IR 05000277/1997005

Insp Repts 50-277/97-05 & 50-278/97-05 on 970608-0809. Violations Noted.Major Areas Inspected:Operations, Surveillance & Maint,Engineering & Technical Support & Plant Support Areas

ML20217A655
Person / Time
Site:	Peach Bottom
Issue date:	09/12/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20217A643	List: IR 05000277/1997005 ML20217A639 ML20217A646
References
50-277-97-05, 50-277-97-5, 50-278-97-05, 50-278-97-5, NUDOCS 9709190254
Download: ML20217A655 (30)

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U. S. NUCLEAR REGULATORY COMMISSION REGION i Docket No , 50 278 License No DPR 44, DPR 56

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Licensee: PECO Energy Company Facility: Peach Bottom Atomic Power Station Units 2 and 3 i Dates: June 8,1997 - August 9,1997 Inspectors: W. L. Schmidt, Senior Resident inspector M. J. Buckley, Resident inspector B. D. Welling, Resident inspector Approved By: -- C. J. Anderson, Chief Reactor Projects Branch 4 -

Division of Reactor Projects

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9709190254 970912 PDR ADOCK 05000277 G PDR

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= EXECUTIVE SUMMARY

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Peach Bottom Atomic Power Station

.NRC Inspection Report 50 277/97-05,50 278/97-05

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This integrated inspection report includes aspects of licensee operations; surveillance and maintenance; engineering and technical support; and ,nlant support area Eant Ooerations:

• Verbal communications among operators in the control room and with others in the

! field were usually excellent. Operators typically conducted thorough briefings prior

to significant operations and t#ing, and following shift turnovers (Section 01).

[ * The inspectors found that emerger.cy operating procedure (EOP) tools and

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equipment were present as listed in the EOP tool inventory procedure, but identified a few minor discrepancies in EOP equipment condition. Overall, the inspectors

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concluded that the tools and equipment were adequate to support performance of EOPs (Section 02.2).

• The NRC identified that procedures at the Unit 2 reactor water cleanup (RWCU)

system local operating station were not being controlled as required. This issue is being treated as a non-cited violation. Corrective actions for this issue were adequate, although not formally documented in the corrective action' process =

(Section 33.1).

• The station's limited distribution of temporary procedure changes (TCs) affecting local operating stations posed an unnecessary burden for operators. Action was taken to expand the TC distribution practice (Section 03.2).

• _ PECO did not ensure that an inoperable control room ventilation radiation monitor was properly tripped and maintained in the tripped condition as required by-Technical Specification 3.3.7.1. Operations staff recognized the noncompliar'ce with technical specifications. However, PECO did not fully identify the extent of the procedure inadequacies that led to this condition. The failure to maintin adequate procedures to control this safety related activity is a violation of Technical Specification 5.4.1 (Section 03.3).

Maintenance:

-* The Unit 3 quarterly high pressure coolant injection (HPCI) system surveillance test was performed satisfactorily. Operators missed an opportunity to identify minor leakage on the HPCI pump inboard seal. Operations and engineering follow-up for this issue was vcry good (Section M1.1).

e l&C technicians satisfactorily accomplished the calibration of the drywell pressure instrumentation. The technicians displayed adequate knowledge _and were qualified il

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to perform this work. Some minor problems with attention to detail, partially repeating sections of the test, and communications did not affect the overall results (Section M1.2).

e During the calibration check of a control room ventilation radiation monitor, technicians were confused on how to determine acceptance criteria, and they signed off a step prior to recording the pertinent data. Further, technicians did not cover a detector hole, for foreign material exclusion purposes, until questioned by the inspector. These discrepancies revealed weaknesses in kno vledge and attention to detail by l&C technicians (Section M1.3),

s PECO identified, corrected, and made a complete operability determination of an exhaust leak on the E 2 EDG caused by a missing gasket on the exhaust ring catcher. Although PECO properly addressed the narrow generic issue for the exhaust ring catcher flanges, PECO did not initiate a PEP or other formal review and thus did not consider the root cause of the missing gasket and the potential for other gasket problems (Section M2.1).

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• The maintenance activities for the reph ament of MO 210-898 were characterized by strong planning and comprehensive execution. The activities had extensive maintenance supervisory oversight and coordination by the system manager (Section M2.2).

Enaineerina:

o The NRC identified procedural discrepancies associated with the emergency diesel generator air start reservoir pressure that could allow inadvertent entry into a TS action statement. Corrective actions were prompt, but failed to address all affected procedures. This issue was of minimal safety impact, but revealed inconsistencies between station procedures, setpoints, and technical specifications (Section E1.1).

• --The NRC conducted a review of PECO's analysis to allow a final feedwater temperature reduction of up to 80*F at full power for cycle extension and during coastdown. The licensee's justification for this operation addressed the appropriate analyses and design evaluations. Also, the inspectors independently observed actual feedwater temperatures to confirm final feedwater temperature did rsot exceed the 80*F limit. The operation of Unit 3 with up to 80*F reduction in feedwater would not significantly reduce the margin of safety to the public for the coastdown to 40% of rated power (Section E1.2),

e Overall, station response to a high pressure condition in the Unit 2 RHR discharge headers was good. Operators entered appropriate abnormal operating procedure Initial actions by the system manager to evaluate and monitor the issue were excellent. However, after the condition appeared to be resolved, engineering was slow in providing a documented status to operations (Section E2.1).

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.- PECO's immediate and follow-up actions in response to the identification of a failed relay during post maintenance testing of the E 1 EDG were timely and comprehensive (Section E2.2).

• PECO's operability evaluation for the leakage identified on the directional control valve on HCU 50 27 reflected generally strong knowledge of the system and the effects of the leakage. The monitoring plan was based on proper assumptions -

Overall, the evaluation and corrective actions were considered very good (Section

E2.3).

e Following the identification of voltage regulation problems on the E-2 EDG, PECO i properly declared it inoperable and took prompt and thorough corrective actions to

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restore operability. Engineering used sound investigative reasoning to address

{ potential common cause failures concerns for the other EDGs (Section E2.4).

• The inspector found that the initial actions related to the stroking failures of high pressure service water (HPSW) system motor operated valves MO-210-89A and MO 210-89C were performed promptly. A number of actions related to the analyses of these and similar auxiliary contact failures remain open. Corrective actions for a related PEP issue were pending or not fully resolved. Due to the ongoing nature of these activities, this issue is considered unresolved, pending completion of licensee analysis and subsequent NRC review (Section E2.5).

• The inspector concluded that PECO's immediate and follow-up actions in response to the identification of a failed relay during post maintenance testing of the E-1 EDG were timely and comprehensiv Plant Sucoort:

• The inspectors noted no negative issues during routine tours of the radiologically controlled areas of both plants. The tours included review of general housekeeping and radiological conditions, postings, and barriers (Section R1).

• The inspectors identified no significant areas of concern during observations of security force activities. The inspectors observed that repair activities on the access building roof were being continuously monitored by security personnel (Section S1).

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TABLE OF CONTENTS

. EX E C UTIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Su m m a ry o f Pla n t St a t u s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vil 1. O p e r a t i o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 i 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 General Comments ................................. 1 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 1 02.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . 1 02.2 Emergency Operating Procedure Tool Inventory . . . . . . . . . . . . . 2 03 Operations Procedures and Documentation ..................... 2 03.1 Uncontrolled Procedures at a Local Operating Station . . . . . . . . . 2 03.2 Distribution of Temporary Procedure Changes . . . . . . . . . . . . . . 3 03.3 Control Room Ventilation Radiation Monitor inoperable . . . . . . . 4 07- Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 07.1 Plant Operations Review Committee (PORC) Meeting ......... 5 ll. Maintenance and Surveillance ......................................6 M1 Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . . . . . . . . 6 M1.1 High Pressure Coolant injection System Surveillance Test (Unit 3)........................................-...... 6 M1.2 Calibration Check of Drywell Pressure Instrumentation PT/PISHH/PSH 3-10100D (Unit 3) ..................... 7 M1.3 Calibration of Control Room Radiation Monitor . . . . . . . . . . . . . . 8 M1.4 Maintenance Activities (62707) ............. ,......... 8 M2 Maintenance and Material Condition of Facilities and Equipment ...... 9 M2.1 E-2 Emergency Diesel Generator Exhaust Gasket Missing / Bolts Missing......................................... 9 M2.2 Replacement of "B" Residual Heat Removal Heat Exchanger Outlet Valve (Unit 2) ............................... 10 111. E n gi ne e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 E1 Conduct of Engineering .................................. 11 E Emergenty Diesel Generator. Starting Air Reservoir Pressure Discrepancy ..................................... 11 E1.2 Unit 3 Coastdown and Reactor Feed Pump injection Te m pe r atu re . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 14 E2.1 Residual Heat Removal System Discharge Header Pressurization (Unit 2) .............................. 14 E2.2 Failed Relay on E-1 Emergency Diesel Generator . . . . . . . . . . . . 15 E2.3 Control Rod Drive Withdrawal Directional Control Valve Leakage ........................................ 15 E2.4 E 2 Emergency Diesel Generator Voltage Regulation Problems . . 17 v

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E2.5 High Pressure Service Water System Valve Stroke Failures . . . . -17

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IV. Plant' Support ................................................ 18 R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . , , . . . 18 S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 18 S2 Status of Security Facilities and Equipment ....................'19

- V. M a nagem e n t M e e ting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 ;

X2 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19-X3 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 llST O F ACRONYM S US ED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

-- INSPECTION PROCEDURES U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 l

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j Bpoort Details Summary of Plant Statut PECO operated both units safely over the period of this repor Unit 2 remained at approximately 100% power throughout the perio Unit 3 entered the period at 98% power, in end-of cycle coastdown. Operators reduced power on June 1314 to investigate a speed control problem on the 3B reactor feed pump turbine. - The unit ended the period at approximately 81 % power, after removal of the fourth stage feedwater heaters on August l. Operations

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01 Conduct of Operations'

01.1 General Comments i

l Operators performed routine activities well Operator response to alarms and

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abnormal conditions was generally very goo The inspectors observed that verbal communications among operators in the control room and with others in the field were usually excellent. Operators typically

. conducted thorough briefings prior to significant operations and testing, and following shift turnover Operators removed the Unit 3 fourth stage feedwater heaters from service without inciden Operational Status of Facilities and Equipment O2.1 Enaineered Safetv Feature System Walkdowns (71707)

The inspectors used Inspection Procedure 71707 to walkdown accessible portions of the following engineered safety feature (ESF) systems:

• HPCI- Unit 3

• E-1 Emergency Diesel Generator

• E-2 Emergency Diesel Generator Equipment operability and material condition were acceptable in all cases. Minor discrepancies were brought to PECO's attention and corrective actions were initiated,

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02.2 Emeroency Ooeratina Procedure Tool Inventorv Insoection Scone (71707)

The inspectors conducted a partialinventory of tools and equipment used in the performance of emergency operating procedures (EGPs), Observations and Findinas

With the assistance of an operator, the inspectors inventoried EOP tools using

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Routine Test (RT) O 100 505-2, " Emergency Operating Procedere Tool Inventory."

The inspectors observed the following:

e The RT procedure was a complete rewrite and significantly improved over the previous recurring action request document. The RT was more clearly j written and included specific steps to ensure that the items were in good working order and to initiato corrective actions for deficiencies. The procedure rewrite was in response to Performance Enhancement Program I

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(PEP) Report Number 10006606, which had identified problems with the previous recurring action request documen * - For those lockers / panels inventoried, all tools and equipment specified in the procedure were present. Most iteins were in good working conditio * A few discrepancies in EOP equipment condition were noted: two multimeters had weak batteries; housekeeping in the T 215 Charging Equipment Lockers was poor; and two of the braided hoses in the T 215

- Lockers were not under the false bottom, as specifie Conclusions The inspectors found that EOP tools and equipment were present as listed in the EOP tool inventory procedure, but identified a few minor discrepancies in EOP equipment condition. Overall, the inspectors concluded that the tools and equipment were adequate to support performance of EOP Operations Procedures and Documentation 03.1 Uncontrolled Procedures at a Local Operatina Station Insoection Scope (71707)

The inspector reviewed plant procedures maintained at selected local operating station .

3 Observations and Findinag During a routine review of plant procedures, the inspector noted some improperly controlled procedures at a local operating station. Some of the system operating (SO) procedures in the controlled procedures binder at the Unit 2 reactor water cleanup (RWCU) filter demineralizer station were not the most recent revision or

- were not marked as " controlled by document services." The affected procedures were Level 1, which require step-by step adherence, in the case of one procedure, SO 12A.1.A 2, "RWCU Automatic Regeneration of a Filter Demineralizer and Post Filter," both revision 8 and revision 9 were in the binde During discussions with operations support and document services personnel, the inspector learned that the Unit 2 RWCU procedure binder had been inadvertently removed from the list of controlled procedure binders approximately 1 to 2 years  !

ago. Thus, document services personnel no longer inserted revisions nor audited the procedures in the binde Operations reviewed this issue informally, initiating no Action Request or Performance Enhancement Process (PEP) report. However, they identified no instances in which the non current procedures may have contributed to any improper operation of the system. Further, procedural guidance specifies that operators should verify the current revision status of a procedure prior to us .

Operations determined that operators had an opportunity to identify the procedure control deficiencies. PECO promptly corrected the RWCU procedure binder discrepancies and added the binder to the document services controlled procedures lis The inspector reviewed several other controlled procedures binders at local operating stations, including the Unit 3 RWCU operating station, and identified no other deficiencie Conclusions The NRC identified that procedures at the Unit 2 RWCU local operating station were not being controlled, as required. This issue constituted a document control violation of minor significance and is being treated as a non-cited violation consistent with Section IV of the NRC Enforcement Policy (NCV 50-277; 50-278/97005 01).

03.2 Distribution of Temocrarv Procedure Chances Insoection Scooe (71707)

The inspector reviewed station practices regarding the distribution of temporary procedure change . . _ _ _ _ _ _ _

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4 Observations and Findinas-The inspector observed that temporary procedure changes (TCs) were distributed only to selected "TC controlled" locations, such as the control room. Other local operating stations or satellite locations did not necessarily receive TCs even if the TCs affected the procedures at that station. For example, a TC affecting EDG procedures may not have been distributed to the controlled procedures binder at the EDG The inspector discussed the TC distribution practices with operations and document services personnel. Operators were expected to verify the revision level and TC status of each procedure prior to performing it at a local operating station. As an alternative, operators could pull a copy of the TC from the control room or from the controlled procedure files in the Administration Building. However, some operators indicated that the TC distribution practice was burdensome and had the potential to delay some actions specified in system operating procedures, for exampl Operations support supervision reviewed the TC distribution practices, as well as the operators' concerns. Operations determined that TCs should be distributed to all affected local operating stations and initiated the necessary changes to the TC distribution practice, Conclusions

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The inspector concluded that the station's limited distribution of temporary procedure changes affecting local operating stations posed an unnecessary burden for operators. Action was taken to expand the TC distribution practic .3 Control Room Ventilation Ra_sliation Monitor Inocerable Insoection Scoce (71707)

The inspector reviewed PECO's initial actions in response to a failed control room ventilation radiation monitor (RIS 0760A). The inspector assessed compliance with procedures and technician specifications as well as procedure adequac Observations and Findinas On July 9 at 5:30 p.m., operators declared RIS 0760A, a main control roora (MCR)

ventilation radiation monitor, inoperable due to unreliable channel check readings (approximately twice the levels of the other channels). Technical Specifications Section 3.3.7.1 requires this channel to be placed in trip within six hour Operators implemented GP-25, Appendix 13, "MCR Ventilation isolation, Division I,"

which placed the channel in trip at 10:25 p.m. At about 3:00 a.m. on July 10, operators observed, while clearing an unrelated alarm, that the " CONTROL ROOM RAD MONITOR DIV. I INITIATED" alarm cleared. This indicated that the radiation monitor channel had been taken out of the trip position. Operators determined that (

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a technician who was troubleshooting the system had removed the trip by changing a switch position and leaving it repositioned sometime after 10:25 p.m. on July The channel did not remain in the technical specification required condition until 3:25 a.m. on July 10, when operators re-tripped this channe Upon discovery of this issue, the inspector questioned how GP 25 controlled placing the channel in a tripped condition. After review of GP 25, operations personnel determined that GP 25 had never been exited, and was still active with the switch position inconsistent with this procedur The inspector also reviewed GP 25 for adequacy. The inspector determined that the procedure contained less than adequate controls to prevent resetting of the trip signal during troubleshooting. PECO initially issued a temporary change to GP 25 to add additional equipment status tags to alert operators and technicians of the equipment condition. After further review, PECO made additional changes to input a jumpered trip signal, independent of troubleshooting switch position Licensee staff recognized the non-compliance with Technical Specification 3.3. and initiated the required licensee event report. However, they did not identify the procedure inadequacies until questioned by the inspecto PECO identified that communications and human performance related problems also contributed to this event. Corrective actions had been initiated by the end of the inspection perio Conclusions PECO did not ensure that an inoperable control room ventilatior, radiation monitor was properly tripped and maintained in the tripped condition as required by Technical Specification 3.3.7.1, Operations staff recognized the non-compliance with technical specifications. However, PECO did not fully identify the extent of the procedure inadequacies that led to this condition. The failure to maintain adequate procedures to control this safety related activity is a violation of Technical Specification 5.4.1. (NOV 50 277; 50-278/97005 02)

07 Quality Assurance in Operations 07.1 Plant Ooerations Review Committee (PORC) Meetina Inspection Scoce (40500)

The inspector attended the Plant Operations Review Committee (PORC) meeting on August 7,199 I

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6 : Observations and Conclusions At the meeting, PORC discussed two safety evaluations associated with operation of the fuel pool cooling system and the demolition of intermediate range monitors (IRMs) to support a wide range neutron monitoring modification. The inspector noted that the PORC Chairman made a last-minute change to the scheduled members because none of the members, as originally planned, had significant operations experience. This was an appropriate decision, as one unscheduled member identified some key questions associated with the demolition of the IRMs, requiring additional actions prior to PORC approval of the safety evaluation. The PORC members demonstrated an adequate safety perspective and maintained a questioning attitude during the meetin . Maintenance and SurveilleDER

?.11 Conduct of Maintenance and Surveillance M 1.1 Hiah Pressure Coolant Iniection Svstem Surveillance Test (Unit 3)

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The inspector observed the performance of surveillance test ST-O-023 301-3, "High l Pressure Coolant Injection Pump, Valve, Flow and Unit Cooler Functional and Inservice Test," on July 7,199 Observations and Findinas The inspector observed that the Unit 3 quarterly high pressure coolant injection (HPCl) system surveillance was satisfactorily conducted according to the surveillance test procedure. The inspector observed portions of the test performed by operators in the HPCI roo No deficiencies associated with the actual performance of the surveillance test were identified. However, operators missed an opportunity to identify minor leakage at the HPCI pump inboard seal. The inspector brought the leakage to the ope;ator's attention. Operations initiated an action request and determined that operability was not affecte The system manager also reviewed the action request, concurred in the operability statement, and planned further investigation and possible repair activities for the next refueling outag ,

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7 Conclusions j The inspector concluded that the Unit 3 quarterly HPCI system surveillance test was performed satisfactorily. Operators missed an opportunity to identify minor leakage on the HPCI pump inboard seal. Operations and engineering follow-up was very goo l M1.2 Calibration Check of Drvwell Pressure Instrumentation PT/PISHH/PSH 3-10-100D (Unit 3) Insoection Scope (61726) The inspector observed instrumentation and controls (l&C) tedni%s performing a

calibration check of the drywell pressure instrumentation on J.e 26,1997.

i Observations and Findinos The inspector observed the performance of Sl3P 10-100-B1C2, " Calibration Check of Drywell Pressure Instruments PT/PISHH/PSH 310100D." The technicians displayed adequate knowledge of the equipment and were generally familiar with the procedure. The inspector noted some minor problems associated with attention to detail and communications, as discussed below:

• At one step in the procedure, the technician had logged the drywell gage pressure in the procedure rather than the actual reading of volts DC, as the procedure required. After determining that the recorded reading was outside the required criteria for this parameter, the technicians recognized that they had taken the wrong reading. The technicians then proceeded to retake the correct reading and then verified that it met the acceptance criteri * During the performance of section 6.5 " GROSS FAILURE TEST OF PISHH/PSH 310100D," the technicians missed the reading because the

" mark" was not heard by the technician's partner. The technicians had missed the mark because of other communications on the line. The technicians went back through the steps of the procedure, setup the same conditions, and repeated this part of the test so a value could be establishe The results were within the stated criteria in the procedur The inspector reviewed the procedure and found no provision to go back and perform a partial section over again, as was done for the missed readin Technicians also did not inform their supervisor before repeating the procedural steps. Through a discussion with maintenance management, the inspector determined that PECO intends to ensure more supervisory presence at the worksite, and expects l&C technicians to consult supervision when problems arise. The inspector determined that the repeated steps did not impact the overall results of the activity. The inspector verified that the technicians were properly qualified for performing the calibration work for the drywell pressure instrumentatio .. .

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8 Conclusi9 nt ,

I&C technicians satisfactorily accomplished the calibration of the drywell pressure instrumentation. The technicians displayed adequate knowledge and were qualified to perform this work. Some minor problems with attention to detail, partially repeating sections of the test, and communicatior.s did not affect the overall result M1.3 Calibration of Control Room Radiation Monitor Inspection Scooe (61726)

The inspector observed l&C technicians performing the calibration check of the control room emergency ventilation radiation monitor on July 7,199 Qblervations and Findinas f- The inspector observed l&C technicians performing selected steps for Sl2R 63L-

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-0760 B1CE, " Control Room Radiation Monitor RIS-0760B Electric Calibration Check." The inspector noted some' discrepancies associated with the signoffs and

[ recording of acceptance criteria. Specifically, the inspector found that a step was

} signed off as being complete prior to recording the necessary data to support ther completion of the step. Further, it was noted technicians were confused on how to calculate the acceptance criteria. One technician had entered a set of acceptance-criteria, but another technician changed these values by subtracting the background radiation from the values in the procedure. Later, the acceptance criteria were changed back to the original values. The technicians briefly discussed this with an l&C supervisor who arrived at the work sit ,

The inspector found that technicians did not cover a detector hole after the detector had been removed. The inspt.ctor brought this to the attention of a technician, who then covered the hole with tape for foreign material exclusion (FME) purposes, Conclusions During the calibration check of a control room ventilation radiation monitor, technicians were confused on how to determine acceptance criteria, and they signed-off a step prior to recording the pertinent data. Further, technicians did not cover a detector hole, for foreign material exclusion purposes, until questioned by the inspector. These discrepancies revealed weaknesses in knowledge and attention to detail by l&C technician M1.4 Maintenance Activities (62707)

The inspectors observed the conduct of portions of the following maintenance activities, identifying no negative issues:

• 2A RHR Heat Exchanger, Seal Weld Floating Head Work Order C0158516 i

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• MO.210 015C Motor Operator Preventive Maintenance iVork Order R0463125 The technician performed a uorough inspection of the motor operator. A missing declutch lever key was identifie M2 Maintenance and Material Condition of Facilities and Equipmerit M 2.1 E 2 Emeroency Diesel Generator Exhaunt Gasket Missina/ Bolts Missino Inspection Scope (627071 Inspectors reviewed PECO's corrective actions for a missing gasket on the E 2 emergency diesel generator (EDG) exhaust ring catcher flange. Also, the inspectors performed a walkdown of the EDGs, with particular attention to bolt and flange areas.

, Observallons and Findinas During a load run on July 30, of tne E 2 EDG, PECO personnel identified an exhaust leak from the governor side ring catcher flange. The gasket materiel for the ring l- ':h flange could no longer be found, but the gap still remained where the gasket tally provides a seal. An evaluation by engineering determined that the (.xhaust I could lead to degradation of surrounding equipment over time. PECO considered the EDG operable, based on an evaluation that considered the amount of exhaust not going to the turbo charger and inputs to the heat load and oxygen content of the EDG compartment. Operators also completed a successfulload run on the EDG, PECO inspected the other EDGs for similar ring catcher gasket problems and found non PECO did not initiate a PEP, or other formalinvestigation. Thus, the licensee missed an opportunity to dotermine a root cause for the missing gasket or evaluate

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the potential for other generic issues with similar gasket Maintenance personnel tightened the flange without installing a gasket as an interim corrective action and checked the torque on the ring catcher flanges with gaskets stillinstelled. This actior was evaluated and recommended by engineering. On August 12, the Fix It Now team installed a new gasket and operations performed a satisfactory E 2 test ru After observing the missing gasket on the E 2 EDG exhaust ring cat @ar. the inspector visually verified proper installation of the all other ring catcher flange gaskets on the EDG, Also, the inspector puformed a walk-down on each EDG inspecting, with particular attention to flanged areas.--

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10 On the E 3 EDG, the inspector found that the flange from the turbo charger discharge to the scavenging air supply was missing two bolts. This was discussed with licensee engineers, who later inspected the affected flange and determined that EDG operability was not affected. PECO technicians subsequently replaced the bolts, Conclusions PECO identified, corrected, and rnade a complete operbility determination of an exhaust leak on the E 2 EDG caused by a missing gasket on the chaust ring catcher. Although PECO properly addressed the narrow generic issue for the exhaust ring catcher flanges, PECO did not initiate a PEP or other formal review and thus did not consider the root cause of the missing gasket and the potential for other gasket problem M2.2 Reolacement of "B" Residud Heat Removal Heat Exchanaer Outlet Valve (Unit 21 insoection Scone (62707)

, The inspector observed maintenance activities associated with PECO's corrective

} actions for a leak through on MO 210-0898, "B" HPSW RHR heat exchanger outlet valve, Observations and Findinos PECO initially discovered a problem with the MO 210 89B valve during surveillance testing on June 28,1995, when the discharge pressure alarm for the D HPSW pump, " System ll HPSW Pump Disch Lo Press," came in the control roo Investigetion by the system manager identified the problem as seat leakage through the "B" heat exchanger outlet valve, Previously, PECO had a similar problem with the Unit 3 heat exchanger outlet valve, and the system manager had a system pressure and flow trend established. The inspector obsctved a through wall opening in the seat wall of about 1 inch in area during internal inspection of the leaking valve, PECO evaluated the 2D hoat exchanger as operable, since the flow and pressure determined by ST O 032 300 2 on September 26,1995 showed flow of 4800 GPM and pressure of 245 PSIG. The requirement established in TS for flow is >4500 GPM with > 233 PSI The 28 HPSW subsystem was placed out of service on June 23 while the "B" HPSW RHR heat exchanger discharge valve replacement took place. The system was retumad to service on June 25, well within the allowed outage time for the system per technical specificetion The inspector reviewed the work package and procedure and found that the work was performed in accordance with procedures. The inspector verified the method and type (double butt) of weld, materials used, and qualifications of the welder I

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working at the valve. Weld material can only be received by a person qualified to do the type weld for that material. Also, the inspector observed the alignment of the replacement valve and noted the strong maintenance supervisory oversight '

throughout the replacement activit ,

i 3- Conclusions i

! The maintenance activities for the replacement of MO 210-89B were characterized t

' by strong planning and comprehensive execution. The activities had extensive i maintenance supervisory oversight and coordination by the system manage ;

l' t lil. Ennineerina

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E1 Conduct of Engineering

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E Emeroency Diesel Gen 6rator Startina Air Reservoir Pressure Discreoancv i i

i ( Insoection Scone (71707,37551) i i

The inspector reviewed technical specification (TS) requirements sod station i procedures associated with the emergency diesel generator (EDG) starting air reservoir pressure settin : Observations and Findinaa '

During a routine inspection of the EDGs, the inspector observ id that the starting air i reservoir pressure for the E 2 EDG was approximately equal to the level which requires entry into a TS action statement. The inspector found that the starting air reservoir pressure gage read 225 psig; a reading below this requires entry into TS action statement 3.8.3.E.1, which specifies restoring air start reservoir pressure within 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> i The inspector noted a number of discrepancies during review of plant procedures  :

and setpoints related to the 225 psig TS criteria: l-e "The Diesel Generator Daily Shutdown Inspection," SO 52A.8.A allowed a minimum reservoir air pressure of 220 psig, vice 225 psig. Further, the ,

procedure allowed the operator to blow down the starting air reservoir to !

200 psig during the daily blowdown of the reservoirs for moisture remova ,

o " Diesel Generator Air Start Reservoir Check Valve Test," ST 0 52C 422 2, allows an as left air reservoir pressure of as low as 220 psig, o " Diesel Generator Air System Startup," SO 52C.1.A, allowed the air pressure to drop to 220 psig before the air compressor starte :

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' ha " auto stort low pressure" alarm setting was 165 psig, significantly b4w the TS action criteria of 225 psi These discrepancies made inadvertent entry into the TS action statement possibl The inspector also noted that the wide range of the gages used for TS operability made accurato determination of the pressure difficult. The gages are O . 600 psig )

gages with incrernents of 20 psig. Operators stated that these gages made it

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difficult to determine the actual pressure within a few psig.

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The inspector discussed with operations supervision the inconsistencies betwoon l plant procedures and the TS action statement criteria. Operations recommended a number of actions for this issue, including:

Raising the auto start setpoint of the starting air compressor from 225 psig to 230 psi *

Raising the " auto start low pressure" alarm setting from 165 psig to above 225 psi * Replacing the current 0 600 psig pressure indicator During a limited review of this issue, operations did not identify any instances in which the actuallogged reading of the air start reservoirs was less than 225 psi Operations and engineering also took prompt actions to address the procedural discrepancies by initiating temporary procedure changes. However, not all affected procedures were changed. For example, " Diesel Generator Air Start Reservoir Check Valve Test," ST O 52C 422 2, still allowed an as left air reservoir prnssure of as low as 220 psi The inspector also discussed the inconsistencies between procedures and TS with the system manager and engineering supervision. Following the end of the inspection period, they determined that the issue had warranted a PEP report when it was first identified. The system manager subsequently initiated a PEP report to investigate the cause and corrective action The inspector determined that the potential safety consequence of this issue was minor. Per TS, the EDGs remain operable with starting air reservoir pressure greater than or equal to 150 psig, as this is the minimum pressure at which one start of the EDG is assured. The 225 psig criteria ensures that a minimum of 5 starts of the EDG can be performed, c. Conclusions During a review of the minimum pressure criteria for the EDG air start reservoirs, the inspector identified procedural discrepancies that could allow inadvertent entry into a TS action statement. Corrective actions were prompt, but failed to address all affected procedures. This issue was of minimal safety impact, but revealed inconsistencies between station procedures, setpoints, and technical specification .

E1.2 Unit 3 Coastdown and Reactor Feed Pumo inlection Temoerature inspection Scone (375511 The inspector conducted a limited review of PECO's analysis to allow a final feedwater temperature reduction of up to 80'F at full power for cycle extension and during coastdown, Observations and Findinas Peach Bottom Units 2 and 3 had previously been analyzed to support feedwater heater out of service operation, but limited to 55'F feedwater temperature reduction at rated power. PECO completed an analysis that supports a feedwater temperature reduction of 80'F, corresponding to a decrease from 381*F to 301 * at rated power conditions. A vendor's analysis used by PECO to justify the reduction in final feedwater temperature as a cycle extension mode of operation opplied to core flows of 100% of rated and greater, as well as to 100% load lin During the review of PECO's evaluations, the inspector noted the evaluation showed the feedwat6r temperature reduction would not impact the current LOC ECCS performance and the anticipated transients without scram (ATWS) analysis results and would have a smallimpact on thermallimits; however, more restrictive fuel thermallimits would be required for off rated core power and flo The analysis included the limiting anticipated operational occurrences with respect to fuel thermallimits based on licensing requirements and the plant FSAR. Of these, the conditions that had possible significant impact included: 1) Feedwater -

contro'ler failure at maximum demand; 2) Load rejection without bypass valve operation; 3) Loss of feedwater heaters; 4) Rod withdrawal error; and 5) Fuel loading error. -

PECO evaluated the effect of the 80'F reduction in feedwater temperature operation on the feedwater nozzle and feedwater sparger for the period of time to coastdown to 40% power. The duration of the reduced feedwater temperature at the end of cycle for the unit would be 3 weeks for rated power and 28 weeks of decreasing power. The final feedwater temperature at the end of coastdown at-40% power is calculated to be 248'F. There would be an impact on the feedwater nozzle, but PECO's projected operating time for Unit 3 (11.4 years) would be below the time interval assumed in the design analysis for seal refurbishment of 14 year With the decreased feedwater inlet temperature, PECO's evaluation showed the usage factor would still be acceptable, Conclusiorig The inspector conducted a review of PECO's analysis to allow a final feedwater temperature reduction of up to 80*F at full power for cycle extension and during coastdown. The inspector verified that the licensee's justification for this operation addressed the appropriate analyses and design evaluations. Alsoithe inspectors

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4 14

) independently observed actual feedwater temperatures to confirm final feedwater

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temperature did not exceed the 80*F limit. The operation of Unit 3 with up to 80*F ,

l reduction in feedwater would not significantly reduce the margin of safety to the public for the coastdown to 40% of rated powe E2 Engineering Support of Facilities c.nd Equipment  ;

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E Residual Heat Removal System Discharae Header Pressurization (Unit 21 Insoection Scoce (37551)

The inspector reviewed actions taken in response to a high pressure condition observed in the Unit 2 Residual Heat Removal (RHR) discharge headers, Observations and Findinas  ;

i On July 15, operators observed an RHR discharge header high pressure alarm and noted increased pressure on both discharge header pressure indicators. Operators took action per the appropriate abnormal operating procedure to reduce pressure

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and clear the alarm. Operations documented the condition on an Action Reques Operators continued to note increasing pressure over the next two day Engineering evaluated this condition and developed an action plan. The system l manager determined that leakage past the B RHR discharge valve, MO 210 025B was the most likely cause initial actions to correct the condition by stroking the -

valve were not successful, Engineering quantified the leakage at 0.1 gpm, significantly below the operability limit of 1.0 gpm. The inspector observed strong, in plant involvement by the system manager in monitoring the condition and recommending corrective actio Operators continued to quantify and control the leakage by using an abnormal operating procedure. The leakage rate remained approximately constant for the next several days. On August 2, operators exited the abnormal operating procedure to perform ST l 010105 2, "RHR B Logic System Functional Test." This test stroked valve MO 210-25B and the condition cleared. Engineering concluded that the valve appeared to have better seated itself. Following the test, however, engineering was slow in documenting on the Action Request the status of the monitoring and resolution efforts. As a result, at the conclusion of the inspection period, some operators were unsure of the status of the conditio , facclusions Overall, station response to a high pressure condition in the Unit 2 RHR discharge headers was good. Operators entered appropriate abnormal operating procedure initial actions by the system manager to evaluate and monitor the issue were excellent. However, after the condition appeared to be resolved, engineering was slow in providing a documented status to operation , _. .._ _ - ...,- _ _ . __ - . _ . , , _ . _ - - - _ . . _ _ , _ . _ - _ . _ _ _ _ _ _ ~ _ _

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E2.2 Failed Relav on E 1 Emeroency Diesel Generator insoection Scoce (71707,375511 The inspector reviewed actions taken following the identification of a fallod relay j l

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during post maintenance testing on the E 1 emergency diesel generator (EDG) on Juns 0,109 Observations and Findinas During post maintenance testing of the E 1 EDG per a routine test procedure, operators observed that the generator field failed to flash. After investigation, technicians determined that a K 1 trip contact failed to close, which prevented the field flash relay from operatin !

- The inspector noted that the EDG remained in an inoperable status pending ,

resolution of the condition. A temporary change was initiated to manually reset the '

affected relay to allow for continued testing, in addition, the licensee addressed the '

immediate generic implications of this issue by visually inspecting the K 1 relays of the other three EDGs to ensure that they would support an automatic star Following replacement of the relay on June 11,1997, the EDG was tested and restored to an operable statu The licensee performed an evaluation and failure analysis at the PECO corporate laboratory. The evaluation concluded that a contact spring was not in its designed position, most likely due to an incorrect installation by the manufacturer. The licensee discussed the issue with the manufacturer and with the vendor that qualified the relay. Based on these discussions and the lack of similar failures documented in industry information, the licensee further considered the event to be an isolated occurrence. The inspector reviewed the licensee's determination and identified no concerns, Conclushtm The inspector concluded that PECO's immediate and follow up actions in response to the identification of a failed relay during post maintenance testing of the E 1 EDG were timely and comprehensiv E2.3 Control Rod Drive Withdrawal Directional C 2ntrol Valve Leakaae Insoection Scone f 37551)

The inspector assessed the licensee's evaluation and corrective actions for the leakage identified on SV 3 03A 13120EX, directional control valve on hydraulic control unit (HCU) 50 2 .

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I 16 b. Observations and Findinas On June 5, PECO identified a water leak at the solenoid valve (SV) on Unit 3 HCU l 50 27, between the SV and the SV body. The directional withdrawal control valve

is located in the line leading from the underpiston side of the control rod drive (CRD)

mechanism, part of the reactor manual control system. The leak was contained within a catch containment. Although operators conservatively reported the leak as 60 drops per minute, the Inspector verified the leak to be 26 to 28 drops per minute l

on that date.

l Although separation is provided between the scram and normal control rod functions to prevent failures in the manual control circuity from affecting the scram circuitry, SV 13120 does perform a passive safety function in the closed positio While it is closed, it prevents diversion of pressurized scram accumulator water from the exhaust water header rather than being directed to the underpiston area of the CRD. This condition affects only control rod 50 2 .

PECO used an evaluation documented in General Electric document GEK-7811/9684, which provides information regarding the effects of a leaking directional control valve on CRD operability. The evaluation results are as follows:

< 1 GPM No affect on CRD notch in performance

> 1, < 2 GPM Shortened settle period >

f > 2 GPM Failure to insert one notch Fails open No CRD movement The licensee staff discussed with the inspector the effects of the leakage, compliance issues, safety impact, and plans for repair. The HCU is planned for repair during the October 1997, outage unless the leakage increased to the point -

where it affected CRD operability, Until the outage, the on shift equipment operator will evaluate the status of this leak once por shif The NRC inspector has monitored this leak and found a slow increase in the leakage: 27 drops / min on July 7,42 drops / min on July 14, and 60 drops / min on July 3 c. Conclusions PECO's operability evaluation for the leakage identified on the directional control valve on HCU 50 27 reflected c,anerally strong knowledge of the system and the effects of the leakage. The monitoring plan was based on proper assumption Overall, the evaluation and corrective actions were considered very good, s

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l 17 E2.4 E 2 Emeroency Diesel Generator Voltaae Reaulation Problems

! Insoection Scone (375511 The inspector reviewed PECO's actions to address the voltage regulation problems on the E 2 ED Observations and Findinas On June 17, operators experienced voltage regulation problems on the E 2 EDG and declared it inoperable. The voltage regulation problems occurred while performing a shutdown of the E 2, after the completion of a routine test. PECO determined that the proper start and operation of the E 2 would not be assured. After_the !

satisfactory completion of corrective maintenance, PECO declared the E 2 EDO- '

operable on June 2 PECO determined the cause of the_ voltage regulation problems to be a loose potentiometer coupling for the motor operated controller. This condition prevented the motor operated controller from returning to its center position when shutdow PECO also replaced and tuned governor control components, as a conservative measare. The motor operated controllers for the other three EDGs were verified by technicians to be in the center position. PECO engineers reviewed the historical operation of the E 2 and other and identified no other problems with voltage regulation. PECO was evaluating the possibility of maintenance activities that could be implemented to prevent a similar failure in the future, Conclusions Following the identification of voltage regulation problems on the E 2 EDG, PECO properly declared it inoperable and took prompt and thorough corrective actions to

-- restore operability. Engineering used sound investigative reasoning to address potential common cause failure concerns for_the other_ EDG E2.5 Hlah Pressure Service Water Svstem Valve Stroke Failures Insoection Scoce (375511 The inspectoS reviewed actions taken to address the failure of high pressure service water (HPSW) system motor operated valves MO 210 89A and MO 210-89C to stroke close Observations and Findinas On July 1,1997, during a HPSW system surveillance test, MO 210-89A and MO-210 89C, the Unit 2 HPSW system discharge isolation valves for the 2A and 2C residual heat removal system heat exchangers, failed to close. An operability determination was performed promptly and concluded that the valves still met their safety related function ,

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! 18 Troubleshooting of the valves by the Fix It Now team revealed they did not close due to a failure of the associated auxiliary contacts in the 480 V motor control center starter coils. The auxiliary contacts were replaced and the valves were ,

tested satisfactoril {

The inspectors noted that there has been a history of auxiliary contact failures in safety related applications. Previous failures occurred in 1993,1995, and 199 The failure in 1996 rendered the Unit 2 B core spray loop inoperable. This event was investigated in PEP issue 10006255. Although the investigation was completed in December 1996, a number of the corrective actions were assigned to be completed over a year later, December 31,1997. Some data was planned for review in August 1997.

t t

The inspector reviewed the results of the failure analysis performed on the HPSW l valve auxiliary contacts. The documentation indicated that some data was not available and that it may have been lost during the troubleshooting proces .

Another review of auxiliary contact failures was initiated on August 5, with a l planned due date of September 15,199 c. Conclusions The inspector found that the initial actions related to the stroking failures of high pressure service water (HPSW) system motor operated valves MO 210 89A and MO 210 89C were perforrned promptly. A number of actions related to the analyses of these and similar auxiliary contact failures remain open. Corrective actions for a related PEP lssue were pending or not fully resolved. Due to the ongoing nature of these activities, this issue is considered unresolved, pending completion of licensee analysis and review of previous corrective actions, and subsequent NRC review. (URI 50 277; 50 278/97005 03)

IV. Plant S.WDRAtt R1 Radiological Protection and Chemistry (RP&C) Controls The inspectors noted no negative issues during routine tours of the radiologically controlled areas of both plants. The tours included review of general housekeeping and radiological conditions, postings, and barrier Conduct of Security and Safeguards Activities The inspectors identified no significant areas of concern during observations of security force activities. The inspectors observed that repair activities on the access building roof were being continuously monitored by security personne _

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4 19 j S2 Status of Security Facilities and Equipment The inspectors conducted routine walkdowns of the protected area and did not identify any significant deficiencie V. Manaaement Meetina X1 Exit Meeting Summary  :

The inspectors presented the inspection results to members of the licensee management on August 21,1997. The licensee acknowledged the findings presente X2 Review of UFSAR Commitments A discovery of a licensee operating their faciHty 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-description. While performing the inspections discussed in this report, the inspector

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reviewed the application portions of the UFSAR that related to the areas inspected. The inspector verified that the UFSAR wording was consistent with the observed plant practicas, procedure and/or parameter X3 Management Meeting Summary On July 29,1997, NRC and licensee management conducted a meeting to discuss the results of the NRC Systematic Assessment of Licensee Performance (SALP) for the period October 15,1995, to June 7,199 .

20 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)

control rod drives (CRDs)

control room deficiency list (CRDL)

control 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 (2R11)

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)

functional testing (FT)

general procedure (GP)

Generic Letter (GL)

health physics (HP)

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 followup items (IFis)

instrument and control (l&C)

intermediate range monitor - neutron (IRM)

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)

low pressure coolant injection (LPCI)

lubricating oil (LO)

main control room (MCR)

modification (MOD)

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motor generator (MG)

nuclear maintenance division (NMD)

nuclear review board (NRB)

offsite dose calculation meaual (ODCM)

offsite power start up source #2 (2SU)

offsite power start up source #3 (3SU)

Peco Energy (PECO)

performance enhancement program (PEP)

plant operations revie'u committee (PORC)

post maintenance ter, ting (PMT)

primary containmen'. (PC)

primary containmerit isolation system (PCIS)

primary containment isolation valve (PCIV)

l protected area (PA)

l quality assuranca (QA)

tcdiologically crantrolled area (RCA)

rated thermal r>ower (RTP)-

reactor core bolation cooling (RCIC)

reactor engir.eer (RE)

reactor feed pump (RFP)

reactor operator (RO)

reactor priatection system (RPS)

reactor w ater cleanup (RWCU)

reliability centered maintenance (ROM)

f residual heat removal (RHR)

residuti heat removal (RHR)

safety evaluation report (SER)

safety related structures, system and components (SSC)

safe'iy relief valve (SRV)

rer!.m solenoid pilat valve (SSPV)

serondary containment (SC)

setilor reactor operator (SRO)

sl i if t technical advisor (STA)

rhift update notice (SUN)

source ange monitor (SRM)

specific gravity (SG)

spent fuel pool (SFP)-

standby gas treatment (SGTS)

standby liquid control (SLC)

station blackout (SBO)

i structure, system and component _(SSC)-

l = surveillance requirement (SR)

I curveillence tect (ST)

systems approach to training (SAT)

technical requirements manual (TRM)

technical specification (TS)

temporary plant alteration (TPA)-

turbine bypass valve (BPV)

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turbine control valve (TCV)

i turbino stop valve (TSV)

undervoltage (UV)

unresolved item (URI)

updated final safety analysis report (UFSAR)

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,c---- - - , , - . - - - - . - - - - - - , . = - - - - - - . - - -.m.-.. , ,

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INSPECTION PROCEDURES USED I

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IP 37551: Onsite Engineering Observations ,

IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving,and Preventing '

! Problems  !

I IP 61726: Surveillance Observations '

l lP 62707: Maintenance Observation i j '

IP 71707: Plant Operrtions IP 71750: Plant Support Observations  :

IP 92700: Onsite Follow of Written Reports of Nonroutine Events at Power Reactor ,

]' Facilities IP 92901: Operations Followup j lP 92902: Followup Engineering l

IP 92903: Followup - Maintenance -!

IP 92904: Plant Support Followup j IP 93702: Prompt Onsite Response to Events at Operating Power Reactors

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k j O

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ITEMS OPENED, CLOSED, AND DISCUSSED Onened NCV 50 277; 50 278/97005 01 Document Control at Local Operating Station VIO 50 277; 50 278/97005-02 Inadequate Procedure for Tripping Control Room Ventilation Radiation Monitor URI 50 277; 50/278/97005 03 Auxiliary Contact Failures CJnind i

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