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Insp Repts 50-277/97-08 & 50-278/97-08 on 971123-980117. Violations Noted.Major Areas Inspected:Plant Operations, Maint,Engineering & Plant Support
	ML20203E370
Person / Time
Site:	Peach Bottom
Issue date:	02/20/1998
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20203E339	List: ML20203E332; ML20203E360; ML20203E370;
References
	50-277-97-08, 50-277-97-8, 50-278-97-08, 50-278-97-8, NUDOCS 9802270033
	Download: ML20203E370 (51)
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4-U. S. NUCLEAR REGULATORY COMMISSION

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REGION I

Docket No ,50 278 License No DPR 44, DPR 56

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Report No i

! Licensee: PECO Energy Comp.any

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Facility: Peach Bottom Atomic Pov<er Station Units 2 and 3 i

Dates: November 23,1S97 to January 17,1938

- Inspectors: A. C. McMurtray, Senior Resident inspector M. J. Buckley, Resident inspector B. D. Welling, Resident inspector R. S. Barkley, Project Engineer J. C. Jang, Senior Radiation Specialist L. L. Eckert, Radiation Specialist G. C. Smith, Senior Security Specialist -

P. R. Frechette, Security Specialist J. F. Williams, NRR Project Manager >

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9802270033 990220 gDR ADOCK 05000277 PDR ,

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EXECUTIVE SUMMARY Peach Bottom Atomic Power Station NRC Inspection Report 50 277/97-08,50-278/97 08 This integrated inspection report includes aspects of licensee operations; surveillance and maintenance; engineering and technical support; and plant support area Plant Ooerat!gns:

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Licensee management decided to shutdown Unit 3 and replace the 'E' safety relief l valve (SRV) after observing a continuing upward trend in the tailpipe temperatur Management also chose to shutdown Unit 2 to perform electro-hydraulic control (EHC) pressure regulator work. These decisions showed good, conservative, operational decision making. Operator performance during these shutdown and startup evolutions was very good. (Sections 01.2 and 2.1)

Station preparations for cold weather weie performed adequately. However, the l inspectors identified a number of discrepancies associated with the documentation and performance of the winterizing routine test procedures, which reflected lapses l in formality and attention to detail. The failure of operations personnel to adhere !

with the requiremants in the test procedures resulted in a violation for procedural non compliance. (Section 02.3)

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Operator performance during two plant transients caused by circulating water system problems was satisfactory. The second transient was initiated by the failure -

of the 2 'C' circulating water pump discharge vaive. PECO's investigations into i both events were in progress at the end of this inspection period. The inspectors will review the results of these investigations for maintenance performance issue (Section O2.4)

On January 2,1998, the unit 2 reactor operator failed to perform the technical

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specification (TS) surveillance requirements (SRs) for verification of proper flow in the recirculation loops. The recirculation loops were not operated outside of the TS requirements during this period. However, it was unclear how station personnel determined that the formal TS SRs were met and why operations personnel failed to review the TSs when unclear information was found in the surveillance test. This issue remains en Unresolved item (URI) pending additional discussion with operations personnel and final review by the licensee. (Section 03.1)

During clearance restoration for the diesel driven fire pump, the motor driven fire pump unexpectedly started. The clearance did not contain any cautions regarding the potential for a sudden drop in system pressure to automatically start the motor driven pump and operations personnel performing the clearance removal were not fully aware of this system condition. (Section O3.2)

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On January 1,1998, the Unit 2 main turbine tripped on main oil pump low pressure during plant start-up after the turbine rolled to a speed of 1400 RPM. Operations ii i

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Executive Summary Con personnel were unaware that the turbine had been rolling for over two hours just prior to the trip. This issue appeared to involve a f ailure of an instrument and control test document to restore the original EHC system alignment af ter testing and the f ailure of operations personnel to fully fobow procedures. Concerns were also identified with the pulling of control rods to increase reactor pressure during this event and the failure of operations personnel to recognize the status of the main turbine or turbine control systems. This issue remains a URI pending additional reviews of the procedures used during this event, review of strip charts and recorded data from this event, and further discussions with reactor engineering and operations personnel. (Section 04.1)

On January 7,1998, Unit 2 control room personnel entered an operational transient procedure when a main steam line high radiation alarm was received twice during power ascension. Concerns were identified with the operators incomplete knowledge of the effects of the hydrogen addition system on main steam line radiation during startups and abnormal reactor feedwater alignments. Also, the procedure did not contain instructions to lower the hydrogen addition during this transient. (Section 04.2)

The inspectors found that a standby liquid control pump discharge valve was in the correct pos' tion, but was not locked, as specified by a clearance restoration for Although of minimal safety impact, this and a second improperly locked valve discovered by the licensee indicated that operators were not always rigorous in independently verifying the condition of locked valves. Corrective actions for this issue were good and included verification of alllocked valves in both units. This issue resulted in a Non-Cited Violation (NCV) for procedural non-complianc (Section 04.3)

M.e intenance:

Af ter the Limerick Generating Station discovered a reactor core isolation cooling

'RCIC) inboard steam velve with the wiring to the thermal overload bypass contact lif ted, the station tested several motor operated valves looking for this conditio This testing was proactive and showed conservative decision making. Technicians performing the testing displayed good adherence to procedures. (Section M1.3)

The station missed an opportunity to plan for the removal of foreign materialin the 2 'C' residual heat removal system heat exchanger. This material, which included metal straps and an extension cord, was first identified in 1994 and had not been tracked for removal during subsequent maintenance periods. Technicians were surprised when they found this material during maintenance activities in January 1998. (Section M2.2)

The station and the NRC identified instances where operations were not informed of degraded conditions on safety related equipment in a timely manner. Although iii

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Executive Summary Con some items were mincr, one involved an RHR system valve that was declared inoperable af ter operations became aware of this degraded valve. (Section M3.1)

On January 4,1998, main steam line bypass valve, BPV 1, unexpectedly opened approximately 25% several times while the Unit 2 reactor operator was raising

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reactor power from 96% to 100%. Instrument and control technicians unknowingly introduced a speed error bias in the speed control portion of the EHC system after

! they tightened a loose connection during replacement activities for the EHC pressure control unit. Instrument and control personnel f ailed to understand what effect tightening the loose connection on the speed control would have on the speed bias signal and the EHC system. (Section M4.1)

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On December 29,1997, all nine bypass valves unexpectedly opened at 155 psig EHC pressure curing the normal depretsurization/cooldown of Unit 2. Operations and engineering personnel failed to understand the effect on the EHC system of a temporary plant alteration which was designed to fail the 'B' EHC pressure regulator and allow replacement of the secondary pressure amplifier card. This lack of system understanding contributed to all the bypass valves unexpectedly opening which resulted in a reactor vessel level transient. (Section E2.1)

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During scheduled maintenance, PECO maintenance personnel identified a broken vlutch gear and found a motor brake installed to a Unit 2 residual heat removal valve motor operator. This motor break was to have been removed per an

, engineering modification in 1988. The broken clutch gear was replaced and the motor brake was removed. The valve was never rendered inoperable due to the installed motor brake. The inspectors will follow-up on the inspections for motor brakes on other valve operators and the results of the failure analyses of the clutch gear. (Section E2.2)

Plant Support:

Security facilities and equipment were determined to be well maintained and reliable. Security procedures were being properly implemented. Security staff knowledge, performance and training were determined to be acceptable. Security <

organization, administration and quality assurance programs were adequate to ensure effective implen;3ntation of the program. A review of the vehicle barrier system determined the system was installed and being maintained in accoro, me with applicable regulatory guidance and requirements. (Sections S1 through S8)

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. TABLE OF CONTENTS EXEC UTIVE S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Summary of Plant Status ............................................1 1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 General Comments .................................1 01.2 Unit 3 Plant Shutdown to Replace 'E' Safety Relief Valve . . . . . . . 2 O2 Operational Status of Facilities and Equipment ................... 3 02.1 St.utdown of Unit 2 Due to Problems with the Electro-Hydraulic Control (EHC) System Pressure Reg.:tator control . . . . . . . . . . . . 3 02.2 2 'B' Recirculation Pomp Speed Control Problems . . . . . . . . . . . . 4 O2.3 Cold Weather Preparations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 O 2.4 Circulating Water System Problems (Unit 2) . . . . . . . . . . . . . . . . 7 03 OperaCons Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . 8 03.1 Missed Technical Specification (TS) Surveillance Requirement (SR)

Test for Verification of Proper Flow in the Recirculation Loops . . . 8 03.2 Unexpected Start of the Motor Driven Fire Pump During Clearance Removal for the Diesel Driven Fire Pump .. .............. 10 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . 11 04.1 Unexpected Trip of Unit 2 Main Turbirie During Start-up . . . . . . . 11 04.2 Unit 2 Main Steam Line High Radiation Alarms During Power A s c e n si o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 04.3 Standby Liquid Control Pump Clearance Restoration ......... 14 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 07.1 Plant Operations Review Committee (PORC) Meeting . . . . . . . . . 16 11. Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 M1 Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . 16 M 1.1 Standby Liquid Control Pump Maintenance . . . . . . . . . . . . . . . . 16 M 2 Unit 3 Primary Containment Local Leakage Rate Testing (LLRT)

Review ........................................17 M1.3 Motor Operated Valve ThermalI'mit Bypass Operability . . . . . . . 17 M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . 18 M2.1 Standby Liquid Cor' trol Pump Crankcase Oil Viscosity ........ 18 M2.2 Foreign Material in 2 'C' Residual Heat Removal System Heat E:: c h a n g e r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 9 M3 Mainten nce Procedures and Documentation . . . . . . . . . . . . . . . . . . . 20 M3.1 Equipment Condition Notification to Operations . . . . . . . . . . . . . 20 M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . 21 M4.1 Unit 2 EHC Speed Error Signal Bias Due to Repair of Speed Control i Card Short ... ..................................21 l

111. E n g in e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 E1.1 Unit 3 Jet Pump Riser Elbow Weld Cracking . . . . . . . . . . . . . . . 23 E2 Engineering Support of Facilities and Equipment .................24 E Inadvertent Operation of Bypass Valves During Unit 2 Shutdown . 24 E2.2 2 'C' Residual Heat Removal (RHR) Pump Suction to Torus Valve Motor Operator Deficiencies .........................25 l

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Tcbla of Contants (cont'd)

E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 E (Closed) URI 50 277(278)/96-04-04: Emergency Diesel Generator (EDG) Output Breaker Response During Testing . . . . . . . . . . . . . . 26 IV. Pl a nt Su pport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 7

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R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 27 ,

R1.1 Implementation of the Radioactive Liquid and Gaseous Effluent l

ControI Programs ........................ ........27

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R2 Status of Radiological Protection and Chemistry Facilities and Equinment i

...................................................28 R2.1 Calibration of Effluent / Process Radiction Monitoring Systems (RMS) l

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, R2.2 Surveillance Tests for Air Cleaning and Ventilation Systems . . . . 29

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R2 Radiological Protection er.d Chemistry Procedures and Documentation . . 30 R7 Quality Assurance (QA) in Radiological Protection and Chemistry Activities

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...................................................30 R8 Miscellaneous Radiological Pratection and Chemistry issues . . . . . . . . . 31 R8.1 Unreviewed Safety Question Review and Radioactive Effluents Control (VIO 50-27 8/97-03 01 ) . . . . . . . . . . . . . . . . . . . . . . . . 31

, R8.2 Tour of Peach Bottom Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 32

S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 32

! S2 Status of Security Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . 33 S3 Security and Safeguards Procedures and Documentation . . . . . . . . . . . 34 S4 Security and Safeguards Staff Knowledge and Performance . . . . . . . . . 34 S5 Security and Safeguards Staff Training and Qualifications .......... 35

S6 Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 35 S7 Quality Assurance in Security and Safeguards Activities ......., .. 36 S8 Miscellaneous Security and Safety Issues . . . . . . . . . . . . . . . . . . . . . . 37 S8.1 Vehicle Barrier System (VBS) (Tl 2515/132) . . . . . . . . . . . . . . . 37 S8.2 Vehicle Barrier System (VBS) .........................38 l S8.3 Bom b Blast Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 8 S8A Procedural Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 S8.5 Security Force Strike Contingency Plans . . . . . . . . . . . . . . . . . . 39 F1 Control of Fire Protection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 40 F1.1 Fire in the 2 'C' Service Air Compressor . . . . . . . . . . . . . . . . . . 40 V. Management Meetings ..........................................41 X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

X2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments . 41 LIST O F ACRONYMS US ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 2 IN FPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . 44 i

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e Report Details Summarv of Plant Statgg PECO Energy operated both units safely over the period of this repor Unit 2 began the period operating at 100% power. On December 29,1997, the unit was shutdown to perform repairs on the main turbine electro-hydraulic control (EHC) syste The unit returned to power operations on January 3,1998 and on January 4 was only able to reach 96% power due to a speed error bias s!gnalin the EHC control system. On January 6, Unit 2 power was reduced to 90% when condenser vacuum decreased following a trip of the 2 'C' circulating water pump. The unit returned to 100% power on January 9 following adjustments to the speed error bias. On January 14, power was reduced to 97% when condenser vacuum decreased after the 2 'C' circulatirig water pump failed to start and the pump discharge valve failed open during post-maintenance testin Power was increased to 100% on January 16 following evaluation of the 2 'C' circulating water pump discharge valve failure and monitoring of Unit 2 condenser vacuu Unit 3 began the period operating at 93% power. The unit was operating at less than full power due to recirculation system flow rate limitations because of weld cracks on the jet pump risers. On November 28,1997, the unit was shutdown to replace the 'E' steam relief valve. The unit returned to power operations on December 1 and reached 93%

power on December 5 following relief valve replacement. The unit remained at about 94%

power for the remainder of the period, with the exception of load drops on December 7, 10, and 11, to troubleshoot t.ad repair a minor tube leak on the 3 'B' condenser waterbo . Operations 01 Conduct of Operations'

01.1 General Comments (71707)

Ove all, operators responded well to the various load changes and shutdowns on Units 2 and 3 throughout the period. The inspectors observed good communications during load change evolutions and very good response to control board alarms received. Generally, good command and control was observed during these shutdowns and load adjustments. The inspectors observed very good reactivity control during rod manipulations for Unit 2 and Unit 3 during shutdowns and scheduled load swings. However, the inspectors also observed minimal i supervisory oversight of the reactor operators during a recirculation pump speed l change on Unit 2. The inspectors observed that the shift supervisor was involved in several other activities unrelated to Unit 2 during this reactivity evolutio The inspectors noted several instances during the period where the operators knowledge of plant systems performance was inadequate and the procedures being 1 Tomcal headings such as 01, M8. etc.. are used in accordance with the Nf4C standardited reactor inspection report outline. Indivktual reporta are not supected to address all outilne topics.

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used did not provide detailed guidance for the evolution being performed. These unexpected events involved the start of the motor driven fire pump, trip of the Unit 2 main turbine, and Unit 2 main steam high radiation alarms are discussed in Sections 03.2,04.1, and 04.2, respectivel In addition, the inspectors identified that operations personnel failed to monitor the temperature of the Unit 2 Condensate Storage Tank (CST) after the CST low temperature alarm annunciated in the control room and was identified as not working properly. Operations personnelinitially checked the CST tank and verified that the tank was warm to the touch and that heating to the CST appeared to be working. However, continued monitoring of this CST was not required after this initial check. Outside temperature surrounding the CST was below freez;ng for several nights prior to the inspectors raising this concer .2 Unit 3 Plant Shutdown to Reolace 'E' Safety Relief Valve Insoection Scone (71707)

The inspectors observed portions of the plant shutdown and startup evolutions for the replacement of the Unit 3 'E' safety relief valve (SRV). Observations and Findinas N3C Inspection Report 50 277(28)/97-07 discussed station response and monitoring following the identification of a high temperature on the 'E' SRV tailpip PECO took conservative action to shutdown Unit 3 on November 28,1997 in order to replace the SRV, based on an increasing temperature trend, inspections of the removed SRV indicated :het some leakage had occurred at the secondary stage dis The inspectors observed selected portions of the shutdown and stcrtup evolutions on November 28 and December 1. Operator actions during reactivity manipulations were deliberate and controlled. Overall, command and control and management oversight were also very good, Conclusions PECO management took appropriate, conservative action to shutdown Unit 3 and replace the 'E' SRV after observing a continuing upward trend in the tailpipe tempera'ure. Operator performance during the shutdown and startup evolutions was ver/ goo _ _ _ - - - - -.. . . . -

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02 Operational Status of Facilities and Equipment 02.1 Shutdown of Unit 2 Due to Problems with the Electro-Hydraulic Control (EHC)

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System Pressure Reaulator Control Insoection Scope (71707 & 37551)

On December 29, Unit 2 was shutdown to replace the secondary pressure amplifier

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card and the potentiometer assemblies on the pressure control unit for the 'B' EHC regulator. Several other forced outage repairs were made to Unit 2 equipment, includir.g repairing the externalleakage from the reactor feedwater check valve, CHK 2 06-28B. This leakage was a main contrhutor to the drywell sump inleakage.

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EHC system. Challenges from fillow up actions from this inspection are discussed in Section M4.1.

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The inspectors observed portions of the plant shutdown and startup and reviewed

the safety evaluation and the temporary plant alteration (TPA) associated with the EHC pressure regulator control.

J Observations and Findinas On December 23,1997, plant management chose to shut down Unit 2 due to problems with the pressure iegulatcr control circuit. On Decembe 15, the back up EHC pressure regulator 'B' took control of reactor pressure without operator actio Subsequent troubleshooting activities revealed that the 'B' pressure regulator secondary pressure amplifier card operated erratically. These troubleshooting activities also showed noise in the input from the pressure control unit motor-operated potentiometer assemblies indicating degradation. The licensee issued Performance Enhancement Program (PEPS) numbers 1000771 and ;0007838 to analyze this issue and the December 15 reactivity management event.

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On December 20, a TPA was performed per Engineering Change Request (ECR) PB

, 97 03475, Revisions 000 and 001. This TPA adjusted the pressure control unit

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potentiometer so that the primary 'A' pressure regulator controlled pressure and failed the 'B' normal / failure switch to the failed position. This action removed the f 'B' pressure regulator from service to prevent inadvertent swapping between regulators. This TPA was also written to allow replacement of the secondary pressure amplifier card at power. A plant transient occurred during the shutdown of Unit 2 because this TPA was instulad The transient is discussed in Section E A safety evaluation was written to support continued operation of Unit 2 with only the 'A' pressore regulator in service. This safety evaluation addressed the issue

raised by the General Electric Services Information Letter (SIL) No. 614, " Backup i Pressure Regulator" regarding the potential of being in an unanalyzed condition when a BWR was operated without a back up pressure regulator. The inspectors reviewed this safety evaluation and did not identify any safety concerns.

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On December 29, Unit 2 was shutdown to replace the amplifier card and the potentiometer assemblies. Several other forced outage repairs were made to Unit 2 equipment, including repairing the externalleakage from the reactor feedwater check valve, CHK 2 06 288. This leakage was a rr' in contributor to the drywell sump i.eloakage. instrument and control technician:, also inspected other subsystems of the EHC system. Challenges from follow up actions from this inspection are discussed in Section M The inspectors noted that the decision to replace the pressure regulator, motor-driven, potentiometer assemblies and secondary pressure amplifier card of f line instead of at power precluded the possibility of a plant translent due to EHC system problems during replacement work. Also, the inspectors noted that the shutdown allowed repair of CHK 2-06 288. The inspectors observed good control room performance during the plant shutdown and start u Conclusions The inspectors concluded that the licensee's decision to remove Unit 2 from service to perform the EHC pressure regulator work showed conservative operational decision making. The inspectors also viewed the other repairs performed while the unit was off line as positiv .2 2 'B' Recirculation Pumn Speed Control Problems Insnection Scope (71707)

On January 10,1998, operators observed that the 2 'B' recirculation pump speed and Unit 2 reactor power increased slightly w;thout operator action. The inspectors reviewed operations and engineering staff response to speed control problems with the 2 'B' recirculation pump.

I Qbfsrs ations and Findinas Operatort c.ntered off-normal procedures and initiated a PEP report due to the unexpected reactivity addition when the recirculation pump speed increase Operators had seen smaller magnitude speed changes on the 2 'B' recirculation pump earlier this year. Monitoring equipment had been installed on the pump motor i generator sets to allow for engineering review of this phenomenon. The previous I occurrences had been documented on an action request (AR).

l Engineering attributed the speed increase to excessive play in the motor generator set speed controllinkage. This condition led to unexpected speed changes in the dW aon of the last change. This condition occurred several hours after a

.culation pump speed was adjusted, ant management and operators were aware of the issue, however, some operators acre not fully knowledgeable or sensitive to the delayed nature of this reactivity addition phenomenon. The inspectors noted that:

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This was an operationally significant issue, however, operators were not 4 tracking this on the equipment deficiency list (for operationally significant items) in the control roo * Engineering and operat:ons did not include this on the material condition focus list to ensure management attention on resolution of the issu * Some operators recognized this as a workaround, however, this issus was not identified as an operator workaround (OWA) during a recent initiative to document all m;nor OWA As interim corrective action for this condition, engineering initiated a temporary change to plant procedures to direct operators to turn the controller knob slightly in the opposite direction af ter making a speed change. This was intended to reduce the potential for the linkage clearanco/ play to cause speed drifting. Engineering e recognized that this was a workaround and was considering options for further repairs or replacement of linkage components. At the end of the inspection period, operations management was still reviewing this issue for possible corrective action The inspectors found that operators responded appropriately after recognizing the minor reactivity addition. While this condition did not lead to a significant reactivity occurrence, it did reveal a continued lack of formality in tracking degraded conditions of low to moderate significanc The inspectors slso noted that although the speed drift problem was first documented in April 1997 and had occurred at least three additional times, neither operations or engineer!ng management had aggressively pursued the resolution of this reactivity management issue. This was evidenced by the lack of inclusion in the material condition focus list and the fact that it was not fullv * nsidered for corrective maintenance or troubleshooting during the Unit 2 forceo outage in December 199 Conclusions Operators responded appropriately to an unexpected speed increase on the 2 'B'

recirculation pump and resultant increase in reactor power. However, this event revealed continued weaknesses in operations tracking and understanding of some degraded conditions as noted in Section M3.1 of this report and Inspection Report 50 277(278) 97-07. Additionally, operations and engineering management had not pursued resolution or troubleshooting efforts consistent with similar reactivity management or potential transient initiator issue ., .- - .__ _

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02.3 .Q.pid Weather Preparations Insoection Scoce (71714)

The inspectors reviewed station preparations for cold weather. The following routine test procedures were reviewed: RT O 040 620 2, Revision 4, " Outbuilding HVAC and Outer Screen inspection for Winter Operation," and RT 0 040 630 2, Revision 4, " Winterizing Procedure."

. Observations and Findinas The licensee performed the cold weather preparation's routine test procedures in early October. The tasks covered by the procedures included such items as placing steam heating systems in service, energizing electric heaters, and shutting air supply louver During the review of '.he completed procedures, the inspectors identified some discrepancies:

Operators made a number of changes to the procedures in an informal manner. For example, operators noted that several thermostats could not be set to the temperature specified in the procedure, but they did not initiate a temporary procedure change, contrary to instructions on temporary procedure changes. Instead, operators initiated procedure enhancement forms after completing the routine test *

No corrective actions were taken for a few deficiencies. For example, some switchgear building air filters were found to be dirty and were marked as unsatisfactory, but no action request (AR) was generated to correct this condition. Other examples involved heaters that did not energize, but the reasons and/or corrective actions were not fully documente The inspectors walked down selected ereas of the site and verified that the procedures were substantially completed. However, during this spot check, the inspectors observed the followlag discrepancies:

Some river outer screen structure heaters (3) were not energize Maintenance was performed on one of the heaters, but it wt.s not restored to the energized position, as specified by the winterizing procedur * Three outer screen structure doors were not fully close * Some outer screen structure door gaskets were damaged or missin * Emergency service water booster pump /Cardox building cubicle louvers were open, allowing cold air to be blown directly into the buildin The inspectors discussed these findings with members of the operations staf Procedure changes were initiated and operators were directed to re-perform portions of the routine test procedure. Operations management acknowledged that the

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completion of those procedures did not meet department expectations for formality and attention to detai The failure of operations personnel to adhere to the routine test procedures for cold weather preparations was a violation of technical specification (TS) 5. Technical specification 5.4.1 requires, in part, that written procedures are implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. (VIO 50 277(278)/97 08 01) Conclusions Station preparations for cold weather were performed adequately. However, the inspectors identified a number of discrepancies associated with the documentation and performance of the winterizing routine test procedures that reflected lapses in formality and attention to detail. Concerns with procedural non adherence were identified in Inspection Report 50 277(278) 97 07. This issue represented a f ailure of operations personnel to ensure procedural compliance during procedure performanc .4 Circulatina Water System Problems (Unit 2) Insooetion Scone (71707)

The inspectors reviewed two instances of circulating water (CW) system problems that led to operational transients (OTs), Observations and Findinas On two occasions during this inspection period, CW system problems caused operators to enter OT procedures. On January 6,1998, the 2 'C' CW pump tripped unexpectedly, and an initial attempt to start the standby 2 'B' CW pump faile The second event occurred on January 14, during a retest, following corrective maintenance for the first issue, in this instance, the 2 'C' CW pump did not start due to a failure of the associated discharge valve motor operator, which had recently been repaired. The discharge valve operator motor cracked and broke away from the valve operator during the second event preventing the valve from being closed locally or remotely. This condition caused the 2 'C' pump to rotate in the reverse direction due to CW flow recirculating through this loo During both events, operators observed lowering condenser vacuum, entered appropriate off normal procedures, and reduced reactor power until condenser vacuum stabilized, Maintenance and engineering personnelinitiated investigations to determine the causes of these events. The evaluation for the second event was to include a full root cause analysis. Both investigations were stillin progress at the completion of this inspection period,

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The inspectors found that operator performance during both transients was satiafactory. The inspectors will assess the results of PECO's investigations for j these maintenance performance issues during future inspection activitie Conclusio Operator performance during two plant transients caused by CW system problems was satisfactory PECO's investigations into both events were it progress at the end of this inspection perio The inspectors were concerned with these two non safety system equipment failures which caused plant transients especially the second event that was caused by the significant failure of the 2 'C' CW pump discharge valvo. The inspectors will review the results of these CW system investigations for maintenance performance issues. (IFl 50 277/97 08-02)

03 Operations Procedures and Documentation 03.1 Missed Technical Soecification (TS) Surveillance Reauirement (SR) Test for Verification of Procer Flow in the Recirculation Looos Insocction Scone (71707)

On January 2,1998, the Unit 2 reactor operator failed to perform the TS surveillance requirements (SRs) for verification of proper flow in the recirculation loops. The inspectors reviewed the documentation associated with these missed SRs to determine compliance with TS requirements, Observations and Findinag On January 3, operations personnel discovered that they had missed performing sections of the formal surveillance test that verified that TS SRs 3.4.1.1 and 3.4.1.2 were met. This test, Surveillance Test (ST)-0-02F 560 2, Revision 0, " Daily Jet Pump Operability," verified that the recirculation loops were operating within TS requirements and that the recirculation system jet pumps were operable. This ST verified that the jet pumps were operable by meeting TS SR 3,4.2.1. Unit 2 was in Mode 2, "Startup," at the tirne the surveillances were missed with the reactor heating up and pressurized to 450 psig per the instructions in General Plant Procedure (GP) 2, Revision 85, " Normal Plant Startup." A surveillance test, ST-0-02F-560 2 was satisfactorily performed on January 3 after the missed SRs were discovere Technical specification SR 3.4.1.1 verified that recirculation loop jet pump mismatch was within specifications and TS SR 3.4.1.2 verified that core flow as a function of THERMAL POWER was also within specifications. Both of these SRs were required _ -

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to be performed in Modes 1 and 2 once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Technical specification SR 3.4.2.1 vorified that there was no degradation in jet pump performance; however, this was only required to be performed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after greater than 25% reactor thermal power was reached. This required the reactor to be in Mode 1, * Power Operation."

The Unit 2 reactor operator determined, based on the wording in ST 0 02F 560-2, that TS surveillances 3.4.1.1 and 3.4.1.2 were also not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after greater than 25% reactor thermal power. The operator discussed the ST requirements with the control room supervisor and the supervisor agreed after reviewing the ST that the operators' interpretation of the ST was correct. The operator marked the sections of the ST which performed TS SRs 3.4.1.1 and 3.4.1.2 as not applicabl This event was documented in PEP 10007762. The " Regulatory Review" section of this PEP noted that the licensee determined that TS SRs 3.4.1.1 and 3.4.1.2 were satisfied on January 2 using alternate methods other than the ST 0-02F 560 These methods included verifying that SR 3.4.1.2 was satisfied through the data in the operator's daily surveillance log and SR 3.4.1.1 was satisfied by the reactor operator's panel walkdowns and routine operator checks. In additio'1, parameters on computer printouts showed that recirculation loop jet pump rnismatch was within specifications of SR 3.4.1.1. Based on these alternate methods, the licensee concluded that this issue was not reportabl The inspectors noted during the review of ST 0-02F-560 2that the ST was unclear and contained conflicting information regarding when each of the TS SRs were required. The inspectors also determined based on the review of the PEP and all other pertinent information that the recirculation loops were not operated outside of the TS SR requirements. However, the inspectors did not understand how the licensee determined that TS SRs 3.4.1.1 and 3.4.1.2 and the requirements of ST 0-02F 560 2 woro met since these surveillances were not performed per the ST. The inspectors were concerned with failure of operations personnel to fully understand the requirements of the TSs for the recirculation loops surveillances and to review the TSs when unclear information was found in the S c. Conclusions The inspectors concluded that the recirculation loops were not operated outside of the TS SR 3.4.1.1 and 3.4.1.2 requirements when the unit 2 reactor operator failed to perform ST-0-02F 560-2on January 2. However, the inspectors were concerned that operations personnel failed to fully understand when these SRs were required per the TSs. The inspectors were also concerned that the operations personnel f ailed to review the TSs when unclear and conflicting information was found in the ST. This issue will be tracked as an Unresolved item (URI) pending additional l

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discussion with the licensee and final determination if the formal TS and ST requirements were mot. This willinclude a review of past practicos for complying with those surveillance requirements during startups and shutdowns and the methods used to determine that the requirements were met for this event and the reportability of this event. (URI 50 277/97 08 03)

O3.2 1)nexpected Start of the Motor Driven Fire Pumo Durina Clearance Removal for the Diesel Driven Fire Pumo Insocction Scone (71707)

The inspectora reviewed the clearance documentation and discussed the unexpected start of the motor driven fire pump during diesel fire pump clearance removal with operations personnel, Observations and Findinqn On December 8,1997, the motor driven fire pump auto started while valving in the diesel driven fire pump during clearance removal for Clearance No. 97003830. The clearance permitted various preventive maintenance tasks on the diesel engine and associated valves and instrumentation to be performe The inspectors were monitoring control room operations during the clearance removal. While aligning the diesel fire pump, the fire protection water supply system momentarily fell below the low pressure automatic start setpoint for the motor driven fire pump and the pump automatically started. The inspectors questioned operations personnel about whether the start of the fire pump was expected and whether the clearance had any cautions regarding the possible starting of this pump during clearance removal. The inspectors learned that the start of this pump was not expected and that the clearance had no cautions regarding this issue. Subsequently, the motor driven fire pump was secured and the clearance was changed to note this potential conditio The inspectors were concerned that operations personnel did not fully understand the fire protection water supply system performance and no cautions were contained in the clearance to alert operators to the potential start of the motor driven pump if system pressure dropped during valve re alignments, Conclusions The inspectors were concerned that the clearance for returning the diesel driven fire pump back to service did not caution operations personnel that the motor driven fire pump could start during valve realignments due to a sudden drop in system pressure. Also, the operators were not fully aware that this potential unexpected system condition existe . . . _ . . _ _ _ _ . _ _ _ __ _ _. _ _- _ _ __ _ _ _ _ _ _ - - ___ _ _ . _ .

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04 Operator Knowledge and Performance

04.1 Unexoocted Trio of Unit 2 Main Turbine Durina start uo Insoection Scoos (71707)

During the Unit 2 reactor startup on January 1,1998, the main turbine tripped automatically after it was inadvertently rolled to a speed of 1400 rpm. The inspectors reviewed the circumstances leading up to this event, PEP 10007760 and associated procedures from this event, and also discussed this event with operations personnel and plant managemen >

, Observations and Findinas On December 31,1997, to support EHC testing by instrument and control (l&C)

personnel, the Unit 2 reactor operator (RO) reset the mechanical trip valve in the main turbine overspeed trip system and selected 1800 rpm on the speed set, at the main turbine (EHC) control panel. The RO also adjusted pressure set to 930 psig

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during this testing. The l&C test procedure did not provide direction to restore the

EHC system configuration to the condition set prior to the testing. Therefore, the main turbine, the pressure set setting, and speed select pushbutton were not restored to the originalline up established by GP 2, Revision 85, " Normal Plant Start-up" prior to the l&C testin On the morning of January 1, during the main control panel walkdown portion of shif t turnover, the on coming shift manager noted that pressure set was at 930 psig

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and directed the RO to readjust the setting to 150 psig (minimum setting). The other two components configuration, however, remained misaligned. Unit 2 reactor was made critical at 5:46 p.m. During the reactor coolant system (RCS) heat up,

when RCS pressure reached 50 psig, the RO was directed by GP 2 to reset the main turbine as per Station Operating procedure (SO) IB.1.A 2, Revision 22, " Main Turbine Startup and Normal Operation." The RO verified that the main turbine was reset, but did not refer to all of the Instructions in SO 18.1.A 2, which contained Instructions to verify that the speed set "ALL VALVES CLOSED" was selecte At 6:25 p.m. during shif t turnover, with RCS pressure at 157 psig, the main turbine control valves opened causing the main turbine to roll off the turning gear

unbeknownst to the off going and on-coming operations personnel. The on-coming

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RO noted that the turbine was not on the turning gear at about 6:35 p.m. when he cracked opened the 'C' reactor feedwater pump discharge valve to restore a low reactor vessel level condition. Subsequently, the control room supervisor (CRS)

directed the RO to commence rod pulls to raise RCS pressure to open the turbine bypass valves. The CRS wanted to raise RCS pressure so that plant conditions would steady out and prevent possible reactor vessellevel swings due to turbine bypass valve cycling. No changes in the positions of any of the bypass valves were observed as RCS pressure increased. Just prior to the main turbine trip, the main turbine lube oil high temperature alarm and hydrogen seal oil / stator water cooling trouble alarm were received in the control roo , - - -- - - -- _- . .-_

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' Af ter the turbine tripped, operations personnel verified that the turbine tripped and placed the turbine on the turning gear. The licensee evaluated any concerns with

rolling the main turbine without pre warming. The licensee determined after discussions with the turbine vendor, General Electric, that the turbine did not experience any distress as a result of this event and was acceptable for long term

operation. The licensee documented this event in PEP 10007760.

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Several key points in this event concerned the inspectors, ine.luding:

the l&C test procedure did not contain any configuration controls to restore the EHC system to the initial conditions found prior to testing.

,

the control room staff did not restore the main turbine, the pressure set

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setting, and speed select pushbutton to the originalline up established by GP 2, Revision 85, " Normal Plant Start up" following the l&C testing.

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Inadequate control panel walkdowns occurred over several shifts.

I Specifically, the main turbine, the pressure set setting, and speed select pushbutton remained min aligned until the on-coming day shift shift manager

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noted that pressure set was indicating 930 psig on January 1, and the i turbine and speed select became self disclosing during the reactor startup.

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The RO did not adhere to procedure SO 18.1.A 2, " Main Turbine Startup and Normal Operation" when resetting the main turbine. Specifically, the RO did not verify that "ALL VALVES CLOSED" was selected on the turbine control pane * After the RO reported that the turbine was not on the turning gear, he did not monitor his indications to verify the condition of the turbine. The turbine speed was rotating for more than two hours. During this time, none of the operations personnel assigned to Unit 2 observed any of the indications that i the turbine was rotating and gaining speed other than coming off of the turning gea * The CRS directed the RO to commence rod pulls to raise RCS pressure to open the turbine bypass valves even though he did not understand why the turbine was off of the turning gear and no change in bypass valve position was observe * The turbine trip became self evident to the operations staff after the main

turbine lube oil high ternperature alarm and hydrogen seal oil / stator water cooling trouble alarm annunciated in the control room.

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The PEP stated that the ROs believed that a dedicated supervisor should

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have been assigned to oversee the Unit 2 startup evolution. Also, one of the reactor operators thought that the work load was excessive during the startup. Neither of these concerns was expressed by the operators during this evolution.

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13 Conclusions Based on the initial review of this event, the inspectors were concerned with the failure of operations staff to fully understand and recognize the main turbine status and the position of the turbine control valves and the speed select portion of the EHC system. Further, the inspectors were concerned with the pulling of control rods to increase RCS pressure while the turb!ne condition remained unknown. The inspectors were also concerned with potential deficiencies and lack of coordination between the operations startup and l&C testing procedures and with the rigor of procedure implementation by the operator This issue appeared to be a violation of TS 5.4.1, " Procedures" due to the concerns identified above. However, the inspectors needed to conduct additional reviews of the procedures used during this event, review of strip charts and recorded data from this e.ent, and further discussions with reactor engineering and operations personnel. This issue will be tracked as an unresolved item (URI) pending further review. (URI 50 277/97-08 04)

04.2 Qoit 2 Main Steam Line Hiah Radiation Alarms Durina Power Ascension latpection Scone (71707 & 37551)

The inspector reviewed the actions of control room personnel for the two main steam high radiation alarms that came in during power ascension following the trip of the 2 'C' circulating water pump and 2 'A' reactor feedwater pump turbine trip testin Observations and Findinag On January 7,1998, operators entered Operational Transient (OT) procedure, OT-103, Revision 6, " Main Steam Line High Hadiation" on two occasions. The highest main steam line radiation monitoring reading was 1670 mr/hr. The main steam line high radiation alarm setpoint was 1625 mr/hr Reactor power level at this time was approximately 72% The main steam line radiation level at this power was normally around 1000 mr/hr. General area radiation levels remained unchanged during this transient. The 2 'A' reactor feedwater pump was not in operation when these transients occurred.

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Operators reduced power in accordance with OT 103. Af ter further investigation, operations and engineering personnel determined that the hydrogen addition rates may have been higher than expected for the feedwater flow rates. After discussing this issue with the hydrogen addition system manager, operators manually reduced the hydrogen addition rate to lower the main steam line radiation level to 850 mr/hr or the normal background level for this reactor power value. Operations personnel initiated PEP number 10007782 for this issue, l

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For many years, the hydrogen addition system was not in service. During the past two years, the system was placed back in service to reduce the effects of intergranular stress corrosion cracking on core components and the recirculation pipin The inspectors reviewed OT 103 and Station Operating procedure (SO) 15.1.A 2, Revision 0, " Hydrogen Water Chemistry System Startup and Normal Operation."

Procedure SO 15.1.A 2 contained a note that the main steam line radiation levels would increase as a result of hydrogen injection. This procedure was used by the operators during the reduction of the hydrogen addition rate. The inspectort also discussed this issue with operations personne The inspectors noted that operations personnel were not fully f amiliar with the interactions of the hydrogen addition rate on main steam line radiation levels during abnormal reactor feedwater system alignment plant startups. Also, the inspectors noted that OT 103 did not contain any instructions in the procedure to reduce hydrogen addition levels when the high main steam line radiation alarm was receive Conclusions The inspectors were concerned with the completeness of the operators knowledge of the effects of the hydrogen addition system on main steam line radiation during startups and during abnormal reactor feedwater alignments. The inspectors were also concerned that OT-103 did not contain instructions to lower the hydrogen addition rate if the main steam line high radiation alarm was received. The fact that the system was placed back in service during the past two years after several years of being out-of service contributed to these concern .3 Standbv Llauld Control Pumo Clearance Restoration Insoection Scope (71707 & 61726)

The inspectors reviewed the post maintenance testing and clearance restoration performed by operations personnel on the 3 'B' standby liquid control (SBLC) pump, Observations and Findinas The inspectors noted during document review that post maintenance testing was accomplished by performing a portion of a quarterly surveillance test. The operators observed no adverse conditions during the tes While verifying the clearance restoration, the inspectors found that one valve was not fully returned to its required status. Specifically, the inspectors observed that the 3 'B' SBLC pump discharge valve, HV 11 13B-3, was open but the lock was not completely engaged. The required position per the clearance restoration sheet was

" locked open."

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The inspectors brought this deficiency to the attention of operations staf Operations personnel promptly locked the valve and initiated a verification of other locked valves in the plant. Operators found one additional valve improperly locked on the Unit 2 automatic depressurization system (ADS) backup nitrogen system. In this instance, the lock was engaged, but the chain did not restrain movement of UA valve handwheel. Tampering was not suspected in either instance since the valves were in their proper position The inspectors noted that the SBLC pump clearance restoration form required independent verification of the valve positions, and the verifications were documented as completed. Operations staff interviewed the operator who did the independent verifications and found that he stated that he had performed the expected actions to verify the position of valve. However,it was evident that both the individual who positioned the valve and the independent verifier did not carefully check that the lock was fully latche The inspectors determined that PECO took appropriate conective actions for this issue. Upon discovering a second improperly locked valve, operations management directed that full verifications of all accessible locked valves in the plant be accomplished. No additional problems were discovered during this revie Management communicated this issue to all operators and other site personnel who

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have cognizance over locked components. The discrepancies had minimal safety

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impact and did not affect system operability since the valves were in their correct positio The f ailure of operations personnel to fully adhere to the Instructions in clearance

number 97003684 during restoration for the 3 'B' SBLC pump was a violation of TS 5.4.1. Technical specification 5.4.1 requires, in part, that written procedures are implemented covering the applicable procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. However, this NRC identified vlotation was of minor safety significanco and is being treated as a Non-Cited Violation (NCV),

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consistent with Section IV of the NRC Enforcement Policy (NCV 50 277(278)/97-08 05), Concl4flRD1 The inspectors found a standby liquid control pump discharge valve in the correct position, but not locked, as specified by the clearance restoration form. Although of minimal safety significance, this and a second improperly locked valve discovered by the licensee indicated that operators were not always rigorous in independently verifying the condition of locked valves. Corrective actions for this issue were good

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and included verification of all locked valves in both units.

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07 Quality Assurance in Operations j 07.1 Plant Ooerations Review Committee (PORC) Meetina l

The inspectors observed two PORC meetings during the inspection period. The PEP evaluation root cause for the September 1997,3 'B' Circulating Water Pump fire was discussed at the first meeting. The problems and corrective actions associated with the reactor feedwater pump high level f ailure to trip and the EHC transient observed during the late December 1997 Unit 2 shutdown was discussed at the second meeting. The inspectors noted good questioning attitude by Scensee

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managemerit during these PORC meetings. Questions asked by the managers to personnel presenting these issues were thorough ana reflected in depth safety focus

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Into issues discusse .

11. Maintenance and Surveillance M1 Conduct of Maintenance and Surveillance M 1.1 Standbv Llauld Control Pumo Maintenance a, lesp_qtetion Scone (62707)

The inspectors observed corrective maintenance performed on the 3 'B' standby liquid control (SBLC) pump. Post maintenance testing and clearance restoration for i this job was discussed in Section 04.3.

, Observations and Findinas The inspectors observed work performed per corrective maintenance work order number C0177825 on the 3 'B' SBLC pump. Technicians investigated a minor oil leak on a pump motor bearing and repacked the pump seals after discovering Indications of slight leakage past the seal Technicians followed the requirements of the work order and maintenar.:e procedures. After consulting with their supervisor, they determined that the bearing oil leak was negligible, and no further work was required. The technicians were i knowledgeable, and the supervisor provided oversight as needed. The inspectors noted that the technicians documented their work on the work order.

' Conclusions l The inspectors observed that maintenance technicians working on the 3 'B' standby liquid control pump were knowledgeable, well supervised, and followed the

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maintenance procedures.

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l M1.2 Unit 3 Primarv Containment Local Leakaae Rate Testina (LLRT) Review (61726)

The inspector reviewed SE CM 01, " Primary Containment Leakage Rate Testing

implementation Plan, Rev. 0" and ST/LLRT 20.00.01, Revision 0, " Local Leak Rate Tests (LLRTs) Documentation and Tracking," to evaluate the results of the LLRTs performed during the Unit 3 outage. These procedures also implemented the performance based testing schedule provisions of the recently published Option B of

, 10 CFR 50, Appendix J. This review found that the overall maximum pathway integrated local leak rate was approximately 0.426 La (i.e., the maximum allowable leakage rate at the calculated peak contalament internal pressure during a design

basis accident) versus the acceptance criteria of 0.6 La. Discussions with the LLRT

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coordinator and a review of LLRT scheduling infermation indicated that only 40* of all Tyre B & C tests had their testing interval extended under the Option B provisions such that they did not require testing during the Unit 3 outage as originally scheduled. Overall, the LLRT program appeared consistent with the provisions of Option B, was well controlled and indicated good preventive maintenance of containment isolmico valves as indicated by the successful overall test results.

j M1.3 Motor Ooerated Valve Thermal Limit Bvoass Operabilltv i Inspection Scone (61726 & 62707)

The inspectors observed testing of several motor operated valve (MOV) thermal bypasses. The licensee performed this testing at Peach Bottom after a reactor core isolation cooling (RCIC) inboard steam valve was discovered with the wiring to the thermal overload bypass contact lifted at the Limerick Generating Statio Observations and Findinas Normally, the control circuits on MOVs for automatically onerated isolation valves are arranged so that motor thermal ocerload protection is provided. During certain accident conditions, this protection is bypassed to prevent automatically initiated valve operation from being interrupted by the motor thermal overload. This thermal overload bypass is provided to allow the valve to reach the required position during

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an accident.

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, When the RCIC MOV deficiency was found at Limerick, the licensee discovered that l their testing method checked both the thermal overload "sealin" leg and the thermal bypass at the same time without separating out the individual contacts.

l Therefore, the condition of the RCIC thermal bypass contact went undetected since

- the contact was not being tested separately. There is no requirement for this type l of testing at Peach Bottom, however, engineering personnel conservatively determined that a verification test of the MOVs would be prudent.

J The licensee successfully tested the thermal overload bypass function on 22 MOV isolation valves at Peach Bottom. No deficiencies were identified with the thermal i

overload bypass circuitry for these valves. This population of MOVs represented a

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sampling of approximately 10% of all valves with thermal overloads at the statio Engineering personnel determined that this was a sufficient population to obtain confidence that the rest of the thermal overloads for MOVs were installed correctl he licensee planned to incorporate thermal overload bypass testing during the next normally scheduled test for MOV The inspectors observed testing of the thermal overload bypass function on selected MOVs. The bypasses functioned properly and maintenance personnel accomplished the testing in accordance with approved procedures. The maintenance personnel maintained effective and precise communications between the control room and work station Conclusions The inspectors concluded that testing of the thermal overload bypass function on selected MOVs was proactive and showed conservative decision making. The testing observed provided a good functional test of the bypass contact. The inspectors also concluded that technicians displayed good adherence to procedures during testin M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Standbv Liould Control Pumo Crankcase Oil Viscosity lasoection Scoco (62701)

Tha inspectors reviewed the discovery of a higher than expected oil viscosity in the 3 'A' SBLC pum Observations and Findinas On December 11,1997, technicians found that the viscosity of the oilin the 3 'A'

SBLC pump crankcase was significantly higher than expected. The oil sample result indicated the viscosity value was 160 centistoke (cst), while the expected value was 68 cst. Operations re sampled the oil to confirm the result. Since the high viscosity value made the operability of the pump questionable, operators declared the pump inoperable and entered the appropriate TS action statement. Technicians drained and flushed the crankcase and then refilled it with the correct oil specified by the lubrication program and the pump overhaul procedur Af ter further review, predictive maintenance technicians found that the oil viscosity had been high since April 1996. To address the generic implications of this issue, management directed that other SBLC pumps be sampled and that oil viscosity values of all plant rotating equipment be reviewed for abnormal values. No problems were identified for other safety related component PECO also found that predictive maintenance technicians had previously evaluated the 3 'A' SBLC pump high oil viscosity and had received correspondence from the

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19 i pump vendor tnat indicated that pump operation would not be adversely affected by the high viscosity oil. However, the technicians did not formally document this information at that time. After the December finding and subsequent review of data, engineering concluded that the pump remained operable with the high viscosity oil.

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The Inspectors determined that operations took appropriate, conservative immedlete actions to declare the SBLC pump inoperable. The inspectors also reviewed the interim and planned long term corrective actions for this issue and identified no concerns. Predictive maintenance personnelInitiated improvements to their review

and documentation processes, Conclusions

, Operations took conservative action when they declared the 3 'A' standby liquid control pump inoperable following the discovery of higher than expected viscosity i oilin the pump crankcase. Investigation by PECO revealed that this condition had been previously evaluated by predictive maintenance personnel, but had not been formally documented, initial corrective actions to replace the oil, evaluate pump operability, and rovlew viscosity records on other plant components were

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satisfactor M2.2 Forelan Materialin 2 'C' Residual Heat Removal System Heat Exchanaer

insoection Scone (62707 & 37551)

The inspectors reviewed PECO maintenance technielans' discovery of foreign materialin the 2 'C' residual heat removal (RHR) system heat exchanger, Observations and FindlDER On January 5,1998, during maintenance on the 2 'C' RHR heat exchanger, :

technicians found broken glass, an electrical extension cord, and metal straps on

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the RHR (shell) side of the heat exchanger. Technicians removed the glass but were unable to remove the cord and metal strap After further investigation, PECO determined that the forelgn material had been previously identified in the heat exchanger in 1994. At that time, engineering '

evaluated the material through a non conformance report (NCR) and dispositioned it as "use as is." This NCR provided an evaluation which allowed the foreign rnaterial to remain in the heat exchanger for an indefinite period of time. However, maintenance did not initiate any action to track this condition and plan for the removal of this material during subsequent maintenance periods. The inspectors learned during discussions with PECO management that they recognized this as a missed opportunit The inspectors noted that maintenance has now taken steps to track foreign material conditions and similar interim "use as is" dispositions. Maintenance

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determined that this will allow maintenance planning to include activities to attempt to remove foreign material, as appropriate, during normally scheduled wor The inspectors also reviewed the NCR generated as result of this issue. The inspectors discussed the report with engineering staff and found that the evaluation considered both normal and post design basis accident operation of the RHR heat exchanger. Engineering concluded that the function of the heat exchanger was not adversely affected, and that deterioration or movement of the material was highly unlikel Conclusions The inspectors had no concerns with operation of the RHR heat exchanger during normal and post design basis accident conditions with the foreign material still present based on the NCR review. This material, which included metal straps and .

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an extension cord, was first identified in 1994 and had not been tracked for removal during subsequent maintenance period However, the inspectors concluded that PECO missed an opportunity to plan for the removal of foreign materialin the 2 'C' RHR heat exchanger during the regularly aheduled maintenance work, Thus, technicians did not expect to find this foreign material during maintenance activities in January 199 M3 Maintenance Procedures and Documentation M3.1 Eauioment Condition Notification to Ooerations Insoection Scope (62707)

The inspectors reviewed the process for notifying operations personnel of corrective maintenance problems and degraded equipment conditions. The inspectors referred to AG CG-026.2, Revision 4, " Corrective Maintenance Action Request Initiation and Processing." Observations and Findinas NRC Inspection Report 50 277(278)/97 07 uiscussed an instance of poor equipment status control, in which a standby safety related station battery charger had been in a degraded, inoperable condition for several months, but was not being tracked by operations personnel. After further review by operations staff, they concluded that 1 they were not notified of the further degradation of this equipment in a timely manne During this inspection period, both PECO and the NRC identified similar examples in which operations were not fully informed of degraded conditions on safety related equipment. Examples included the following:

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,

w- pr- w *<--rv -%y--y .y7-- we w---wy;-+--swp-e-- - - , - - ->----------vw. , -4e.- g-W-w+ yea--.e* - - - -- e m.-s-

__ _._. _ _ _._ _____ _ _ ._..__ _ _._ _ _ _._ - _

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Maintenance noted a degraded condition on an RHR system motor operated

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valve breaker, and the maintenance supervisor considered the component operable. The AR for the problem was not routed to operations in a timely

,

manner for an operability determination. When operators reviewed the condition, they declared the valve Inoperable. Operations raised concerns about the untimely routing for the operability determination. Shortly af ter the valve was declared inoperable; maintenance corrected the breaker problem and the valve was made operabl * The inspectors noted that ARs for packing leakage on safety related instrument root valves were not toisted to operations for operability determinations

The inspectors found that an AR on an RCIC steam line outboard isolation valve was not routed to operations for an operability determinatio The inspectors discussed these findings with operations and maintenance staf Following the discussion, operations initiated a PEP report to review the issue and developed corrective actions to communicati these issues to appropriate plant supervision, Conclusions The station and the NRC identified instances where operations staff were not informed of degraded conditions on safety related equipment in a timely manne The inspectors were concerned that the failure to inform operations of these degraded conditions could result in operations personnel being aware of potentially inoperable equipment. Some items identified during this inspection were of minor significance; however, one issue involved an RHR valve that was declared inoperable by operations after they became aware of the degraded condition on this valv M4 Maintenance Staff Knowledge and Performance M4.1 Unit 2 EHC Soeed Error Sianal Blas Due to Repair of Soeed Control Card Short

' inspection Scope (62707 & 37551)

On January 4,1998, main steam line bypass valve, BPV 1, unexpectedly opened approximeply 25% several times while the Unit 2 reactor operator was raising reactor pcwer using control rods. Unit 2 was at appro@nately 96% power and reactor pressure was stable at 1028 psig when this occurred. - The inspectors >

reviewed this issue and the licensee corrective actions that allowed Unit 2 to reach 100% power.

L

_ . . _ . . - - , _ . . _ _ . . _ _ _ . _ . _ _ _ _ _ _ . _ _ . _ _ _ - _ _ _ . - . - _ . - . _ . _ _ _ - .

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O

i i

b. Qbservations and Findinas

During replacement activities for the EHC pressure control unit, the l&C technichns discovered a short circuit on a card in the speed control vection of the LHC syste This short was due to a looso connection on the card. The instrument and bontrol technicians tightened the connectinn and reinstalled the car During subsequent troubleshooting of this issue, l&C personnel discovered 0.5 volts in the speed error circuitry that was producing a 15% speed error signal. This ;

signal should have shown 0% speed arror. This condition was documented on AR '

number A112822 <

Ongoing analysis of this condition by eng!neering and l&C personnelindicated that the 15% speed error was caused by the repair to the speed control card loose ;

connection. Retightening this connection was believed to have introduced the ,

speed error since this error had earlier been unknowingly compensated due tn the

~

,

shor Engineering personnelissued a non conformance report (NCR) under ECR number 98 00036, Revision 000 to raise the load set value from 105% to 120% to compensate for the speed error. This allowed the required 105% value to come out of the summer for speed control and load control. This ECR contained a safety evaluation for operating the unit with this change to the load set value. Several operations procedures were also changed to reflect the revised nominalindicated

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margin between the load set and actual power due to the speed bia Subsequently, the load set was raised and unit 2 power was increased to 100% on January The inspectors reviewed the ECR, safety evaluation, and AR for this condition and verified that the affected operations procedures had been changed. The inspectors had no concerns with the change to the load set. However, the inspectors noted

'

during these reviews that l&C personnel did not fully understand the effect on the EHC system of tightening the loose connection on the card in the speed control section, c. Conclusions The inspectors had no concerns with the analysis or changes made to increase the load set value to compensate for the speed error blas. However, the inspectors were concerned with the fai!ure of the l&C personnel to fully understand the operation of the speed control circuitry and what effect tightening the loose

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connection would have on the signal and the EHC system.

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- - _ _ _ -_ __ _ - - - . ___

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lli. Enoineerina E1 Conduct of Engineering E1.1 Unit 3 Jet Pumo Riser Elbow Weld Crackina Insoection Scone (37551)

The inspectors reviewed the interim operating strategy, safety evaluation, and flaw evaluation for the cracks found in the jet pump risers during the October 1997, Ur,:t 3 refuHing outage, Observations and Findinas Engineering personnel performed an assessment of the cracks on the jet pump risers and determined that the reactor could be returned to service and operated on an interim basis pending repairs, with restrictions on recirculation flow to limit crack growth by f a"gue. The licensee described its interim operating strategy in a letter dated October 30,1997. The Office of Nuclear Reactor Regulation (NRR) staff requested additionalinformation on November 7,1997, which the licensee provided on November 17,1997. The licensee provided a revised interim operating strateg on November 19,1997. Thie interim strategy was implemented under the provisions of 10 CFR 50.59, and limits recirculation flow to 91 % for up to 800 hours0.00926 days 0.222 hours 0.00132 weeks 3.044e-4 months , and 80% for 2,224 hour0.00259 days 0.0622 hours 3.703704e-4 weeks 8.5232e-5 months The NRR staff agreed with the licensee that no unreviewed safety question existe The staff concluded that the licensee's flaw evaluation is in accordance with Appendix C to Section XI of the ASME Code, and that ASME Code component structuralintegrity margins would be maintained for the specified operating porlod under the interim operating strategy. The staff noted that the licensee reserved 18.4% margin in terms of final crack length to account for uncertainties and inaccuracles in its evaluation. This margin gave the staff additional assurance that the f acility could be safely operated until repairs are performe On December 22,1997, the licensee documented its decision to use a mechanical clamp as the permanent crack repair, and that a repair outage is scheduled for early March 1998. The licensee committed to inform the NRC of changes to the operating strategy which require revision of the 10 CFR 50.59 safety evaluatio The licensee will provide a summary of actual operating history documenting actual recirculation flow rates and time periods under the interim strategy following the repair outage, Conclusions The licensee's flaw evaluation for cracks found on the jet pump risers was %

accordance with the ASME code and provided adequate margin for continued safe operation of Unit 3. The inspectors had no concerns with the licensee's safety evaluation or interim operating strateg .

.

E2 Engineering Support of Facilities and Equipment E2.1 Inadvertent Operation of Bvoass Vylves Durina Unit 2 Shutdown Insoection Secow (71707 & 37551)

On December 29,1997, all nine bypass valves unexpectedly opened at 155 psig EHC pressure during lowering of the 'A' EHC pressure set from 190 psig to 150 psig during the normal depressurization/cooldown of Unit 2. The inspectors reviewed TPA performed per ECR number PB 03475, Revisions 000 and 001 which contributed to this event and Operations General Procedure [GPb3, Revision 77,

" Normal Plant Shutdown." Observations and Findinas ,

While lowering EHC pressure to allow a depressurization nf the Unit 2 reactor to i less than 50 psig, all bypass valves opened. The reactor pressure was 120 psig at the time. The EHC pressure set was immediately raised until all the bypass valves closed. EHC pressure was then lowered at 1.0 psig increments. At 156 psig, six bypass valves opened up. Pressure set was then raised to 159 psig and all six bypass valves closed again. During these changes in EH. pressure, pressure control swapped from the 'A' regulator to the 'B' regulato During this transient, reactor vessel level swelled from a steady state of + 22.0" to

+ 50.0" then back to + 22.0." The 2 'A' reactor feedwater turbine tripped automatically during this trancient. This issue is discussed in section E The licensee's investigation into this transient revealed that the TPA that removed the 'B' pressure regulator from service helped cause this event. This TPA failed the

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'B' normal /f ailure switch by installing a jumper which closed tne failure switc With this failure switch closed, the lower 1 kilohm resistor in the circuit shorted out when the pressure sat point was lowered. This condition tied the voltage signal to ground since the resistance was shorted out. This caused the 'A' regulator voltage signal to be lower than the 'B' signal so that the 'B' regulator took control and resulted in all the bypass valves opening.- After the vessel was depressurized, the licensee jumpered the 'A' normal / failure switch and was able to r:aplicate the circuit behavior with the 'A' pressure regulator circuitry. This TPA was removed and the

'B' pressure regulator motor operated potentiometer assemblies and secondary pressure amplifier card was replaced prior to start u After reviewing the TPA and operations procedures, the inspectors noted that this event was another example of the failure of the operators and engineering personnel to understand what effect the work document had on the system. Specifically, operations and engineering personnel did not fully understand the effect of the TPA on the EHC system. The inspectors noted that the TPA was written to replace the

"B" pressure regulator card at power and not while shutdown. The inspectors determined that the f ailure to fully understand ble effect of the TPA during shutdown conditions inhibited operations personnel from adding procedural cautions

._ . - . - . .

.

in the shutdown procedures. These cautions would have provided additional assurance that the pressure regulation and turbine-generator control system operated as required during the shutdown evolution, Conclusions The inspectors were concerned with the failure of operations and engineering personnel to understand the effect on the EHC system of the TPA which was designed to fail the 'B' EHC pressure regulator and allow replacement of the secondary pressure amplifier card. This lack of system understanding contributed to all the bypass valves unexpectedly opening which resulted in a reactor vessel level transien E 2.2 2 'C' Residual Heat Removal (RHR) Pumo Suction to Torus Valve Motor Onorator

, Deficiencies ingp_ggtlon Scone (62707 & 37551)

During scheduled maintenance, PECO maintenance personnelidentified a broken clutch gear and found a motor brake installed to the RHR Torus suction valve motor operator, MO 210-013C. The inspectors reviewed applicable documentation and discussed these issues with engineering and maintenance personnel to understand the causes and corrective actions for these deficiencies. The inspectors also independently evaluated whether these deficiencies were applicable to other valves, Observations and Findinag While the 2 'A' RHR system was out of service, maintenance personnel found what appeared to be a rnotor brake electrical connection on the 2 'C' RHR Torus suction valve operator motor. Engineering personnel verified that the motor break was installed. Review of this issue by engineering personnel revealed that the motor brake installed on this valve was to have been removed by an engineering modification in 1988. This engineering modification was also supposed to remove the brakes from several other safety related valve operator motors. The RHR system electrical drawing, M 1 S 65, Revision 96, " Unit 2 Wiring Diagram: Electrical Schematic Diagram RHR System," did not show this electrical brake to the 2 'C'

RHR Torus suction valve operator moto McIntenance removed the motor brake from MO 210-013C prior to testing and wrote PEP 10007785 to document this deficiency. Maintenance planned to change the MOV maintenance procedure to add a step to verify that no motor brakes were installe The inspectors reviewed NRC Information Notice 93 98, " Motor Brakes on Valve Actuator Motor." This Information Notice discussed the potential for MOVs with motor brakes installed to failif the design basis voltage was insufficient during a degraded voltage condition to allow the motor brakes to re'7se. The inspectors noted that the design basis voltage to the 2 'C' RHR pump suction to the torus,

._ _ _ _ . ._ ____. _ . _ _ _ _ _ . _ _... _ . _ _ _ _ . _ . .

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l *

I 26 MO 210 013C,was verified during the preventive maintenance program on the

MO During testing of this valve, the maintenance personnel noticed an abnormal noise coming from the valve operator in the tripper finger area where the lever for conversion to manual operation is located. Subsequently, maintenance personnel

, disassembled and inspected the valve operator and found a part of a tooth missing from the worm shaft clutch gear. The worm shaft clutch gear and the grease in the operator were removed and replaced. The knob which contacted the tripper fingers was filed down to correct the noise problem. The valve operator was reassembled and the valve was successfully retested and returned to servic The inspectors observed portions of the valve operator's disassembly, reassembly, and testing. The inspectors observed that the tooth breakage on the worm shaf t clutch gear ran though the stamp mark on the end of the gea Conclusion Based on the performance history and voltage available during an accident to the 2

'C' RHR pump torus suction valve, the inspectors concluded that the Installed motor brake did not render this valve inoperable. However, the Inspectors were concerned that other safety related MOVs could have motor breaks installed even though the breaks had supposedly been removed per the 1988 engineering modification. The inspectors will follow up on the identification and inspection of other MOVs for motor brakes, any modification control issues concerning the 1988 engineering modification, and any generic implications from the results of the failure analysos on

"

.a broken worn uhaft clutch gear. (IFl 50 277(278)/97 08 06)

E8 Miscellaneous Engineering Issues i

E (Closed) URI 50 277(2781/96-04-04:Emeraency Diesel Generator (EDG) Outout Breaker Resoonse Durino Testing On June 6,1996, operations personnel identified an unexpected condition during a simulator exercise that affected all four EDGs. While any EDG was running and unloaded, the output breaker would fail to automatically close following a loss of offsite power. Generally, thit vas only possible during EDG testing prior to paralleling the diesel to the grid. This condition was caused by a sealin of the 4 KV breaker anti-pumping features and had unknowingly been introduced into the control

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_ --. . -.- - _ - - - - - - __-._ - - -_. - _ - ---.

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circuit logic in June 1995 daring modification P 231. Modification P 231 was designed to provide automatic transfer from the EDG parallel mode to the isochronous mode of operation. The EDG output breaker could be shut during this condition by momentarily placing the breaker in the trip position to clear the anti-pump relay seal i Interim corrective actions included: declaring the EDGs inoperable during testing; training operations personnel and revising procedures to specify the required actions to shut the EDG output breaker; and performing additional analyses to identify other potential scenarlos where the EDG output breaker would lockout, iho inspectors had no concerns with the interim actions, however, the inspectors were concerned with any safety and regulatory significance associated with this design condition. These concerns were forwarded to NRR for revie .

-

NRR visited the Peach Bottom site and reviewed the electrical distribution system control and schematic diagrams and the current licensing basis. NRR concluded that the safety significance of this design condition was low and the licensee remained in compliance with the Technical Specifications during routine EDG testing. NRR also determined that the EDG remained within the licensing basis and was not required to respond to a loss of coolant accident or a loss of offsite power while in this condition. NRR identified no new issues during this review. Based on the NRR review and the licensee's interim corrective actions, the inspectors have no further concerns with this issu IV. Plant Support R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Imolementation of the Radioactive Liould and Gaseous Effluent Control Proarams Insoection Scooe (84750-01)

The inspection consisted of: (1) a tour of the plant, including the control room, (2) _

review of liquid and gsseous effluent release permits, and (3) review of unplanned /unmonitored release pathways,if any, Observations and Findinas The inspectors toured Units 2 & 3, selected effluent radiation monitoring systenis (RMS), selected air cleaning systems, and the control room. All effluent RMS and air cleaning systems were operable at the time of this inspectio Rad:oactivo liquid and gas release permits contained: (1) gamma measurement

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results; (2) tritium measurement results; (3) projected dose calculation results; (4)

cumulative dose contributions from radioactive gas and liquid releases for the current calendar quarter; (5) RMS readings 'before, during, and end of release); and

_ _ _ _ _ . _ . _ _ _ _ _ _ . . _ _ _

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(6) aler. tnd alarm setpoints. The inspectors determined that tha licensee followed associated procedures and the requirements of the Offsite Dose Calculation Manual (ODCM).

The licensee completed a significant upgrade to the chemistry laboratory including non radiological measuring equipment. Another notable improvement to the radioactive effluent's program was new laboratory quality control sof tware, Conclusiong Based on the above reviews, the inspectors determined that the licensee implemented the radioactive liquid and gaseous effluent control programs effectivel R2 Status of Radiological Protection and Chemistry Facilities and Equipment R 2.1 Calibration of Effluent /Procest_ Radiation Monitorina Systems (RMS) Insoection Scoce (84750-01)

The inspectors reviewed the most recent calibration results (electronic and radiological calibrations) for the following effluent and process RMS with respect to licensee procedures, Technical Specifications (TS) and ODCM requirements:

Liquid Radwaste Effluent Monitor (common),

Liquid Radwaste Effluent Flow Meter,

Reactor Building Closed Component Cooling Monitors (both units),

Service Water Effluent Monitors (both units),

Emergency Service Water Effluent Monitor (common),

Main Stack Noble Gas Monitors (common, normal and wide range),

Roof Vent Noble Gas Monitors (both units),

Offgas Monitors (both units)

The inspectors also reviewed the most recent radiological calibration results performed by the Chemistry Department staff for the following process RMS:

Control Room Vent Monitor,

Refuel Floor Vent Exhaust Monitors (both units), and

litywell High Range Monitors (both units) Observations and FindiO21 The Instrumentation and Controls (l&C) Department performed both the electronic and the radiological portions of RMS calibrations. Calibration results were within the licensee's acceptance criteri The inspectors noted no inadequacies pertaining to the calibration of the liquid radwaste effluent flow mete __ _ __ _ _ ... _ _ _ ._ _ _ . _ __ _ _ _ _ _ __._ _ _ _ _ _

O

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During a review of older RMS (manuf acturers other than Sorrento), the inspectors noted that radiological calibrations were good, linearity checking was good, high voltage was properly set by determining the optimum high '. >ltage Jet point, and

_

electronic alignments were appropriate. Tracking and trending efforts by the ,

syJtem engineer were very goo ,

During a review of newer RMS (manufactured by Sorrento), the inspectors noted that the radiological calibration techniques used by the licensee were acceptable because beta scintillator detectors are inherently stable. Linearity checking was good. Tracking and trending efforts by the system engineer were very goo However, the electronic portion of the calibration of these monitors was wea High voltage was checked at one point, but the inspectors noted that these RMS continually self monitor high voltage. Electronic alignment checks were minima This was discussed with the System Engineer who agreed to review the matter and make changes to calibration procedures as appropriat Conclusions Based on the above evaluation, the inspectors concludea that this program area was good. A minor weakness was noted pertaining to the electronic portion of a calibration of RMS manufactured by Sorrent R2.2 Surveillance Tests for Air Cleanina and Ventilation Systems Insoection Scope (84750 01)

The inspectors reviewed the licensee's: (1) most recent surveillance test results, and (2) performance summaries with respect to l echnical Specification (TS) and Updated Final Safety Analysis Report (UFSAR) requirements for the control room, standby gas treatment, and turbine building ventilation system Observations and Findinas The inspectors noted that deficiencies identified during surveillance testing were corrected and as lef t conditions met the licensee's acceptance criteri The licensee periodically checked and recorded the differential pressure across turbine building ventilation HEPA filters, t

l The licensee's TS specify Regulatory Position C.6.a of Regulatory Guide (RG) 1.52, Revision 2, March 1978, as the requirement for the laboratory testing of the

,

chercoal. RG 1.52 references ANSI N5091976," Nuclear Power Plant Air Cleaning j Units and Components." ANSI N5091970 specifies that testing is to be performed

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in accordance with paragraph 4.5.3 of RDT M 161T, " Gas Phase Adsorbents for

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=

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i 30

! Trapping Radioactive lodino and lodine Components." The most recent test results met the licensee's existing charcoal test acceptance criteria. Charcoal efficiency I testing was conducted by a vendor service. The inspectors inforrned the licensee of alternative charcoal testing methodologie '

<

, Conclusions

,

The inspectors concluded that the licensee maintained a good program for air I

cleaning system R3 Radiological Protection and Chemistry Procedures and Documentation- insoection Scoos (84750 01)

. An ODCM review was conducted that consisted of: (1) review of set point calculation methodologies: (2) review of selected parameters for calculating

projected doses; and (3) review of ra; _. lve liquid and gaseous discharge

'

pathways. The inspectors also reviewed the 1996 Annual Radioactive Effluent Report to verify implementation of the TS/ODCM.

l Observations and Findinas

The ODCM contained set point calculation methodologies for radioactive liquid and j gaseous effluent RMS. The inspectois also noted that the ODCM contained all

! relevant parameters as found in Regulatory Guide 1.109, NUREG 0133, and site specific factors. Radioactive liquid and gaseous effluent pathway diagrams were

also provided as required. No new ODCM discrepancies were noted (see Section i R8.2).

.

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The Annual Radioactive Effluent Report provided total quantities of liquid and

! gaseous effluent released from both units and included projected doses to the

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public. The inspectors determined that the licensee met the TS/ODCM reporting requirements and the report contained the information specified in the ODCM. No

'

i obvious emissions, trends or anomalous measurements were identified.

, Conclusions i

The licensee's ODCM contained all the necessary information and guidance to support the radioactive liquid and gaseous effluent control programs. No

discrepancies were noted pertaining to the Annual Radioactive Effluent Report. All liquid and gaseous discharges for 1996 were well within regulatory requirements.

R7 Quality Assurance (OA) in Radiolegical Protection and Chemistry Activities

' insoection Scope (84750-011-

The inspection consisted of reviews of the most recent TS required radioactive effluents control program audit, surveillances, and a Chemistry Department self-assessmen _ _ . . _ . _ . . . _ . . .__ _ _ _ _ _ _ __ _ . . _ _ ,. _ _. _ . . , _ _ _ . - . _ _ . . _ , -

_ . - . _ _ - - - - - . - _ . - - - . - - - - - - . - - - - -

l

l

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4 The inspectors reviewed the radiochemin.try laboratory quality assurance / quality control (OC) programs to determine the adequacy of controls with respect to sampling, analyzing, and evaluating data. The inspectors reviewed results pertaining to: (1) the intra laboratory and inter laboratory comparison; (2) blind

duplicate samples; (3) reproduction techniques (reproducibility for sampling and analyzing); and (4) instrument control charts,

~ Observations and Findinas l

The 1997 QA Audit was effective and adequately covered the effluent control program including ODCM implementation. A technical specialist with applicable experience was on the audit team. No findings of regulatory significance were identifie No discrepancies were noted pertaining to the intra laboratory, inter-laboratory, or

,

blind sampling comparative tests. Laboratory QC data results indicated that the licensee implemented very good quality control of Chemistry laboratory counting equipmen l

>

' Conclusions

!

Quality assurances of the effluents control program and quality control of chemistry sampling analysis and detection equipment was considered to be very goo R8 Miscellaneous Radiological Protection and Chemistry issucs R Unroviewed Safety Question Review and Radioactive Effluents Control !

(VIO 50 278/97 03-01)

,

~

In NRC Inspection Report 50 278/97 03,it was noted that the licensee did not ,

formally consider potential impacts regarding radioactive effluents control prior to ,

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breaching the turbine building that resulted in a violatir'n. The inspectors reviewed the licensee's response to NOV 50 278/97-03 01 and considered the corrective actions to be reasonable. Tha inspectors verified the corrective actions and changes had been made by the licensee to better address the need for considering impacts on the radioactive effluent's control program during the modifiedtion revl process. Based on this review, the violation is closed, in addition to the corrective actions implemented to address the violation, Chemistry l department personnel conducted a thorough walkdown of the turbine building and 1 identified several perforations and seam cracks in the roof. Licensee staff analyzed !

each to determine whether the differential pressure at each location was either l positive or negative. The licensee established continuous sampling stations at each i of the holes where the differential pressure was positive. At the time of the inspection, work orders had been initiated for repair and the engineering department was conducting a safety evaluation of the existing condition. No major safety !

consequence is expected, l

l l

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R8.2 Tour of Peach Bottom Unit 1 On December 4,1997, the inspectors toured the decommissioned Unit 1 facilit This plant was a 40 MWe, high temperature, gas-cooled reactor and was shutdown in October 1974. All fuel for this reactor has been removed from the site. The inspectors did not identify any significant concerns with the maintenance of Unit 1 during this tou S1 Conduct of Security and Safeguards Activities Inspection Scooe (81700)

Determine wnether the conduct of security and safeguards activities met the licensee's commitments in the NRC-approved security plan (the Pian) and NRC regulatory requirements. Areas inspected were: access authorization program; alarm stations; communications; protected area access control of personnel and packages and material, Observat!ons and Findinas Access Authorization Proaram The inspectors reviewed implementation of the Access Authorization (AA) program to verify implementation was in accordance with applicable regulatory requirements and Plan commitments, lhe review included an evaluation of the effectiveness of the AA procedures, as implemented, and an examination of AA records for seven individuals. Records reviewed included both persons who had been granted and had been denied access. The AA program, as implemented, provided assurance that persons granted unescorted access did not constitute an unreasonable risk to the health and safety of the public and that appropriate actions were taken when persons were denied access or had their access terminate Alarm Stations. The inspectors observed operations in both the Centrai Alarm Station (CAS), and the Secondary Alarm Station (SAS). This observation included a! arm response, post turnover, and interviews with the alarm station operators. The alarm stations were equipped vvith appropriate alarms, surveillance and communications capabilities and were continuously manned by knowledgeable operators. No single act could remove the piant's capability for detecting a threat and calling for assistance because the alarm stations were sufficiently diverse and independent. The Central Alarm Station (CAS) did not contain any operational activities that could interfere with the execution of the detection, assessment and response function Communications. Both alarm stations were capable of maintaining continuous intercommunications, communications with each security force member (SFM) on duty, and calling for assistance from both on and offsite organizations. These communications capabilities have been enhanced by the recent acquisition and installation of more powerful radios in security and emergency vehicle . - - . - . - - - - - -- - - - . - . - - _ - - .

e

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Protected Area (PA) Access Control of Personnel and Hand-Carried Packaacs. The

inspectors observed operations at the personnel access portal a number of times during the course of the inspection. Positive controls were in place to ensure only authorized individuals were granted access to the PA. All personnel and hand-carried items entering the PA were pioperly searched and the last SFM controlling access to the PA was in a position to perform this function effectively.

. PA Access Control of Material. The inspectors observed material processing in the warehouse. The licensee had positive control measures for all materials entering the PA. Materials entering the PA ware identified, searched and authorized by the

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licensee. Materials entering the PA via the warehouse were searched by properly trained and qualified individuals.

c. Qgngiusions The licensee was conducting its security and safeguards activities in a manner that protected public health and safety and that this portion of the program, as

,

implemented, met the licensee's commitments and NRC requirement S2 Status of Security Facilities and Equipment a. Inspection Scooe (81700)

Areas inspected were: Testing, maintenance and compensatory measures; PA detection and assessment aid; personnel and package search equipment and vehicle barrier systems, b. Observations and Findinas Testina Maintenance and Compensatorv Measures. The inspectors reviewed testing and maintenance records for security-related equipment and found that documentation was on file to demonstrate that the licensee was testing and

maintaining systems and equipment as committed to in the Plan. A priority status

was being assigned to each work request and repairs were normally being completed within the same day a work request necessitating compensatory measures was generated. The inspectors reviewed security event logs and maintenance work requests generated over the last year. These records indicated

.

that the need for compensatory measures was extremely minimal. When

'

necessary, the licensee implemented compensatory measures that did not reduce the effectiveness of the security system as it existed prior to the need for the compensatory measure.

, EA Detection and Assessment Aids. The inspectors observed the licensee's performance test of the entire Intrusion Detection System (IDS). All zones of the

,

10S were tested, and generated appropriate alarms. The test of the IDS was accomplished in accordance with the established testing procedure. The IDS was

functional and effective. The inspectors observed camera coverage, in the CAS, of the entire perimeter, while it was being walked down. The camera coverage and overlap were very good. The licensee's assessment aids were functional and effectiv .- --- . .- . - . -. _ _ , - -

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Personnel and Packaae Search Eauioment. The inspectors observed both the routine use and the daily performance test of the licensee's personnel and package search equipment. All search equipment was observed to perform its intended function, Conclusions The licensee's security facilities and equipment were determined to be well maintained and reliable and were able to meet the licensee's commitments and NRC requirement S3 Security and Safeguards Procedures and Documentation f Insoection Scope (81700)

.

Areas inspected were: security program plans, implementing procedures and j security event logs.

i b. Observations and F;edinos i

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Security Procram Plans. The inspectors verified that selected changes to the Plan

, associated with the vehicle barrier system (VBS), as implemented, did not decrease the effectiveness of the Plan, i

Security Proaram Procedures. Review of selected implementing procedures associated with the VBS determined the procedures were consistent with the Plan

>

commitments, and were properly implemented.

i Security Event Loas. The inspectors reviewed the Security Event Log for the

previous six months. Based on this review, and discussion with security management, it was determined that the licensee appropriately analyzed, tracked,

,

resolved and documented safeguards' events, c. Conclusions Security and safeguards' procedures and documentation were being properly implemented, Event Logs were being properly maintained, and effectively used to analyze, track, and resolve safeguards events.

i S4 Security and Safeguards Staff Knowledge and Performance a. Insoection Scoce (81700)

Areas inspected were security staff requisite knowledge ano capabilities to accomplish their assigned functions.

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b. Observations and Findinas Security Force Reauisite Knowledae. The inspectors observed a number of SFMs in the performance of their routine duties. These observations included alarm station

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I 35 i

operations, personnel and package access control searches, and PA patrols. In addition, interviews were conducted with SFMs and security management.- Finally,

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training records were reviewed (see S5). Based on all of the above activities, it was determined that the SFMs were knowledgeable of their responsibilities and duties, and could effectively carry out their assignments.

!

i Resoonse Caoabilities. The inspectors reviewed the licensee's response strategies, response drills and critiques and evaluated feedback to the training department for lessons learned, i

c. Conclusions The SFMs adequately demonstrated that they have the requisite knowledge necessary to effectively implement the duties and responsibilities associated with their positio S5 Security and Safeguards Staff Training and Qualifications

,

a. Insoection Scoce (81700)

i Areas inspected were security training and qualifications and training records.

b. Observations and Findinas

, Security Trainina and Qualifications. The inspectors reviewed training records of ten SFMs and observed weapons' qualifications for two SFMs. The records review and weapons' qualification observation indicated that the security force was being trained in accordance with the approved T&Q plan.

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Trainina Records. The inspectors' review of training records determined that the

' records were accurate and contained sufficient information to determine the current qualifications of the individual.

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c. Conclusion

Suurity force personnel were being trained in accordance with the requirements of the NRC approved T&Q plan. Training records were being properly maintaine Finally based upon the findings documented in paragraph S4, the inspectors determined that the training was effective and provided the security force with the requisite information needed to effectively implement the Plan.

l-S6 Security Organization and Administration a. Insoection Scoce (81700)

Areas inspected were: management support, effectiveness and staffing levels.

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b. Observations and Findinas Manaaement Sucoort. The inspectors reviewed various program enhancements made since the last program inspection to determine the level of management

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support. These enhancements included the allocation of resources for the following

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Upgrade of the offsite communications system to include installation of new more powerful radios in six security and emergency vehicle *

Upgrades to the assessment system, including the installation of six new pan tilt and zoom video cameras and a new video switche *

Installation of an upgraded video-capture system to enhance assessment capabilitie *

Training of ont : s Instrument and Control Technicians to repair radio communicatiow systems, therefore, reducing the need for offsite support in maintaining these system Manaaement Effectiveness. The inspectors reviewed the management organizational structure and reporting chain, Security managements position in the organizational structure provides a means for making senior management aware of programmatic needs. Senior management's positive response to requests for i equipment, training and resources in general have contributed to the effective administration of the security progra Staffino Levels. The inspectors verified that the total number of trained SFMs immediately available on a shift met the requirements specified in the Plan c. Conclusiorig The level of management support was adequate to ensure effective implementation of the security program, and was evidenced by adequate staffing levels and continued resource allocation to improved training and equipment to enhance effective implamentation of the security progra S7 Quality Assurance in Security and Safeguards Activities a. Inspection Scoce (81700)

Areas inspected were: audit /self-assessment program, problem analyses, corrective actions and effectiveness of management controls, b. Qbservations and Findinas Audit /Self-Assessment Proaram. The inspectors reviewed the licensee's Security Program Audit Report (Assessment A1061530 conducted March 24-April 7,1997)

and Fitness-for-Duty (FFD) Audit Report (Assessment A1102592 conducted l

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August 2-October 2,1997). There were no findings in the security audit and one deviation identified during the FFD audi The deviation was not indicative of major programmatic weaknesses. The FFD audit was enhanced by the use of technical specialists. Finally, a review of the response to the audit finding indicated that the actions taken to address the finding would enhance program implementation, The self assessment program was well defined and structured. Self assessments were performed in the areas of security operations, access controls, security systems and training. The self assessments were comprehensive, and results well documented. The data generated was trended, and the results were well organize Problem Analyses. The inspectors reviewed data derived from the self assessment program. The analyses was effective, and problem areas are trended and identifie Corrective Actions. The inspectors reviewed corrective actions implemented by the licensee in response to the internal QA audit. The corrective actions were effective, and should prevent recurrence of the findings associated with the corrective action Effectiveness of Manaaement Controls. The inspectors observed that the licensee has a program in place which was effective in identifying, analyzing and resolving problems. The corrective actions taken by the licensee, in response to the audit l findings were adequate and should prevent recurring problems. The same could be said for the self assessment program relative to the ability of the licensee to identify and analyze problem .Qrnclusions TI e review of the licensee's Audit /Self-Assessment program indicated that the audits were comprehensive in scope and depth, that the audit findings were reported to the appropriate level of management, and that the program was being properly administered. In addition, the corrective actions that were implemented were effectiv S8 Miscellaneous Security and Safety issues S8.1 Vehicle Barrier System (VBS) (Tl 2515/132)

General On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection of Plants and Materials," to modify the design basis threat for radiological sabotage to include the use of a land vehicle by adversaries for transporting personnel and their hand-carried equipment to the proximity of vital areas and to include the use of a land vehicle bomb. The amendments require reactor licensees to install vehicle control measures, including vehicle carrier systems (VBSs), to protect against the malevolent use of a land vehicle. Regulatory Guide 5.68 and NUREG/CR-6190were

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l l 38 issued in August 1994 to provide guide,ce acceptable to the NRC by which the licensees could meet the requirements of the amended regulation A February 28,1996, letter from the licensee to the NRC forwarded Revision 8, to its physical security plan. The letter stated, in part, that vehicle control measures meet the criteria of 10 CFR 73.55(c)(7),(8) and (9) and Regulatory Guide 5.68 dated August 1994. A NRC June 19,1996, letter advised the licensee that the changes submitted had been reviewed and were determined to be consistent with the provisions of 10 CFR 50.54(p) and were acceptable for inclusion in the NRC-approved security pla This inspection, conducted in accordance with NRC Inspection Manual Temporary Instruction 2515/132," Malevolent Use of Vehicles at Nuclear Power Plants," dated January 18,1996, assessed the implementation of the licensee's vehicle control measures, including vehicle barrier systems, to determine if they were commensurate with regulatory requirements and the licensee's physical security pla S8.2 Vehicle Barrier System (VBS) Insoection Scoce (Tl 2515/132)

The inspectors reviewed documentation that described the VBS and physically inspected the as-built VBS to verify it was consistent with the licensee's summary description submitted to the NRC and was in accordance with the provisions of NUREG/CR-619 Observations and Findinas The inspectors' walkdown of the VBS and review of the VBS summary description disclosed that the as built VBS was consistent with the summary description and met the specifications in NUREG/CR 619 Conclusion The inspectors determined that there were no discrepancies in the as-built VBS or the VBS summary descriptio S8.3 Bomb Blast Analvsis Insoection Scoce (Tl 2515/132)

The inspectors reviewed the licensee's documentation of the bomb blast analysis and verified actual standoff distances provided by the as built VB . . - . _ _ _ _ _ _

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39 Observations and Findinas The inspectors' review of the licensee's documentation of the bomb blast analysis determined that it was consistent with the summary description submitted to the NRC. The inspectors also verified that the actual standoff distances provided by

their as-built VBS were consistent with the minimum standoff distances calculated using NUREG/CR-6190. The standoff distances were verified by actual field

, measurements.

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! Conclusion No discrepancies were noted in the documentation of bomb blast analysis or actual

standoff distances provided by the as-built VBS.

S8.4 Procedural Controls

. Insoection Scooe (Tl 2515/132)

The inspectors reviewed applicable procedures to ensure that they had been revised to include the VBS, t Qbservations and Findinas The inspectors reviewed the licensee's procedures for VBS access control measures, surveillance and compensatory measures. The procedures contained effective controls to provide passage through the VES, provide adequate surveillance and inspection of the VBS, and provide adequate compensation for any

degradation of the VB Conclusion

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The inspectors' review of the procedures applicable to the VBS disclosed no discrepancie S8.5 Security Force Strike Continaency Plans Insoection Scope (Tl 2515/132)

1- Evaluate the licensee's strike contingency plans to verify that trained personnel are available to support staffing levels consistent with staffing requirements and that plans are in place to insure security operations continue in a safe and orderly manner in the event of a strike.

- Observations and Findinas

$ The inspectors reviewed the licensee's contingency plan to be implemented in the event of a strike, and reviewed training and qualification records for contingency force personnel that were available to replace striking officers in the event of a strike,

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40 Conclusion The licensee had taken appropriate action to insure that an adequate number of trained and qualified personnel were available to meet regulatory required staffing levels and continue security operations in a safe and orderly manner in the event of a strik F1 Control of Fire Protection Activities F1.1 Eire in the 2 'C' Service Air Comoressor insoection Scooe (71707. 62707. & 71710)

The inspectors reviewed the station response to a fire in the 2 'C' service air compressor on December 11,199 Observations and Findinas Operators responded to a fire in the 2 'C' service air compressor at about 3:20 on December 11,1997. The fire was extinguished within five minutes and was limited to the compressor motor. PECO conducted a critique of the fire brigade response and considereo that overall efforts were good, but found some opportunities for improvement in communications between the control room and the fire brigad PECO discovered that the fire was most likely caused by an inboard bearing cage failure and subsequent overheating of the bearing. The inspectors reviewed the maintenance history on the air compressor and found that annual preventive maintenance had been conducted as schedule In early November, predictive maintenance technicians identified noisy bearings and high vibration on the compressor motor. The motor was placed on an increased monitoring frequency (biweekly). Further readings in early December indicated increasing vibration amplitudes and maintenance technicians recommended that the motor be worked before its scheduled preventive maintenance date of May 199 The maintenance was tentatively re-scheduled for March 1998. Based on review of the vibration data, maintenance technicians did not believe that failure was imminent, so they did not request a higher priority for this corrective maintenance issu The inspectors discussed the issue with the preventive maintenance technicians and independently reviewed the bearing vibration data. The inspectors determined that the data did not show signs of imminent failure. The inspectors had no concerns with the priority the maintenance group placed on inis issue based on information reviewed, Conclusions The station fire brigade response to a fire in the 2 'C' service air compressor motor was good; however, operations identified some opportunities to improve

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communications between the control room and the fire brigade. The inspectors reviewed predictive maintenance activities on this component and identified no concerns. Technicians had been monitoring increased motor bearing vibration, but the data did not indicate that a failure was imminen V. Manoasment Meetinas X1 Exit Meeting Summary

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The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on January 20,1998. The licensee acknowledged the

findings presented.

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The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie X2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments A discovery of a licensee operating their facility in a manner contrary to the Updated Final

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Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the UFSAR descriptions. While performing the inspections discussed in this report, the inspectors

, reviewed the applicable portions of the UFSAR that related to the areas inspected. The

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inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters. Since the UFSAR does not specifically include security program requirements, the security inspectors compared licensee activities to the NRC approved physical security plan, which is the applicable document. While performing the security inspection discussed in this report, the inspectors reviewed Chapter 3 of the Plan titled, " Protected Area Perimeter." Based on discussions with security supervision, procedural reviews, and direct observations, the inspectors determined that barriers were installed and maintained as described in the Plan and applicable procedures.

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LIST OF ACRONYMS USED action request (AR)

action statement (AS)

administrative guideline (AG)

APRM gain adjust factor (AGAF)

as low as-reasonably achievable (ALARA)

average power range monitors - neutron (APRMs)

central alarm system (CAS)

control rod drives (CRDs)

con'rol room emergency ventilation (CREV)

core power and flow log (CPFL)

core spray (CS)

core thermal power (CTP)

design input document (DID)

electro-hydraulic control (EHC)

eleventh refueling outage (3R11)

emergency core cooling system (ECCS)

emergency diesel generator (EDG)

emergency operating procedures (EOP)

emergency preparedness (EP)

emergency service water (ESW)

end-of-cycle (EOC)

engineering change request (ECR)

engineered safety feature (ESF)

fitness-for-duty (FFD)

fix-it-now (FIN)

functional testing (FT)

general procedure (GP)

Generic Letter (GL)

health physics (HP)

high efficiency particulate (HEPA)

high pressure coolant injection (HPCI)

high pressure service water (HPSW)

hydraulic control unit (HCU)

improved TS (ITS)

independent safety engineering group (ISEG)

inservice inspection (ISI)

inspector follow-up items (IFis)

instrument and control (l&C)

intermediate range monitor - neutron (IRM)

intrusion detection systems (IDS)

licensee event report (LER)

limited senior reactor operators (LSROs)

limiting conditions for operation (LCO)

load tap changer (LTC)

local leak rate test (LLRT)

loss of coolant accident (LOCA)

loss of off-site power (LOOP)

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low pressure coolant injection (LPCI)

lubricating oil (LO)

main control room (MCR)

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modification (MCD)

motor generator (MG)-

nuclear maintenance division (NMD)

nuclear quality assurance (NOA)

NRC-approved physical security plan (The Plan)

nuclear review board (NRBi offsite dose calculation manual (ODCM)

offsite power start up source #2 (2SU)

offsite power start-up source #3 (3SU)

Peco Energy (PECO)

performance enhancement program (PEP)

plant operations review committee (PORC)

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post-maintenance testing (PMT)

primary containment (PC)

primary containment isolation system (PCiS)

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primary containment isolation valve (PCIV)

protected area (PA)

quality assurance (QA)

quality control (QC)

radiation monitoring system (RMS)

radiologically controlled area ;RCA)

radiological protection and chemistry (RP&C)

rated thermal power (RTP)

reactor core isolation cooling (RCIC)

reactor engineer (RE)

reactor feed pump (RFP)

reactor operator (RO)

reactor protection system (RPS)

reactor water cleanup (RWCU)

reliability centered maintenance (ROM)

residual heat removal (RHR)

safety evaluation report (SER)

- safety related structures, system and components (SSC)

safety relief valve (SRV)

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scram solenoid pilot valve (SSPV)

secondary alarm system (SAS)

secondary containment (SC)

security force members (SFM)

senior reactor operator (SRO)

shift technical advisor (STA)

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shift update notice (SUN)

source range monitor (SRM)

specific gravity (SG)

spent fuel pool (SFP)

standby gas treatment (SGTS)

standby liquid control (SLC)

station blackout (SBO)

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structure, system and component (SSC)

surveillance requirement (SR)

surveillance test (ST)

systems approach to training (SAT)

technical requirements manual (TRM)

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technical specification (TS)

temporary plant alteration (TPA)

training and qualification (T&O)

turbine bypass valve (BPV)

turbine control valve (TCV)

turbine stop valve (TSV)

undervoltage (UV)

unresolved item (URI)

updated final safety analysis report (UFSAR)

vehicle barrier system (VBS)

wide range neutron monitoring system (WRNMS)

INSPECTION PROCEDURES USED IP 37551: Onsite Engineering Observations IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Observations

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IP 81700: Physical Security Program for Power Reactors IP 84750-01 Radioactive Waste Treatment, and Effluent and Environmental Monitoring

IP 92700: Onsite Follow of Written Reports of Nonroutine Events at Power Reactor Faci 4 ties IP 92901: Operations Follow-up IP 92902: Follow-up - Engineering IP 92903: Follow up - f.1aintenance IP 92904: Plant Support Follow-up .

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IP 93702: Prompt Onsite Response to Events at Operating Power Reactors Tl 2515/132: Malevolent Use of Vehicles at Nuclear Power Plants ITEMS OPENED, CLOSED, AND DISCUSSED Ooened 50 277/97-08-01 VIO Cold Weather Preparations Procedural Non-compliance 50 278/97 08-01 VIO Cold Weather Preparations Procedural Non-compliance 50-277/97-08-02 IFl Unit 2 Circulating Water System Problems 50-277/97 08-03 URI Missed TS SR Ter.t for Verification of Proper Flow in the Recirculation Loops 50-277/97-08-04 URI Unexpected Trip of Unit 2 Main Turbine During Start-up 50-277/97-08-05 NCV Procedure Non-Adherence: Minor Safety Significance 50-?78/97-08-05 NCV Procedure Non-Adherence: Minor Safety Significance 50-277/97-08-06 IFl Review of Failure to Remove MOVs Motor Breaks and Broiwn Worm Shaft Gear Failure Analysis

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50 278/97-08-06 IFl Review of Failure to Remove MOVs Motor Breaks and Broken Worm Shaft Gear Failure Analysis

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Closed 50 277/97-08-05 NCV Procedure Non Adherence: Minor Safety Significance 50-278/97-08-05 NCV Procedure Non Adherence: Minor Safety Significance j 50-277/96-04-04 URI EDG Output Breaker Response During Testing 50 278/96-04-04

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URI EDG Output Breaker Response During Testing

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50 278/97 03-01 VIO Inadequate Safety Evaluation for Unit 3 Turbine Building Modification

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v t e Letter Sequence '
TAC:MA1741, (Approved, Closed)
Initiation Acceptance... Administration Questions Answers Results Approval, Approval Other:
MONTHYEAR1998-10-01 [Table View]

IR 05000277/1997008

Text

REGION I

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1997 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 99(0) Security Operator Exams Emergency Planning Other