IR 05000277/1986024
| ML20212G810 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/14/1987 |
| From: | Gallo R, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212G794 | List: |
| References | |
| 50-277-86-24, 50-278-86-25, NUDOCS 8701210179 | |
| Download: ML20212G810 (22) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/86-24 & 50-278/86-25 Docket No. 50-277 & 50-278 j
License No. DPR-44 & DPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name:
Peach Bottom Atomic Power Station Units 2 and 3 Inspection At: Delta, Pennsylvania Inspection Conducted: November 8,1986 - January 2,1987 Inspectors:
T. P. Johnson, Senior Resident Inspector R. J. Urban, Resident Inspector Reviewed By:
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/ #!87 J. H. Williams, Resident Inspector date'
//&/f7 Approved By:
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Robert M. Gallo, Chief date Reactor Projects Section 2A, DRP Inspection Summary:
Routine, on-site regular and backshift resident inspection (81 hours9.375e-4 days <br />0.0225 hours <br />1.339286e-4 weeks <br />3.08205e-5 months <br /> Unit 2; 77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> Unit 3) of accessible portions of Unit i
2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, Standby Gas Treatment system (SGTS) review, GE HGA type relays, control rod 10-47, l
maintenance, and outstanding items, i
Results: Safety evaluations for Unit 3 control rod 10-47 were determined to be adequate and complete. The Unit 3 3B standby liquid control system pump motor breaker was inadvertently opened by an operator. The SGTS was determined not to be susceptible to a single failure problem noted at another facility.
Personnel error caused the Unit 3 torus level to exceed Technical Specification limits. The use of GE HGA relays was noted in numerous safety related systems. A management meeting to discuss the Peach Bottom " Enhancement Program" was held at the site.
e701210179 870114 PDR ADOCK 05000277 O
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DETAILS 1.
Persons Contacted B. L. Clark, Administrative Engineer
- J. B. Cotton, Superintendent Plant Services G. F. Dawson, Maintenance Engineer
- R. S. Fleischmann, Manager, Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist J. F. Mitman, Radwaste Engineer D. L. Oltmans, Senior Chemist F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Engineer
- D. C. Smith, Superintendent Operations J. E. Winzenried, Staff Engineer Other licensee employees were also contacted.
- Present at exit interview on site and for summation of preliminary findings.
2.
Plant Status 2.1 Unit 2 Unit 2 began the inspection period at full reactor power. A load drop to 70% reactor power occurred on November 15, 1986, to conduct condenser water box inspections. On November 17, 1986, a runback occurred to 65% reactor power apparently due to problems in the static inverter power supply. A load drop occurred on December 20, 1986, to 60% reactor power to change the control rod pattern.
The unit operated at full power for the remainder of the inspection period.
2.2 Unit 3 Unit 3 began the inspection period during power ascension from a startup that began on November 6, 1986.
The unit operated at or near full power until December 3, 1986, when load was temporarily reduced to 70%. On December 13, 1986, the turbine generator was taken off line to repair a steam leak. The turbine was returned to service on December 14, 1986, and full power was achieved on December 15, 1986.
A load drop to 52% occurr-d on December 26, 1986, to leak test condenser water boxes and to withdraw control rod 10-47 (see detail 3.2).
The unit was shut down on December 28, 1986, to repair several steam leaks. The unit was returned to service on
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December 29, 1986; however, the temporary repair of the high pressure turbine steam leak was not successful and the unit was shut down on January 2,1987 to complete a permanent repair.
3.
Previous Inspection Item Update 3.1 (0 pen) Unresolved Item (278/86-20-02).
3B Standby Liquid Control System Pump breaker terminal strip pulled out.
See detail 4.2.1, 3.2 (0 pen) Unresolved Item (278/86-20-01).
Unit 3 control rod 10-47 uncoupling. Control rod 10-47 was noted as being uncoupled during a reactor startup on November 5, 1986.
The licensee determined that the uncoupling was possibly due to an improperly engaged inner filter or due to excessive crud accumulation.
These conditions could cause the internal " uncoupling rod" to become displaced. The rod was dec-lared inoperable, disarmed, and inserted full in. General Electric and PECo performed safety evaluations (November 10, 1986 and December 12, 1986). These safety evaluations concluded that control rod 10-47 could be withdrawn using notch control. Other recommendations included:
limit drive pressure to less than 400 psid; insert rod prior to a manual scram; perform weekly coupling integrity checks; perform coupling check after an automatic scram; and replace the drive during the next outage. The PORC and NRB reviewed and approved the withdrawal of control rod 10-47.
On December 26, 1986, the licensee performed Special Procedure (SP) 969, " Unit 3 Withdrawal / Insertion of Control Rod 10-47 Above 30% Power".
The licensee withdrew contrcl rod 10-47 one notch at a time verifying the rod moved by reviewing local neutron power (TIP)
traces. At position 48, a successful coupling check was performed.
The licensee revised the following general plant (GP) procedures to implement control rod 10-47 withdrawal "special conditions":
GP-2-3 Appendix 1, Startup Rod Withdraw Sequence Instructions
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GP-3, Normal Plant Shutdown.
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GP-9-3, Appendix 1, Unit 3 Shutdown Instructions.
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GP-18 COL, Scram Review Procedure,
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The inspector reviewed the safety evaluations, the completed SP-969, the revised gps, and discussed control rod 10-47 movement with licensee engineers and operators.
Control rod 10-47 was withdrawn during a startup on December 29, 1986. During the startup, the inspector verified the following items:
rod withdrawal using notch control, adequate overtravel test at position 48, and rod drive pressure at about 250 psid. Within the
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scope of the review of the withdrawal of control rod 10-47, no violations were noted. The actual cause of uncoupling of control rod 10-47 on November 5, 1986, remains unresolved.
The drive will be replaced during the next Unit 3 refueling outage currently scheduled for September 1987. The unresolved item remains open pending control rod drive maintenance and determination of the cause of uncoupling.
4.
Plant Operations Review 4.1 Station Tours The inspector observed plant operations during daily facility tours. The following areas were inspected:
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Control Room
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Cable Spreading Room
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Switchgear and Battery Rooms Reactor Buildings
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Turbine Buildings
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Radwaste Building
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Recombiner Building Pump House
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Diesel Generator Building
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Protected and Vital Areas
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Security Facilities (CAS, SAS, Access Control, Aux SAS)
High Radiation and Contamination Control Areas
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Shift Turnover 4.1.1 Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specifications.
Presence of a senior licensed operator in the control room was verified frequently.
4.1.2 The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within Technical Specification requirements and normal operating limits.
ECCS switch positioning and valve lineups were verified based on control room indicators and plant observations.
Observations included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instruments.
On November 19, 1986, the inspector noted that both the Unit 2 and Unit 3 full core displays had several deficiencies including digital roo position display errors and, red and green rod position backlights not illuminated.
The inspector reviewed Technical Specification Table 3.2.F which requires control rod position or neutron monitoring to be operable.
The
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inspector checked each control rod position on both units to verify consistent position indication on the four rod display and on the process computer (00-7). The full core display is primarily used for operator information. Daily
. control rod positions are verified per ST 9.1 by checking actual rod position with the process computer. A weekly control rod exercise test per ST 9.21 is performed and control rod positions are also verified. The inspector discussed the full core display problems with licensee engineers who had previously identified the problem. Ap-parently, replacement parts are difficult to procure and the licensee is pursuing a modification. The inspector concluded that the instrumentation in TS Table 3.2.F was operable and that each control rod's position was known.
No violations were noted.
The inspector will follow licensee modifications for the full core display.
4.1.3 Selected control rocm off-normal alarms (annunciators)
were discussed with control room operators and shift supervision 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 knowledgeable of alarm status and plant conditions.
4.1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personnel.
4.1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compliance with administrative procedures and regulatory guidance. No inadequacies were identified.
4.1.6 Tbc inspector observed the main stack and both reactor building 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 identified.
4.1.7 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 '
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4.1.8 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 acceptable.
4.1.9 The inspector observed the nuclear instrumentation subsystems (source range, intermediate range and power range monitors) and the reactor protection system to verify that the required channels were operable.
4.1.10 The inspector frequently verified that the required off-site electrical power startup souices and emergency on-site diesel generators were operable.
4.1.11 The inspector monitored the frequency of in plant and
control room tours by plant and corporate management.
The tours were generally adequate.
4.1.12 The inspector verified operability of selected safety related equipment and systems by in plant checks of
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valve positioning, control of locked valves, power supply availability, operating procedures, plant drawings, instrumentation and breaker positioning.
Selected major components were visually inspected for leakage, proper lubrication, 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.
Systems checked included high pressure coolant injection (HPCI), primary containment ventilation and secondary containment isolation.
During the review of the primary containment ventilation systam the inspector noted that the mimics on control room panels 20C03-3 (Unit 2) and 30C03-3 (Unit 3) were different. Unit 3 was more complete and accurate. The inspector reviewed the Peach Bottom detailed control room design review (DCRDR) report and noted that this
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deficiency was reported on human engineering discrepancy (HED) No. SD2-02. The inspector discussed the
deficiency with licensee engineers. The licensee stated that the DCRDR deficiencies (HEDs) were scheduled to be completed as follows:
Unit 2 remote shutdown panel - 1987 refueling
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outage.
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~6 Unit 2 control room panels - 1988 refueling outage.
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Unit 3 control room and local panels - 1987
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refueling outage.
The inspector will follow the implementation of the HED corrective actions in a futare inspection.
4.2 Followup On Events Occurring During the Inspection 4.2.1 Unit 3 Standby Liquid Control System (SLCS) Pump Breaker With Unit 3 at 70% reactor power on December 4, 1986, at 3:00 a.m., a SLCS squib valve loss of continuity alarm and loss of indicating lights occurred. The licensee found the 3B SLCS pump 480 volt breaker at motor control center (MCC) E234-RB opened. The licensee closed the breaker and the 3B SLCS pump motor indications and alarm returned to normal at 3:30 a.m.
No effect on the 3A SLCS pump was noted. The licensee performed panel walkdowns of both units, and checked the valve positions at the control rod drive hydraulic control units.
No abnormalities were noted.
The inspector noted the occurrence of this event at 7:00 a.m. on December 4,1986, during control room log reviews. A similar event occurred on the same breaker on October 17, 1986 (NRC unresolved item 278/86-20-02).
The licensee determined that the apparent cause of the December 4, 1986, event was an operator inadvertently bumping the breaker handle while placing a blocking tag on a breaker at the MCC directly above the 3B SLCS breaker compartment. The bases for this conclusion was through a zone search of the security computer and individual interviews.
The licensee's investigation of the October 17, 1986 event has not determined the cause of a terminal strip being pulled out in the MCC breaker compartment. The unresolved item 278/86-20-02 remains open.
The inspector discussed the December 4, 1986, event with the licensee and checked the E234-RB MCC area. The inspector determined that it was plausible for an operator to inadvertently bump a breaker handle while tagging another component directly above.
The inspector stated that non-licensed operators should be more careful when tagging MCC breakers. The licensee agreed
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and stated that all operators were reminded to exercise more care when tagging breakers on MCCs.
The inspector had no further questions at this time.
No violations were noted.
4.2.2 Unit 2 Partial Containment Isolation With Unit 2 at 100% power, a partial group III primary containment isolation occurred for the containment oxygen analyzer valves. At 1:15 p.m. on December 9, 1986, during licensee troubleshooting of a failed solenoid valve (SV-2980), a fuse blew resulting in the isolation of the eight outboard oxygen analyzer sample valves.
The licensee suspended troubleshooting, replaced the fuse, returned the system to operation, and made an ENS call at 2:19 p.m.
The inspector reviewed the suspected LER, reviewed the appropriate electrical schematic drawing E-324, discussed the event with licensee engineers and licensed operators, and reviewed appropriate piping diagrams.
The inspector also monitored the ENS call. The inspector verified that the oxygen analyzer system was operable and that indication of primary containment oxygen level was available. The inspector also verified that licensee actions for an inoperable containment isolation valve (SV-2980) were in accordance with Technical Specification 3.7.D and 4.7.D.
.The inspector will review the LER when it is issued.
No violations were noted.
4.3 Logs and Records
The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equipment and lock-out status, jumper log validity, conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed: Shift Supervision Log, Reactor Engineering Logs, Unit 2 Reactor Operator's Log, Unit 3 Reactor Operator's Log, Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits, Locked Valve Log, Maintenance Request Forms, Temporary Circuit Modification Log, and Ignition Source Control Checklists.
Control Room logs were compared against Administrative Procedure A-7, Shift Operations.
Frequent initialing of entries by licensed
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operators, shift supervision, and licensee on-site management constituted evidence of licensee review. No unacceptable conditions were identified.
4.4 Unit 3 Midcycle Shutdown Unit 3 restarted in March 1986 (cycle 7) with crack indications in several welds. An NRC Order dated March 20, 1986, required a mid-cycle shutdown to examine three unrepaired welds and two recircu-lation system inlet safe ends. The licensee submitted a letter dated October 8, 1986, including an August 1986 technical report, requesting to continue Unit 3 cycle 7 operation without conducting the midcycle examination of these welds and safe ends. A meeting was held between NRC/PECo on November 24, 1986, to discuss the licensee's request from relief of the midcycle examination.
The licensee's basis for this relief was improved reactor water chemistry with a goal of maintain-ing conductivity less than 0.3 micrombos/cm, and good results from the crack arrest verification system (CAVS). The CAVS shows that actual crack growth is below the predicted values.
The inspector attended the November 24, 1986, NRC/PECo meeting, reviewed the August 1986 technical report " Technical Basis for Operation of Peach Bottom Unit 3 Through Cycle 7 with Certain Recirculation Inlet Safe End and Piping Weld Ultrasonic Indications" and the October 8, 1986, letter.
The inspector verified the "as stated" good chemistry by independently reviewing plant chemistry data and results.
The inspector also verified the operating history of the CAVS.
In a letter dated December 22, 1986, the licensee committed to the following:
Continue to maintain chemistry as good as possible (conductivity
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goal of 0.3 micromhos/cm).
Implement hydrogen water chemistry on both units during the
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1987 refueling outages.
Replace the recirculation and associated piping, and safe
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ends that are susceptible to IGSCC during the Unit 3 outage scheduled to begin in September 1987.
In a letter dated December 31, 1986, NRC approved relief from the Unit 3 midcycle shutdown for ultrasonic examinations.
However, the more stringent reactor coolant leak rate of 2.0 gpm unidentified leakage continues to be in effect for Unit 3.
During the inspection period, the inspector frequently verified that the Unit 3 leak rate was less than the limi _
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Within the scope of the review of the Unit 3 midcycle shutdown and related documents, no vinlations were noted.
4.5 Engineered Safeguards Features (ESF) System Walkdown The inspector performed a detailed walkdown of portions of the core spray system in order to independently verify the operability of the Unit 2 and 3 systems. The core spray system walkdown included verification of the following items:
Inspection of system equipment conditions.
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Confirmation that the system check-off-list (COL) and
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operating procedures are consistent with plant drawings.
Verification that system valves, breakers, and switches are
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properly aligned.
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Verification that instrumentation is properly valved in and operable.
Verification that valves required to be locked have
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appropriate locking devices Verification that control room switches, indications and
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controls are satisfactory.
Verification that surveillance test procedures properly
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implement the Technical Specifications surveillance requirements.
The inspector determined the Core Spray Systems in Units 2 and 3 to be operable. Hewever, several minor equipment deficiencies were identified. An Anaconda metal conduit hose for one of the two Pylet space heaters on the Unit 2 "C" core spray pump motor was pulled loose from its connector. Wires were visible and one of the two heaters was not functioning. Also, the oil cooler outlet isolation valve (HV-33-21089C) for emergency service water (ESW) on the Unit 2
"C" core spray pump n.otor was missing its handwheel nut. The ESW valve is locked open, but by turning and removing the handwheel several times, the position of the valve could be altered without unlocking the chain.
Finally, the inlet isolation valve (HV-14-33A)
for PCV-34A (pressure control valve, keep full system for Core Spray Loop A) was found throttled open, rather than open as stated in COL S.3.4.E.2, " Core Spray System Manual Valve Line-Up".
Licensed operators were questioned concerning this discrepancy.
The valve is kept throttled to reduce the amount of water entering the torus through a leaking valve (M0-2-14-26A) in the Core Spray Loop A full flow test line. These deficiencies were brought to the attention of
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the licensee for appropriate corrective measures. -The inspector will check that these items are corrected in a future inspection.
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No other deficiencies nor violations were noted.
5.
Standby Gas Treatment Syst m Review
Based on information from another facility, the inspector reviewed the standby gas treatment system (SGTS) design, operation and potential failure modes. The identified design deficiency at the other facility was a single failure of one of the SGTS train's charcoal deluge system, concurrent with a loss of off-site power. This condition would result in loss of the SGTS function of removing radiciodines due to a failed open outlet cross connect damper in the SGTS.
The peach Bottom SGTS design was reviewed. Units 2 and 3 share a common SGTS. The system includes two redundant filter trains and three SGTS fans. On a Unit 2 initiation, the "A" SGTS fan and "A" train start. On a Unit 3 initiation the "C" SGTS fan and "B" train start.
I The "B" SGTS fan is a backup for either unit, and either filter train can be utilized by each unit. Single temperature elements provide for fire protection deluge of the charcoal filters.
With respect to a single failure (i.e., deluge actuation), the SGTS would continue to perform its safety function.
Deluge actuation is alarmed in the control room. Operator action provides for the isolation of the affected filter train, and starting of the redundant filter train.
Each filter train is provided with inlet and outlet air operated dampers. The dampers fail open on loss of power or on loss of air pressure. However, the air solenoid is powered from vital power (emergency buses) and each has redundant air supplies. The instrument-air system is supplied by three air compressors per unit; two of which have emergency bus power feeds. Thus, the SGTS would remain operable with a loss of off-site power concurrent with a single failure of the deluge system.
The inspector reviewed SGTS design and operating information including
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the FSAR, electrical schematic and control diagrams, system operating
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procedures, technical specifications, and surveillance test procedures.
The inspector also discussed system operation and design with licensee engineers and operators. A walkdown of accessible portions of the
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system was also performed.
I The licensee had previously, in 1984, identified a SGTS fan design logic problem. The deficiency was reported in LER 2-84-08 and NRC inspector follow item 277/84-15-02 was opened. The licensee performed a modification to eliminate the design problem, and NRC Inspection 277/85-29 reviewed the modification and closed the open item.
Within the scope of the review of the SGTS design, operation and potential failure modes, no unacceptable conditions were noted.
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6.
Review of Licensee Event Reports (LERs)
6.1 LER Review
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The inspector reviewed LERs submitted to the NRC to verify that the details were clearly reported, including the accuracy.of the description and corrective action adequacy. The inspector
. determined whether further information was required, whether generic implications were indicated, and whether the event warranted on-site followup.
The following LERs were reviewed:
LER No.
LER Date Event Date Subject
- 2-86-22 Reactor scram on low condenser vacuum November 12, 1986 October 13, 1986
- 2-86-23 Potential degradation of primary November 12, 1986 containment integrity October 11, 1986
- 3-86-21 Exceeding suppression pool level November 20, 1986 October 21, 1986
- 3-86-22 Resin injection resulting in manual scram December 1, 1986 October 30, 1986
- 3-86-23 Reactor scram during turbine shell warming December 4, 1986 November 4, 1986 3-86-24 RCIC isolation due to loose wire in panel December 8, 1986 November 8, 1986
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6.2 LER On-Site Followup For LERs selected for on-site followup and review (denoted by asterisks 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 i
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6.2.1 LER 2-86-22 concerns a Unit 2 reactor scram on October 13, 1986, caused by low main condenser vacuum. The scram and followup was reviewed in NRC Inspection 277/86-19. The scram occurred when the 2B condensate pump was removed from service due to failure. The pump's suction valve did not close completely due to a piece of wire mesh lodged in the valve seat.
The wire mesh was from the remnants of a startup strainer that was removed after startup testing. Apparently the strainer was removed by cutting it away from its mounting ring in the suction flange. A small ring of the screen material remained, and eventually loosened and became lodged in the seat of the condensate pump suction valve.
Thus the root cause of this scram was a combination of equipment failures (condensate pump, suction valve, and startup screen) combined with personnel error associated with removal of the startup screen.
Licensee corrective actions include planned inspection of the remaining five condensate suction lines for both units. No inadequacies were identified relative to this LER.
6.2.2 LER 2-86-23 concerns a potential degradation of the Unit 2 primary containment. On October 11, 1986, with Unit 2 at 54% power, following operation of the #2 transversing in-core probe (TIP) system, the primary containment valve display panel indicated that #2 TIP ball valve was
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mid position (i.e., both red and green lights off).
There are five TIP ball valves and one common indicating light. The individual position lights at panel 20C13 indicated that all five TIP ball valves were closed.
Licensee engineers cycled all five TIP ball valves and the #2 TIP ball valve indicated open. The licensee monitored another limit switch for the #2 TIP ball (in lieu of the closed limit switch) and concluded that the valve was closed. An apparent limit switch problem could not be followed up on due to the high radiation levels in the TIP room. On October 14, 1986, further investigation determined that the #2 TIP ball valve was not fully closed.
The TIP ball valve is a normally closed 3/8 inch solenoid to open, spring closed valve. The TIP ball valve connects the TIP detector and drive mechanism to the TIP tubes in the reactor core. Also provided in each line is a remotely operated explosive isolation valve. The TIP ball valves are primary containment group IID isolation valves.
They close automatically on low reactor water level or on high drywell pressure.
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The ifcensee determined that #2 TIP ball valve had not stroked closed sufficiently to pick up the closed limit switch.
Local observations determined that the ball valve had travelled approximately 75 degrees of the 90 degrees of travel. The licensee closed the valve locally.
Subsequent leak testing of the valve determined that the ball valve was closed, however the travel had not picked up the closed limit switch. The licensee reported this event because the #2 TIP ball may
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not have been completely seated.
Primary containment integrity requires that all penetrations required to be closed under accident conditions be capable of being closed by operable primary containment isolation valves.
The #2 TIP ball valve was not fully closed, however the explosive valve was operable to isolate the penetration.
The inspector reviewed this event and discussed it with licensee engineers and operators. The inspector examined a replacement TIP ball valve and discussed valve operation with the licensee. The inspector reviewed the appropriate electrical schematic and piping diagrams for the TIP system.
FSAR section 7.3 regarding primary containment isolation and Table 7.3.1 were reviewed.
Primary containment Technical Specification 3.7.A.2 and associated bases and definitions were also reviewed.
The inspector concluded that primary containment integrity was maintained and that no violation of Technical Specifications occurred. The bases for this conclusion were as follows:
(1) the #2 TIP ball valve had travelled far enough in the closed direction to isolate the line, (2) the #2 explosive valve was operable to isolate the line if the #2 TIP ball valve failed to provide leak tightness, (3) a leak test of the partially closed ball valve indicated leak tightness. The licensee discovered this event, promptly reported it to the in:pector, and followed up with an LER.
Licensee corrective actions included:
(1) replacing the ball valve on October 16,1986,(2) cycling the reraaining four TIP ball valves satisfactorily, and (3) reviewing the event with the engineer involved in the initial troubleshooting.
The inspector verified the corrective actions and had no further questions at this time. No violations were noted.
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6.2.3 LER 3-86-21 concerns Unit 3 HPCI testing which resulted in the suppression pool level exceeding the technical specification (TS) limit of 14.9 feet at 9:50 p.m. on October 21, 1986.
HPCI was being tested in accordance with ST 6.5, "HPCI Pump, Valve, Flow, Cooler". ST 6.5 normally requires about ten minutes of HPCI turbine operation during which steam is added to the suppression pool. A problem with HPCI turbine speed indication, combined with apparent inattention by the reactor operator resulted in the suppression pool level exceeding the TS maximum inventory by about 6500 gallons (14.95 feet).
The licensee restored suppression pool level to within TS limits within 80 minutes.
TS limiting condition for operation (LCO) 3.0.C requires the level to be restored within six hours or to be in a hot shutdown condition.
Therefore, the TS LCO was adhered to.
Additional licensee corrective actions included revising ST 6.5 to ensure that suppression pool level is monitcred and recorded prior to and during HPCI testing. The inspector reviewed LR 9027 (torus level) and noted that level increased to 14.95 feet and was greater than the limit for about one hour. The inspector also discussed this event with the licensee,-
reviewed control room logs and verified corrective actions.
No inadequacies with the LER, nor violations, were noted.
6.2.4 LER 3-86-22 concerns a Unit 3 condensate demineralizer (3E) resin injection and manual scram due to high reactor water conductivity on October 30, 1986. The event was reviewed in NRC Inspection 277/86-19, 278/86-20. The licensee concluded that the cause of resin injection was residual resin in the demineralizer outlet plenum or piping following filter element replacement. The maintenance procedure was revised to include a thorough independent inspection of demineralizer outlet plenum and outlet piping. The 3E condensate filter demineralizer was re-inspected and returned to service.
Filter element replacement continues and no further problems have been noted. The licensee estimates that about ten pounds of resin (one gallon) we:e injected from the 3E demineralizer. The resultant chemistry excursion caused pH to decrease to 3.9 and conductivity to increase to 41.5 micrombos/cm.
Conductivity was lowered to less than ten micrombos/cm and pH was returned to the range 4-10 within eight hours.
There were no inadequacies relative to the LE.
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6.2.5 LER 3-86-23 concerns a reactor scram on Unit 3 on November 4, 1986, during turbine shell warming. The event was reviewed in NRC Inspection 278/86-20. The licensee determined that the root cause of this event was attributed to an inadequate design of the first stage pressure meter combined with inattention of the reactor operator performing the startup procedure.
No inadequacies were identified relative to the LER.
7.
Surveillance Testing The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were available for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met.
Parts of the following tests were observed:
ST 3.3.1, APRM Functional and Calibration Test, performed on Unit
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3 on December 3, 1986.
ST 12.12, Unit 1 Exclusion Area Inspection, performed on December
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30, 1986.
In addition, a review of the following completed surveillance tests was performed:
ST 3.1.3, SRM Functional and Calibration Check, performed on Unit
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3 on December 29, 1986.
ST 3.2.3, IRM Functional and Calibration Check, performed on Unit
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3 on December 29, 1986.
ST 4.13.A, A Core Spray Line Vent Accumulator Level Switch
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Functional Check, performed on Units 2 and 3 on August 4, 1986 and November 3, 1986.
ST 4.13.B, B Core Spray Line Vent Accumulator Level Switch
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Functional Check, performed on Units 2 and 3 on August 4, 1986 and November 3, 1986.
No inadequacies were identified.
8.
Maintenance For the following maintenance activities the inspector spot-checked administrative controls, reviewed documentation, and observed portions of the actual maintenance:
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Maintenance Procedure /
Document Equipment Date Observed MRF #86-900003 Unit 3 control rod #30-59 December 22, 1986 hydraulic control unit valve
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MRF #86-7706 Unit 3 tigh pressure turbine December 31, 1986 Administrative controls checked included maintenance request forms (MRFs), blocking permits, QC involvement, plant conditions, TS LCOs, equipment turnover and information, post maintenance testing.
Documents reviewed included maintenance procedures, material certifications, RWPs, MRFs, and receipt inspections.
No inadequacies were identified.
9.
Radiation Protection 9.1 Routine Observations During the report period, the inspector examined work in progress in both units, including health physics (HP) procedures and controls, dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection instruments use, and handling of
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potentially contaminated equipment and materials.
The inspector observed individuals frisking in accordance with HP procedures. A sampling of higa radiation doors was verified to be locked as required.
Compliance with RWP requirements was verified during each tour.
RWP line entries were reviewed to verify that personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements.
No unacceptable conditions were identified.
9.2 Source Checks for Radiation Instrumentation The inspector reviewed the daily source checks for radiation monitoring instrument R0-2A. Procedure HP0/CO-1, " Radiation Dose Rate Survey Techniques" requires a daily response check for all instruments.
The licensee performs this source check in accordance with procedure HP0/CO-120, " Operation of the Sr/Y-90 Check Source for R0-2A's".
The source check is performed on all scales of the instrument.
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On November 17, 1986, the strontium / yttrium-90 (Sr/Y-90) check source failed. The licensee initiated a check source with a
" button" source. The " button" source is a lower curie source and therefore can only source check the R0-2A on the lower scale (0-50 mr/hr). The licensee revised procedure HP0/CO-120 to allow the use of the " button" source.
The inspector reviewed procedures HP0/CO-1 and 120 and discussed implementation with health physics technicians and engineers. The inspector reviewed check source data sheets and in use R0-2A instruments. The inspector also contacted a regional specialist regarding use of a " button" source to perform source checks only on the low range scale of the R0-2A, who confirmed that use of a check source on the low scale only was adequate to determine the operability of the R0-2A instrument.
The licensee repaired the Sr/Y-90 check source on December 5, 1986, and re-initiated R0-2A source checks on all instrument scales. Within the scope of the review of the source checks for radiation instruments, no violations were noted.
10. Physical Security The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: operations of the CAS and SAS, checks of vehicles on-site to verify proper control, observation of protected area access control and badging procedures on each shift, inspection of physical barriers, checks on control of vital area access a1d escort procedures.
No inadequacies were identified.
11. General Electric Type HGA Relays 11.1 Background The inspector performed a review of the application of GE type HGA relays in safety related systems at Peach Bottom. The concern is for HGA relay seismic qualification in Class IE electrical systems. Specifically, HGA relays experienced contact chatter during seismic testing at Wyle Test Labs. Another BWR concluded
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that GE HGA relays were unsuitable due to this contact chatter; as a result, the HGA relays were removed from safety related equipment. Also, during the desiga of the Limerick facility, GE HGA relays were not used. Based on a GE analysis, it was determined that the HGA relay operation became marginal at 0.99 acceleration. Therefore, to provide enhanced seismic capability, a substitute GE relay (HMA) was used.
(Reference NRC Inspection 50-352/86-23).
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The HGA relay is a hinged armature type, high speed auxiliary relay. When the coil is energized, a magnetic flux flows through the armature pole piece and attracts the armature. Two auxiliary contacts are mechanically coupled to the armature. These auxiliary contacts can be normally open or normally closed types.
These contacts can be used to make or break auxiliary circuits.
11.2 Findings The inspector reviewed system electrical schematic drawings and inspected selected safety related control panels and cabinets for both Unit 2 and Unit 3.
The inspector also reviewad instruction manuals E17-337 and 228 which include a description of the GE HGA relays.
The inspector determined that the following safety related systems use the GE HGA for system logic actuations:
System (#)
Panels Location Core Spray (14A)
2(3)0C32,33 Cable Spread Room Residual Heat 2(3)0C32,33 Cable Spread Room Removal (10A)
RCIC (13A)
2(3)0C34 Cable Spread Room HPCI (23A)
2(3)0C39 Cable Spread Room ADS (2E)
2(3)0C32,33 Cable Spread Room 4KV Emergency 00C29A thru D Control Room Switchgear The GE HGA relays used include the following models:
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12HGA11J52 (125 VDC)
12HGA51A42F (125 VDC)
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12HGA11A52F (125 VDC)
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12HGA11A70F (120 VAC)
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HGA relays were also noted to be used in non-safety related applications.
The inspector questioned licensee engineers with respect to HGA relay applications, noted problems and experience. The licensee performed a search of NPRDS data and determined that an HGA relay failure in the Unit 3 ADS logic (relay 3-2E-K32B) occurred on November 12, 1985.
Unit 3 was shutdown at the time, and the relay (ADS high drywell pressure bypass timer) coil burned up destroying the relay. The cause was determined to be wear and age, and the relay was replaced and tested properly.
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The inspector also discussed the HGA relay with licensee corporate mechanical engineering personnel. The licensee stated that in followup to unresolved safety issue (USI) A-40, industry has surveyed damage after seismic events.
No indication of failures of HGA relays have been noted. A review of HGA relays will be performed-by the licensee including specific system applications at Peach Bottom.
11.3 Conclusion HGA relays are used in a number of safety related systems at Peach Bottom. Misoperation of the HGA relays could cause system failures.
The licensee has stated that based on current information, there is no indication of HGA relay failure during actual seismic events. The inspector will continue to follow the HGA relay seismic qualification as well as the overall plant seismic requalification.
Within the scope of the review of HGA relay applications and experiences, no violations were noted.
12. Management Meetings 12.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspection.
During the inspection, licensee management was periodically notified verbally of preliminary findings by the resident inspectors.
No written inspection material was provided to the licensee during the inspection. No proprietary information is included in this report.
12.2 Attendance at Management Meetings Conducted by Region Based Inspectors Inspection Reporting Date Subject Report No.
Inspector Nov 3-7, 1986 Environmental 277/86-23 Jang Monitoring 278/86-24 Nov 18, 1986 Enforcement N/A N/A Conference (Health Physics)
Dec 8-11, 1986 Operator 277/86-22 Lange Licensing Exams 278/86-23
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20 Dec 8-19, 1986 PRA Inspection 277/86-25 Bettenhausen Dec 15,16,29-31, Health Physics 277/86-26 Dragoun
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1986 278/86-26 l
12.3 NRC Region 1/PECo Management Meeting on December 19, 1986 On December 19, 1986, a management meeting was held at the Peach Bottom Station. At this meeting, PECo discussed their approved
" Peach Bottom Enhancement Program (PBEP)".
The PBEP was developed in response to the June 1986 SALP Report and the Region I Diagnostic Team Inspection Report 277/86-12 and 278/86-13. The PBEP is designed to improve the short and long term safety, reliability, and operating effectiveness at Peach Bottom.
Specific goals, objectives, action items and tasks of the PBEP were discussed.
In addition, the following items were discussed:
organization / communications changes, operating status, INPO evaluation status, chemistry status, outage planning and health physics status. A list of meeting attendees is included in Attachment 1 to this inspection report.
The inspector will continue to follow the implementation of the PBEP. Another management meeting will be scheduled in six to eight weeks.
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ATTACHMENT 1 PECo/NRC Meeting December 19, 1986 NRC T. P. Johnson, Senior Resident Inspector, PBAPS R. M. Gallo, Chief, Projects Section 2A, DRP R. R. Bellamy, Cnief, Radiation Protection Branch, DRSS D. R. Muller, NRR/ DBL Project Director R. J. Clark, NRR/ DBL, Project Manager L. H. Bettenhausen, Operations Branch, DRS J. H. Williams, Resident Inspector, PBAPS W. F. Kane, Director, Division of Reactor Projects T. E. Murley, Regional Administrator PECo R. H. Logue, Assistant to Manager - Nuclear Support B. L. Clark, PBAPS Administrative Engineer W. M. Alden. Nuclear Support, Licensing Section D. L. Oltmans, Senior _ Chemist, PBAPS W. J. Boyer, Engineering & Research A. E. Hilsmeier, Senior Health Physicist, PBAPS J. B. Cotton, Superintendent Plant Services, PBAPS M. Cassada, Director of Radiation Protection J. F. Mitman, PBAPS Maintenance Engineer A. A. Fulvio, Technical Engineer, PBAPS S. R. Roberts, Operations Engineer, PBAPS R. H. Moore, Superintendent, QA Division F. W. Polaski, Outage Planning Engineer, PBAPS F. J. Coyle, PB Mechanical Project Engineer M. Reitmeyer, Construction Division, PBAPS D. J. Burns, PB Mechanical Assistant Project Engineer R. S. Fleischmann, Manager, PBAPS G. M. Leitch, Manager, Nuclear Generation Department J. W. Gallagher, Vice President, Nuclear Operations J. S. Kemper, Senior Vice President, Engineering and Production V. S. Boyer, Senior Vice President J. Johanson, PBEP Team J. E. Winzenried, PBEP Team J. B. Richard, Consultant to PEco D. C. Smith, Superintendent Operations, PBAPS Commonwealth of Pennsylvania S. Maingi, Principal Nuclear Engineer, Bureau of Radiation Protection