IR 05000277/1998002

Insp Repts 50-277/98-02 & 50-278/98-02 on 980315-0504. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20249A083
Person / Time
Site:	Peach Bottom
Issue date:	06/09/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20249A071	List: IR 05000277/1998002 ML20249A070 ML20249A078
References
50-277-98-02, 50-277-98-2, 50-278-98-02, 50-278-98-2, NUDOCS 9806160037
Download: ML20249A083 (34)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

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License No DPR-44 l DPR-56 l

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Report No Docket No Licensee: PECO Energy Company Correspondence Control Desk P.O. Box 195 Wayne, PA 19087-0195 Facility Name Peach Bottom Atomic Power Station Units 2 and 3 Inspection Period: March 15,1998 through May 4,1998 Ir.spectors: A. McMurtray, Senior Resident inspector M. Buckley, Resident inspector B. Welling, Resident inspector R. Lorson, Senior Resident inspector, Seabrook A. Lohmeier, Senior Reactor Engineer A. Blamey, Reactor Engineer Approved by: Clifford J. Anderson, Chief

. Projects Branch 4 Division of Reactor Projects 9906160037 990609 PDR ADOCK 05000277 0 .PDR

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l EXECUTIVE SUMMARY '

Peach Bottom Atomic Power Station 4 NRC Inspection Report 50-277/98-02,50-278/98-02 This integrated inspaction report included aspects of licensee operations; surveillance and maintenance; engineering and technical support; and plant support areas. The report covers a seven-week period of resident inspection and an inspection by a regional engineering specialis Ooerations:

e- Operator performance during the April 6,1998, troubleshooting of a minor level increase in the Unit 2 torus was very good. Operations personnel exhibited good planning and coordination for the troubleshooting activities. (Section 01.1)

e The removal of the fifth stage feedwater heaters from service for Unit 2 on April 29, 1998, was performed effectively using appropriate procedures, clear communications between operators, attentive reactor engineering oversight, and I effective control by shift supervision. (Section 01.3)

e The one NRC-identified and severallicensee-identified instances of valves found mispositioned or out of their expected position collectively represent weaknesses  !

in plant status control. This item remains unresolved pending further progress in l the investigations into these issues, as well as inspector review into possible i violations of Technical Specification 5.4.1 for procedure adequacy, and 10CFR 50 Appendix B, Criterion XVI, Corrective Action. (Sections O2.2, M4.1, E2.2)

e Around March 22,1998, the inspectors identified that high pressure coolant injection (HPCI) system operating procedure SO 23.1.B, "HPCI System Manual i Operation," was not adequately maintained, because inaccuracies with the HPCI  !

vibration monitoring system were not described. The procedures failed to account  !

for vibration system inaccuracies during the first 30 minutes of operation. This was  !

considered a violation of the station Technical Specifications for procedure  !

adequacy. This was considered significant since the instructions in SO 23.1.B-2 to trip the HPCI pump on high vibration readings could erroneously shut down a HPCI pump, when performing a safety function, at a time when the HPCI pump vibration monitoring equipment was known to be unreliable. (Section 03.2) l Maintenance:

o The maintenance activities associated with the packing adjustment on the 2D high pressure service water pump, E-3 emergency diesel generator, ar'd circuit breaker maintenance activities for the emergency service water sluice gate motor operated valve (MOV) 2233A were performed in accordance with procedures in a thorough and professional manner. (Sections M1.1, M1.2, M1.5)

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Executive Summary (cont'd) .

e The controls to remove a control rod drive mechanism were good. Licensee self assessment activities were effective in that the licensee identified a future improvement in communications between the control room and maintenance personnel undervessel when the mechanism was 'irst removed. (Section M1.3)

o ' On July 9 and 10,1997, instrument and control personnel failed to comply with the

- technical. specification action time requirement for placing the 'A' channel of the main control room emergency ventilation (MCREV) system in trip within six hours of making the channelinoperable. This was a violation of Technical Specification 3.3.7.1. This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (Section M8.1)

Enaineerina:

e The engineering performance and oversight of the contractors were good for the modification work associated with the Unit 3 jet pump riser cracking repai (Section E1.1)

e On March 22,1998 reactor e' ngineers did not recommend positive actions to reduce a thermal limit ratio when approaching the Technical Specifications limit, which did not meet operations department expectations for const..vative plant operations. No technical specification limits were exceeded. The licensee procedure enhancements and other corrective actions for this issue were adequate.- (Section E2.3)

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e Plant engineering provided timely, comprehensive support following the

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identification of a increasing trend in the tailpipe temperature for safety relief valve (SRV) 71K by control room operators during the Unit 3 startup following the 3J12 outage. (Section E2.4)

e Engineering personnel performed a good investigation of a shorter than expected reactor period during the startup following outage 3J12. . The actions identified by engineering to improve the test data review for the Wide Range Neutron Monitoring System and the rod worth predictions by the PECO reactor fuel services group were comprehensive. (Section E2.5)

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Executive Summary (cont'd)

Plant Suonort:

e On April 24,1998, the NRC identified that licensee. failed to maintain the radiation area signs at the access to the North Isolation Valve Room (NIVR), a known and surveyed radiation area, visible and conspicuous. In addition, the inspectors found the NIVR door open and unguarded. This is considered a violation for failure to properly establish, implement, and risaintain procedures and instructions as required by Peach Bottom Technical Specifications 5.4.1. This condition had the potential for plant personnel to unknowingly enter a posted high radiation area without proper -

knowledge of ongoing conditions or radiological conditions for the NIVR. (Section 1 R1.1 ) -

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O TABLE OF CONTENTS EX EC UTIV E S UM M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii TA BLE O F C O N TE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v Summary of Plant Status . . . . . . . . . . ................................. 1 1. O pe ra t io n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 Torus Level increase Troubleshooting Observations (Unit 2) . . . . . 1 01.2 Observation of Startup from Outage 3J12 . . . . . . . . . . . . . ... 2 01.3 Removal of the 5th Stage Feedwater Heaters from Service (Unit 2)

...............................................3 02 Operational Status of Facilities and Equipment ................... 4 02.1 Unit 3 Drywell Close-out inspection . . . . . . . . . . . . . . . . . . . . . . 4 02.2 Plant Status Control Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 03 Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . 6 03.1 Clearance and Tagging Review . . . . . . . . . . . . . . . . . . . . . . . . . 6 03.2 (Closed) URI 50-277(278)/98-01-01High Pressure Coolant injection Post-Maintenance In-Service Test . . . . . . . . . . . . . . . . . . . . . . . 7 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 07.1 Clearance and Tagging Assessment . . . . . . . . . . . . . . . . . . . . . . 8 11. M ainte n a n ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 M1.1 - 2D High Pressure Service Water (HFSW) Pump Packing Adjustment

...............................................9 M1.2 Preventive Maintenance on E-3 Emergency Diesel Generator Room Fans...........................................10 M1.3 Control Rod Drive Mechanism Changeout (Unit 3) . . . . . . . . . . . 10 M1.4 Surveillance Observations .............. ............11 M1.5 Emergency Service Water Sluice Gate MOV2233A Circuit Breaker M ainten an ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . 12 ~

l M4.1 Unit 3 Main Steam Line Flow Instrument Valve Found Out of Position ........................................12 l- M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 .

M8.1 (Closed) Licensee Event Report (LER) 50-277(278)/2-97-004 Non-compliance with Technical Specifications when Technical l Specification Action Times were Exceeded and VIO 50-277(278)/

97-05-02 Inadequate Procedure for Tripping Control Room Ventilation Radiation Monitor .........................13 M8.2 - (Closed) VIO 50-277(278)/96-08-01 Failure to Ensure Contractor Personnel Were Qualified . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 l

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Table of Contents (cont'd) j

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l l i . Engineering . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 5 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 ;

E Installation of Jet Pump Riser Clamps (Unit 3) ........... 15 ;

' E1.2 Forced Interruption of Power Generation in 1997............ 15 E2 _ Engineering Support of Facilities and Equipment . . . . . . ............ 16 E2.1 ' (Closed) URI 50-277(278)/97-02-05 Review of Iratrumentation-that Requires Electrical Power to Perform a Technical Specification -

Function, VIO 50-278/97-02-04,and LER 3-97-003 . . . . . . . . . . . 16 E2.2. Residual Heat Removal Stayfull Valves Found Out of Position . . . 17

.E2.3 Control of Reactor Thermal Limit Ratio (Unit 2) . . . . . . . . . . . . . 18 E2.4 Safety Relief Valve 71K Tailpipe Temperature increase (Unit 3) . 2 E2.5 Unexpected Short Reactor Period During Startup . . . . . . . . . . . .. 20-E2.6 Resolution of ISEG Findings ..........................22

.E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 i E8.1 ' (Closed) LER 50-277(278)/2-96-04 High Pressure Coolant injection System inoperable Due to a Leak in Cooling Water Relief Valve 1. 22 i EB.2- (Closed) URI 50-278/95-18-01 HPCI Steam Line Vibration . . . . . 23  :!

E8.3 '(Closed) VIO 50-277(278)/97-02-02 incorrect Scaffolding . l Installation . . . . ..................................23 1 E8.4 (Closed) VIO 50-277(278)/96-06-01 Failure to Fully Understand the impact of Modification P-231. . . . . . . . . . . . . . . . . . . . . . . 24 E8.5 . (Open) Unresolved item 97-02-03," Station Blackout Line Testing Acceptance Criteria" . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

'lV. Plent Support ................................................24 l R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 24  !

R1.1 Control of Radiation Areas . . . . . . . . .. . . . . . . . . . . . . . . . . . 24 V. M anage ment Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 6 -

X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 X2- Review of Updated Final Safety Analysis Report (UFSAR) Commitments . 27

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i ATTACHMENT i Attachments - List of Acronyms Used

- Inspection Procedures Used .

- Items Opened, Closed, and Discussed s

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Report Details Summary of Plant Status PECO operated both units safely over the period of this repor ' Unit 2 began this inspection period at 100% power. On March 21, unit load was reduced to perform control rod pattern adjustments, waterbox cleaning, and reactor feed pump turbine testing. On April 27, unit load was reduced due to an inoperable control rod. On

- April 29,- following repairs, the unit was restored to 100%.

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Unit 3 began this inspection period shutdown in maintenance outage 3J12 for repairs on jet pump riser cracks. On March 25, foreign material was found in the 3A core spray pump. This issue was documented in MRC Inspection Report 50-278/98-05. On April 4, the unit was returned to 100%, where it remained for the rest of the period. PECO

. occasionally reduced unit load for control rod pattern. adjustments and other activitie .

1. Operations 01 . Conduct of Operations'

01.1 Torus Level increase Troubleshooting Observations (Unit 2) Insoection Scope (71707)

The inspectors observed portions of troubleshooting activities conducted by  !

operations personnel for a slow increase in Unit 2 torus level, j 1 Observations and Findinos

. In early April 1998l operators observed a slight increase in torus level over a 24- l hour. period. This condition was reported to plant engineering personnel, who drafted a tr'oubleshooting procedure to determine the cause. Operations personnel then performed the procedure, Troubleshooting, Minor Rework and Testing i Procedure (TMT)98-126, on April 6,199 i

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, The in:pectors determined that the planning and coordination for this testing was . l

- good ~and that communications between equipment operators and the control room

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appropriate technical specifications action statements during these activities. The i L minor increase in torus level was resolved.

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l 1 Topecal headmes such as 01, Me, etc are used in accordance with the NRC standardaed reactor inspection report outhne. Individual reports are not m expected to address all outline topic ~

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'2 l ~ The troubleshooting activities included shutting and opening the residual heat L removal system (RHR) torus suction valve MO 2-10-13A. During the valve stroking,

! .the assigned equipment operator noted that the valve motor operator sounded different than other similar motor operators.

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Operations personnelinitiated further troubleshooting and inspection of the motor

operator to determine the cause of the abnormal noise. On April 7, maintenance technicians determined that the motor operator was operating satisfactorily. The cause of the sound was an installed motor brake.

The inspectors documented in NRC inspection report 50-277(278)97-08that a

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found installed on the 2C RHR torus suction valve, MO-2-10-13C. An inspector followup item (IFI) 50-277(278)/97-08-06was opened to track the identification and inspection of other motor operated valves for motor brakes. The inspectors will followup on any issues with the installed motor brake on MO-2-10-13A during that

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IFl revie The inspectors determined that the equipment operator exhibited a good questio".!ng ;

attitude by identifying the abnormal noise on the MO-2-10-13A motor operatti j The inspectors also noted that shift management took prompt action to investigate this issu Conclusions Operator performance during the April 6,1998, troubleshooting of a minor level increase in the Unit 2 torus was very good. Operations personnel exhibited good planning and coordination for the troubleshooting activitie i i

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. 01.2 Observation of Startuo from Outaae 3J12 l I :Jnsoection Scoos (717071- .l l

The inspectors observed control room operations at various times during the Unit 3 ;

startup from March 30 through April 2,1998,'following maintenance outage 3J1 . Observations and Findinas On March 30, the inspectors noted that the control room staff was not aware that l maintenance personnel were performing post-maintenance test cycling of vacuum ,

relief valve (VRV) 9096H during the drywell walkdown. Communications between '

i maintenance and control room personnel were not effective since VRV 9096H was cycled several times before the operations personnel were able to get the ,

- , - maintenance technician to stop cycling the valve. While this event had no safety

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I l 3 The reactivity changes observed were adequately controlled. However, the

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inspectors observed weak three-part communication during control rod scram l timing. During this evolution, the person announcing.the control rod to be scrammed did not give enough time, nor acknowledge the repeat back of the

! operator observing the rod scram from the front panel. Scram timing was a well-l controlled evolutio An unexpected short period occurred during the startup and is ~ discussed in Section L E2.5. The initial actions by the operators for the short period were goo On March 30,1998, the inspectors noted increased noise in the control room during peak activity periods. During these periods, thers were 15 to 20 people in the control room. During these periods order in tha control room was challenge During periods with fewer personnel in the control room and decreased activity, the inspectors observed that operation of the unit became more deliberat Conclusions From March 30 through April 2,1998, control room activities during the Unit 3 startup following outage 3J12 were adequately controlle .3 Removal of the 5th Staae Feedwater Heaters from Service dinit 2)

- LrL9DeCtion ScoDe (71707)

The inspectors observed portions of the removal of the fifth stage feedwater heaters from service on Unit Observations and Findinos

' As part of the reactor coast down activities, Peach Bottom has typically removed l

the fifth stage feedwater heaters from service. There are three separate fifth stage feedwater heaters (A, B, and C) normally in service. This evolution reduced feedwater temperature and allowed a higher reactor power to be maintaine .The Unit 2 fifth stage feedwater heaters were removed from service on April 29, 1998, using abnormal operating procedure AO 12.4-2, " Removing The Fifth Stage i Feedwater Heaters From Service During End Of Cycle Coast down and Return To Normal Shutdown Condition," Revision 1. Reactor engineers monitored the response of the reactor plant to the changes in feedwater temperature due to removal of the heaters from service. The operations shift manager and control room l

supervisor also provided oversight for the evolutio !

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! . The communications with equipment operators and.within the control room were l very good. After each feedwater heater was taken out of service, operators - !

carefully monitored plant parameters until an acceptable response was verifie .

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4 Conclusions The removal of the fifth stage feedwater heaters from service for Unit 2 on April 29, 1998, was performed effectively using appropriate procedures, clear communications between operators, attentive reactor engineering oversight, and effective controls by shift supervisio Operational Status of Facilities and Equipment O2.1 Unit 3 Drvwell Close-out Insoection Insoection Scoos (71707)

On March 25,1998, the inspectors performed a close-out inspection of the Unit 3 drywell at the end of maintenance outage 3J12 to verify that material used for maintenance activities had been removed and that the drywell was ready for purge to facilitate plant start-u Observations and Findinas The inspectors identified some foreign materialin the drywell. This material included a screwdriver, several small allen wrenches, and several small screws that were found in the lowest level of the drywell. The most significant items found during this inspection were a couple of unattached metal, pipe lagging, cover These covers were found laying in the middle level of the drywell and appeared to be left over from piping lagging reinstallatio The inspectors also observed water leaking in a steady stream through some ventilation ductwork. The source of this leakage was believed to be from a sealin the upper cavity area. This leakage stopped after the upper cavity was drained down to support reactor vessel head reinstallation and the ventilation was dried out prior to plant restar Conclusions Following resolution of the items identified during the closeout inspection of the drywell at the end of maintenance outage 3J12, the ccadition of the Unit 3 drywell was acceptable for restar .2 Plant Status Control issues Insoection Scope (71707)

The inspectors reviewed one NRC-identified and several licensee-identified instances of valves found mispositioned or out of their expected positio _ _ - _ _ _

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I 5 Observations and Findinas )

p During February and March 1998, plant personnel had identified several examples of L valves found out of.their required or expected position. In most cases, these valves l lwere in non-safety related, balance-of-plant systems, and there was no impact on the plan On April 16,1998, the inspectors observed that the Unit 2 'B' steam jet air ejector -

, main steam supply header control valve, 2-CV-22398, was not in its expected

! position. The volve was in the manual (band) position instead of automatic and

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indicated approximately 60% open.' In comparison, the corresponding Unit 3 valve a was in the automatic position and was closed. The Station Operating (SO) procedures including checklist for. aligning the steam Jet air ejector system provided limited guidance for the position of this valve. Control room personnel indlcated that this valve may have been placed in the abnormal position during the trip of the

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2C~ circulating water pump on January 14,1998. Even though this valve was not in the expected position, this condition had no impact on the steam jet air ejector

> system since 2-CV-2239B was completely isolated from the air ejector flo In addition to these non-safety related valves, the licensee identified three safety related valves found mispositioned during this inspection period. On March 27, instrumentation and control (l&C) technicians found a Unit 3 main steam line flow instrument isolation valve out of position while the unit was shutdown. Also, on March 17, a manual rssidual heat removal (RHR) system valve was found out of position in each unit. ' These issues are discussed in detail in Sections M4.1 and E2.2, respectivel . The Operations department has initiated actions to address component mispositionings on a generic basis. These actions included reviewing procedures by system and improving equipment restoration detail';in work package The inspectors determined that,' taken collectively, these issues indicated a weakness in plant status control. Many of_the mispositionings were related problems in procedure adequacy. Also, the inspectors noted that procedure

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- adequacy problems had been previously identified with the RHR valves discussed above, but procedure revisions were not made until after these valves were found out of positio l

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Investigations of some of these issues were still in progress at the conclusion of this inspection period. This item remains unresolved pending further progress in these investigations. The inspectors will review the findings from these investigations to determine if there are any potential violations of Technical Specification 5.4.1 for procedure adequacy, and 10 CFR 50 Appendix B, Criterion XVI, Corrective Actions, i for the timeliness of the corrective actions for the RHR valves. (URI 50-

-277(278)/98-02-01)

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6 Conclusions l The one NRC-identified and several licensee-identified instances of valves found mispositioned or out of their expected position collectively represent weaknesses i in plant status control. This item remains unresolved pending further progress in the investigations into these issues, as well as inspector review into possible

violations of Technical Specification 5.4.1 for procedure adequacy, and 10 CFR 50

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Appendix B, Criterion XVI, Corrective Action Operations Procedures and Documentation 03.1 Clearance and Taaoina Review insoection Scoce (71707)

l The inspectors reviewed selected safety related clearances: '

1. 97002635 #98001346 #98001301

1. 98001298 #98031548 Observations and Findinas The inspectors noted that the tagouts/ clearances were properly prepared and authorized in accordance with the Peach Bottom Clearance and Tagging Manua Some of the tagouts were derived from pre-established " library" clearances that-were written to support repetitive jobs, such as preventive maintenance. The original clearances were based on plant drawings that in many cases had been revised. The inspectors noted that operations personnel appropriately verified that the clearances were reviewed against the latest revisions of the drawing The inspectors found that some clearances contained recommendations or key information for operations shift supervision. For example, one clearance i recommended that a shift briefing be held to discuss specific aspects of the wor The inspectors considered this to be good, useful supporting inforrnation for operations shift personne The inspectors identified no concerns with the tags hung in the plant. Also, the '

clearance sheets reviewed by the inspectors were properly filled out, appropriately reflecting the positions of the tagged component Conclusions The selected safety related tagouts reviewed were acceptably prepared and l implemented.

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~ 03.2 jClosed) URI 50-277(278)/98-01-01Hiah Pressure Coolant Iniection Post- l Maintenance In Service Test '! Inspection Scooe (71707 & 61726)

The inspectors reviewed control room procedures and the vibration monitoring equipment for operation and testing of the Unit 2 High Pressure Coolant Injection

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t .Qhaprvations and Findinas As discussed in NRC inspection report 50-277(278)/98-01, operations performed surveillance procedure, ST-O-023-301-2, Revision 19, "HPCI Pump, Valve, Flow and Unit Cooler Functional and in-Service Test" to verify operability of the Unit 2 HPCI system on March 13,1998.

. After startup of the HPCI system, the inspectors questioned operations shift l ~ management as to the significance of the high HPCI vibration meter and recorder i r readings in the control room. The meter indicated greater than 5.0 mile and the

! recorder had spikes up to 5.92 mils. The control room supervisor referred to the i operating procedure, SO 23.1.B-2, Revision 11, "HPCI System Manual Operation,"

l: for the limit on vibration. Personnel monitoring the HPCI booster pump vibration  ;

L locally communicated that pump operation was in the alert range, but no exact j ' number was determined. After reviewing SO 23.1.B-2, shift management directed .

L the Unit 2 operator to shutdown the HPCI turbine. Based on the inspectors'-

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observations, the operators appeared to question the reliability of the monitoring . l

'l equipment in the control roo )

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- The HPCI system remained inoperable until further testing and local monitoring L -indicated that vibration readings were within acceptable values. Operations and- 1 j maintenance personnel determined that there was no actual vibration problem with I i the HPCl pump / turbine. The HPCI system valves and compartment coolers functioned as expected during the tes !

- The inspectors discussed the operation of the HPCI control room vibration monitor with the system manager, operations and 1&C personnel. The licensee indicated

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that the vibration monitoring equipment needs to be in operation for at least 30 o minutes before it can be considered reliable. Due to its design, the control room L . vibration monitoring equipment does not function properly until it warms up to b operating' temperatur . The inspectors noted that the precautions of system operating procedure SO 23.1.B-2,"HPCI System Manual Operation," Revision 11, direct the operator to trip .

w -- m < the HPCl turbine immediately if excessive vibration (greater than 3.5 mils) is observed. There was no direction in the procedure to wait for the vibration j monitoring equipment to warm up prior to being used. The inspectors were j concerned that due to the instructions in SO 23.1.B-2 and the unreliability of the i HPCI pump vibration monitoring equipment, a normally operating HPCI pump could 1 i

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be shut down when needed to perform a safety function. The precaution directing

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immediate tripping of the turbine at 3.5 mils operation was based on a vendor l recommendation.

l After further review of this issue, the licensee initiated changes to operating procedures'for both units. The revisions added a caution statement to procedures SO 23.1.B,"HPCI System Manual' Operation" and SO 23.7.A, "High Pressure Coolant injection Automatic Initiation Response," to make operators aware of vibration monitoring system inaccuracies during the first 30 minutes of operation.

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- Technical Specification 5.4.1 requires that written procedures be established, L implemented, and maintained covering activities as recommended in Regulatory Guide 1.33, Appendix A, November 1972. These activities include startup, l

operation, and shutdown of safety related system Contrary to the above, around March 22,1998, the inspectors identified that the licensee' failed to properly maintain the procedures for HPCI system manual operation, since the procedures did not provide instructions about the inaccuracies of the HPCI system vibration monitoring system. (VIO 50-277(2781/98-02-02)

!' Conclusions .

O Around March 22,1998, the inspectors identified that high pressure coolant injection (HPCI) system operating procedure SO 23.1.B, "HPCI System Manual l: Operation," was not adequately maintained, because inaccuracies with the HPCI vibration monitoring system were not described. The procedures failed to account

[' for vibration system inaccuracies during the first 30 ' minutes of operation. This was l considered a violation of the station Technical Specifications for procedure adequacy. This was considered significant since the instructions in SO 23.1.B-2 to

trip the HPCI pump on high vibration readings could erroneously shut down a HPCI

, pump, when performing a safety function, at a time when the HPCI pump vibration L monitoring equipment was known to be unreliable.

p 0 Quality Assurance in Operations

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07.1 Clearance and Taaaina AssesFE' tD1 JDanection Scone (71707) l

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The inspectors reviewed the findings and attended the exit meeting for a Quality Assurance (QA) clearance and tagging program assessmen Observations and Findinas OA assessors generated five Performance Enhancement Program (PEP) reports )

during the clearance and tagging assessment. The PEPS primarily addressed ;

documentation deficiencies in the operations and maintenance areas. The 1

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9-assessment listed several findings and recommendations, indicative of a critical review.

l Conclusion I

l The Quality Assuranca clearance and tagging program assessment was critical and thorough.

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11. Maintenance

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M1- Conduct of Maintenance . M 1.1 2EL}4iah Pressure Service Water (HPSW) Pumo Packina Adiustment Insoection Scope (62707)

The inspectors cbserved the maintenance activities and reviewed the procedure for a packing adjustment on the 2D high pressure service water (HPSW) pum Observations and Findinos

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Operators had written an action request to address water spraying from the 2D

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HPSW pump during operation. Pump performance was within required parameters.

j On April 22, maintenance personnel from the Fix-It-Now team made adjustments to

the 2D HPSW pump packing using procedure M-032-001, Revision 3, "High Pressure Service Water (HPSW) Pump Maintenance."

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The inspectors observed that the maintenance technicians established proper communications and coordinated activities with the operators in the control roo The technicians followed the maintenance procedure step-by-step, as required for a L- Level 1 procedure. The inspectors also observed that the maintenance supervisor provided good oversight of packing adjustment activitie After the packing adjustments were made, the inspectors questioned the maintenance technicians about the criteria for packing gland leakoff. Although the technicians were experienced and knowledgeable of the packing adjustment

,

requirements, they were not aware of any leakoff criteria. After further L investigation, the technicians determined that the packing gland leakage should be approximately 8-10 drops / minute per inch of shaft diameter. Due to temperature limitations, a slight spray of water was still coming from the packing gland after final packing adjustments. The technicians documented in the work order that the pump should be repacke !

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10 Conclusions i

On April 22,1998, the work to adjust the packing on the 2D high pressure service j water pump was performed in accordance with procedures in a thorough, j professional manner. The work supervisor provided good oversight. Technicians l - were expenenced and generally knowledgeable of their assigned task M1.2 Preventive Maintenance on E-3 Emeraency Diesel Generator Room Fans i

l Insoection Scoce (62707)

The inspectors observed portions of preventive maintenance performed on the E-3 emergency diesel generator (EDG) room fans on April 13,199 Observations and Findinas The inspectors observed that maintenance personnel were using the applicable work orders and procedures. The inspectors noted that the maintenance technicians were knowledgeable of the work activities and that pre-job briefings were held prior to performing wor The inspectors also noted that appropriate technical specification action statements were entered while the EDG was inoperable. No issues were identified with planning and work control for this maintenance activit Conclusions The preventive maintenance for the E-3 emergency diesel generator room fans on April 13,1998 was performed according to procedure . M1.3 Control Rod Drive Mechanism Chanoeout (Unit 3) ,

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' Insoection Scoce (61726 & 62707)

!

The inspectors observed the removal of a control rod drive mechanism from the undervessel area during maintenance outage 3J1 .

l Observations and Findinas I

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The inspectors observed good control of the control rod drive mechanism removal evolution. Nuclear Maintenance Division (NMD) technicians performed the work in the undervessel area, in direct communications with personnel in the reactor building. The work was monitored from the reactor building by video monitors.

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The inspectors also observed good support by radiological protection personne ,

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!, Control room personnel were briefed on the evolution and were aware that this was considered to be an operation with the potential to drain the reactor vessel f

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l (OPDRV). One reactor engineer was stationed in the control room to coordinate the i evolutio Operations id'entified an opportunity to improve communications at a kay part of the evolution, specifically when the. control rod drive mechanism was first removed. At this step, there was a concern about excessive leakage. Ths control room

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operators were not in direct communications with personnci nesr the undervessel area and they assumed that there was no excessive leakago .i no report was made to the control room. Operations personnel determined that a positive report of no excessive leakage would provide more timely information to the operators. This enhancement was documented during the post-job critique and was planned for

' incorporation in future control rod drive mechanism removal wor Conclusions The controls to remove a control rod drive mechanism were good. Licensee self assessment activities were effective in that the licensee identified a future improvement in communications between the control roora and the maintenance personnel undervessel when the mechanism was first remove M1.4' Surveillance Observations Insoection Scoos (61726)

The inspectors observed operators perform the following surveillance test procedures:

S" 410h ' a~ 12 "B" RHR Loop Pump, Valve, Flow, and Unit Cooler-Frf 31 and inservice Test (Unit 2)

i M, 3t L2, Rev 4 " Motor Driven Fire Pump Operability Test' Observat, q j ngs The operators w ..s ne these surveillance tests in accordance with the procedur Cor.clusions The operators performed the two observed surveillance tests in accordance with the procedur ,

M1.5 Emeroency Service Water Sluice Gate MOV2233A Circuit Breaker Maintenance Insoection Scone (62707)

< The inspectors observed the maintenance activity and reviewed the work documentation for the circuit breaker inspection / maintenance for the emergency service water (ESW) sluice gate motor operated valv l i

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'~ Observations and Findinas-

.On April 22,1998, the inspectors observed electrical maintenance technicians performing maintenance on the circuit breaker for the ESW sluice gate motor operated valve, (MOV) 2233A. The technicians informed the inspectors that operations personnel had authorized the work, and the inspectors verified that the clearance ~ tag was on the correct breaker. The inspectors observed that the .

technicians were professional and familiar with the procedure. .The breaker maintenance was completed without incident. The work activity was performed per procedure M-056-001, Revision 14, "480 Volt Motor Control Center Circuit Breaker -

Assembly and Cubicle Thermal Maintenance." fanclusions Or April 22,1998, the circuit breaker maintenance activities for the emergency

' service water sluice gate motor operated valve (MOV) 2233A were performed well and in accordance with station ~ procedure M4 Maintenance Staff Knowledge and Performance M4.1 Unit 3 Main Steam Line Flow Instrument Valve Found Out of Position Insoection Scoos (62707)

The inspectors reviewed an investigation by instrumentation and controls (l&C)

personnel into the discovery of a Unit 3 main steam line flow instrument isolation valve found out of its required posit!o Observations and Findinas On March 27,1998, following a reactor vessel pressure test, operators received alarms indicating a failure had occurred on a 'B' main steam line flow instrumen Operators directed l&C technicians to perform a calibration check of main steam line flow instrument During the calibration check, l&C technicians found the low side isolation valve (ISV-3-02-117BL) for the 'B' main steam line flow instrument shut. ' its required position was open. The main steam line flow instrument provides a safety related signal to shut the main steam isolation valves on a high flow conditio .

I&C personnel reviewed maintenance work orders and found that the last recorded operation of the valve was during refueling outage 3R11. The documentation ,

L indicated that the associated instrument, DPT-3-02-1178, was properly restored to l

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[ service. Plant personnel also reviewed operations daily surveillance logs and l  : operator logs and found that DPT-3-02-117Btracked satisfactory while the plant :

was in operation between 3R11 and the shutdown for outage 3J12. No failure alarms were recorded from this transmitter. Based on this information, Peach

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Bottom personnel concluded that the instrument was operable while Unit 3 was in operatio Further review indicated that some work was performed on the same instrument rack as DPT-3-02-117B during 3J12. Thus, I&C personnel determined that it was possible that technicians may have inadvertently operated ISV-3-02-1178L while Unit 3 was shutdown. Alternatively, they questioned whether the valve may have been slightly off its seat or the valve leaked by, allowing the instrument to indicate normally l&C personnel initiated actions to check the integrity of the valve during the next outag I&C personnel also identified that the procedure that last controlled the operation of ISV-3-02-117BLdid not include valve-by-valve restoration instructions. Specifically, ST-l-02B-650-3," Excess Flow Check Valve Operability," Revision 6, only required i technicians to verify the restoration of the instrumen The inspectors determined that this issue represented an example of weak plant status control, as discussed in Section O2.2. Although the investigation by Peach Bottom personnel did not identify the activity that caused the mis-operation of the valve, it revealed that the procedure that last operated it did not specify valve-by-valve restoration. Further, the inspectors noted that this procedure did not include independent verification that the instrument was properly returned to service. The inspectors will review this issue as part of the unresolved item discussed in Section O Conclusions

.

This valve is one of several examples documented in this report of valves found mispositioned or out of their expected position and collectively represent weaknesses in plant status control. This item remains unresolved pending further progress in the investigations into these issues, as well as inspector review into possible violations of Technical Specification 5.4.1 for procedure adequacy, and 1 10 CFR 50 Appendix B, Criterion XVI, Corrective Action M8 Miscellaneous Maintenance issues M8.1 (Closed) Licensee Event Reoort (LER) 50-277(278)/2-97-004 Non-comoliance with Technical Specifications when Technical Specification Action Times were Exceedgd and VIO 50-277(278)/97-05-02 Inadeouate Procedure for Triooino Control Room Ventilation Radiation Monitor On July 9,1997, the 'A' channel of the main control room emergency ventilation

,

(MCREV) was removed from service for repair and testing. The channel was declared inoperable and placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as required by technical specification 3.3.7.1. Subsequently, instrument and control technicians placed the local key-lock switch of the 'A' channel MCREV radiation monitor into the "ON" position which negated the channel trip that had been inserted. The switch was in the "ON" position for greater than six hours after the channel was

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, removed from service. -A plant reactor operator (PRO) discovered this condition on L , July 10.; The 'A' channel was returned to the tripped condition after the local key-l' lock switch was returned to the "OFF" position. All work was stopped on the L radiation monitor pending further review of the event.

i l In inspection Report 50-277(278)/97-05,the inspectors determined that the

procedural controls for ensuring that the radiation monitor would be maintained in-l the tripped condition were inadequate. The NRC issued a violation for non-l compliance with technical specification 5.4.1 due to the failure to maintain adequate procedures to control this safety related activity.

I The inspectors reviewed the corrective actions from LER 50-277(278)/2-97-004 and VIO 50-277(278)/97-05-02. These corrective actions included revising General Procedure (GP)-25 Appendix 13, Revision 4, " Main Control Room Ventilation,-

Division l" and GP-25 Appendix 14, Revision 4, " Main Control Room Ventilation, L . Division 11." These revisions required a jumper installation to trip the MCREV radiation monitors instead of using the key-lock switches. Also, the corrective l

actions included requiring Operations and instrument and Control personnel to l review this event. The inspectors determined during on-site inspections that all of these corrective actions had been adequately completed and the inspectors had no l : additional concerns regarding this event.

L However, the failure to comply with the technical specification action time i L requirement on January 9 and 10,1997, for placing the 'A' channel of the MCREV l L in trip within six hours of making the channel inoperable was a violation of

Technical Specification 3.3.7.1. This non-repetitive, licensee-identified and

corrected violation is being treated as a Non-Cited Violation (NCV), consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-277(278)/98-02-03)-

L M8.2 (Closed) VIO 50-277(278)/96-08-01 Failure to Ensure Contractor Personnel Were L Qualified o i

$ NRC inspection Report 50-277(278)/96 08 identified that PECO had not evaluated H l' the qualifications of vendor personnel who performed soldering, crimping of electrical leads, and torquing evolutions on safety-related systems. PECO's H

corrective actions included: implementation of badging controls for vendor L personnel until verification of the worker's training and qualifications, and revision i

of the Vendor Craft Training Program (VCT-1) to strengthen the control and verification of vendor qualification The inspectors reviewed procedural changes that resulted from these corrective

- actions and concluded that PECO's corrective actions were reasonable and adequate. The inspectors had no additional concerns with this violatio !

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i 111. Ena!neerina i E1 Conduct of Engineering i

E Installation of Jet Pumo Riser Clamos (Unit 3) Insoection Scone (37551; 62707)

The inspectors reviewed engineering performance in implementing a major repair- '

l . through the use of contractors, including in-plant observations,' the 10 CFR 50.59 determinations and modification package P00769," Jet Pump Riser Structural

' Enhancements for PBAPS Unit 3."

- b. . Observations and Findinas The inspectors noted that engineering was effective in the oversight of the contractors repairing the Unit 3 jet pump riser pipe cracks. The jet pump riser

! cracks were repaired by installing clamps on the jet pump riser elbows. The ,

inspectors noted that the work was well planned. The inspectors also noted that close engineering oversight and support for the project existed, including visual ]

observation of the testing of the installation equipment at the contractor's facilit The inspectors had no concerns with the 10 CFR 50.59 evaluations for this l modification.

' Conclusions The engineering performance and oversight of the contractors were good for the modification work associated with the Unit 3 jet pump riser cracking repai .E1.2 - Forced Interruption of Power Generation in 1997 l

r Insoection Scone (37550)

The inspector evaluated PECO engineering response to forced power generation interruption during 1997.

L Observations and Findinas l

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The inspector reviewed the number and type of unplanned power generation interruptions (UPGI) for Units 2 and 3 shown in the Average Gross MWe Generation

Chart for 1997.. Three unplanned power interruptions for Unit 2 to below 600 MWe p included an EHC fluid leak, loss of DC voltage during swap of battery chargers, and  !

. . . EHC back-up pressure set _ amplifier repair. . Unit 3 experienced four unplanned power interruptions, including recirculation pump motor low oil level trip, recirculation pump trip due to a cable fault, hydraulic control unit maintenance, and a safety relief valve leak repair. In each case, the inspectors found that site

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! 16 engineering had determined the appropriate root causes and effective corrective actions had been taken to address safe operation.

l Conclusions Engineering had performed effective evaluations of the three Unit 2 and four Unit 3 unplanned power generation interruptions and the root causes and corrective actions for those events were appropriat E2 Engineering Support of Facilities and Equipment E2.1 (Closed) URI 50-277(278)/97-02-05 Review of Instrumentation that Reauires Electrical Power to Perform a Technical Specification Function. VfD 50-278/97-02-04, and LER 3-97-003 Insoection Scoce (37551)

The inspectors reviewed the corrective actions for the inoperable 3C reactor feed pump turbine high water level trip function. This technical specification function was inoperable between April 4 and April 14,1997, due to a blown fuse in the pump control circuit. The inspectors also reviewed PECO's actions to identify and resolve issues concerning technical specification required channel checks that do not verify power available to circuits that need power to operate. This concern was identified during the initial review of the inoperable 3C trip functio Observations and Findinas in NRC Inspection Report 50-277(278)/97-02, the inspectors identified that the surveillance test specified by PECO to meet the daily channel check of the 3C reactor feed pump turbine high level trip instrument was not complete, since it did not verify power to the feed pump trip logic. The inspectors questioned whether similar inadequacies could exist for other surveillance tests as a result of the licensee's conversion to improved Technical Specifications. PECO initiated a review of other instrumentation to determine if similar conditions existe As part of the corrective actions to the violation for the inoperable 3C high level trip function, the licensee changed the shiftly reactor operator rounds to verify that there was power to the reactor feed pump turbino high level trip instrumentatio This was performed by completing the daily channel functional surveillance through observation of an illuminated light in the control roo PECO initiated an Action Request (A1099989)to review channel checks associated with new or more restrictive Technical Specification requirements. This review was part of the corrective actions for VIO 50-278/97-02-04. This review determined whether a loss of power could cause a loss of channel function and whether the power loss could be detected. The results of this review indicated that nine applicable items had channel check requirements. All were detected by an alarm

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l annunciator in the control room, were not affected by a loss of power, or were

' included on the reactor operator shift rounds and checkoff sheets.

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Ths inspectors noted that the station prints showed that the safety function of four of the items identified would be unaffected by a loss of power. The inspectors also verified that the reactor operator rounds included items where an alarm annunciator

would not indicate a loss of power. Based on a review of the licensee's acti'

request results, survei'. lance tests, and station electrical prints, the inspectot ;ound

'that the items identified during the channel check review were resolve The inspectors reviewed the corrective actions for LER 50-278/3-97-003and VIO 50-278/97-02-04,which documented the 3C reactor feed pump turbine high water level trip function inoperability. In addition to the corrective actions discussed above, the licensee performed the following training:

• instructed plant personnel on the importance of promptly communicating to the operating shift any operability concerns identified during plant troubleshootin *' instructed engineering support personnel on the importance of timely review of outstanding corrective maintenance requests pertaining to their systems and of developing a questioning attitude concerning troubleshooting result Conclusion  !

The corrective actions resulting from the inoperable 3C reactor feedpump turbine high water level trip function between April 4-14,1997, were adequately complete E2.2 Residual Heat Removal Stavfull Valves Found Out of Position Insoection Scone (37551. 71707)

The inspectors reviewed the circumstances regarding the residual heat removal 1RHR) valves HV-2-10 65 and HV-3-10-65 out of their required positio a Qbaprvations arid Findinas On March 17,1998, the operations manager found RHR stayfull system valve HV-3-10-65 out of its required position. The valve 'was open, instead of closed, as !

specified in plant check-off lists and drawings. Operations personnel also found the .!

Corresponding valve in Unit 2 out of the required position.

" The Unit 2 valve was last operated by RT-O-010-6_10-2,"2A RHR Heat Exchanger j Leak Test," Revision 5, which inenrrectly restored the valve to the open positio {

The Unit 3 valve was left open due to an incorrect restoration position specified in

clearance #97002299. Operations personnel identified that several procedures that

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re-positioned the HV-10-65 valves did not restore these valves to the required

[

position. The normal position of the HV 10 65 valves was changed as part of the t- a-I

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resolution to Non-Conformance Report (NCR) 96-03167. Operations personnel also noted that these procedural problems had been identified by Quality Assurance (QA)

in September 1997, during a OA surveillance. Although procedure changes had been initiated, the procedures had not been revised before the valves were found out of positio Operations and engineering personnel performed a prompt operability determination for these mispositioned valves. They concluded, after eeview of Inservice Testing (IST)information, that system operability was not affected. The licensee was investigating the issue through the Performance Enhancement Program (PEP)

proces The inspectors noted that three issues contributed to this weakness in plant status control that led to the HV-10-65 valves being out of their required position:

i 1) Operations personnel specified incorrect restoration instructions for a clearanc ) Engineering personnel did not ensure that the procedures that controlled the i HV-10-65 valves left the valves in the correct positio l 3) Procedure changes initiated in response to QA findings were not completed l before one of the valves was manipulated by one of the procedures, j The inspectors noted that the licensee's investigation into these issues was still in progress at the completion of the inspection period. This issue will be reviewed further following completion of this investigation, as part of the unresolved item discussed in Section 0 Conclusions This valve is one of several examples documented in this report of valves found mispositioned or out of their expected position and collectively represent weaknesses in plant status control. This item remains unresolved pending further progress in the investigations into these issues, as well as inspector review into possible violations of Technical Specification 5.4.1 for procedure adequacy, and 10 CFR 50 Appendix B, Criterion XVI, Corrective Action E2.3 Control of Reactor Thermal Limit Ratio (Unit 2) Insoection Scooe (71707 & 37551)

The inspectors reviewed the licensee-identified inappropriate control of a reactor thermallimit ratio during a Unit 2 power ascensio Observations sad Findinas

During power ascension on March 22,1998, operators and reactor engineers were monitoring the thermal limit ratio to help ensure that they would not exceed the l Technical Specification maximum value of 1.0. Reactor engineers ran a 3D

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monicore predictor case to determine the expected value of the maximum fraction of limiting critical power ratio (MFLCPR) during power ascension. The predicted value for MFLCPR was 0.983 when the reactor was at full powe Power ascension continued to 100%. Initially when the reactor reached 100%

power, the reactor engineer determined that the MFLCPR value was 0.990. The reactor engineer and operations shift management discussed the thermallimit value and chose to continue to monitor it, rather than inserting control rods to reduce the thermallimit ratio. They believed that the core xenon transient would improve the thermallimit margin. The next thermallimit printout showed that the MFLCPR value was at 0.996. The control room operators inserted control rods to reduce reactor power and the thermal limit valu Reactor engineering and operations personnel reviewed this event and concluded that the final thermal limit value was too close to the Technical Specification limi Reactor engineering personnel determined that the procedural guidance to reactor engineers and operations for MFLCPR control needed enhancement. Specifically, reactor engineering initiated the following changes:

• - Power ascension will be temporarily halted at 95% until tuli power thermal limit values are evaluated for sufficient margi * Procedure guidance will specify that when a thermallimit ratio reaches 0.990, operaters should take action to reduce power, rather than to continue to monitor thermallimit trend Operations management told the inspectors that the event did not meet their expectations for conservative plant operations. However, they considered the-corrective actions for this event to be appropriat .

The inspectors noted that the event was discussed with all reactor engineers. The inspectors also observed that the temporary hold at 95% was implemented during a Unit 2 power ascension in late April. The inspectors reviewed the planned corrective actions and discussed these actions with reactor engineering and operations personnel. The inspectr>rs determined that procedure enhancements and I other corrective actions for this issue were adequat I Conclusions '

On March 22,1998 reactor engineers did not recommend positive actions to  !

reduce a thermal limit ratio when approaching the Technical Specifications limit,  !

l which did not meet operations department expectations for conservative plant l operations. No technical specification limits were exceeded. The licensee

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- procedure enhancements and other corrective actions for this issue were adequat ,

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E2.4 ? Safetv' Relief Valve 71 K Tailaine Temperature increase (Unit 3) Insoection Scone (62707 & 37551)

[ ' The inspectors reviewed the engineering support for an increasing trend in tailpipe l t temperature for safety relief valve (SRV) 71K.

l Observations and Findinos

l Several days after the Unit 3 startup following 3J12, on April 7,1998, operators observed an upward trend in the tailpipe temperature for SRV 71 K. All other ten

^

SRV tailpipe temperatures for Unit 3 had reached stable temperatures. This

observation was referred to plant engineering personnel for resolution.

L

! Engineering personnel determined that the SRV 71K tailpipe temperature had not yet l reached its steady-state, baselino temperature. Engineering promptly provided shift -

operations personnel with a monitoring action plan and developed a temperature curve showing the expected temperature rise with time. Based on a comparison

! with historical data,' engineers determined that the SRV was not leakin Operations personnel plotted the actual temperature rise over several days.

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, . The inspectors reviewed the monitoring plan and the actual plotted temperature L

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. data, iThe' inspectors noted that the actual temperature data closely followed the predicted temperature rise. The inspectors determined that engineering personnel L , demonstrated a good understanding of the SRV expected performanc . Conclusions )

Plant engineering provided timeiy, comprehensive support following the identification of an increasing trend in the tailpipe temperature for safety relief valve (SRV) 71K by control room operators during the Unit 3 startup following the 3J12 ,

outage, j L

E2.5 : Unexoected Short Reactor Period Durina Startuo

, .. l Insoection Scope (71707 & 37551)

The inspectors reviewed an engineering investigation of an unexpected short period l during the reactor startup from maintenance outage 3J1 l Observations and Findinas I During the startup' from the 3J12 outage, operators observed an abnormally short l

. reactor period while pulling control rod 14-51 to criticality. The osak period noted

- on wide range neutron monitoring system (WRNMS) channel 'C' was approximately 30 seconds, which is shorter than the minimum expected period of 50 second Operators took prompt, appropriate actions to take the reactor subcritical until the event was fully understood by operatioris and reactor engineering personnel. The l'

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second approach to criticality resulted in a much longer period of approximately 200 seconds.

L Plant engineering personnel reviewed the event and identified two conditions which combined to produce the short period. The first condition was a higher than

expected period response on the WRNMS channel 'C.' The second condition was a l higher than expected notch worth for rod 14-51.

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The higher than expected period response on the WRNMS channel 'C' was due to the "mean squared voltage (MSV) offset" parameter being set higher than the other L ' channels. The larger offset setting led to a step change in the indicated period seen

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by the operators during this event. The 'C' channel indicated a period of -

I approximately 30 seconds when other channels indicated between 50 and 70 seconds.' Engineering personnel determined that a more thorough review M the WRNMS testing data during outage 3R11 would have identified the higher than

. nominal setting. Engineering personnel also determined that a procedural limit l should have been set for the MSV offset value.-

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The second contributing factor was a higher than expected notch worth for rod 14-51 from notch 8 to 10. Prior to the Unit 3 startup, PECO reactor fuel services engineers noted, during a computer model run of core performance, that rod 14-51 was not.a high worth rod. PECO concluded that the fuel services engineering group should investigate this event and determine if improvements could be made to the -

accuracy of the off-line computer model.

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The inspectors discussed the event with engineering staff members. The inspectors considered the engineering investigation of this event to be thorough. The

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engineering investigation identified a number of areas for improvement and engineering initiated several corrective actions to address the investigation finding . The inspectors noted that the shorter-than-actual period indication on WRNMS channel 'C' did not result in any operability concerns, but did result in a challenge to operators during the startu ConclusioD1

' Engineering personnel performed a good investigation of a shorter than expected reactor period during the startup following outage 3J12. The actions identified by Engineering to improve the test data review for the Wide Range Neutron Monitoring System and with rod worth predictions by the PECO reactor fuel services grou were comprehensive.

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E2.6 Resolution of ISEG Findinas t

. Insoection Scone (37550)'

l The inspectors evaluated the interface between engineering and the Independent Safety Ent,ineering Gro'up (ISEG)in support of evaluating and providing corrective action in resolution of plant issues. The inspectors reviewed synopses of ISEG findings and corrective actions taken by engineering, Observations and Findinas The inspectors found that engineering personnel had effectively addressed ten ISEG recommendations. The inspectors determined that engineering personnel provided the appropriate technical response and corrective actions to each of these ISEG

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concern '

' Conclusions e

L Engineering personnel provided the appropriate technical response and corrective

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actions to the ten ISEG concern E8 Miscellaneous Engineering issues l

E (Closed) LER 50-277(278)/2-96-04 Hiah Pressure Coolant Iniection System l-Inonerable Due to a Leak in Coolina Water Relief Valve

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On April 17,1996, the Unit 2 %gh Pressure Coolant injection (HPCI) system was i declared inoperable and removeJ from service following the discovery of a 10 drop per minute leak from the inlet nipple of the HPCI cooling water line relief valve. This relief valve was a 1" x 1-1/2" Crosby model JMB-C-E relief valve. Following the discovery, the cooling water system was isolated and the relief valve was replace ' The valve replacement was performed in approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and the valve was  ;

. returned to service long before the technical specification 14 day action time l ex9 ired. The removed relief valve was sent to the PECO Valley Forge lab for failure analysis. The results from this analysis indicated that the failure mechanism was L , intergranular Stress Corrosion Cracking. Corrective actions from this event included I having engineering personnel work with the valve manufacture to determine if any l other valves constructed of the same nickel alloy were supplied to the statio The inspectors reviewed the licensee's docurmtation for this event and inspected

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the Unit 2 HPCI pump and turbine. Based on these on-site inspections, the

inspectors determined that all corrective actions for this event had been adequately completed. lThe licensee determined subsequent U this event that all similar vintage Crosby relief valves at Peach Bottom had been replaced. The inspectors had no additional concerns with this issue.

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23 4 E8.2 (Closed) URI 50-278/95-18-01 HPCl Steam Line Vibration The inspectors determined that the HPCI steam line vibration reduction program, involving comprehensive analytic justification together with increased support i rigidity modifications, had reduced pipe line vibration. The inspectors conducted an  !

on-site walk-down inspection from a catwalk over the HPCI steam piping while HPCI  !

was in operation and found that the amplitudes of vibration had been greatly reduced as a result of additional supports. However, one section of 10 inch pipe ,

was observed to vibrate at a greater amplitude than determined by the original j analysis. Engineering personnel provided the inspectors with an updated analytic <

summary justifying that the section was acceptable based on measured vibratory

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stress amplitudes being below the material endurance limit. The inspectors reviewed the analytic summary and had no concerns. On this basis, there had been  ;

no regulatory requirements violated, and the inspectors had no additional concerns with this issu I E8.3 (Closed) VIO 50-277(278)/97-02-02 Incorrect Scaffolding Installation NRC Inspection Report 50-277(278)/97-02 identified multiple examples where scaffolding had been installed in contact or close to safety related systems and components without a prior engineering evaluation. PECO developed several corrective actions including:

• Development of a team to review the scaffolding procedural requirements and revision of the Scaffolding Erection Procedure (M-C-700-335)to clarify the scaffoldi,g erection guidanc * Training of personnel, including supervisory staff, on the M-C-700-335 procedural requirements and change * Conducting a comprehensive plant walkdown to identify other potential scaffolding problem The inspectors performed a walkdown of selected scaffolding installations and did not identify any concerns regarding the separation of scaffolding from safety-related structures and components. The inspectors also reviewed the changes to M-C-700-335 and randomly verified that personnel and supervisory staff had received training on the M-C-700-335 requirements. The inspectors concluded that PECO's corrective actions for this violation were adequate and had been met. The inspectors had no additional concerns with this issu _ _ _ _ _ _ _ _ _ _ . l

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E8.4 (Closed) VIO 50-277(278)/96-06-01 Failure to Fully Understand the imoact of

Modification P-231 NRC Inspection Report 50-277(278)/96-06 noted that PECO implemented modification P-231 to the emergency diesel generator starting circuitry without fully understanding the impacts of this change. Specifically, PECO installed this -

modification without recognizing that it affected the residual heat removal pump starting t?me. The corrective actions for this violation included revising engineering

! procedure MOD-C-09, " Design Control and Processing Of Engineering Change L Requests." This revision required that safety-related, electrical logic design changes l - have a formal review to' determine the operational impact and included the need to perform and document a thorough change analysis in the course of a design l verification _for modifications. Additionally, PECO trained design engineers on the

- MOD-C-9 requirements and expectations for design verification. The inspectors L reviewed the changes to MOD-C-9 and the training provided for the design engineers and concluded that PECO's actions ware acceptable. The inspectors had no additional concerns with this violatio E8.5 l(Ocen) Unresolved item 97-02-03 " Station Blackout Line Testina Accentance Criteria"

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'NRC Inspection Report 50-277('278)/97-02 questioned whether 'the Station Blackout

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. Line (SBO) test acceptance criteria of greater than 7000 KW 'was adequate during

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SBO line load testing. This acceptance criteria was consistent with the PECO submittal and the NRC safety evaluation which documented that the station met the NRC SBO requirements; The information submitted by PECO stated that 7000 KW would be the design load necessary to get both units to safe shutdown. The inspectors discussed this issue with an electrical system manager who indicated L that approximately 7400 KW would actually be required to place both units in a shutdown condition. The system manager also indicated that additional SBO line parameters were monitored during the test to ensure that the SBO line was capable of meeting its design loading requirements. The inspectors will continue to review

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this issue to determine whether PECO's test criteria and test methods are adequate and to resolve the discrepancies between the information submitted to the NRC and the requirements necessary to meet the SBO rul IV. Plant Sunnort R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Control of Radiation Areas Insoection Scone (71750)

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The inspectors reviewed instructions, procedures and practices for control of Radiation Areas including control of the Uni + 2 North isolation Valve Room (NIVR)

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[ b. . Observations and Findinos While performing an inspection in the reactor building on April 24,1998, the

, inspectors found the door to the NIVR open and unattended. The radiation posting L . signs could not be seen, since the door was against the room wall. The licensee had not posted any other radiations signs for the room while the door was open.

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The only barrier which prevented general entry into this room was a strip of contamination tape on the floo The inspectors questioned a hsalth physics (HP) technician that was providing support to operations personnel working in the room about the posting requirements

,_ and controls for this room. The technician stated that there should have been a L barrier / posting at the entrance to the room and the door should have been shut.

ll After operatior.s personnel finished working in the NIVR, the HP technician closed l and locked the door before departing.

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The inspectors reviewed the Peach Bottom radiation survey record for this area and l ,

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determined that the general area radiction of the NIVR was less than 100 mrom/hr.

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, The NIVR was normally posted and controlled as a high rad:ation area because

' during an initiation of the high pressure coolant injection system, the room dose rate could exceed the 100 mrem / hour criteria. Peach Bottom decided to control the g room as a High Radiation Area in accordance with Peach Bottom Technical

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Specification 5. Health Physics procedure, HP-C-215," Establishing and Posting Radiologically l Controlled Areas," Revision 2, required each Radiation Area to be conspicuously

, posted with a sign or signs bearing the radiation' symbol and the words

" CAUTION l - RADIATlON AREA." Contrary to this requirement, when the inspectors initially arrived at the NIVR on April 24, the signa at the access to the NIVR were not visible or conspicuou This is considered a violation for failure to properly establish, implement, and L, maintain procedures and instructions as required by Peach Bottom Technical

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Specifications 5.4.1.' This condition had the potential for plant personnel to unknowingly enter a posted.high radiation area without proper knowledge of g ongoing conditions or radiological conditions for the NIVR. (VIO 50-277(278)/98-l- 02-04)

i Conclusions .

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i On April 24,1998, the NRC identified that licensee failed to maintain the radiation area signs at the access to the North isolation Valve Room (NIVR), a known and surveyed radiation area, visible and conspicuous, in addition, the inspectors found

. the NIVR door open and unguarded. This is considered a violation for failure to

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~ properly establish, implement, and maintain procedures and instructions as required

.by Peach Bottom Technical Specifications 5.4.1. This condition had the potential for plant persortnel to unknowingly enter a posted high radiation area without proper knowledge of ongoing conditions or radiological conditions for the NIVR.

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V. Manasement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results at the conclusion of the inspection at an exit meeting on May 6,1998. The licensee acknowledged the findings l presented. No proprietary information was identified by the license 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 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 inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter !

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L ATTACHMENT 1 LIST OF ACRONYMS USED AR action request AG administrative guideline AGAF APRM gain adjust factor l ALARA as-low-as-reasonably-achievable APRM average power range monitors - neutron CRD control rod drive CREV control room emergency ventilation CPFL core power and flow log CS core spray CTP core thermal power EHC electro-hydraulic control

ECCS emergency core cooling system l EDG emergency diesel generator EOP emergency operating procedures EP emergency preparedness ESW emergency service water l ECR engineering change request l ESF engineered safety feature FIN fix-it-now FT functional testing GP general procedure GL Generic Letter HP health physics HEPA high efficiency particulate HPCI high pressure coolant injection HPSW high pressure service water HCU hydraulic control unit ITS improved TS ISEG independent safety engineering group ISI inservice inspection IFl inspector followup items l&C instrument and control IRM intermediate range monitor LER licensee event report LCO limiting conditions for operation l LLRT local leak rate test

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LOCA loss of coolant accident l LOOP loss of off-site power l LPCI low pressure coolant injection j LO lubricating oil MFLCPR maximum fraction of limiting critical power ratio MOD modification MG motor generator NMD nuclear maintenance division PECO PECO Energy PEP performance enhancement program t

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- Attachment 1

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PORC- ! plant operations review committee PC .. primary containment QA quality assurance l QC , ; quality control '  !

RMS radiation rnonitoring system RC ' radiologically controlled area -

RP& radiological protection and chemistry RCIC ~ reactor core isolation coolinD j RE reactor engineer 1RFP reactor feed pump .

i RO reactor operator

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reactor protection' system - I RWC reactor water cleanup RHR residual heat removal SER- : safety evaluation report SRV ' safety relief valve-SSPV scram solenoid pilot valve S secondary containment -

SRO- senior saactor operator STA ' shift technical advisor SRM: source range monitor -i SFP- spent fuel pool SGTS ' standby gas treatment

SLC standby liquid control SBO station blackout SSC . structure, system and component SR : surveillance requirement

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ST- surveillance test TS technical specification URI unresolved item

.UFSAR . updated final safety analysis report WRNMS ' wide range neutron monitoring system i

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Attachment 1 3

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INSPECTION PROCEDURES USED i i

IP 37550: Engineering Observations  !

IP 37551: Onsite Engineering Observations IP 61726: Surveillance Observations IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support Observations IP 92700: Onsite Follow of Written Reports of Nonroxine Events at Power Reactor Facilities IP. 92901: Operations Followup IP 92902: Followup - Engineering IP 92903: Followup - Maintenance IP 92904: Plant Support Followup IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-277/98-02-01 URI Plant Status Control issues 50-278/98-02-01 URI Plant Status Control Issues 50-277/98-02-02 VIO Failure to Properly Maintain Procedures for HPCI System Manual Operation 3 50-278/98-02-02 VIO Failure to Properly Maintain Procedures for HPCI System Manual Operation 50-277/98-02-03 NCV Failure to Comply with Main Control Room Emergency Ventilation Technical Specification Requirements 50-278/98-02-03 NCV Failure to Comply with Main Control Room Emergency Ventilation Technical Specification Reqv:rements

'50-277/98-02-04 VIO Failure to Properly implement Radiation Area Procedures 50-278/98-02-04 VIO Failure to Properly implement Radiation Area Procedures Closed 50-277/98-02-04 NCV Failure to Comply with Main Control Room Emergency Ventilation Technical Specification Requirements for Tripping a Control Room Ventilation Radiation Monitor 50-278/98-02-04 NCV Failure to Comply with Main Control Room Emergency Ventilation Technical Specification Requirements for Tripping a

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Control Room Ventilation Radiation Monitor 50-277/98-01-01 URI High Pressure Coolant injection Post-Maintenance Test I

50-278/98-01-01 URI High Pressure Coolant injection Post-Maintenance Test 50-277/2-97-004 LER Non-Compliance With Technical Specifications When Technical Specification Action Times Were Exceeded 50-277/97-05-02 VIO Inadequate Procedure For Tripping Control Room Ventilation Radiation Monitor l

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Attachment 1 4 50-278/97-05-02 VIO Inadequate Procedure For Tripping Control Room Ventilation Radiation' Monitor 50-277/97-02-05 URI Review of instrumentation that Requires Electrical Power to Perform a Technical Specification Function 50-278/97-02-05 URI Review of Instrumentation that Requires Electrical Power to Perform a Technical Specification Function 50-278/97-02-04. VIO . Inoperable Reactor Feed Pump High Reactor Level Trip 50-278/3-97-003 LER Technical Specification Non-Compliance Due To Loss of 3C

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Reactor Feed Pump High Water Level Trip 50-277/2-96-04 LER High Pressure Coolant Injection System inoperable Due'to Leak in Cooling Water Relief Valve 50-278/95-18-01 URI HPCI Steam Line Vibration 50-277/96-08-01 VIO Failure to Ensure Contractor Personnel Were Qualified 4 50-278/96-08-01 VIO Failure to Ensure Contractor Personnel Were Qualified I 50-277/97-02-02 VIO Incorrect Scaffolding installation 50-278/97-02-02 VIO Incorrect Scaffolding installation 50-277/96-06-01 VIO Failure to Fully Understand the impact of Modification P-00231 50-278/96-06-01' VIO Failure to Fully Understand the Impact of Modification P-OO231 Discussed /97-08-0 IFl Review of Failure to Remove MOVs Motor Breaks and Broken ,

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

, Worm Shaft Gear Failure Analysis 50-277/97-02-03 URI Station Blackout Line Testing Acceptance Criteria

[- 50-278/97-02-03 URI Station Blackout Line Testing Acceptance Criteria l=

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