IR 05000277/1986009
| ML20203F443 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 07/24/1986 |
| From: | Johnson T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203F398 | List: |
| References | |
| 50-277-86-09, 50-277-86-9, 50-278-86-12, IEB-86-001, IEB-86-1, NUDOCS 8607310068 | |
| Download: ML20203F443 (23) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/86-09 & 50-278/86-12 Docket No. 50-277 & 50-278 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: May 10 - June 17, 1986 Inspectors:
T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector Reviewed By:
E. M. Kelly, Sr. Resident Inspector Limerick Approved By:
p P 24-F6 T. P.IJohnson, Acting Chief date DRP, Section 2A Inspection Summary:
Routine, on-site regular and backshift resident inspection (151 hours0.00175 days <br />0.0419 hours <br />2.496693e-4 weeks <br />5.74555e-5 months <br /> Unit 2; 135 hours0.00156 days <br />0.0375 hours <br />2.232143e-4 weeks <br />5.13675e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, l
operational safety, radiation protection, physical security, control room acti-vities, licensee events, surveillance testing, maintenance, and outstanding items.
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Results:
Failure to promptly identify and correct potential degraded conditions of the emergency load center transformers is an apparent violation. This condition apparently existed for several years (detail 4.1.13).
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DETAILS 1.
Persons Contacted J. B. Cotton, Superintendent Plant Services 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, 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 power.
Power reductions occurred frequently due to high oil temperatures in the main power transformers (MPT) (see detail 4.2.1).
On May 31, 1986, the 2B recirculation pump tripped due to field ground overcurrent (see detail 4.2.2).
The unit remained in single loop operation (S35%
power) until June 2, 1986. The unit was at or near full power for the reminder of period except for a rod swap and power reductions for MPT temperatures.
2.1 Unit 3 Unit 3 began the inspection period at full power.
Power reductions also occurred due to high temperatures in the MPT (see detail 4.2.1).
Preventive maintenance on ona recirculation pump MG set and trip of the other on June 7, 1986, resulted in no forced circulation flow (see detail 4.2.3).
The unit remained at or near full power for the remainder of the period except for power reduction for MPT temperatures.
3.
Previous Inspection Item Update 3.1 (Closed) Violation (277/85-29-01; 278/85-33-01).
Failure to follow procedures A-26 and A-26A when preparing permits for blocking equipment and procedure A-2 when making expedited changes to A-26 and A-26A. The inspector reviewed the revised procedures l
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A-26 and A-26A, and the licensee response to the violations dated January 21, 1986. The inspector also reviewed QADP-16, Rev. 9,
" Procedure for Review of Procedures" and discussed the revision with the Peach Bottom site QA supervisor. The inspector concluded that the QA Division had talen appropriate corrective steps associated with A-2 and no further actions were necessary.
Based upon these reviews and discussions, this item is closed.
3.2 (Closed) Violation (278/85-33-03).
Failure to make reports to the NRC as required by 10 CFR 50.72 and 50.73.
Eight reactor protection system (RPS) actuations occurred on Unit 3 between August 29 and October 11, 1985, which were not reported to the NRC as required.
Unit 3 was shut down and the fuel was removed from the reactor vessel at the time of these RPS actuations. The licensee submitted LERs 3-85-21 and 3-85-22 on December 18 and December 20, respectively, which reported these eight RPS actuations. A memorandum was issued on October 11, 1985, by the licensee, stating that all ESF actuations including RPS actuations occurring while the reactor is defueled will be reported to the NRC.
This item is closed.
3.3 (Closed) Unresolved Item (277/84-01-03; 278/84-01-03). Completion and Record Maintenance for Surveillance Tests (STs). The unresolved item pertains to the proper completion and documentation for the following STs:
ST 10.5, RWM Operability Check; ST 10.6, RSCS Functional Test; and ST 10.9, CRD Scram Insertion Timing Following a Reactor Scram.
ST 10.5 was reviewed
during NRC Inspection 277/85-25 and 278/85-21, and determined to be adequate. The inspector reviewed ST 10.6, Revision 15,
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10/28/85 and ST 10.9, Revision 7, 5/22/85. The revised STs include appropriate completion signoffs. Based on inspector review of the STs, the unresolved item is closed.
I 3.4 (Closed) Violation (277/85-29-02).
Failure to perform Surveillance Test (ST) On a Portal Monitor. The licensee
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responded to the violation in a letter dated January 21, 1986.
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The inspector reviewed the response and determined it to be adequate. The licensee performed a satisfactory calibration per ST 4.9.B on September 25, 1985, the day the overdue ST was identified by the inspector. The licensee determined that the cause for the missed ST was a schedule oversight by the Susquehanna Lab. Corrective actions to prevent recurrence include establishing a tracking mechanism within the Susquehanna Lab and training lab I&C technicians how to use it.
Based on the above review, the violation is closed.
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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 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
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Pump House
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Diesel Generator Building 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 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.
4.1.3 Selected control room 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, t
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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 The inspector observed 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 identified.
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 TS channels were operable.
4.1.10 The inspector frequently verified that the required TS off-site electrical power startup sources 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 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 core spray and RHR on both units.
No inadequacies were identified.
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4.1.13 Emergency Load Center Transformer Gas Pressure On May 16, 1986, while making a tour of Unit 2 and Unit 3 Reactor Buildings, the inspector observed that the gas pressure was'zero in emergency load center transformers E-234 and E-334. These transformers are ITE gas sealed 4160 to 480 volt, 500 KVA transformers.
There are four similar transformers in each unit:
Unit 2 - E-124, E-224, E-324, E-424; Unit 3 - E-134, E-234, E-334, E-434.
After discussions with the licensee, the inspector accompanied the Operations Electrical Supervisor to examine the eight emergency load center transformers.
The "as found" condition is listed in Attachment 1.
The gas pressure on at least four of the eight transformers was low (E-234, E-334, E-434, and E-424).
When the condition of the transformers was brought to licensee management's attention, immediate action was taken to repressurize the transformers. On May 19, 1986, the inspector verified that the emergency transformers were pressurized on May 19, 1986, and at other times subsequent to May 19, 1986.
The 4KV/480V emergency load center transformers are part of the auxiliary power system which is used to provide reliable power for loads important to safety under accident conditions.
Eight 4KV emergency switchgear buses (four per unit) supply all power required for safe shutdown of the plant.
Power is fed directly from the buses to motors larger than 200 hp and tnrough the 4KV to 480V emergency load center transformers to the 440 volt emergency auxiliary load center switchgear buses which feed power to emergency mot 1 trol centers for distribution to smaller motors and The vendor manual,.I-T-E Manual IB-5607-2, Issue A,
" Instructions for Installation and Maintenance for the Gas Sealed Transformers" states that as long as the proper pressure is maintained within the tank no other maintenance is required. The transformers are filled at the factory with the proper gas to 5 psig pressure at 25 degrees C.
The vendor manual states that in the event of loss of pressure, load must be reduced so that hot spot temperature remains below 220 degrees C.
The vendor manual also states that a reduction of internal tank pressure to atmospheric reduces the load capacity of the transformer to approximately 50%.
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The inspector questioned the adequacy of the transformers to handle safety related loads in their "as found" condi-tion.
The licensee indicated that the normal operating loads were larger than the emergancy loads on the trans-formers and therefore the transf;rmers could handle the emergency loads. The licensee contacted the vendor to obtain additional information on transformer performance with reduced gas pressure.
The inspector requested veri-fication that the transformers would operate satisfactorily under required accident conditions.
This item is unresolved pending receipt of information on the transformer loads'and performance under accident conditions (277/86-09-01; 278/86-12-01).
The inspector expressed concern that the transformers which are safety related equipment were not being maintained properly. The non-licensed plant operator daily round sheet, dated January 13, 1983, listed acceptance criteria for the transformer pressure as -4.5 to +13 psig, and temperature less than 200 degrees C.
The acceptance criteria for pressure was determined to be
+6 to 10 psig and the daily round sheet was revised by the licensee.
A review was made of plant operator round sheets for the period from 1982 through the present time to ascertain the length of time the transformers were in a potential degraded condition. Transformer E-124 appeared to be in a satisfactory condition during this time period. The other seven transformers had extended periods of operation, from 1982 through 1986, with reduced gas pressure.
Three additional safety related 4KV/480V gas filled transformers supply power to loads associated with the emergency cooling towers which are common to Units 2 and 3.
These transformers are checked weekly and their condition recorded on a separate round sheet. No acceptance criteria was listed on these round sheets.
The inspector examined records for 1985 and 1986 and determined that these transformers (E-13A, E-23A, E-43A)
were also in a potential degraded condition in that the transformer pressure was less than 6 psig.
10 CFR 50, Appendix B, criterion XVI, as implemented in the Peach Bottom Atomic Power Station Quality Assurance Plan, Volume III, paragraphs PR 16.1 and S016.1 requires that measures be established to assure that conditions adverse to quality are promptly identified and corrected.
Failure to identify and correct the
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potential degraded condition of the load center transformers is a violation of 10 CFR 50, Appendix B, Criterion XVI (277/86-09-02; 278/86-12-02).
4.1.14 Transformer Temperature Gauge Modification-The inspector reviewed E&R Mod 459 (EP-81-036) for the installation of temperature gauges to replace the failed hot spot temperature indicators on safety related 4KV/480V transformers E-134 and E-324. Approval for this Q-listed equipment modification was documented in a licensee memorandum dated February 15, 1978.
The originally installed temperature gauge measured internal hot spot temperature. The licensee replaced the inoperative gauges with ones that measure surface (skin) temperature and correlate the surface temperature to hot spot temperature.
The Mod package included the correlation curve, however the curve was not used by plant personnel to accurately monitor transformer temperature.
In addition, the inspector noted
the following inadequacies in the Mod documentation:
The vendor manual had not been updated to describe the new temperature gauges.
Mod Control Sheet, Part II, Item VII and check off list (Appendix G) did not require a change in the plant operator round sheet.
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MRF-2-54-C-2-43 for E-324 temperature gcuge replacement indicates that the equipment is not Q-listed, when most
^# the documentation correctly describes it as Q-listed.
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MRF 2-54-C-2-43 has section 7, " Operational Verifica-tion" signed off as done on April 8, 1982. However, as recorded on the operator rounds sheet, the temperature gauge read offscale low before and after the gauge replacement. Subsequently, in 1986, another MRF was initiated to repair or replace the gauge.
The inspector questioned how the operability checks were made when the MRF was signed off in 1982.
The inspector expressed concern with the number of discrepancies in the documentation for Mod 459. The status of the vendor manual update and the method of operational verification are considered unresolved pending licensee i
response and further NRC review.
(277/86-09-03)
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4.2 Followup On Events Occurring During the Inspection 4.2.1 Main Power Transformers (MPT) High Temperatures During the inspection period both Unit 2 and Unit 3 MPTs experienced recurring high oil temperatures when at or near full load.
There are three single phase 500 KV MPTs for each unit. The MPTs are forced oil, air cooled (F0A) transformers manufactured by McGraw Edison.
The MPTs have two monitored oil temperatures, return oil and hot spot winding.
The temperature alarms and limits are 85 degrees C and 115 degrees C; and, 115 degrees C and 140 degrees C, respectively.
The licensee initiates power reductions upon receipt of a high temperature alarm in the MPT. Power reductions of 59 to 350 MWe reduce the oil temperature to below the alarm setpoint.
In addition, the licensee began taking hourly temperature readings for all the MPTs. The licensee contacted the vendor, who recommended a water lance cleaning of the oil radiators.
The licensee performed the water lancing, and an improvement was noted as the magni-tude of power reductions required was reduced. The cause of the high MPT oil temperatures is unknown, but the licensee believes that the most probable cause is a decrease in air flow and therefore heat transfer resulting from the addition of the new Administration Building in 1984.
Neither unit operated at full power during the summer of 1985.
The inspector reviewed the McGraw Edison vendor manual and discussed the MPT temperature problems with the licensee. The inspector also examined each of the MPTs,
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monitored local temperatures and observed portions of the water lance cleaning evolutions.
The inspector will continue to follow licensee long term corrective actions.
Within the scope of the MPT temperature problems, no violations were identified.
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4.2.2 Unit 2 Recirculation Pump Trip At 8:33 p.m., on Saturday, May 31, 1986, while Unit 2 was operating at 96% power, the 2B recirculation pump M-G set tripped on field ground overcurrent. The operators entered procedure OT-112, Recirculation Pump Trip, Rev. 2, and inserted deep control rods. At 9:20 p.m., the unit was at 33% power and operating in single
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loop. On Monday, June 2, 1986, the inspector reviewed the following completed procedures associated with single loop operation:
ST 1. 8 Recirculation System Baseline Data - 1 and 2
Loop Operation, Rev. 2, performed June 1, 1986 on loop A.
ST 9.21-2 Jet Pump Operability - Single Loop Operation, Rev. 2, performed June 1, 1986.
ST 9.1-2, The Surveillance Log - Single Loop Operation, Rev. O, performed June 1, 1986.
ST 3.10 Core Thermal Hydraulic Stability Monitoring, Rev. O, performed June 1 at 6:23 a.m., and 5:05 p.m.
ST 3.3.2.A Calibration of APRM System for Single Loop Operations, Rev. 4, performed June 1, at 4:20 and at 3:00 p.m.
The licensee determined that the generator brushes were worn and causing electric arcing and chatter. The 2B recirculation water pump MG set was repaired and returned to service at 3:52 p.m., on June 2, 1986. The inspector observed portions of the maintenance. The licensee decided to also rebrush the 2A recirculation pump MG set. The 2A MG set was secured, maintenance performed, and returned to service on June 2, 1986. No unacceptable conditions were observed.
4.2.3 Unit 3 Recirculation Pump Trip On June 7, 1986, with Unit 3 at 33% power and the 3B recirculation pump out of service for preventive maintenance on the MG set generator brushes, the 3A recirculation pump MG set tripped at 11:35 a.m.
The operator implemented procedure OT 112, Recirculation Pump Trip, Rev. 2,Section II.
The 3A recirculation pump trip was caused by a faulty temperature switch which was activating before the drive oil temperature reached the 210 degree F trip setpoint.
Switch calibration requires a plant shutdown, therefore the licensee reduced the operating oil temperature to prevent activating the switch.
The licensee returned the 3A recirculation pump to service at 11:55 a.m. and began monitoring the oil temperature as indicated on control room recorder TR-3-2-184-26 point 9.
Unit 3 was without forced reactor recirculation loop flow for 30 minutes.
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On June 9, 1986, the inspector reviewed control room logs, Procedure OT-112, Technical Specifications (TS),
and discussed the trip with licensee operators and engineers. TS 3.6.F.5 allows continued operation with no reactor recirculation loop flow for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if reactor power is limited to TS figure 3.6.5.
Procedure OT-112 implements these TS requirements. The inspector determined that the licensee appropriately followed OT-112 and TS 3.6.F.5.
The inspector also reviewed the Unit 2 related requirements in TS 2.1.A.4, which states that the reactor shall not be operated in the natural circulation mode. The inspector questioned the licensee why Unit 2 and Unit 3 TSs were different. The licensee's representative stated that Unit 3 had implemented the thermal-hydraulic stability monitoring requirements of TS 3.6.F (TS Amendment #107, December 3, 1984). A TS change request will be processed for Unit 2 to allow operation as discussed in Unit 3 TS.
The licensee reviewed the Unit 2 and 3 TS differences and decided until the TS change is approved for Unit 2, to initiate a reactor scram on either unit if both reactor recirculation loops are lost. The licensee committed to revise procedure OT-112 to implement the more conservative Unit 2 TS requirement. The inspector will continue to monitor for unit operation without both loops of recircu-lation flow and will follow the Unit 2 TS change request.
No violations were identified.
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 Log 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 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 management constituted evi-dence of licensee review. No unacceptable conditions were identi-fied.
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4.4 Meteorological Monitoring System The inspector performed a review of the Peach Bottom meteorological monitoring system in order to verify conformance with FSAR section 2.3.3.2.
The Peach Bottom meteorological measurements program was updated in May 1983 to conform with the requirements of Regulatory Guide 1.23, (proposed revision 1) and NUREG-0654, revision 1.
The on-site meteorological system includes instrumentation located at four different weather station towers:
tower 1A located at Unit 1, tower 2 located at the microwave tower, the hill pole tower behind Units 2 and 3, and the river tower. The meteorological towers measure weather variables at different heights including: wind speed, wind direction, standard deviation of wind speeds, temperature, temperature difference, dew point, and precipitation. These variables are displayed locally at towers 1A and 2, remotely in the control room, and are input to the release calculation computers.
The inspector verified that the meteorological monitoring system FSAR commitments were being implemented including:
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data transmission, storage and display.
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maintenance performed in accordance with vendor manuals.
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aaily checks of system performance.
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weekly inspection of system equipment.
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semi-annual instrument calibrations.
The inspector also toured the meteorological monitoring facilities, monitored equipment operation, and discussed system operation with licensee technicians and engineers.
Within the scope of the review of the meteorological monitoring system, no unacceptable conditions were identified.
4.5 Engineered Safeguards Features (ESF) System Walkdown The inspector performed a detailed walkdown of portions of the primary containment isolation system (PCIS) in order to independently verify the operability of the Unit 2 and 3 systems.
The PCIS walkdown included verifications of the following items:
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Review of documents listed in Attachment 2.
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Inspection of system equipment condition __ _ _ ___
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i Confirmation that the system check-off-list (COL) and
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Verification that system valves, breakers, and switches are
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properly aligned.
Verification that instrumentation is properly valved in and
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Verification that valves required to be locked have
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appropriate locking devices
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Verification that control room switches, indications and
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j controls are satisfactory.
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Verification that surveillance test procedures properly
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implement the Technical Specifications (TS) surveillance
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requirements.
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The inspector noted that several PCIS valves listed in the FSAR
j were not in TS Table 3.7.1.
The inspector discussed this with j
licensee engineers. The licensee was aware of the deficiency and
is in the process of submitting a TS change request t.o revise TS i
Table'3.7.1.
The. inspector verified that the valves not in the TS
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Table 3.7.1 were being operated, tested, and maintair.ed as PCIS
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violations were noted.
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IE Bulletin 86-01, RHR Pumps Minimum Flow Valve Logic Problems On May 23, 1986, the inspector was informed of an I&E Bulletin (86-01)
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s that was to be issued later that day to all BWRs.
The Bulletin
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concerns a condition noted at another BWR that was discovered during followup to I&E Information Notice 85-94. The condition could possibly disable all RHR pumps due to single failure in the minimum flow logic for the RHR system.
GE responded to the identified problem in a letter dated May 22, 1986.
The potential problem (caused by a single failure)
could result in a no flow condition through all operating RHR pumps, and thus result in RHR pump damage in a few minutes.
Loss of the RHR pumps would disable the LPCI, shutdown cooling, head spray, drywell spray, and torus cooling (spray and cooling) modes of the RHR system.
The inspector reviewed the I&E Bulletin, GE letter, Peach Bottom RHR system minimum flow valve arrangement, and discussed the problem with the licensee. Peach Bottom documents reviewed include:
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Electrical schematic drawing, RHR system, M-I-S 65 series, Rev. 70
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4 P&ID M-361, RHR system, sheets 1 and 2, Rev. 27.
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Instrument Data Sheet, MI-P-38-222, Rev. 52.
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j The inspector determined that the Peach Bottom arrangement differs from that discussed in the Bulletin and the GE letter.
Each Unit 2 and 3 J
RHR pump has a normally closed motor operated minimum flow valve,
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MD-10-16. There are two RHR pumps per loop and two loops (A and B) per unit. The RHR loops A and B are separated by a normally closed and de-energized motor operated valve M0-10-20, as required by TS
3.5.A.3.c.
The RHR pump minimum flow valve (M0-10-16) logic operates as follows: On RHR pump start, the valve opens after ten seconds on
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l low flow (high delta p) as sensed by a separate differential pressure
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indicating switch (DPIS-10-121).
If the flow increases (low delta p),
the valve will close.
On subsequent low flows, the valve will reopen;
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and, the valve will close on stopping of the RHR pump.
No common piping or valves were identified which would cause failure of more than one RHR pump.
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The licensee responded to Bulletin 86-01 in a letter dated May 30, i
L 1986. The inspector reviewed the response and discussed it with licensee engineers. Within the scope of the followup to I&E Bulletin 86-01, no unacceptable conditions were identified.
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Review of Licensee Eve'nt Reports (LERs)
6.1 The inspector reviewed LER's submitted to NRC:RI to verify that l
the details were clearly reported, including the accuracy of the description and corrective action adequacy.
The inspector
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determined whether further information was required, whether
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generic implications were indicated, and whether the event warranted on-site followup. The following LER's were reviewed:
LER No.
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- 2-85-24, Rev. 1 Inoperable PCIS valve for the 02 analyzer system June 2, 1986
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hovember 3, 1985
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2-85-26, Rev. 1 Control rod blocking while in a full out position i
May 28, 1986
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- 2-86-10 PCIS actuations during #1 transformer fire i
May 13, 1986 April 13, 1986
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May 5, 1986 I
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May 23, 1986 testing April 23, 1986 l
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3-85-23, Rev. 1 PCIS actuation caused by pulling the wrong fuse l
May 27, 1986
November 15, 1986
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3-86-03, Rev. 1 PCIS actuation caused by pulling the wrong fuse j
May 28, 1986
February 19, 1986 i
3-86-11 PCIS group III due to blown fuse f
May 21, 1986 i
April 25, 1986 i
- 3-86-12 Unit 3 scram from 81% during 500 KV substation i
May 27, 1986 testing due to personnel error
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April 26, 1986
- 3-86-13 Unit 3 neutron monitoring scram while shutdown May 23, 1986 due to personnel error April 26,1986
- 3-86-14 Unit 3 SDV level high scram while shutdown due to May 23, 1986 personnel error April 26, 1986 6.2 On-Site-Followup For LER's 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 reviewed.
6.2.1 LER 2-85-24 was revised by the licensee to clarify that poor communications between operations and maintenance personnel was not a contributing factor to this event.
The inspector reviewed this inoperable PCIS valve event
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in NRC Inspection 277/85-40. No inadequacies were identified relative to this LER.
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6.2.2 LER 2-86-10 concerns a group II and III PCIS actuation on April 13, 1986, on both units caused by loss of power i
due to the #1 transformer fire. These events were
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reviewed in NRC Inspection 277/86-07, 278/86-07.
No i
inadequacies were identified relative to this LER.
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6.2.3 LER 2-86-12 concerns a group II and III PCIS actuation on April 13, 1986, on both units caused by the loss of the E-2 DG due to a failed speed switch. This event was reviewed in NRC Inspection 277/86-07, 278/86-07.
The licensee determined that the problem with the E-2 DG was
caused by a failed drive pin at the connection between
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the engine drive shaft and the speed device resulting in slippage. The slippage then caused the diesel engine speed switches to alternately close and open, resulting in oscillation of the red and green control lights in
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the control room.
The licensee determined that the failure was due to normal usage, and repaired the speed switch device.
Additional repairs are planned for the other three DGs during the next scheduled annual DG inspection.
In addition, the speed switches have been added to the annua'. DG inspection program. The inspector will review these r9 pairs in a future inspection. No inadequacies were noted relative to this LER.
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6.2.4 LER 2-86-13 concerns a scram from 100% power on April i
23, 1986, on Unit 2 due to TCV fast closure during CIV testing. This event was reviewed in NRC Inspection l
277/86-07.
The licensee determined that the cause of l
inadvertent closure of the #1 CIV when the #2 CIV closed was due to a hydraulic transient resulting from air
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entrapped in the EHC lines. The licensee replaced the fast acting solenoids on the #1 and #2 CIVs, and l
installed restricting orifices on the emergency trip supply ports. GE recommended this modification in order to dampen hydraulic transients in the trip supply header without affecting the trip function.
In addition, all six CIVs were stroked successfully before startup; and, while at power during surveillance testing on April 27, 1986. No inadequacies were noted relative to this LER.
6.2.5 LERs 3-86-12,13, and 14 concern scrams on Unit 3 (one at 81% power and two while shutdown) and each event was reviewed in NRC Inspection 277/86-07, 278/86-07.
No inadequacies were noted relative to the LERs.
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Surveillance Testing t
The inspector observed surveillance tests to verify that testing had
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been properly scheduled, approved by shift supervision, control room
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procedures were being used, redundant systems or components were
available fer service as required, test instrumentation was calibrated, i
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work was pertarmed by qualified personnel, and test acceptance criteria
were met.
Parts of the following tests were observed:
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ST 1.3-2, PCIS Logic System Functional Test, Revision 9, 2/5/86, l_
performed on Unit 2 on June 10, 1986.
ST 2.10.26, Functional Check of the ECCS A/C-2 Card File, Revision
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j 4, 2/23/84, performed on Unit 3 on June 10, 1986.
In addition, a review of the following completed surveillance tests was
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j performed (see detail 4.2.2 also):
ST 2.25.1.4, PS-2-10-118, 122A, 1228 Calibration; Revision 1,
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performed on February 18, 1985, on Unit 2.
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ST 2.25.2, PS-2-14-47A, B Calibration; Revision 2, performed on
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January 30, 1985, on Unit 2.
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ST 2.30.1.4, PS-3-10-118, 122A, 122B Calibration; Revision 1, performed on August 1, 1984, on Unit 3.
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ST 2.30.2, PS-3-14-47A, B Calibration; Revision 1, performed on Nove.nber 1, 1984, on Unit 3.
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ST 6.6, Core Spray A Pump, Valve, Cooler Functional Test, Revision 22, performed on Unit 2 on March 14, 1986.
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ST 6.6F, Core Spray A Pump, Valve, Flow, Cooler Test, Revision 3, performed on Unit 2 on April 15, 1986.
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ST 6.7, Core Spray B Pump, Valve, Cooler Functional, Revision 23, performed on Unit 2 on April 8, 1986.
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ST 6.7F, Core Spray B Pump, Valve, Flow, Cooler, Revision 4, performed on Unit 2 on May 5, 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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Procedure /
f Document Equipment Date Observed MRF #3-86M4057 3B instrument May-28, 1986 nitrogen compressor i
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i-MRF #2-86M4174 2B reactor June 2, 1986
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j recirculation
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pump MG set i
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MRF #2-86M3608 Fan Room June 12, 1986 l
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protective wire
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Administrative controls checked included maintenance requests, blocking
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permits, fire watches and ignition source controls, item handling reports, and shift turnover information. Documents reviewed included procedures, material certifications and receipt inspections.
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No inadequacies were identified.
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Radiation Prote.ction
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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 potentially contaminated equipment and materials.
The inspector observed individuals frisking in accordance with HP
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procedures. A sampling of high radiation doors was verified to be
locked as required. Compliance with RWP requirements was verified l
during each tour.
RWP line entries were reviewed to verify that l
personnel had provided the required information and people working in
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RWP areas were observed to be meeting the applicable requirements. No I
unacceptable conditions were identified.
l 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 i
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 and escort procedures.
No inadequacies were identified.
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11. Core Spray and RHR Interfacing Systems Leaks
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The inspector performed a review of the Unit 2 and 3 core spray and RHR l
systems with respect for the potential of interfacing systems LOCA. An interfacing system LOCA is by leakage from the reactor through an attached system, and into that system's low pressure piping. The l
resultant path would bypass primary containment, and overpressurize the l
l low pressure piping.
l The Peach Bottom arrangement for core spray and RHR is similar. The j
injection lines from the reactor to the low pressure piping is as
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l normally locked open manual valve.
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normally closed testable check valve with an air operated bypass
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valve.
normally closed injection valve.
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accumulator line for the " keep fill" systems.
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normally open injection valve.
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pressure switch and control room alarm for leakage indication.
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relief valve.
pressure indicator for control room indication (core spray only).
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low pressure piping for pumps.
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l Technical Specification 6.14 requires the licensee to implement a propram to monitor for and reduce potential leakage at least every refueling cycle from the following systems:
RHR, core spray, RCIC, HPCI, and reactor water cleanup. This program is implemented by the semi-annual performance of surveillance test (ST) procedures, ST 12.15 series. The inspector reviewed these procedures and verified that the STs were being performed as required. The licensee did not identify any abnormal leakage in 1985/86.
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The inspector performed a review of the most recent leakage data for the testable check valves and normally closed injection valves.
The injection valves are leak tested as required by 10 CFR 50, Appendix J, local leak rate testing (LLRT).
Both Unit 2 and 3 core spray and RHR injection valves (MO-14-12 A,B and M0-10-25 A,B) LLRT was performed during 1985 with satisfactory results.
In addition to LLRT, the licensee performs leak tests of the testable check valves and the
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closed injection valves during reactor vessel hydrostatic testing.
l Hydrostatic testing was performed during May 1985 for Unit 2 and during l
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i January 1986 for Unit 3.
The testable check valves for Unit 2 and 3 loop "A" core spray (AO-14-13A) exhibited high leakages. The licensee initiated a MRF for each valve, and repair is scheduled next refueling.
The licensee also performed LLRT on selected core spray and RHR testable check valves.
The LLRTs were performed in preparation for a TS change request to LLRT requirements (TS Table 3.7.4).
The inspector reviewed the draft TS change request.
The licensee is changing the
LLRT boundary from the two motor operated injection valves to the
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testable check valve and the normally closed injection valve.
Results of this LLRT for the selected core spray and RHR testable check valves indicated high leakage for the Unit 2 RHR A loop and for the Unit 3 core spray A and B loops. Thus, the Unit 3 core spray loop A testable check valve (AO-3-14-13A) has high leakage as noted both during the j
hydrostatic test and the LLRT.
The inspector performed walkdowns of the accessible portions of the
l Unit 2 and 3 core spray and RHR systems monitoring for potential
leakage and none was found. The inspector noted that the Unit 2 loop B.of core spray "high pressure" (leakage) alarm was out of service.
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The alarm (20C2030 #10) has an open cable between the pressure switch and the cable spreading room. MRF #2-14-M85-6849, dated September 14, 1985, was written to initiate repairs which are scheduled for the next Unit 2 refueling outage. The core spray loop has pressure indication in the control room as a backup to the out of service leakage alarm.
The inspector reviewed the MRF and discussed the out of service leakage alarm with the licensed operators. The operators were knowledgeable of plant status. A def'ci~.cy sticker is attached to the alarm window denoting the out of trvice condition.
The inspector also reviewed the acoustic monitoring of the testable check valves. The core spray testable check valves (AO-14-13A,B) and the RHR testable check valves (AO-10-46A,B) are currently monitored i
with accelerometers which readout in the control room.
Readings are l
monitored and print out continuously. The accelerometers are mounted
on the valves as to measure packing leakage from the external actuator arms' (attached to disc) stuffing boxes.
Based on interviews with engineers in charge of acoustic monitoring:
the accelerometer
arrangement is such that seat leakage through the core spray A0-14-13 l
valves could be detected; however, the current arrangement probably could not detect seat leakage on the RHR A0-10-46 valves. The engineers indicated that accelerometer relocation (or additional j
accelerometers) could possibly detect A0-10-46 seat leakage.
The PECo
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acoustic engineers do have experience in monitoring for valve seat leakage with accelerometers.
The 1985 and 1986 data for A0-14-13 and i
A0-10-46 (Units 2 and 3) was reviewed and indicated no packing leakage and thus probably no excessive seat leakage.
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Within the scope of the review of the potential for interfacing system leakage, no violations were identified.
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12.
In-Office Review of Public and Special Reports i
The inspector reviewed the following:
Peach Bottom Fire on November 14, 1985, in the Radwaste Building,
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dated May 21, 1986.
t Unit 3 Inservice Inspection Report dated May 28, 1986.
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No unacceptable conditions were noted.
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13. Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations.
Unresolved items are discussed in Detail 4.1.13 and 4.1.14.
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14. Management Meetings 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 the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection.
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No proprietary information is included in this report.
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o ATTACHMENT 1 Emergency Load Center Transformer Condition On May 16, 1986 Pressure (6-10 psig)
Transformer (range desired).
Temperature Degrees C (Maximum 220 C)
Amps Unit 2 E-324
Inoperable (MRF initiated)
E-224
<50
E-424
'3 115
E-124
100
Unit 3 E-234
100
E-434
125
E-134
60
E-334
90
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ATTACHMENT 2
PCIS DOCUMENTATION REVIEWED Technical Specifications sections and tables 3/4.2.A, 3/4.2.B,
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3/4.7.D
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I FSAR section 7.3.1 i
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Electrical schematic drawings 6280-MI-S23, sheets 1 thru 19
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(various revisions)
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I GP-8, Primary Containment Isolation, Revision 18, 03/01/86 f
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i GP-8A, Bypassing Isolations to Units 2 and 3, Revision 1, 05/04/82 i
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GP-88, Resetting Inboard Half Isolation, Revision 1, 05/04/82
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GP-8C, Resetting Outboard Half Isolation, Revision 4, 03/31/86
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ST 1.3-2, PCIS Logic System Functional Test, Rev. 10, 5/16/86
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i S1 1.3-3, Unit 3 PCIS Logic System Functional Test, Rev. 7, 2/5/86
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ST 6.2, PCIS Normally Open Valves, Rev. 13, 1/6/86.
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