combined Inspection Report Nos. 50-277/85-30; 50-278/85-27) the licensee determined that a dimensional verification of the identical Unit 3 MO-154 valves would be completed during the current outage. To facilitate the verification, the licensee completed a preliminary revision of Maintenance Procedure M-10.3 to reflect the actual Walworth valve configuration and provide documentation for the dimensional inspection The inspector reviewed the completed PORC approved Maintenance Request Form (MRF 8507265) for the dimensional verification of the B loop RHR in-jection valve M0-3-10-1548 completed November 2, 1985. All dimensions documented were within the Walworth recommended thread dimensions for both the locknut to yokenut engagement and the stem to yokenut engagement. The one discrepancy noted concerned the slight damage of approximately 4 inches of 2 yokenut external threads by the locknut set screws. Two set screws are drilled and tapped through the locknut 90 degrees apart and counter-bored into the yokenut to prevent the locknut from backing off the yokenu The valve was reassembled with the original parts and with 3 set screws at 120 degrees apart drilled and tapped through the locknut into the yokenut in place of 2 set screws 90 degrees apart. The valve was tested for oper-ability and placed back into service on November 6, 198 The licensee requested the present M0-154 valve vendor (Aloyco) to provide an engineering analysis to check the adequacy of the locknut to yokenut joint strength, and determine if 3 set screws drilled and tapped through the locknut at 120 degrees would provide a more equal distribution of loading between the yokenut and locknut. Since the engineering evaluation for the yokenut-locknut engagement was performed without taking into ac-count the presence of set screws, Aloyco approved the use of three set screws in their letter to the licensee dated August- 30, 1985. The licensee documented this field change in the MRF package for valve M0-3-10-154 A modification (MOD 1845) has been issued to design and install a lifting beam so that the limitorque operator for valve M0-3-10-154A can be re-moved. Lnce the operator is removed the valve can be disassembled for dimensional verification and during reassembly the 3 set screw field change can be completed. The licensee intends to install the lifting beam and perform the M0-3-10-154A valve dimensional verification prior to the end of the current outag The inspector noticed that the three set screw change had not been incor-porated into the proposed revision to Maintenance Procedure M-10.3. The licensee's representative stated that the set screw change would be re-viewed for incorporation into the procedur The completion of the MO-3-10-154A valve dimensional verification and the incorporation of the set screw change into Procedure M-10.3 will be re-viewed in a subsequent inspection (IFI 278/85-41-05).
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8., Maintenance
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For the following' maintenance activities the inspector spot-checked admin-
~. istrative controls, reviewed documentation, and observed portions of the actual maintenance:
Maintenance ,
Procedure 6 ,
Document ' Equipment Date Observed S.4. CRD Friction Testing October 30, 1985 \
M.10.24 3C RHR Moto November 4, 1985 M.1 RHR Pump December 3, 1985 L t
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Administrativecont)olecheckedincludedmaintenancerequests, blocking 1 m permits, fire watches and ignition source controls, item handling reports, and shift turnover information. Documents reviewed included procedures,
material certifications and receipt inspections, welder qualifications and weld information' data shee A
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No inadequ'acies were identifie [s ' ' Radiation Protection ,
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During this report period, the inspector examined work in progress includ- N'
ing Health Physics (HP) controls, badging, protective clothing use, adher-ence to Radiation. Work Permit (RWP) requirements, surveys and handling of potentially contaminated equipment and material The inspector observed in'dividuals frisking in accordance with Health Physics procedures. A sampling of high radiation doors was verified to be locked qas. required. Compliance with RWP requirements was verified during each tour. RWP line: entries were reviewed 4.o verify that personnel had
.nrovided'the required information and people working in RWP areas were
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observed to be meeting tha applicable requirements. No unacceptable con-ditions were identifie ,
1 Physical Security The inspector monitored security activities for compliance with the ac- .
cepted Security Plan and associated implementing procedures, including: '
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ope _ rations of the CAS and SAS, checks of vehicles on-site to verify proper control, observation of protected area access control antf; badging proce-dures on each shift, inspection of physical barriers, checks on control of vital area access and escort procedures. No inadequacies were identifie ,
3 At 6:00 a.m. on October 28, 1985, a contracter employee found 10 live 22
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caliter cartridge sFells in the Unit 3 reactor building elevator. The elevator is within the protected area butsoutside tne vital are The
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k u 1 contractor employee reported this to the Control Room, and the shells were turned over to security. The licensee performed a search of the area, however, nothing more was found except an empty 22 cartridge shell bo The inspector discussed finding of'the shells with the licensee, and ques-tioned how the shells went through security apparently undetected. A re-view of the " Performance of Metal Detection Devices Review Guidelines #3,"
Revision'1, dated February 16, 1978, requires the metal detectors to de-tect eight ounces of non-ferrous meta Ten live 22 caliber shells weign less than one oun_c (Each shell weighs 29 grains or about 0.06 ounce.)
The licensee weighed the 10 shells and the result was 2.5 to 2.7 grams per shell or less than 1.0 ounce tota At 10:00 a.m. on October 31, 1985, the licensee reported that the source of the 10 live 22 caliber cartridge shells found on October 28, 1985, had been< identified. The individual had previously used his jacket while hunting, forgot that the shell box was in a pocket, and wore it to work on site. The shells apparently fell out of his jacket pocket while riding the Unit 3 reactor building elevator where the shells were later foun The inspector further discussed this event with'the license The licensee counselled the individual who brought the shells on site. The
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inspector had no further questions at this tim N,,.
_ 1 Emergency Service Water (ESW)_ Modification 4 11.1 ESW Chemical Injection Modification
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The inspector reviewed modification package 1693 (MOD 1693) for Unit 3 which involved the installation of two metering pumps to inject two
, corrosion treatment chemicais (polysilica and polyacrylate) into the Emergency Service Water (ESW) system. Polysilica is a filming agent
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which forms a protective coating on carbon steel pipin Polyacrylate is a dispersant which minimizes pitting corrosion caused a by water sediments and silt depositing on piping. ESW chemical in-t -
jection is intended to mitigate future corrosion effects after recent cleaning of the ESW piping. This cleaning was done by hydrolazing ,
the ESW piping per MOD 155 ' The inspector reviewed the PORC approved safety evaluation for MOD 1693. The inspector agreed that the modification did not create an unreviewed safetv question as defined in 10 CFR 50.59 and did not involve a change to Technical Specifications. The inspector reviewed the letter, dated May 15, 1985, from the Commonwealth of Pennsylvania, Department of Environmental Resources, to PECo which authorized the
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use NALC01370 (polyacrylate scale inhibitor) and NALCO 2513 (sodium
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silicate corrosion inhibitor for steel) in the ESW system. The three completed MRFs (8506809, 8506814, and 8506872) pertaining to MOD 1693 were also reviewed.
y s The inspector observed an operational test of the ESW chemical injec-
' tion system. A verification was made that the chemical injection N ,
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feed tap is located on the service water system piping just upstream of ESW-system safety related boundary. .The inspector verified that an isolation valve and check valve are provided on the injection line prior-to the chemical injection feed tap to prevent service water back-flow during injection and system maintenance. A confirmation was made that the injection skid / drum laydown was surrounded by a 2 inch dam to contain chemical leaks and minor spill The licensee's safety evaluation for MOD 1693 stated that if one 55 gallon drum of each chemical was drained into the radwaste floor drain system the radwaste floor drain demineralizer would be exhaust-e The inspector confirmed that the licensee had plugged the only radwaste floor drain located near the injection syste The licensee will revise the Peach Bottom FSAR to indicate this modi-fication to the ESW syste Within the scope of the review of these modifications on the ESW sys-tem, no unacceptable conditions were identifie .2 Emergency Service Water (ESW) System Cleaning, Valve and Piping
. Installation Modification The inspector reviewed modification package 1557-(MOD 1557) which involved the hydrolazing and cleaning of the ESW system and installa-tion of access taps and drains to facilitate such cleaning in the future. The modification was deemed necessary by the licensee after examination of a section of Unit 2 ESW piping revealed considerable deposits of iron oxide solids on the inner wall of the pipe. ' Metal-lurgical examination indicated that the ESW~ pipe wall had experienced both general and pitting corrosion but the remaining wall thickness was found to be within piping specifications. To assure sufficient flow for the Unit 3 safety-related equipment supplied by the ESW sys-tem, pipe replacement or cleaning was necessar The inspector reviewed the safety evaluation associated with MOD 1557 for completeness in addressing potential safety questions in accor-dance with 10 CFR 50.59. The safety evaluation states that the modi-fication does not involve an unreviewed safety question and no changes to the Technical Specifications are required. The following Technical Specifications were reviewed by the licensee to make tnis determination:
3.5A Core Spray and LPCI 3.5C HPCI 3.5D RCIC 3.5F Low Pressure Cooling and Diesel Availability 3.9A Auxiliary Electrical Equipment 3.9B Operation with Inoperable Equipment 3.9C Emergency Service Water System i
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The modification work required the isolation of both core spray sys-
. tems, low pressure cooling injection system (LPCI), and the contain-ment cooling subsystems. Technical Specification 3.5F allows the <
above isolations if the reactor is in cold shutdown and none of the work to be performed had the potential to drain the reactor vesse Regarding this modification, the inspector verified that these above requirements were met. The safety evaluation had received the appro-priate level of review and had been PORC approve The inspector reviewed the Maintenance Request Forms (MRF) and other documentation for this modification (MOD 1557) listed in the Attach-ment to this report. The drawings listed in the Attachment satis-factorily incorporated MOD 1557 change The inspector reviewed the final Modification Acceptance Test (MAT)
for. MOD 1557, " Unit 3 ESW System Flow Verification For ECCS Room Coolers". All flows were verified to be above minimum flow re-quirements for each ESW component as required by the safety evalua-tio The MAT for MOD 1557 was verified to be PORC approved on October 30, 198 Check Off List (COL) ST/ISI 6-3b, Check Off List for the visual exam-ination of Class 3 ESW components during a system pressure test was reviewed. The ESW system hydrostatic test occurred on November 6, 1985. The test was conducted at a pressure greater than 110% of op-erating pressure as required by the safety evaluation. The three leaks discovered during the test were properly documented and given MRF numbers for repairs (MRFs 8507753, 8507754, and 8507755).
ST/ISI-6 Appendix R, ESW system piping pressure test (ECCS room cool-ing portion to pond discharge) was reviewed. The hydrostatic test occurred on November 5, 1985, at a pressure greater than 110% of op-erating pressure as required by the safety evaluation. The inspector verified that the four hour hold time with no apparent decrease in system pressure was observed during the tes Special procedure #829, MOD 1557 freeze seal procedure was reviewe The procedure outlines the actions and safety precautions necessary when using freeze plugs in the Unit 3 ESW torus ring header in order to facilitate piping replacement and tap, flange,and valve installation in various sections of the ESW system without having to isolate the entire system. The inspector verified that the procedures were followed for each of four freeze plugs installed and that both before and after ultrasonic examinations were performed on each ESW torus ring header freeze area. The special procedure was PORC approved on-July 19, 198 _- _
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Administrative procedure A-8B COL Appendix, Rev. 13, Locked Valve Check Off List, Unit _3 was reviawed. The inspector verified that the new ESW isolation valves added y the modification are incorporated into the latest revision of the ESW locked valve check off lis The inspector reviewed various weld liquid penetrant examinations, nonconformance reports, certified material test reports, engineering work letters, construction job memorandums, Q-listed material requi-sitions and verifications, and PORC meeting minutes involving the ESW modificatio The inspector visually verified that the temporary secondary contain-ment penetrations required for the hydrolancing hoses had been sealed (MRF 8504935). A visual inspection was made of all four core spray rooms for proper ESW-isolation valve installation and line up and other modification work. No discrepancies were foun The licensee stated that FSAR Figure 10.7.1 (P&ID M-315) for the ESW and HPSW systems will be revised in the next FSAR revision. The in-spector has no further question Within the scope of the review of this modification (MOD 1557) on the ESW system, no unacceptable conditions were identifie . Electrical Equipment Modifications The inspector reviewed the modification packages for the following activities:
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Replacement of the Class IE 125/250 VDC batteries (MOD 1519)
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Replacement of RPS and PCIS Agastat GP series relays with EGF' series relays (MOD 1565)
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Replacement of magnetic coil assemblies in the RPS and PCIS HFA re-lays (MOD 959)
The inspector reviewed the licensee's safety evaluation reports, surveil-lance test procedures, and PORC meeting minutes. Each modification pack-age was checked for consideration of revisions to the FSAR and the Technical Specifications. In each case, the in plant modification work was done, but the associated documentation and review were not complet Not all testing had yet been performed for MODS 959 and 1565. The inspec-tor verified that the status of testing and documentation was adequate for plant condition No discrepancies were identifie .
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12.1 Replacement of the Class IE 125/250 VDC Batteries (MOD 1519)
The licensee determined that the Class IE 125/250 VDC batteries were aging such that replacement was indicated before the batteries became unable to meet the requirements of the Technical Specifications. The battery changeout was previously accomplished on Unit 2 under MOD 1048 (see NRC Inspection Report 50-277/85-15).
The Unit 3 battery changeout was performed under MOD 1519. The in-spector reviewed the licensee's safety evaluation for completeness in addressing potential safety questions. The inspector verified that-seismic analyses had been performed on the new battery racks, that floor loadings had been checked for the new heavier batteries, and that the applicable FSAR revision was being prepare The inspection of the Unit 2 batteries had identified that certain cell spacer rod nuts were loosely torqued and that a silicone lubri-cant compound had been used during battery installation which had not been specifically aporoved by the battery vendor. The inspector physically verified that the Unit 3 batteries spacer rod nuts were not loose and confirmed that tha battery vendor had determined that the silicone lubricant compound was compatible with battery material No deficiencies were identifie .2 Replacement of Agastat GP Series Relays with EGP Series Relays (MOD 1565)
The Agastat GP series relays have experienced earlier than antici-pated end-of-service-life failures at other facilities as reported in IE Information Notice No. 84-20. MOD 1565 involves replacing the normally energized RPS and PCIS Agastat GP series relays with EGP series relays. The new relays have an upgraded coil insulation and an improved bobbin materia The inspector reviewed the licensee's safety evaluation for complete-ness in addressing potential safety questions. The inspector veri-fied that the wattage of the new relays had been determined by the licensee to be similar to the old relays and that heat load and fire protection aspects of the relay replacement had been considered. Not all of the Modification Acceptance Tests (MATS) for MOD 1565 were complete at the time of the inspection. Certain systems affected by this modification, such as RPS. were required to support core loa The inspector verified that Special Procedure 870, " Plant Conditions Necessary To Reload Fuel Unit 3", required completion and PORC ap-proval of a partial MAT for MOD 1565, and that the necessary MAT steps were documented as complet No deficiencies were identifie .
12.3 Replacement of Magnetic Coil Assemblies in HFA Relays (MOD 959)
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As reported in IE Bulletin 84-02, several facilities have experienced failures of Class IE relays with nylon /(Lexan) coils. One of the actions required by the Bulletin was to replace the nylon /Lexan coils (or the entire relays) with ones qualified for the intended servic MOD 959 replaces these coils with those used in the GE Century Series Class IE HFA relays which were tested by the vendor to meet the ser-vice condition The inspector reviewed the licensee's safety evaluation for complete-ness in addressing potential safety questions. The inspector veri-fied that the licensee had determined that the new coils would have no adverse effect on RPS or PCIS circuits. The new coils are rated for circuit operating voltage and draw less current than the coils being replaced. Not all of the MATS for MOD 959 were complete at the time of the inspection. The inspector verified that Special Proce-dure 870 required completion and PORC approval of a partial MAT for MOD 959, and that the necessary MAT steps were documented complet No deficier.cies were identifie . Snubber Functional Testing The inspector reviewed the licensee's activities pertaining to the func-tional testing of safety related snubbers. During the current refueling outage, the licensee has performed the functional testing of safety related snubbers as required by the Technical Specifications (TS) 3.1 A large number of snubbers in the initial test samples, both mechanical and hydraulic, failed the test. As a result of these and subsequent test failures, every snubber was-required to be functionally tested (71 mechan-ical/ Pacific Scientific in sizes PSA 1/2, 1, 3, 10 and 35 were tested and 123 hydraulic /ITT Grinnell in sizes 1-1/2, 2-1/2, 3-1/4 and 4 were tested).
The end result was 47 of 71 Pacific Scientific (PSA) mechanical snubbers and 53 of 123 hydraulic ITT Grinnell snubbers failed the tes Every snubber, except for one recently installed hydraulic snubber, was rebuilt or refurbished even if the snubber had passed the functional test. '
After the rebuilding or refurbishment, the snubbers were retested satisfactoril Testing of mechanical snubbers was performed in the Bergen-Paterson Pipesupport Corporation mobile test facility. The testing, disassembly, inspection, parts replacement, reassembly and retest for these snubbers
. was performed by Bergen-Paterson personnel in accordance with licensee e PORC approved proceduce Testing of hydraulic snubbers and all che work associated with rebuilding and retesting was performed by the licensee's personnel. The tests were performed using ITT Grinnell hydraulic snubber test equipmen L ,
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13.1 Mechanical Snubbers The licensee's initial 10% functional test sample per TS 4.11. resulted in 3 out of 7 snubbers failing the test criteria. In accordance with TS 4.11.D.4 requirements, additional tests were performed and more failures required that all 71 mechanical snubbers be tested, 47 of the 71 mechanical snubbers failed some portion of the' functional tes The following tables summarize the failures by snubber size and by functional test acceptance criteri Failures Related To Size Sizes PSA 1/2 PSA 1 PSA 3 PSA 10 PSA 35 Total 8 1 3 56 3 Failures 5 0 1 40 1 Failed Acceptance Criteria High Acceleration A 27*
Low Acceleration B 7 1 C
High Drag 4,,
D Frozen 5 1 2 A = Restraining action achieved at higher than specified acceleration B = Restraining action improper. Locked-up under imposed load C = Drag load higher than specified D = No movement
= Includes 2 snubbers with both high and low acceleration
- = Includes 2 snubbers with low acceleration ,
The disassenbly and inspection records described failure mechanisms related to the following: excessive grease, hardened grease and dirt, bent rods in the size PSA-1/2 rod and bearing assembly, thrust bearing indentations, brass keeper and balls escaping from the ball bearing screw assembly, corrosion of internal parts (one with water inside), and one snubber that had the inner thrust bearing race axially displaced and jammed on the ball screw shaf .
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The licensee's preliminary data catcgorized the failures as:
Problem PSA 1/2 PSA 1 PSA 3 PSA 10 PSA 35 Grease 27 Bent Rods 5 Ball Screw 2 Thrust Bearing 9 Corrosion or Overload 1 2 1 The licensee has received conflicting information from the local PSA representative and the PSA home office representative regarding the use of grease on the chrome plated surface that mates with the capstan spring inner diameter. The local PSA representative thought grease had been eliminated from use on the capstan spring in 1981 and was a contributor to high acceleration failures. The PSA home office representative stated to the licensee that the grease had not been eliminated from use. The licensee committed to obtain a formal response regarding the use of grease on the capstan sprin .
The licensee's corporate engineering office is currently evaluating the test details to determine the cause of failure, any generic implication, and the resolution of each identified failur The licensee is proceeding with an engineering evaluation to determine if there were any adverse effects on the supported piping or compo-nents due to the snubber test failures. The inspector noted that several of the recorded test loads exceeded the catalog load ratings and the test procedure load requirements and asked that the licensee address this matte It was also noted that the problems associated with snubber thrust bearing failures could indicate an excessive load conditio These snubber failures were generally on the SRV discharge lines. The licensee has requested its Corporate Engineering office to conduct analysis related to this proble .2 Hydraulic Snubbers The inspector verified that the licensee's initial 10% functional test sample resulted in 9 out of 13 snubbers failing the acceptance test criteria of TS 4.11.D.4. Having 9 failures necessitated the testing of all snubbers since the TS require tha testing of an addi-tional 10% for each failed snubber. Of the 123 hydraulic snubbers, 53 failed the tes Failures were due to lock-up (restraining action)
and bleed rates being outside the acceptance rang The inspector determined that all snubbers, except one, were rebuilt, retested and met the acceptance criteria prior to reinstallatio The one snubber (23-DBN-SI) that wasn't rebuilt was recently installed (on July 13,1985), and was tested and found satisfactory prior to installatio .
, 25 The licensee is currently performing an evaluation to determine the cause of failures, the generic implication and the resolution of each identified failure. The licensee is also proceeding with an engt-neering evaluation to determine if there was any adverse effect on-the supported piping or component due to the failur .3 Findings-The functional testing of both mechanical and hydraulic testings has identified areas which require the licensee's evaluation and resolu-tion, and include:
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Cause of failure
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Resolutica of each identified failure -
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Engineering evaluation to determine if there was any adverse effect on the supported piping or component due to the snubber failur The above findings are unresolved (278/85-41-02) pending completion of the licensee's analysi . RHR Pumps 14.1 3C RHR Pump Motor Fire-At 5:30 a.m. on November 2, 1985, a fire was discovered in the 3C RHR pump motor. The fire alarm had sounded, followed shortly by a 3C RHR pump trip alarm. At the time of the fire, Unit 3 was involved in moving fuel during core reload. The 3C RHR pump was running provid-ir.1 the required flow for the pipe weld overlays being performed on the reactor recirculation and RHR piping. The plant fire and damage tean responded to the 3C RHR pump room to find the motor engulfed in fl an e s . The fire was extinguished in about seven minutes with port-able C02 extinguishers. Fuel reload and weld overlay work was .
suspended. The licensee broke secondary containment to exhaust the smoke and to remove the motor from the pump room. Once secondary co.itainment was restored, fuel reload recommenced. The motor and pump were uncoupled, disassembled and inspected for damage. A General Electric representative was on-site on November 3, 1985, to
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inspect the motor. The motor lower guide bearing was damaged, the rotor bars were' gouged and scorched, and the stator windings were burnt and gouged. -The pump sustained internal damage to the impeller seat and pump casin The motor is a 2000 HP GE vertical induction model 5K6348XC29A and the pump is a Bingham single suction single stage centrifugal model 18x24x28 CVI The inspector examined the motor damage on November 3, 1985. The following items were observed:
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The lower guide (roller) bearing had several damaged ball bear-ings and several ball bearings were displaced from the retaining ring The rotor and stator punchings (bars) had contact damage and were gouge The lower bearing oil reservoir had fire damag The lower stator windings were burn '
-In addition, the inspector discussed motor indications and damage assessment with the GE vendor representative The inspector examined the pump damage in the maintenance shop on November 18 and 19, 1985, and observed the following:
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The lower impeller wear ring was off the impeller and fused to the pump casing wear ring in a cocked positio A piece of the impeller wear ring was broken off and exhibited excessive wear as indicated by gouging and mechanical erosio The wear ring surfaces on the impeller were discolored indicat-ing high temperature condition The seal gland throttle bushing was fractured.
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The upper wear ring was attached to the impeller, however the wear ring was discolore The licensee obtained a replacement motor from another reactor facil-ity. A new RHR pump impeller and shaft were installed; the pump
. was repaired and coupled to the replacement motor. The 3C RHR pump was returned to service and tested satisfactorily on November 18, 198 <
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, 27 The inspector attended a meeting on November 19, 1985, to discuss the 3C RHR pump and motor failure. At this meeting, the licensee indi-cated that the most probable cause of the 3C RHR motor fire and pump failure was as follows: the pump impeller lower wear ring cracked and came off the impeller; and a piece of the wear ring lodged be-tween the casing wear ring and the impeller resulting in an upward thrust to the pump and moto The 3C RHR pump failure was discussed at the Nuclear Review Board (NRB) meeting on December 5, 1985 (see detail 5). During the licen-see review of the pump failure, it was noted that the 3C RHR motor bearing high temperature alarm occurred (160 degrees F) ca October 30, 1985, a few hours after pump start and three days prior to pump failure. The motor bearing high temperature alarm prints out on the control room computer typer only when the alarm first occurs or when the computer is reinitialized or when demanded by the operator. The alarm condition is not annunciated on an alarm windo At the time of the alarm, Unit 3 was in cold shutdown with over one hundred alarm conditions on the alarm typer. The alarm condition went undetected by the control roum operators. The NRB indicated that they would direct a review of the computer alarm typer design and priorities, and control room operators computer alarm typer response procedure The inspector will follow these activitie The licensee performed a metallurgical analysis on the failed wear ring. The licensee's representative stated that the impeller wear ring is 410 stainless steel, A182 grade F6 with a Rockwell C hardness of 33 to 39 and the failure mechanism of the wear ring was due to intergranular stress cracking corrosion (IGSCC). The replacement
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wear rings for the 3C RHR pump impeller are of the same materia The 3C RHR pump performance has been satisfactory since repai No violations were identifie .2 3A, 38, 3D RHR Pumps On November 16, 1985, while replacing the lower pump casing gasket on the 3A RHR pump, the licensee noted that the pump lower impeller wear ring was off the impeller and cracked in three places. The 3A RHR pump is identical in design to the 3C RHR pump. A Bingham represen-tative was onsite on November 20, 1985, to review the RHR pump find-
-ings. Based on the 3A and 3C RHR pump fir, dings, the licenseo decided to inspect the 3D and 3B RHR pump The licensee repaired the 3A RHR pump, using a new impeller with the same wear ring material, and returned the pump to service on November 26, 1985. Also, on November 26, 1985, the licensee made an INPO Net-work notification regarding the recent Unit 3 RHR pump failures. The
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inspector reviewed the Network notification and determined it to be complete and factua During disassembly and inspection of the 3B and 3D RHR pumps on November 26, 1985, the licensee noted the following conditions: The 3B pump lower wear ring was cracked, twisted off the impeller and jammed into the pump casing wear rin The 3D pump upper wear ring was pulled off the impeller, cracked in several places, and welded to the upper pump casing wear rin The 3D RHR pump had damage to the pump journal bearing; however, the lower impeller wear ring was still intac The inspector met with the licensee on December 2, 1985, to discuss the Unit 3 RHR pumps including failure mechanism, spare parts status and current repair status. The licensee has determined that the 3A, 3B, and 3C RHR pumps all have similar indications, i.e., lower impel-1er wear ring cracking and detachment. The 3D RHR pump appears to have a different failure mechanism due to the damaged upper wear ring and pump journal bearin The 3B and 3D RHR pump repairs are in progress. The 3A RHR pump performance has satisfactory since repai No violations were identifie .3 RHR Pump Performance The inspector reviewed Unit 3 RHR pump test data since 1983. The test data was compiled by the licensee based on surveillance test results. The following parameters were trended in tabular format and graphically:
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pump differential pressure (psi)
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motor amps
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pump vibration (mils)
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pump flow (gpm)
The inspector will review licensee's repair and testing activities for the 3B and 3D RHR pumps and the formal engineering and metallur-gical reports regarding the RHR pump failures (IFI 278/85-41-03).
1 Unit 3 Restart Restrictions The licensee plans to implcment additional measures to allow operation with the crack indications on the recirculation inlet safe ends and welds 2-AS-8 (pipe-to-suction valve weld on the "A" recirculation liae) and 2-BD-12 (pipe-to-discharge valve weld on the "B" recirculatien line). At
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the present time these measures are being evaluated by NRC-NRR, as commit-ted in PECo letter dated November 27, 1985. These measures will include the following:
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Improved water chemistry requirements will b2 imposed above 25% pow-er. The reactor water conductivity will be limited to less than or equal to 0.3 micro Siemen per centimete A crack growth monitoring system will be installed to simulate crack growth in the piping material (MOD 1763).
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Technical Specification leakage restrictions will be modified to lim-it unidentified leakage to less than or equal to 2 gpm with a maximum increase of I gpm in 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Unit shutdown to conduct mid-cycle (8 to 10 months of accumulated reactor power operation) inspection of the "J" and "F" safe ends and welds 2-AS-8 and 2-BD-1 The inspector will observe compliance with any new reactor coolant leakage limits, and the water chemistry criteria during Unit 3, cycle 7 operatio The licensee is currently installing the crack growth monitoring system as MOD 1763 and the inspector will continue to review this area. Any addi-tional requirements imposed on the licensee by the forthccming NRC Order for Unit 3 restart will be inspected at a later dat . Steam Separator Hold Down Bolts On November 22, 1985, while tightening the hold down bolts on the steam separator, four of 48 bolts were found to be brokc The bolts are ap-proximately 16 feet long by 3 inches in diameter and weigh over three hun-dred pounds. A sample of one inner bolt was sent to GE on November 25 for analysis. The inner bolt had broken just above the weld that attaches the sleeve with the anti-rotation pin to the inner bolt. Based on visual inspection of the inconel material and the water environment the licensee postulated that failure was due to IGSCC. A verbal report made by GE to the licensee on thL analysis of the bolt sample appears to confirm the failure to be from IGSCC. The inspector examined new bolts on tne Refuel Floor on November 27. GE is preparing an analysis to justify operation with only 24 of the 48 bolts. The licensee plans to use 24 new bolts from Limerick Unit 2. The inspector will review the GE analysis and licensee's safety evaluation (50.59 review) when they are availabl While removing the bolts, one broken bolt was dropped and landed on top of the ram's head of a jet pump. After revising the procedure and modifying the bolt-handling tool the li ssee attempted to retrieve the bolt, but it fell into the bottom of tl.e anailu The bolt was retrieved on December 8, 1985. The licensee has initiated an investigation of the incident, which will Le reviewed by the inspector. The licensee's inspection of the annulus area for damage will be followed by the inspector. The
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. 30 inspector will follow the licensee's activities in this area including justification for use of 24 bolts, inspection of the bolts, and damage inspection of the reactor vessel internals (IFI 278/85-41-04).
17. Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations. An unre-solved item is discussed in detail 1 . Inspector Follow Items Inspector follow items are items for which the current inspection findings are acceptable, but due to on going licensee work or special inspector interest in an area, are specifically noted for future follow-u Fol-low-up is at the discretion of the inspector and regional managemen Inspector follow items are discussed in details 4.4. , 14.3 and 1 . Management Meetings A verbal summary of preliminary findings was provided to the Station Su-perintendent at the conclusion of the inspectio During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection. No proprietary informa-tion is included in this report.
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ATTACHMENT (see Section 11.2) ,
Date MRF N Description Completed 8504019 Replace ESW Piping B RHR Room 10/31/85
.8504021 Replace ESW Piping C RHR Room 10/29/85 8504022 Replace ESW Piping D RHR Room 11/01/85 8504023 Replace ESW Piping A Core Spray Room 11/01/85 8504024 Replace ESW Piping B Core Spray Roem 11/06/85 8504025 Replace ESW Piping C Core Spray Room 11/01/85 8504026 Replace ESW Piping D Core Spray Room 11/13/85 8504027 Replace ESW Piping A RHR Room 10/29/85 8504934 Install New Flanges in ESW RHR & 10/29/85 C.S. Rooms-8504963 Install ESW Isolation Valves, RHR & 10/29/85 C.S. Rooms 8504964 Install ESW Isolation Valves and 11/04/85 Piping, HPCI Room 8504965 Install ESW Isolation Valves and 10/30/85 Piping, RCIC Room 8507415 Flush A RHR Room Coolers 11/06/85 8507416 Flush B RHR Room Coolers 10/23/85 8507417 Flush B RHR Seal Water Coolers . 10/29/85 8507418 Flush D Core Spray Motor Oil Cooler 10/29/85 8507420 Flush D RHR Seal Water Coolers 10/23/85~
8507421 Flush A Core Spray Motor Oil Cooler 10/23/85 8507422 Flush B Core Spray Motor Oil Cooler 10/23/85 Drawing N System FSK-3033-20 A Core Spray Room FSK-3033-22 B Core Spray Room FSK-3033-21 C Core Spray Room FSK-3033-23 D Core Spray Room FSK-3033-15 HPCI Room FSK-3033-3 A RHR Room FSK-3033-2 B RHR Room FSK-3033-1 C RHR Room FSK-3033-4 D RHR Room
.FSK-3033-33 Torus Room P&ID M-315 ESW and HPSW Systems
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