IR 05000277/1998011
| ML20202J552 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 02/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202J530 | List: |
| References | |
| 50-277-98-11, 50-278-98-11, NUDOCS 9902090169 | |
| Download: ML20202J552 (32) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION I -
License Nos.
DPR-44 DPR-56
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t Report Nos.
98-11 l
98-11 Docket Nos.
50-277 I
7 Licensee:
PECO Energy Company
Correspondence Control Desk P.O. Box 195 Wayne, PA 19087-0195
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' Facility:
Peach Bottom Atomic Power Station Units 2 and 3
Inspection Period:
November 10,1998 through January 4,1999 Inspectors:
A. McMurtray, Senior Resident inspector j
M. Buckley, Resident inspector -
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B. Welling, Resident inspector S. Dennis, Operations Engineer
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J. Carrasco, Reactor Engineer M. Thadani, NRR Project Manager Approved by:
Curtis J. Cowgill, Chief Projects Branch 4 i
Division of Reactor Projects J
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I 9902090169 990201
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PDR ADOCK 05000277 O
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EXECUTIVE SUMMARY
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.i Peach Bottom Atomic Power Station l
- NRC inspection Report 50-277/98-11, 50-278/98-11 f
This inspection report included aspects of licensee operations; surveillances and maintenance; engineering and technical support; and plant support areas.
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Operations-l The plant operators performed well during the Unit 3 shutdown'and startup for the e
instrument nitrogen leak repair and the reduction in power for replacement of the raain
turbine lubricating oil baffler valve and pump. Procedures were properly followed and i
communications and shift oversight were effective and professional. (Section 01.1)
1 Control room operators responded as expected to an electrical transient caused by a e-loss of the 2 emergency auxiliary transformer. Licensee personnel took timely and
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effective corrective actions to repair damaged terminal components, address the generic j
concoms, and restore the emergency transformer to operation. (Section O2.1)
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On November 30,1998, inadequacies in a breaker manipulation procedure led to an e
unexpected loss of one off-site power source and several emergency safety feature
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actuations. Plant operators performed well during this event while challenged by the loss of control rod drive pumps and reactor water cleanup system isolation on both units and j
, a recombiner isolation and power reduction on Unit 3. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV),
consistent with Section.Vil.B.1 of the NRC Enforcement Policy.- (Section 03.1).
Three licensed operators failed to successfully complete requalification training during e-the licensee requalification training program which ran from April 1994 through March 1996. Additionally, as a result of the failure to make up missed training until April 1998,
~ one operator license renewal application, was submitted to the NRC with inaccurate information. The application incorrectly certified that the applicant had met the requirements of the approved requalification program during the effective term of the then current license. This was a violation of 10 CFR 55.57(a)(4) and 10 CFR 55.9.
Corrective actions for the misrad training and inaccurate application were adequate.
(Section 05.1)
e Procedure adherence in the performance of winterizing procedures was improved.
However, weaknesses in station winterizing procedures and personnel attentiveness to heating / ventilating system equipment led to a number of minor, cold weather-related equipment problems. (Section 08.1)
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L Executive Summary (cont'd)
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i Maintenance-
l Station personnel' discovered that a Technical' Specification Surveillance Requirement for
'e average power range monitor channel calibration was not met during Unit 2 power :
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ascension due to an inaccurate heat balance calculation. The heat balance calculation
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- inaccuracy was due to substitute values installed by instrument and control and i
engineering personnel during flow transmitter calibrations. The calculated heat balance
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values were always conservative from a safety perspective and station personnel took
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l adequate and reasonable corrective actions for this event. This non-repetitive, licensee-l identified and corrected violation is being treated as a Non-Cited Violation (NCV),1 consistent with Section Vll.B.1 of the NRC Enforcement Po! icy. (Section M4.1)
l Engineerina Three reactor core thermal management problems occurred during this inspection period e
related to the 3D MONICORE program. Two problems were related to configuration I
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' management of input data to the program and one was related to unexpected program
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and developed appropriate corrective actions. No thermallimits were exceeded as a l
result of these problems. (Section E4.1)
Plant Support.
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Radiation protection personnel provided very good oversight of control rod blade
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component removal from the Unit 3 spent fuel pool and replacement of a Unit 2 i
traversing incore probe. Good awareness for As-Low-As-Reasonably-Achievable l
(ALARA) by personnel involved with this work, and effective planning and monitoring by radiation protection personnel resulted in low doses for these activities. (Section R4.1)
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The licensee had appropriately maintained the barriers and isolation zones around the
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. protected area.. Security equipment in the Central Alarm Station and Secondary Alarm-l l.
. Station areas were functioning properly. Activities in these areas would not have
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interfered with the execution of the detection, assessment or response functions.
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TABLE OF CONTENTS
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EXECUTIVE SU M MARY...................................................... ii i
TABLE OF CONTE NTS........................................................ lv
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Summary of Plant Status....................................................... 1 i
1. Operations............................................................... 1
Conduct of 0perations............................................ 1 j
01.1 General Com ments........................................ 1 O2 Operational Status of Facilities and Equipment........................ 2
02.1 Inoperable Off-site Power Source and Station Blackout Line Due to the Failure of the 2 Emergency Auxiliary (EA) Transformer
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Operations Procedures and Documentation........................... 3 03.1 Loss of Off-Site Power Source and 2SU Bus Trip Due to Electrical Bus Switching During Planned Breaker Maintenance and (Closed) Licensee Event Report (LER) 50-277/2-98-008......................... 3 03.2 Unexpected Unit 3 Rod Worth Minimizer Rod Block During Control Rod Drift Alarm Test........................................... 4
Operator Training and Qualification........................,......... 6 05.1 Licensed Operator Requalification Training Program and (Closed)
Unresolved item (URI) 50-277(278)/98-04-01 Failure of Certain Licensed Operators to Complete Requalification Training.................. 6 I
Miscellaneous Operations issues.................................. 9 08.1 (Closed) Violation (VIO) 50-277(278)/97-08-01 Cold Weather Preparations............................
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l lI. M ainte n a nce.......................................................... 10 M1 Conduct of Maintenance........................................ 10 M1.1 General Observations..................................... 10 I
M4 Maintenance Staff Knowledge and Performance...................... 11 M4.1 Failure to Meet Technical Specification (TS) Surveillance Requirements i
for the Absolute Difference in the Average Power Range Monitor (APRM)
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Channels and the Calculated Reactor Power Due to Substitute Feedwater Flow Temperature Correction Factors in the Heat Balance Calculation (Closed) LER 50-277/2-98-007............................ 1 1 M8 Miscellaneous Maintenance Issues................................ 12
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l M8.1 (Closed) VIO 50-277(278)/97-07-02 Three Examples of Procedure Non-Adherence - 3B High Pressure Service Water Pump Maintenance, Station l
Battery Startup, Cooldown Operation......................... 12 111. E n ginee rin g........................................................ 13 E1 Conduct of Engineering...................................
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E1.1 ISFSI Pad and Retaining Walls..........................
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l E1.2 Reinforced Concrete Bridge over Rock Run Creek..............
l E2 Engineering Support of Facilities and Equipment...................... 15 E2.1 Reactor Water Cleanup System Automatic isolations (Unit 2)......
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l E3 Engineering Procedures and Documentation......................... 16 E3.1 Review of the 1997 Annual Report of 10 CFR 50.59 Evaluations...
E4 Engineering Staff Knowledge and Performance...................... 16 E8 Miscellaneous Engineering Issues................................. 19 E8.1 (Closed) URI 50-277(278)/96-06-02 Station Blackout (SBO) Line Review
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I IV. Plant Support.......................................................... 20 R1 Radiation Protection and Chemistry Controls (RP&C).................. 20 i
R1.1 Locked High Radiation Doors and Posting inspections During Plant Tours
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....................................................... 20 R4 Staff Knowledge and Performance in RP&C.......................... 20 R4.1 Radiation Protection Controls During High Radiation Work Activities
...................................................... 20 S2 Status of Security Facilities and Equipment.......................... 21 S2.1 General Integrity of Protected Area (PA) Barriers and Inspection of Central Alarm Station (CAS) and Secondary Alarm Station (SAS)..
V. M anagement Meetings.................................................... 22 X1 Exit Meeting S um mary.......................................... 22 Attachment 1 - List of Acronyms Used-Inspection Procedures Used
- Items Opened, Closed, and Discussed Attachment 2 - Synopsis - NRC Office of Investigations Report No. 1-98-020 V
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Report Details
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l Summary of Plant Status
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t PECO operated both units safely over the period of this report.
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Unit 2 began this inspection period at 100% power. During the early morning of December 19, 1998, unit load was reduced to 60% to repair a leak on the B3 feedwater heater extraction steam line. Unit load returned to 100% power during the aftemoon of December 19 following this repair. On January 2,1999, unit load was reduced to 65% to allow repairs to the main
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turbine #3 control valve. The unit was retumed to 100% power on January 3.
l Unit 3 began this inspection period at 100% power. The unit was manually scrammed on November 27,1998 to repair an instrument nitrogen supply line. The unit was retumed to 100%
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power on December 1. On December 3, the main turbine was taken off line to replace the main turbine lube oil baffle booster pump and valve. The reactor remained critical while this work was J
performed. The unit was retumed to 100% power on December 11. Unit power remained at 100% for the rest of the period.
I. Operations
Conduct of Op:Malons'
01.1 General Comments j
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Inspection Scope (71707)
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The inspectors observed portions of the Unit 3 shutdown and startup for instrument nitrogen leak repair and the reduction in power to allow tripping the main turbine to facilitate replacement of the main turbine lubricating oil baffler valve and pump. The inspectors also verified that heatup and cooldown rates were maintained within requirements during these maneuvers,
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Observations and Findinas i
I On November 27,1998, operators shut down Unit 3 to repair a nitrogen leak on an air operated valve inside the drywell. The unit was restarted on November 28 following repairs. On December 3,1998, operators noted abnormal vibration and noise coming from the main turbine lube oil reservoir. Subsequent troubleshoo'ing indicated that the main turbine baffle booster pump was performing unsatisfactorily.
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l The operators commenced a well controlled load reduction to the allow removal of the
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l main turbine from service. Unit 3 was maintained critical on the bypass valves until the
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main turbine lube oil baffle pump and valve were replaced, tested, and returned to
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outline individual reports are not expected to address all outline topics.
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service. The retum to full power was well controlled, in accordance with procedures, and the unit operated well within acceptable operating parameters.
Plant operators performed well during these maneuvers and appropriately followed site J
procedures. Professional and effective communications and shift oversight were also observed. Reactor coolant heatup and cooldown rates were well controlled within requirements.
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Conclusions The plant operators performed well during the Unit 3 shutdown and startup for the instrument nitrogen leak repair and the reduction in power for replacement of the main turbine lubricating oil baffler valve and pump. Procedures were properly followed and communications and shift oversight were effective and professional.
O2 Operational Status of Facilities and Equipment i
O2.1 Inocerable Off-site Power Source and Station Blackout Line Due to the Failure of the 2
Emeraency Auxiliary (EA) Transformer a.
Inspection Scope (71707)
The inspectors observed the actions taken by Peach Bottom Site personnel in response to the trip of the 2 SU-E Breaker due to failure of the 2 emergency auxiliary (EA)
transformer. The inspectors also reviewed the associated electrical schematics related to this event.
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Observations and Findinas On December 27,1998, with both units 61 !TS power, the 2 SU-E breaker tripped open on high current. The applicable (E312, E323, E332, E343) 4KV emergency bus feeder breakers fast transferred to the 3SU-E feed automatically. The breaker trip resulted in isolation of the reactor water cleanup systems and loss of the 'A' control rod drive (CRD)
pumps on both units, and start of the control room emergency ventilation (CREV)
system. Control room operators maintained the plant in a stable condition during this transient, with no indication of changes in reactor water level, pressure, or power. The licensee submitted a 10 CFR 50.72 event notification due to the engineered safety feature (ESF) actuations.
The inspectors independently examined the 2 EA transformer and observed that the cable connection panel sides had bulged out and the insulators for the cable connections were significantly damaged. The licensee's investigation revealed that the 'B' phase support bushings on the 2 EA transformer 4KV side had failed, causing a short circuit and overpressure event in the terminal panel. The overcurrent 251B and 251C relays on the 28U-E breaker had tripped in response to overcurrent. There was no other significant damage to the transformer or 4 kV bus cables. Maintenance technicians repaired the terminal connections to the transformer and replaced the damaged insulator v
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The licensee determined that stress on the insulator bushings due to mechanical loading of the cables into the transformer had created fine cracks that allowed conditions for a short circuit. The licensee took action to eliminate the condition and evaluated the possibility for these conditions on other site transformers. The licensee stated that recent preventative maintenance and inspection of the other transformers should provide adequate assurance that their insulators are in satisfactory condition.
During a review of electrical schematics and procedures related to station blackout (SBO), the inspectors noted that station blackout procedures did not address energizing the emergency buses with the SBO line through the 3 EA transformer if the 2 EA
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transformer was not operable. The inspectors noted that the SBO rule did not require having the capability to energize the emergency buses with the SBO line through the 3 EA transformer, but PECO indicated inat they would consider developing a procedure to
provide this flexibility.
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Conclusions Control room operators responded as expected to an electrical transient caused by a
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loss of the 2 emergency auxiliary transformer. Licensee personnel took timely and l
effective corrective actions to repair damaged terminal components, address the generic
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concerns, and restore the emergency transformer to operation.
l O3 Operations Procedures and Documentation
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03.1 Loss of_Off-Site Power Source and 2SU Bus Trio Due to Electrical Bus Swltchina Durina l
Planned Breaker Maintenance and (Closed) Licensee Event Report (LER) :50-277/2-98-008 l
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Inspection Scope (71707)
l The inspectors reviewed the plant and operator response to the trip of the SU25 breaker during transfer of the No. 2 startup feed bus from 2SU to 343SU. This review included the operating procedures and the licensee's evaluation of the cause of the event.
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Observations and Findinas l
On November 30,1998, operations personnel established a breaker lineup which caused the offsite SU-25 breaker to unexpectedly trip during realignment of the 13kV electrical system. This de-energized the 2 Start-up and emergency auxiliary l
transformers resulting in six 4KV emergency buses fast transferring to the 3 Start-up and i
emergency auxiliary buses.
During the electrical switching activities, system operating (SO) procedure, SO 53.6.B, Revision 27, " Auxiliary Electrical System Transfer Operations" directed the transfer of the 2SU-B bus feeder from 2SU bus to 343SU bus. Due to procedure inadequacies, the 2SU bus was unexpectedly de-energized while transferring the 2SU bus feed. This initiated an electrical transient and resulted in the loss of control rod drive (CRD) pumps,
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reactor water cleanup system (RWCU) isolations, and engineered safety feature (ESF)
actuations on both units, control room emergency ventilation (CREV) start, and a -
recombiner isolation on Unit 3. Control room operators reduced reactor power on Unit 3 due to the recombinerisolation.
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The licensee determined that syv.em modifications in 1992 were not adequately incorporated into the existing operating procedures. Following this event, operations personnel re-preformed these procedures in the simulator and the equipment performed
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as it did during the transient.
l Due to the ESF actuations, the licensee made an event notification to the NRC in
accordance with 10 CFR 50.72. The inspectors completed an on-site review of the
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licensee's LER submittal, and had no concerns with the report or corrective actions l
presented.
Technical specifications 5.4.1 requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Appendix A. Regulatory Guide 1.33, Appendix A, includes procedures covering energizing and changing modes of operation for on and off site electrical systems. Contrary to the above, as of November 30,1998, PECO did not properly establish written procedures for changing electrical system modes. Specificaliy, procedures SO 53.6.B Revision 27, " Auxiliary Electrical System Transfer Operations and SO 53.7.T, Revision 0, "Startup Bus Outage" were inadequate for controlling electrical system mode changes.
The inspectors concluded that the operators took appropriate actions during this event and that the licensee's corrective actions for this event were reasonable and effective.
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Therefore, this non-repetitive, licensee-identified and corrected violation and is being -
treated as a Non-Cited Violation (NCV), cor6sistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-277/98-11-01)
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Conclusions i
On November 30,1998, inadequacies in a breaker manipulation procedure led to an l
unexpected loss of one off-site power source and several emergency safety feature l
actuations. Plant operators performed well during this event while challenged by the loss
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of control rod drive pumps and reactor water cleanup system isolation on both units and a recombiner isolation and power reduction on Unit 3. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV),
i consistent with Section Vll.B.1 of the NRC Enforcement Policy.
O3.2 Unexoected Unit 3 Rod Worth Minimizer Rod Block Durina Control Rod Drift Alarm Test a.
Inspection Scooe (71707)
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l During performance of a routine test (RT) of the control rod drift alarm, the Unit 3 reactor j
operator received an unexpected rod worth minimizer (RWM) rod block in both the insert
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and withdraw directions. The inspectors discussed this issue with operations and reactor
engineering personnel and reviewed applicable documentation.
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Observations and Findinas On December 6,1998, the Unit 3 reactor operator was performing RT-O-003-930-3, Revision 5, " Control Rod Drift Alarm Test" with rearnr power below the low power setpoint. Prior to performing the test, an RWM ince,-t error was present because rod 14-15 was past its insert limit due to a bad position indicator. When rod 02-23 was moved inward to position 46 during the performance of RT-O-003-930-3, a second insert error occurred and an RWM insert rod block occurred. The RWM latched into the rod group containing rod 14-15 at its current position, sensed a withdraw error, and an RWM withdraw block also occurred. In response, operations personnel entered Abnormal Operating (AO) procedura 62A.1-3, Revision 14, " Rod Worth Minimizer System Manual Bypass" to bypass the RWM and restore rod 02-23 to its original position. Rod 02-23
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was retumed to position 48, the RWM was reinitialized, and AO 62A.1-3 was exited.
The licensee initiated Performance Enhancement Program (PEP) report 10009245 for this event. During their investigation for this PEP, the licensee determined that RT-O-003-930-3 did not prevent performance of this RT below the RWM low power setpoint.
Similar procedures, such as the control rod exercise surveil lance test, were not allowed to be performed below the low power setpoint.
The inspectors determined based on interviews, that operations personnel involved with inis issue did not fully understand the logic for the RWM rod blocks. Although the Unit 3
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reactor operator expected the insert rod block when he moved rod 02-23 to position 46, he did not expect the withdraw block. Because of this block, he had to manually bypass the RWM to restore rod 02-23 to the original position to complete the alarm test.
The inspectors noted that corrective actions for PEP 10009245 included making changes to RT-O-003-930-3 to ensure that reactor power was greater than the RWM low power setpoint prior to performing the test. Corrective actions also included training for licensed operators and reactor engineers that emphasized the latching criteria used by the RWM. The inspectors reviewed these corrective actions and had no concerns.
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Conclusions Unexpected rod worth minimizer insert and withdraw rod blocks occurred when the Unit 3 reactor operator inserted a control rod one notch during a control rod drift alarm test.
Overall, corrective actions for this issue were comprehensive and addressed the identified causes.
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Operator Training and Qualification l
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.05.1 Licensed Operator Raa"dication Trainino Proaram and (ch) Unr==%d item (URI)
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50-277(278)/98-04-01 Failure of Certain Licensed Ooerators to Comma Raa"-Nian Training l
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Insoection Scone (71001)
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The inspectors followed up on unresolved item (URl) 50-277(278)/98-04-01 which descrioed the failure of four licensed operators to make up missed training following the
training period of April 1994 to March 1996. Additionally, the inspectors reviewed an
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issue concoming the accuracy of operator license renewal applications (NRC Form 398) :
l submitted to the NRC during the past 4 years. An in-office and on-site review of the i
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' Past and current training attendance records
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Previous and current revisions of the Peach Bottom (PB) licensed operator
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requalification training course plan (POC-2.4 Revs.7&8)
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l Licensee corrective action documents; PEP 10008441,10008445,10004734,
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10007366, and AR-A1168753 Licensee letters further explaining the issues, dated April 16,1998 and September
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Operator license renewals (NRC Form 398) submitted from 1994 through 1998
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Also reviewed was the NRC Office of Investigation Report No.1-98-020 (synopsis
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documented in Attachment 2),
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Observations and Findinos
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The inspectors found upon review of the documents'and an NRC Office of investigations l
(01) report that four individuals had not completed the 24 month licensed operator requalification training (LORT) cycle which was conducted from April 1994 through March 1996. The inspector noted that one of the individuals, per Peach Bottom procedure POC-2.4-Rev.7, was not required to attend requalification training due to being enrolled during that reriod in a Senior Reactor Operator License Upgrade class i
which covered the san nubject areas. However, the inspector found that during that cycle, the other three individuals missed training in subject areas which included i
technical specifications, normal and emergency operating procedures, and plant l-systems. Further, the operators had not made up the training, in some cases, until April j
1998. Therefore, the three operators had not successfully completed the 24-month j
LORT cycle from April 1994 through March 1996 which is contrary to 10 CFR 55.59a(1).
Additionally, as a result of the missed training, the inspectors found that one of the
- individuals, had not successfully completed the requalification program and had
submitted a license renewal application (NRC Form 398), signed by the operator and
authorized representatives of the facility. The application certified that the individual met
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- the approved requalification program as required by 10 CFR 50.54(1-1) and 10 CFR j
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t 55.59(c). An approved program constitutes, in part, attendance at all training or
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completion of make up training. The signed application, certifying program completion, i
was submitted on October 4,1996 and the inspector's review of licensee records found l
that make up training for numerous missed training sessions was not completed until l
April 1998. Therefore, the program was completed in April 1998 and not on October i
4,1996, as certified on the applicants NRC Form 398. Accordingly, the signed l
- application was inaccurate which is contrary to 10 CFR 55.57(a)4 and 55.9.
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i The inspectors reviewed licensee root cause analysis and corrective actions as noted
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Missed Reaualification Trainina The licensee determlaed that the root cause of the missed requalification training was
due to inadequate guidance and. subsequent incorrect interpretation of attendance requirements in the licensed operator course plan, POC2.4 Rev.7. The course plan stated at step 6.1.2.3.1. that "the individual shall make-up the missed training by an
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altemative method as determined by the Manager-Operations Training." The "altemative j
method" permitted by certain members of the operations training department, in these cases, was successfully passing the annual requalification exam in lieu of training l
attendance. The licensee has determined this was the wrong interpretation of 10 CFR l
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l 55.59 requirements.
j The inspectors verified the associated corrective actions are complete as noted below.
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L Memorandum to all licensed operators dated June 1,1998, from the Senior i
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Manager-Operations, stating training attendance expectations and requirements per 10 CFR 55.59.
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Revision of the course plan, POC2.4 Rev.8 section 7.5.2.2, which specifically
describes attendance requirements and the requirement to make up missed i
training within 12 weeks (the end of the following cycle) or be removed from license duties until the training is complete.
Revision of the course plan, POC2.4 Rev.8 section 7.5.2.3, which states that all
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training deficiencies must be complete prior to taking any part of the annual or biennial exams.
Revision of the course plan, POC2.4 Rev.8 section 7.5.2.2, which requires
notification of the Senior Manager-Operations for failure to make up training within the prescribed time limit.
Revision of training attendance sign-in sheets with at least two levels of
supervisory review.
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i Additionally, the inspectors reviewed attendance records for the previous six months and l
found them to be up to date, attendance at a very high level, and make up sessions I
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l completed as required. Also noted, were ongoing management meetings with all l
operators during the current requalification cycle, reemphasizing training expectations.
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The inspectors concluded that the root cause for the missed training was programmatic (
and not willful on the part of individuals, in that the program was not specific regarding
.i the requirements for determining successful completion of training. Additionally, the root j
r cause was adequately documented and the associated corrective actions were
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L comprehensive, fully implemented, and acceptable overall.
l Inaccurate NRC Form 398 I
The licensee determined that the root cause of the inaccurate NRC Form 398 was due to the lack of a single point of ownership in the license application submittal process as described in procedure A-C-10 - Operator Licenses (PEP-10007366 and AR-A1168753).
The procedure described the correct process for application completion and submittal l
. but delineated responsibility among various licensee personnel for completion. No single
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l point contact was apparent in A-C-10 to assure accurate completion prior to submittal.
The recommended corrective action by the licensee was a revision of procedure A-C-10 l
to assure that the submittal process is clarified with responsibility clearly identified.
I The inspectors determined that root cause determination for the inaccurate 398 form was l
reasonably thorough. The inspectors also determined that one corrective action,
revision of procedure A-C-10. which described the process for submission of operator
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license renewal applications, will be completed in February 1999 according to licensee AR A1168753.
l The inspectors concluded that the inadequate program requirements to ensure attendance at LORT and avoid excessive delays in make up training most likely caused the inaccurate NRC Form 398 to be submitted. Accordingly, the actions contrary to the various requirements noted above are collectively viewed as one violation. (VIO 50-277(278)/98-11 02)
l No further concerns were identified during the reviews of the issues raised by URI 50-277(278)/98-04-01.
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Conclusions L
Three licensed operators failed to successfully complete requalification training during l
the licensee requalification training program which ran from April 1994 through March l
1996. Additionally, as a result of the failure to make up missed training until April 1998, l
one operator license renewal ap@ tion (NRC Form 398), was submitted to the NRC with inaccurate information. The application incorrectly certified that the applicant had met the requirements of the approved requalification program during the effective term of I
the then current license. This was a violation of 10 CFR 55.57(a)(4) and 10 CFR 55.9.
Corrective actions for the missed training and inaccurate NRC Form 398 were adequate.
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i 08-Miscellaneous Operations lasues
- 08.1 (Closed) Violabon (VIO) 50-277(278)i97-08-01 Cold leather Preparations Procedural.
j Non-Comoliance
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a.
Insoection Scone (71707. 92901) -
NRC Inspection Report 50-277(278)/97-08 discussed a number of discrepancies l
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associated with the documentation and performance of wintenzing procedures.- in i
response to the Notice of Violation, dated March 25,1998, PECO attributed the cause of
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the violation to poor procedure compliance. The inspectors reviewed the corrective
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. actions for the procedure compliance ' deficiencies, as implemented in the performance of
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routine tests RT-O-040-620-2, Revision 6, " Outbuilding Heating, Ventilation and Air
. Conditioning (HVAC) and Outer Screen Inspection for Winter Operation," and RT-O-040-630-2, Revision 5, " Winterizing Procedure," in November 1998.
b.
Observations and Findings The inspectors noted that the completed routine ' test procedures were well-documented, and maintenance action requests were initiated for all identified equipment deficiencies.
A spot-check of several components revealed no discrepancies. The inspectors concluded that this violation was closed.
Despite these improvements in procedure compliance, several minor equipment problems occurred during a period of cold weather in early January 1999, including.
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A frozen instrument line for the 3A circulating water pump. ' Operators found that
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the doors to the pump structure did not fully close and had gaps in the
.j weatherstripping. Although the affected instrument line provided only control i
room indication, an adjacent instrument line provided pump trip functions. If frozen, this could lead to a pump trip and subsequent plant transient.
Failed circulating water pump structure roof exhauster dampers, which were not
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shutting as required when the associated fan was off.
Some non-functional reactor building area heaters, discovered after receiving a
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standby liquid control system tank / pipe low temperature alarm.
j A non-functional heating / cooling fan in the E4 emergency diesel generator (EDG)
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room.
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E4 EDG Jacket water low temperature alarm. EDG operability was not affected.
- The inspectors brought these issues to the attention of operations personnel, who reviewed the adequacy of the winterizing procedures as well as their implementation.
Operations management determined that the winterizing procedures needed some minor
improvements and that personnel needed to be more attentive to heating / ventilating system equipment and to components potentially affected by cold weather.
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Conclusions Procedure adherence in the performance of winterizing procedures was improved.
However, weaknesses in station winterizing procedures and personnel attentiveness to j
heating / ventilating system equipment contributed to some minor, cold weather-related equipment problems.
ll. Maintenance i
M1 Conduct of Maintenance M1.1 General Observations
NRC Inspection Procedures 62707 and 61726 were used in the inspection of plant
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maintenance and surveillance activities. The inspectors observed and reviewed selected portions of the following maintenance and test activities:
Flaintenance Observations:
Observed On:
Replace Relay & Verify Operation in RPS, RO 264628 December 14,1998 Replace Relay & Verify Operation in RPS, RO 264066 December 14,1998 Replace Relay & Verify Operation in RPS, RO 264033 December 14,1998 Replace Relay & Verify Operation in RPS, RO 264035 December 14,1998 Investigate & Doble Test Transformer, CO 185854 December 30,1998 Surveillance Observations:
Observed O_0:
RT-O-007-550-2 Containment Gross Leak Rate Detection November 30,1998 S12M-7J-872-BICQ Calibration Check of CAD /CAC Oxygen December 3,1998 and Hydrogen Analyzers and Recorder ST-O-60A-210-3 APRM System Calibration During Two December 8,1998 Loop Operation Sl2A-2-RPS-A1 FQ Functional Test of RPS "A" Card File December 14,1998 ST-O-052-700-2 E1 EDG 24 Hour Endurance Test December 15,1998 RT-O-052-202-2 E2 Diesel Generator Load Run December 31,1998 The work and testing performed during these activities was professional and thorough.
Technicians were experienced and knowledgeable of their assigned tasks. The work and testing procedures were present at the job site and actively used by the technicians and operators for activities observed. Good pre-job briefs were observed poor to the performance of the surveillances observed. System managers were usually present during surveillance tests and provided good technical oversight.
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M4 Maintenance Staff Knowledge and Performance M4.1 Failure to Meet Technical Soecification (TS) Surveillance Recuirements for the Absolute Difference in the Averaoe Power Rance Monitor (APRM) Channels and the Calculated Reactor Power Due to Substitute Feedwater Flow Temperature Correction Factors in the Heat Balance Calculation (Closed) LER 50-277/2-98-007 a.
Inspection Scope (62707 & 37551)
On November 16,1998, station personnel discovered that a technical spec;fication surveillance requirement involving calibration of the APRM channels had not been met during Unit 2 power ascension due to an inaccurate heat balance calculation. The heat balance calculation inaccuracy was due to substitute values installed for feedwater flow temperature correction factors during flow transmitter calibrations. The inspectors reviewed the corrective action documentation and procedures associated with this event.
The inspectors also discussed this event with applicable operations, instrument and control, and engineering personnel.
b.
Observations and Findinos On November 7,1998, operations personnel in the Unit 2 control room observed that the megawatt electric output did not agree with the reactor core thermal power.
Subsequently, reactor engineering personnel discovered that three feedwater flow temperature sabstitute values were installed in the plant monitoring computer system (3D-MONICORE). When the substitute values were removed, reactor thermal power dropped from 98.5% to 92.5% and station personnel recalibrated the APRM channels.
The substitute values were originally installed during reactor feed flow transmitter calibration checks on October 8,1998 and were not removed following the checks.
These correction factors affected the calculated heat balance and resulted in actual core thermal power being less than indicated core thermal power. The errors in the heat balance calculation caused the absolute difference between the APRM channels and the calculated reactor power to be outside of TS surveillance requirements.
Station personnel determined that the primary cause of this event was the failure to properly track and remove the substitute values following completion of the feed flow transmitter calibration checks. The procedures for these checks were changed to ensure that substitute values were removed following calibration. Station personnel also reviewed other procedures that could impact the 3D-MONICORE heat balance calculation and updated them as required to address any generic concerns from this
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l issue. The corrective actions for this issue also addressed training applicable station l
personnel about the causes and corrective actions from this event.
The inspectors performed an on-site review of the LER and PEP associated with this event. The inspectors determined that station personnel took adequate and reasonable corrective actions for this issue.
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Technical Specification Surveillance Requirement (SR) 3.3.1.1.2 requires that the absolute difference between the average power range monitor (APRM) channels and the l
calculated power be less than or equal to 2% reactor thermal power. This SR is applicable 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after operating at greater than or equal to 25% reactor thermal power.
Contrary to the above, from November 4 until November 7,1998, the absolute difference between the (APRM) channels and the calculated power was greater than 2% reactor thermal power with reactor thermal power greater than 25%. This condition occurred because substitute feedwater flow temperature correction values had been left in the plant monitoring system during calibration checks of reactor feed flow transmitters on October 8,1998. These values affected the calculated heat balance and resulted in actual core thermal power being up to six percent less than indicated core thermal power. This non-repetitive, licensee-identified and corrected violation is being treated as an NCV, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV) 50-277/98-11-03 c.
Conclusions Station personnel discovered that a Technical Specification Surveillance Requirement for average power range monitor channel calibration was not met during Unit 2 power ascension due to an inaccurate heat balance calculation. The heat balance calculation inaccuracy was due to substitute values installed by instrument and control and engineering personnel during flow transmitter calibrations. The calculated heat balance values were always conservative from a safety perspective and station personnel took adequate and reasonable corrective actions for this event. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV),
consistent with Section Vll.B.1 of the NRC Enforcement Policy.
M8 Miscellaneous Maintenance issues M8.1 (Closed) VIO 50-277(278)/97-07-02 Three Examples of Procedure Non-Adherence - 3B
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Hioh Pressure Service Water Pumo Maintenance. Station Batterv Startuo. Cooldown Operation NRC Inspection Report 50-277(278)/97-07 identified multiple examples where operations and maintenance personnel failed to properly implemented procedures. The station's corrective actions included:
Adoption of a "back to basics" approach with focus on safety culture, procedure
use and work package use Increased emphasis on the use of the STAR (Stop, Think, Act, Review) principle
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during work performance More formalized pre-job briefs
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The inspectors noted that the back to basics program refocused the way operators and maintenance technicians performed equipment manipulations and worked in the control room and the plant. Self and peer checking by plant personnel have improved procedural and work package adherence. The maintenance organization incorporated a check list into pre-job briefings to improve standardization. The inspectors concluded that these actions have improved the performance of procedure and work package implementation. The inspectors had no additional concems with this violation.
111. Enaineerina E1 Conduct of Engineering t
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E1.1 ISFSI Pad and Retainina Walls a.
Inspection Scope (60851)
This inspection reviewed independent spent fuel storage installation (ISFSI) engineering design and construction activities associated with the storage pad and retaining walls.
b.
Observations and Findinas The inspectors reviewed PECO Energy Calculation No. PS-0959, for the pad where the I
spent fuel casks will be stored. The inspectors verified the geometric accuracy of the l
mathematical model, which used a finite element method. The material properties were l
correctly input in the analysis. PECO used the right seismic ground motion input. Soil l
structure interaction analysis was adequate; the soil beneath has been analyzed to not l
liquefy under the safe shutdown earthquake (SSE) ground motion. Assumptions for the calculation and consideration of variability were good. Also, PECO's reinforcement requirements for the pad were reasonably conservative; reinforcement distribution was uniform and symmetric; consideration of soil and load variations to determine maximum l
moments and shear was good; and the seismic response evaluation was reasonably
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conservative.
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The inspectors reviewed key aspects of PECO calculation PS-0960, regarding the East l
and West retaining walls. The inspectors found that the design for the retaining walls met the pertinent code requirements established in the Design input Document (DID)
ECR No. 98-0081. The proper criticalload combination was applied to the East and l
West walls, and the associated footings. The methodology used to calculate the I
reactions were acceptable, and the results showed adequate design margins. The assumptions for the calculation were conservative. This conservatism resulted in additional margins, which were estimated to be 10%.
c.
Conclusion PECO design calculations for the storage pad, east and west walls, and associated
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footings were prepared in accordance with established design input documents and regulatory guidance. Calculation results met code requirements and were conservative.
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E1.2 Reinforced Concrete Bridae over Rock Run Creek a.
Inspection Scope (60851)
This inspection reviewed key aspects of the analysis and design of the reinforced concrete bridge over Rock Run Creek. To enable the transportation of loaded casks from the power block to the storage pad (ISFSI), a cast-in-place, reinforced concrete bridge was constructed over Rock Run Creek.
b.
Observations and Findinos The inspectors reviewed PECO Nuclear calculation No. PS-0962, regarding the structural analysis of the Rock Run Creek Crossing Bridge and its supporting abutment, including the supporting piles. The analysis of the bridge used a three dimensional space frame computer program model, using a finito element model. The inspectors found the mathematical model to be accurate, the material properties were correctly incorporated into the mathematical model for the finite element analysis, the loads and the load combination were considered in accordance with American Concrete Institute (ACl)-349 with an acceptance criterion established in NUREG-1567.
The maximum shears and bending moments were correctly used in the design of the piles and beams. However, the inspectors noted that the design of the bridge deck was done using load case 16 and not loaded using load case 14 or 15 which were related to cask drops and have maximum moments. The inspectors questioned the rational of this evaluation. PECO Nuclear noted that in the Design input Document (DID), the bridge will be designed to withstand a cask drop load without causing permanent deformation of the bridge betim/ pile system. Also, some damage can be tolerated provided that timely repairs are made to the bridge deck. The inspectors noted that this " tolerable damage" I
to the bridge deck was not quantified. PECO Nuclear performed a calculation using the maximum tending moment corresponding to load case 14. This calculation satisfactority demonstra'.ed that the deck will maintain its structural integrity without any permanent
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deformatian of the rebar. Therefore, the ability of the deck to transfer loads to the beams will be maintained. The inspectors reviewed this calculation and determined that it was acceptable. The thickness of the deck will be increased from 12" to 14" to provide additional protection to the structural members of the bridge.
c.
Conclusion PECO design calculations for the bridge used to transport loaded spent fuel casks, were prepared in accordance with established design input documents and regulatory guidance and were acceptable.
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' Engineering Support of Facilities and Equipment i
E2.1. Reactor Water Cleanuo System Adamatic laa*ns (Unit 2) ~
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Inspection Scone (37551. 71707)
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t The inspectors reviewed two Unit 2 reactor water cleanup (RWCU) system automatic l
engineered safety feature (ESF) isolation events that took place on September 15,1998, l
and on December 1,1998. Both occurred due to high flow signals generated while
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operators were retuming the system to service.
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Observations and Findings On September 15, a RWCU system isolation occurred as reactor operators were
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. opening the RWCU domineralizer bypass valve. Engineers initially determined the l
l cause of the event to be a leaking RWCU dump control valve, CV-2-12-055.
.i Subsequent inspection of CV-2-12-055 and further review by a cross-discipline team led
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to the conclusion that a problem with the sequence of valve operations in the RWCU i
system operating procedure, SO 12.1.A-2, " Reactor Water Cleanup System Startup for
Normal Operations of Reactor Vessel Level Control," caused a flow spike and was a more likely primary cause of this event. Engineers revised this procedure in November
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1998. The team identified a contributing cause to be air entrapment in the differential pressure instrument sensing lines. The inspectors noted that the initial engineering investigation was not sufficiently thorough to recognize the procedure deficiency. The inspectors determined that this procedure deficiency was of minor significance and not subject to formal enforcement action.
On December 1, an RWCU isolation occurred as operators were opening the system inboard and outboard isolation valves. Engineering personnel were continuing to review this event. They were pursuing the following: investigating water hammer effects and air entrapment in instrument sensing lines, installing a temporary modification to determine the magnitude of the pressure / flow spike during opening c f isolation valves, and considering installation of switches or jumpers to tempora >ily bypass the isolation function. The inspectors identified no concems with the progress of this investigation.
c.
Conclusions Two Unit 2 reactor water cleanup system isolation events that occurred on September 15,1998 and on December 1,1998, were not directly related. The licensee's investigation of these events was found to be acceptable.
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Engineering Procedures and Documentation
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- E3.'1 Review of the 1997 Annual Rooort of 10'CFR 50.59 Evmin=+ians i
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Inspection Scope f37001)
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j Revision 15 of the Updated Final Safety Analysis Report (UFSAR).; This review was
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performed to determine if the 10 CFR 50.59 reports involved any unreviewed safety
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questions and verify that the UFSAR had been properly updated.
b.
Observations and Findin9s
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On July 23,1998, PECO submitted its 1997 annual report for Peach Bottom Atomic.
j Power Station, Units 2 and 3, as required by 10 CFR 50.59(b)(2). On May 8,1998,.
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PECO submitted Revision 15 of the UFSAR, pursuant to the requirements of 10 CFR 50.71(e)(4).
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The 1997 report contained descriptions of design changes, and the safety evaluation of
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unreviewed safety questions. The inspectors reviewed a sample of the descriptions
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provided in the 1997 annual report and found that the description of the changes were
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adequate and that the changes did not involve unreviewed safety questions.
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The inspectors also reviewed a sample of summary reports against the May 8,1998 UFSAR update, and found that the changes made pursuant to 10 CFR 50.59 were incorporated as updates to UFSAR.
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Conclusion Changes summarized in the 1997 annual 10 CFR 50.59 report were adequately described to conclude that they did not involve unreviewed safety questions, and the changes were adequately described in the May 8,1998 UFSAR update.
E4 Engineering Staff Knowledge and Performance E4.1 Performance Durino Challenoes to Thermal Limit Marains and APRM Technical
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Specificetion Surveillance Reauirements a.
lnsoection Scoos (37551 & 71707)
The inspectors reviewed the safety significance, causes and corrective actions following
the discovery of a non-conservative thermal limit calculation for fresh fuel in the process computer data bank. The inspectors also reviewed the role of reactor engineering in the
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failure to meet the TS surveillance requirements for the APRM channels following startup j
from the Unit 2 outage. The inspectors observed reactor engineering personnel j
responding to a step increase in thermal limits values on Unit 3 after a Transversing
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incore Probe (TIP) run and update of the local powe: range monitors (LPRMs). All three of these issues and related topics were discussed with reactor engineering.
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Observations and Findinas Non-Conservative Thermal Limit for Maximum Fraction Of Limitina Power Density During preparation for the development of the PBAPS Unit 2 Cycle 13 process computer data bank, PECO engineering discovered a difference between the as-delivered Cycle i
12 data bank and the recent Cycle 12 wrap-up. The difference was in a Control Rod Blade History (CBH) Peaking factor switch. The ficansee found that this condition had existed since October 1996 for Unit 2 and October 1997 for Unit 3.
With the incorrect CBH Peaking Factor model, the treatment of the MFLPD thermal limit for fresh fuel was incorrect in the non-conservative directior.. The licensee determined through a review of past history that no thermal limits had been Oxceeded as a result of this error. The non-conservative MFLPD values were a concem only for unit 3, since this was the or ly unit operating with fresh fuel. Certain individual fresh fuel bunoles in unit 3 showed a 9% non-conservative MFLPD value. Since these particular fresh bundles were more than 9% below the core leading exposed bundle, there was no impact on the overall core leading MFLPD fer Unit 3. The licensee leamed from the vendor that this condition was due to a data b.nk variable being changed automatically by the 3D MONICORE during the install: tion of the data bank. Reactor engineers did not recognize, when the first proc ( ss computer case was run on each unit at the beginning-of-cycle, that the control blade nistory peaking factor switch automatically changed back to the initial value.
Initial corrective actions included administratively limiting MFLPD to 0.97 or less for both units. Subsequently, PECO engineering completed an update to the 3D MONICORE program for each unit to correct the CBH and permanently reset the peaking factor switch. A post-update test was run to verify that the problem had been corrected, and that the software would not reset the peaking factor value.
The inspectors noted that the 3D MONICORE data bank performs no function which would be required to mitigate an accident or transient. The computer program functions only to monitor thermal limits. A 10CFR50.59 safety evaluation concluded that the update to the data bank would not constitute an unreviewed safety question. The inspectors had no concerns with this evaluation.
The inspectors noted that the licensee initiated a PEP to further investigate this problem but that, as of the end of the inspection, this investigation had not been fully completed.
The licensee has determined that a GE information letter regarding the computer program was disseminated to Limerick but not Peach Bottom. Therefore the automatic
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changing of the control blade history peaking factor was not recognized by Peach
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l Failum to Meet Technical Specification Surveillance Reauirements for the Absolute Difference in the APRM Channels and the Calculated Reactor Power As discussed in Section M4.1, station personnel discovered that a TS surveillance requirement involving calibration of the APRM channels had not been met during Unit 2 power ascension due to an inaccurate heat balance cak,ulation. This event was caused by the failure to properly track and remove substitute values that input into the 3D MONICORE heat balance calculation. This resulted in a non-cited violation.
The inspectors noted that a contributing cause for this event was that licensee procedures did not provide for alterr' ate means to verify 3D MONICORE heat balance accuracy. As part of the corrective actions for this event, reactor engineering personnel created a core thermal power monitoring procedure to provide attemate methods to verify the acct. racy of reactor power calibrations.
Unexpected Thermal Limit increase Followina Traversina incore Probe (TIP) 3D MONICORE Update On December 14,1998, l&C technicians performed a TIP run on Unit 3 for the LPRM gain calibration. When the TIP data files were uploaded into the 3D MONICORE computer program for calculation of the thermal limits, the values for Maximum Fraction of Limiting Power Density (MFLPD) increased. The new value wcs 0.983 which was above PECO's administrative limit of 0.980. Prior to the TIP run, the core leading MFLPD value was 0.950. The control room operators informed reactor engineering as required by procedure. Fuel and Services Division and Reactor Engineering personnel began the development of a control rod pattem adjustment to increase thermal limit margin while trending MFLDP. Reactor engineering did not expect the sudden increase in MFLPD as a result of the initial change in the control rod pattem and TIP run and contacted the fuel and 3D MONICORE vendor to determine the possible causes for this increase.
MFLPD continued to increase until it reached 0.992, which was above the 0.990 action level specified in operations procedures. Reactor power was reduced 25 MWth which caused MFLPD to lower to a value of 0.958. Subsequently, operators made a control rod pattem adjustment and continued to monitor thermal limits.
The inspectors observed reactor engineers monitoring thermal limits values and providing guidance for the reduction of reactor power and subsequent control rod pattem adjustments. The inspectors determined that the reactor engineers responded appropriately during these evolutions. Based on review of the transient parameters, the inspectors determined that no technical specification limits were violated. The inspectors
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noted that station administrative procedural guidance provided margin to ensure these thermal limit requirements were not exceeded.
Reactor engineering planned to provide procedural guidance to prevent the sequences that could lead to sudden MFLPD increases. They were also investigating other possible corrective actions to prevent this condition.
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Conclusions Three reactor core thermal management problems occuned during this inspection period.
related to the 3D MONICORE program. Two problems were related to configuration management of input data to the program and one was related to unexpected program
. results. The licensee investigated these problems and took appropriate initial actions and developed appropriate corrective schons. No thermallimits were exceeded as a result of these problems.
E8 Miscellaneous Engineering issues E8.1 (Closed) URI 50-277(278V96-06-02 Station Blackout (SBO) Line Review On July 9,1996,' members of the Nuclear Reactor Regulation (NRR) staff reviewed the implementation of PECO's commitment to 10 CFR 50.63 " Station Blackout." 'The NRR inspectors toured the Conowingo Hydroelectric Station, which is the generation source for the Peach Bottom SBO line. The inspectors were concerned that at times no
' Conowingo hydro units, that could supply the SBO line, were generating power or being used as electrical condensers (spinning reserve). The inspectors questioned how reliability of the line was monitored since there were times when no units were operating or spinning. The inspectors were also concemed that a wooden utility pole was used at the Susquehanna Substation where the SBO line leaves the breaker and goes underground. The inspectors questioned how the use of a wooden pole was consistent with the stated design criteria for wer.ther-related events.
The licensee informed the inspectors that during a station bladout, Peach Bottv'1 would be started f;om a " black start" since the Conowingo generating units and condensing units trip when a blackout occurs. The station has shown that the SBO line can be manually connected to supply the startup bus in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> which meets the SBO commitment requirements. Therefore, hydro units were not required to be operating or on spinning reserve at all times. Also, the SBO equipment, from the buses at Conowingo to the Peach Bottom switchgear, were included in the 10 CFR 50.65 " Maintenance Rule" program. The reliability of this equipment is monitored through the maintenance rule.
The inspectors determined that this met the SBO rule criteria and addressed this concem.
The licensee notified the inspectors that the severe weather assumptions made in the original design of the wooden 'atility pole were bounded by the most likely weather-related events. Therefore, the inspectors determined that the pole met the requirements as stated in the original desigr of the SBO line and met the SBO rule. The inspectors had no additional concems witq this issu,
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IV. Plant Suonort
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R1 Radiation Protection and Chemistry Controls (RP&C)
l R1.1 Locked Hioh Radiation Doors and Postina insoections Durina Plant Tours i
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Inspection Scope (71750)
The inspectors toured the Unit 2 and 3 turbine and reactor buildings during the j
inspection period and verified that high radiation doors were properly posted and Iceked, i
if required.
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Observations and Findinas
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The inspectors tested approximately 25 high radiation doors that were required to be j
locked. The inspectors also observed numerous radiological postings throughout the
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Unit 2 and 3 turbine and reactor buildings. All high radiation doors required to be locked
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were found locked. No deficiencies were noted with the radiological postings. All locked high radiation doors tested and postings observed met the requirements of Technical Specification 5.7. No concems were identified by the inspectors.
c.
Conclusions Locked high radiation doors and postings in the Unit 2 and 3 turbine and reactor buildings, observed during this inspection period, were adequately maintained per technical specification and plant administrative requirements.
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R4 Staff Knowledge and Performance in RP&C R4.1 Radiation Protection Controls Durina Hiah Radiation Work Activities a.
Inspection Scope (71750)
The inspectors observed Iadiation protection controls during removal and hydrolyzing of control rod blade components in the Unit 3 spent fuol pool and replacement of a Unit 2 i
traversing incore probe (TIP). The inspectors also reviewed the applicable radiation
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control planning and As-Low-As-Reasonably-Achievable (ALARA) awareness at the job site.
b.
Observations and Findinas The inspectors observed the performance of radiation protection personnel during the Unit 3 spent fuel pool work and replacement of the Unit 2 TIP. Radiation protection personnel wore actively overseeing these activities and monitoring worker dose using a remote moniter. Tbs inspectors observed good awareness of ALARA during these jobs and effective planning, which resulted in low doses for these activitie n
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Radiation protection personnel provided very good oversight of control rod blade component removal from the Unit 3 spent fuel pool and replacement of a Unit 2 -
. traversing incore probe. Good awareness for As-Low-As-Reasonably-Achievable (ALARA) by personnelinvolved with this work, and effective planning and monitoring by radiation protection personnel resulted in low doses for these activities.
S2-Status of Security Facilities and Equipment S2.1 General Intearity of Protected Area (PA) Barriers and Inspection of Central Alarm Statian -
(CAS) and Secondary Alarm Station (SAS)
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Inspection Scope (71750)
The inspectors toured the site perimeter to observe the condition of the PA barriers and the isolation zones around the PA barriers. The inspectors also toured the Central Alarm Station (CAS) and the Secondary Alarm Station (SAS) to verify that the site was maintaining the appropriate alarm, surveillance, and communication capabilities and that no activities in the CAS would interfere with the execution of the detection, assessment and response function.
b.
Observations and Findinos The inspectors observed that the protected ama barrier had no openings and was not
- 1 damaged or degraded and appropriately maintained. The barrier did not show any sign of erosion at the base and there were no substantial rock debris accumulations against any of the fences. The isolation zones were free of objects and permitted observation by CAS and SAS operators.
The CAS and SAS alarm, surveillance, and communication capabilities were being appropriately maintained and no activities in these areas interfered with the execution of the detection, assessment or response functions.
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Conclusions i
The licensee had appropriately maintained the barriers and isolation zones around the l
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protected area. Security equipment in the Central Alarm Station and Secondary Alarm Station areas were functioning properly. Activities in these areas would not have interfered with the execution of the detection, assessment or response functions.
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V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the results of the inspection to members of licensee management on January 8,1999. The licensee acknowledged the findings presented.
No proprietary information was identified by the licensee.
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ATTACHMENT 1 i
LIST OF ACRONYMS USED i
AO abnormal operating.
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' APRM.
Average Power Range Monitor
AR action request
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'BTP Branch Technical Position -
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CAS Central Alarm Station
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CBH.
control rod blade history i
CM-Corrective Maintenance -
l CRD Control Rod Drive CS'
DID Design input Document i
DOT Department of Transportation
ECR Engineering Change Request'
i EDG Emergency Diesel Generator i
ESF Engineered Safety Feature
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FCR Field Change Request
'i FIN Fix-It-Now-FLLLP Fraction of Limiting Load Line Power i
O GP general procedure
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. independent spent fuel storage installation ITS Improved Technical Specifications i
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LCO limiting condition for operation LER licensee event report -
I LOCA.
loss of coolant accident LORT Licensed operator requalification training LPRM Local Power Range Monitor LSRO Limited Senior Reactor Operator MCRD Main Control Room Deficiency MFLPD Maximum Fraction of Limiting Power Density
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MOV motor operated valve
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NCV non-cited violation NOTICE
. notice of violation PBAPS Peach Bottom Atomic Power Station PECO.
PECO Energy-PECON PECO Nuclear PEP performance enhancement program PDR public document room
'PMT Post-Maintenance Testing
.RO Reactor Operator RP radiation protection
' RPM radiation protection manager RWCU reactor water cleanup RHR residual heat removal-RT Routine Test i
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RWM Rod Worth Minimizer-SAS Secondary Alarm Station
SBO Station Blackout
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SR Surveillance Requirement SSE Safe Shutdown Earthquake i
ST surveillance Test i
TS technical specification
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TSA technical specification action
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UFSAR updated final safety analysis report l
URI Unresolved item j
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Attachment 1
INSPECTION PROCEDURES USED
IP 37001 10 CFR 50.59 Safety Evaluation Program IP 37551 Onsite Engineering Observations IP 60851 Design Control of IFSFl Components
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IP 61726 Surveillance Observations l
IP 62707 Maintenance Observations I
IP 71001 Licensed Operator Requalification Program Evaluation
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IP 71707 Plant Operations
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IP 71750 Plant Support Observations IP 92903 Followup - Engineering i
ITEMS OPENED, CLOSED, AND DISCUSSED
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9P.911
None
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Opened / Closed
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50-277/98-11-01 NCV Loss of Off-site Power Source and 2SU Bus Trip Due to Electrical
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Bus Switching to Support Planned Breaker Maintenance (Section O3.1)
50-277/98-11-02 VIO Failure of Certain Licensed Operators to Complete Requalification Training and inaccurate License Renewal Application Submitted to i
l the NRC (Section 05.1)
50-278/98-11-02 VIO Failure of Certain Licensed Operators to Complete Requalification
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Training and Inaccurate License Renewal Application Submitted to the NRC (Section O5.1)
50-277/98-11-03 NCV Failure to Meet Technical Specification Surveillance Requirements for the Absolute Difference in the Average Power Range Monitor Channels and the Calculated Reactor Power (Section M4.1)
Closed 50-277/2-98-007 LER Failure to Meet Technical Specification and Associated LCO
Requirements of the Absolute Difference in Average Power Range
Monitor and Calculated Power of Less Than or Equal to 2 Percent (Section M4.1)
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50-277/2-98-008 LER Loss of Off-site Power Source and 2SU Bus Trip Due to Electrical Bus Switching to Support Planned Breaker Maintenance (Section j
03.1)
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Attachment 1
'50-277/98-04-01 URI Failure of Certain Licensed Operators to Complete Requalification Training (Section O5.1) -
50-278/98-04-01 URI ' Failure of Certain Licensed Operators to Complete Requalification Training (Section 05.1)
50-277/96-06-02 URI
. Station Blackout Line Review (Section E8.1)
50-278/96-06-02 URI - Station Blackout Line Review (Section E8.1)
i 50-277/97-08-01
- VIO Cold Weather Preparations Procedural Non-Compliance
(Section 08.1)
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50-278/97-08-01 VIO. Cold Weather Preparations Procedural Non-Compliance
(Section O8.1).
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50-277/97-07-02 VIO Three Examples of Procedure Non-Adherence - 3B High Pressure i
Service Water Pump Maintenance, Station Battery Startup, Cooldown Operation (Section M8.1)
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r 50-278/97-07-02
- VIO Three Examples of Procedure Non-Adherence - 3B High Pressure
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Service Water Pump Maintenance, Station Battery Startup,
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Cooldown Operation (Section M8.1)
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Attachment 2
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SYNOPSIS - NRC OFFICE OF INVESTIGATIONS REPORT NO.1-98-020 l
On April 24,1998, the NRC Office of Investigations (01) Region 1(RI), initiated an investigation
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regarding an allegation that four Peach Bottom Atomic Power Station (PBAPS), NRC licensed operators had not attended all required training, including makeup training, and therefore, did
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not complete the PBAPS Licensed Operator Requalification Training (LORT) program during the
April 1994, to April 1996, Mo-year cycle, as required by NRC regulations. ~ it was fuither alleged that licensed operator applicant Personal Qualification Statements (NRC Form 398s) submitted by the licensee for two of those individuals, are inaccurate, based on their failure to complete LORT.
l Based on the evidence developed during the investigations, Ol:RI concludes that thrt.3 of the licensed operators did not attend all of the requalification training, and, thus, did not conglete
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l the LORT program, in violation of NRC regulations. It could not be substantiated that the
. licensed operators deliberately failed to complete the LORT program, or that the facility f,censee j
(PBAPS) deliberately violated NRC regulations regarding LORT. Also, based on the faure to complete the LORT, it is concluded that one 398 is inaccurate, but it could not be subs'antiated I
that the 398 was deliberately and knowingly made false when it was sent to the NRC.
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