IR 05000277/1998009

Insp Repts 50-277/98-09 & 50-278/98-09 on 981116-1204. Violations Noted.Major Areas Inspected:Reactor Core Isolation Cooling & 4kV Electrical Distribution Sys Operation Under Normal & Emergency Operating Conditions

ML20202J831
Person / Time
Site:	Peach Bottom
Issue date:	02/01/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20202J815	List: IR 05000277/1998009 ML20202J808 ML20202J824
References
50-277-98-09, 50-277-98-9, 50-278-98-09, 50-278-98-9, NUDOCS 9902090257
Download: ML20202J831 (25)

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U. S. NUCLEAR REGULATORY COMMISSION REGION 1 License Nos: DPR-44 DPR-56 l

Report Nos: 50-277/98-09 50-278/98-09 Docket No Licensee: PECO Energy Company Correspondence Control Desk

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P.O. Box 195 Wayne, PA 19087-0195 Facility: Peach Bottom Atomic Power Station Units 2 and 3 Inspection Period: November 16,1998 through Decernber 4,1998 Team Leader: A. Lohmeier, Senior Reactor Engineer inspectors: J. Yerokun, Senior Reactor Engineer B. Welling, Resident inspector R. Bhatia, Reactor Engineer  !

L. James, Reactor Engineer B. Gupta, Contract Engineer Approved by: Glenn W. Meyer, Chief Civil, Mechanical, Metallurgical Engineering Branch Division of Reactor Safety 9902090257 990201 PDR ADOCK 05000277 G PDR

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TABLE OF CONTENTS PAGE EXECUTIVE S U M MARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lii lil . Enginee rin g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 E Reactor Core isolation Cooling (RCIC) System . . . . . . . . . . . . . . . . . . . . . . 1 E1.2 4 Kv Electrical Distribution System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

E CFR 50.59 Safety Evaluation Program . . . . . . . . . . . . . . . . . . . . . . . . . 14 E Implementation of 10 CFR 50.59 Program ..................... . . . . 14 r

j E5 Engineering Staff Training and Qualifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 E CFR 50.59 Safety Evaluations Program Training and Qualifications . . . . 15 E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 I

E Effectiveness in identifying, Resolving, and Preventing Problems . . . . . . . 16 V. M anagement Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 X1 Exit Meeting Summary . . . . . . .... .... ........ ......... . ........ 18 l

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EXECUTIVE SUMMARY Peach Bottom Atomic Power Station Units 2 &3 NRC Inspection Report 50-277/98-09 & 50-278/98-09 During the period November 16 and December 4,1998, the NRC conducted an engineering team inspection of the Peach Bottom Atomic Power Station, Units 2 & 3. The overall objective of the inspection was to assess the effectiveness on engineering in providing for safe operation of the plant. The inspection focused on the reactor core isolation cooling and 4kV electrical distribution systems' operation under normal and emergency operation conditions. The inspection also addressed the performance of engineering in support of the operations and '

maintenance functions, with emphasis on problem identification and corrective action implementation, and plant safety evaluations. Within the scope of the inspection, the team's conclusions are identified below:

. The RCIC system was maintained operable and capable of performing its safety function. The existing procedures for operation, surveillance, and maintenance of system components were generally accurate and consistent with the licensing and design bases. However, weaknesses were found in dispositioning repetitive failures of primary containment isolation valve CHK-3-13C-38 without thorough documented engineering investigation. The failures remain a troubleshooting priority for the system manager. (E1.1)

. The team identified two discrepancies involving the design basis stroke times for the l torus suction valves in procedure ST-0-013-301-2 and the design basis torus water temperature in procedure EOP T-102, which represented a violation of 10 CFR 50, Appendix B, Criterion ill, Design Control. PECO took appropriate actions to address the violation and also had ongoing actions, such as the calculation enhancement program, to address the problem. (E1.1)

. The team concluded that the installed 4 KV electrical distribution system was consistent with the design basis, and that this system was capable of performing its design function during normal and abnormal operating conditions. Also, the existing procedures for operation, surveillance, and maintenance of system components were accurate and consistent with the licensing and design bases. (E1.2)  :

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. An analysis of degraded 4 Kv undervoltage relays was performed in 1996 and used to demonstrate that the plant was within the design basis, but was not independently reviewed and approved. The team reviewed the analysis and found it acceptable, and the analysis was subsequently reviewed and approved by engineering. (E1.2)

• The procedures supporting the 10 CFR 50.59 and FSAR updating processes were acceptab'e, providing comprehensive guidance and detailed responsibilities for implemeating the requirements of 10 CFR 50.59 and 10 CFR 50.71(e). (E3.1)

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PECO has implemented an acceptable 10 CFR 50.59 program that produced l

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applicability determinations and safety evaluations of good quality, met regulations and applicable plant procedures, and provided sufficient details and references to support the ,

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The engineering staff training to support the 10 CFR 50.59 safety evaluation program l was acceptable. (E5.1)

. Problem identification and evaluations for issues found in performance indicator

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l summaries, LERs, ISEG reports, and the EP&MC focus list were generally effectiv The timeliness and appropriateness of corrective actions for identified issues in the team's review were generally good. (E7.1)

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Report Details Summarv of Plant Status Both Units 2 & 3 were at 100 percent power during the inspection period from November 16 through December 4,199 Ill. Enoineerina E1 Conduct of Engineering l E Reactor Core Isolation Coolina (RCIC) System Inspection Scope (IP 93809)

j The team assessed the accuracy of design, testing, maintenance, and operational l information in support of reactor core isolation cooling (RCIC) system performance

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Updated Final Safety Analysis Report (UFSAR) and Technical Specifications (TS),

Design Basis Document (DBD), drawings, normal and emergency operating procedures, and inservice and surveillance procedures and results. The inspection also included a review of analysis and calculations that verified the accuracy of design assumptions of i support system modifications and system performance during normal and accident

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conditions. The team conducted walkdowns of accessible portions of the system and held related technical discussions with system and design engineers, Observations and Findinas

! System Desian l The RCIC system consists of a steam-driven turbine-driven pump unit with associated piping and valves designed to provide 600 gallons per minute (gpm) of water to the reactor vessel during a loss of feedwater event to keep the top of active fuel covere The system is normally aligned to take suction from the preferred but non-safety related l- condensate storage tank (CST), and it automatically transfers suction to the safety- l

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related torus upon reaching a low level (5 feet) in the CST. The system design analysis shows that a system response within 15 minutes at a flow rate of 525 gpm is sufficient to replenish reactor inventory loss during a loss of feedwater. In an anticipated transient ,

without scram (ATWS) situation when boron dilution would be a concem, AlWS  !

mitigation analysis shows that RCIC flow of 600-630 gpm would not cause excessive i dilution of Boro Based on a review of test data and pump performance curves, the team verified that the pump was capable of providing the required 600 gpm to the reactor vessel at up to a maximum discharge pressure of 1500 psig. In addition, the team verified that at the 3 required flow rates and operating conditions, adequate net positive suction head (NPSH)

(t 20 feet) would be available (NPSHa of 36.7 feet in the torus, without taking credit for

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l System Ooerations l

The team reviewed some normal and emergency operating procedures (e.g., EOP T-100, Scram; and T-101, RPV Control) for the RCIC system and identified no concem The team observed the conduct of surveillance test RT-0-013-725-2, RCIC Response l Time Test, on Unit 2. This biannual test was conducted to verify that RCIC system will l produce rated flow and pressure within 30 seconds from a cold start. Although the test

! was satisfactorily completed, the team observed a discrepancy with the RCIC pump j outboard bearing oiler level. The level indication was out-of-sight low following the test l run. When questioned by the team, maintenance personnel indicated that although the l lubrication for the outboard bearing was adequate, the out-of-site low level indication was i unexpected.' They therefore initiated an action request to investigate possible venting l problems with this oiler / bearing housing. The team found the PECO actions satisfactory, and had no other concems.

i Surveillance and Testina  !

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l The team reviewed the prescribed inservice tests for selected RCIC system valves to

verify that the safety functions of the valves were properly tested. The team reviewed

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the acceptance criteria specified in ST-0-013-301-2, "RCIC Pump, Valve, Flow and Unit l

Cooler Functional and in-Service Test." Two instances were noted that appeared to be l In conflict with design basis expectations. The torus suctior valves, MO-13-39 and l MO-13-41, were assigned limiting values of 39.5 and 40 semds. These were higher l l than the values of 33.5 and 35 seconds determined in Calculation 18247-M-016, RCIC j Pump Suction Transfer Timing, to be the limit that ensures adequate NPSH for the pump l during suction swap-over from the CST to the torus. The team found this to be an l example of where PECO had not properly translated design information into procedure j Meanwhile, PECO initiated actions to verify the IST stroke times specified in the  ;

calculation prior to revising those in the surveillance procedure. The team reviewed l previous test results, and was satisfied that the issue presented no immediate concem, since the valves have operated well within the appropriate times, and the referenced ISI !

time limit was within the design basis. Also, PECO indicated that their ongoing efforts to improve the control and implementation of calculations would adequately ensure that such problems were precluded from recurrin I The team reviewed the ongoing calculation improvement program and determined that it was comprehensive and appropriate. Nevertheless,10 CFR 50, Appendix B, Criterion l

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lil, Design Control, requires that measures shall be established to assure that design basis information is correctly translated into specifications, drawings, procedures and instructions. Therefore, the failure to translate the calculated limiting stroke times for the RCIC torus suction valves MO-13-39 and MO-13-41 into IST procedure ST-0-013-301-2 i to ensure adequate NPSH for the RCIC pump, was identified as an example of a '

l violation of an NRC requirement. (VIO 50-277(278)/98-09-01).

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p Maintenance

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The team reviewed the maintenance practices relative to RCIC system and noted that I preventive maintenance (PM) and corrective maintenance (CM) items were dewately l

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tracked and prioritized. Degraded conditions had been assessed for impact on

! operability. The team reviewed the maintenance history for pump suction pressure i

switches PS-2-13-067 and PS-3-013-067 and identified no concern. The team also

)i reviewed the instrument calibration sheets for PS-2-13-067, FS-2-13-057, pump discharge flow switch und LISL-2-13-170 and 171. The team verified that the prescribed

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setpoints for the instruments correlated to the design setpoint :

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Preventive maintenance intervals for the RCIC turbine minor and major inspections were j based on the vendor's recommendations, although some re. commended periodic j maintenance items had not been adopted. For example, the recommended frequent

inspectica of the over-speed trip assembly was not adopted; this could have reduced the

Unit 3 RCIC system inoperability period in May/ June 1998. Nonetheless, no adverse j trends in system performance or maintenance trends could be attributed to the rejection

[ of the recommended periodic maintenance item :

The team conducted a walk-down of the accessible areas of the system including the f RCIC pump room, control room and the attemate shutdown panel areas, and did not

identify any discrepancie I

Cabulations

! The team reviewed selected calculations to ascertain that they supported the system's j design and licensing bases. The following calculations were reviewed:

l 18247-M-001. Maximum Torus Temcerature for the ECCS. Revision 5 l

l This cal <,ulation computed the suction piping head losses, NPSH, and maximum

} torus temperature when RCIC and emergency cole cooling system (ECCS)

j pumps are aligned to take suction from the torus. The team identified an

arithmetic error in the calculated piping head losses used for determining khe j ^

maximum torus water temperature for RCIC pump operation. This error resulted

in a higher than appropriate torus water temperature (200*F instead of 187'F)

i being used in the '> asis for RCIC operation under emergency operating j procedure (EOP) conditions. The team brought the error to the attention of j- enginearing personnel, who initiated a non-corfcrmance report. Upon further j review, PECO determined that other calcuistions that used this calculation as an

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input were also affected by the changes and that changes were necessary to

EOP T-102, Prirrary Ct,ntainment Control. Both the team and PECO verified that

the error had no impact on RCIC acccmplishing its design function during a loss of feedwater event without a LOC Following this discovery, the team performed a limited extent-of-condition review of other portions of the 18247-M-001 calculation and found similar discrepancies t .. _

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in the high pressure coolant injection (HPCI) portion. PECO indicated that these errors would be addressed through a previously issued PEP report (#6493),

which documented numerous weaknesses in the control of calculations performed years ago, i l

The team determined that due to calculation errors, pen engineering failed to i asste that the design information for RCIC was correctly translated into procedures and instructions when the torus water temperature limitation for RCIC operation was incorrectly indicated in NPSH curves that are used in EOP T-102, ;

Primary Containment Control, Step T/T-7. The team verified that the corrective i actiore, to immediately address this issue were adequate. The problem was entered in the corrective action process. and a temporary change was initiated to correct the temperature in the EOP. The team also agreed that PECO's ongoing efforts in the calculation improvement area would reasonably address any similar problem. This instance was, nevertheirw another example of a violation of 10 i CFR 50, Appendix B, Criterion lil, Design Control. (VIO 50-277(278)/98-09-01) !

18247-M-016. RCIC Pumo Suction Transfer Timina. This calculation was performed to determine the acceptable maximum opening stroke times for the RCIC pump suction valves from the Torus (MO-13-39 and MO-13-41) that w ll ensure that the RCIC pump continues to have adequate NPSH as the suction swaps over from the CST to the torus. The conclusion was that the maximum )

allowable opening time for the Unit 2 valves was 37.75, while for the Unit 3 vaives i was approximately 66 second The team noted that the calculation included several conservative assumptions l such as assuming that there is no flow from the torus to the pump until the valves are completely open; and also assuming that the suction swap over is not initiated until the CST level is at the pump's suction outlet (below the actual swap-over setpoint of 5 feet).

18247-M-032. RCIC System NPSH Followina LOCA 247 I i

This calculation showed that adequate NPSH (> 20 feet) would be available in the torus following a LOCA (outside RCIC design basis) while not taking credit for containment over pressure. The calculated NPSHa were approximately 37 feet for an intermediate break LOCA (IBLOCA) situation and 30 feet for a small break LOCA (SBLOCA)

ME-0695. Rev. O. Net Positive Suction Head (NPSH) Limits for HPCI and RCIC Pumos for Peach Bottom Unit This calculation determined the emergency operating procedures' (EOPs) NPSH limit, which was defined as the highest torus temperature that provides adequate net positive suction head for the RCIC or HPCI pump taking suction on the toru The NPSH limit is a function of pump flow and suppression charnber over pressure, and is used to preclude RCIC or HPCI pump damage due to cavitatio W ';

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Desion Chances The team reviewed several changes / modifications made to the system to determine if l

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the changes had been accomplished properly and did not create any negative impact on system functionality. The team's revieva found that the changss had been properly evaluated, as follows:

l - ECR 94-11398. HPCl/RCIC Resoonse Time Chano This Engineering Change Request (ECR) addressed changing RCIC response time from 30 to 50 seconds. The change was made in order to establish a more realistic and less restrictive licensing basis for Peach Bottom. The change did i

not involve any physical system change, and it was supported by a General

- Electric (GE) analysis that the team reviewed. The amount of makeup water required after a reactor scram for the proposed rerate condition of 3,694 MWt

, was approximately 525 gpm within 15 minutes of the scram.- The revised RCIC l flowrate of 600 gpm and response time of 50 seconds demonstrated that the

system was capable of performing its intended safety function.

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ECR 95-05469. HPCl/RCIC Room Cooler Operability This ECR addressed the adequacy of RCIC room temperature without the room cooler operating. Previously, via MOD 5346, PECO had removed one of the two coolers from service from the emergency service water system due to low flow ,

margins. Calculation PM-957, HPCl/RCIC Room Temperature Profiles for 95'F !

River Temperature, showed the temperature profile for the RCIC room following a !

small break LOCA with and without room coolers available. Without coolers, the I maximum temperature attained in the room would be 129'F. Since this was j acceptable for system operability, the change that was prev'ously made to !

disable one of the two coolers was bounded and a%a acceptable. The team !

verified that the initial room temperature used for the analysis was based on i expected design basis condition. During subsequent walk-downs of the RCIC pump room, the team verifieKi that there was no equipment in the room that could not function at elevated temperatures of up to 129'F. Most of the switches :

associated with the pump were located outside the pump roo ECR 95-05169. RCIC Govemor Valve Stem '

This was a material change for the RCIC turbine govemor stem, due to generic l

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industry problems with govemor stem binding. In 1996 engineering personnel drafted an ECR to replace liquid-nitride stainless steel govemor stems with l Inconel stems. Industry experience had shown that the nitride stainless steel

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stems were subject to binding due to corrosion. Engineering determined that the l

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Inconel stems would reduce the likelihood of binding. The team judged the

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Miscellaneous Enaineerina Issues The team reviewed engineering staff performance for three selected issues as described in following sections:

RCIC turbine covemor stem bindina:

Peach Bottom engineering personnel took actions in response to industry information and NRC Information Notice 98-24, which discussed design oversights associated with replacement govemor stems, leading to instances of binding. Engineers examined design information for the installed governor stems and drafted an engineering change to replace the existing govemor assembly carbon spacers with new ones that provide a larger clearance area. The epacers were replaced on Unit 2 in October 1998, and Unit 3 ;

spacers are scheduled for replacement in October 1999. Interim actions for Unit 3 l include: conducting an extended 2-hour confidence run and relying on previous verifications completed in October 1997. The team concluded that engineering personnel took prompt and reasonable actions in response to this issu Rooeat failures of Unit 3 RCIC barometric condenser vacuum Dumo check valve The team noted repetitive failures of the Unit 3 barometric condenser vacuum pump check valve, CHK-? 13C-38. This 2-inch lift check valve, which is upstream of the torus j and is a primary containment isolation valve (PCIV), was considered inoperable at the time of the inspection. Despite at least five valve failures or instances of sticking between 1990 and 1997, engineering personnel rejected a design change proposed by maintenance personnel in 1997. Engineering documented only limited justification, indicating that there was no problem with the type of valve, and a like-in-kind replacement with a cleanliness check of the barometric condenser would address the !

proble After replacement in October 1997, additional failures of the valve occurred in November 1997 and January 1998. In January 1998, maintenance again recommended a design i change. In October 1998, a design change was approved, and currently the failures remain a troubleshooting priority for the system manager. The team identified weaknesses in engineering performance regarding this issue. For example, engineering documentation for justifying rejecting the design change was limited and engineering did not have correct information on the intemal material of the valve. Also, despite numerous failures, engineering did not initiate a PEP corrective action document and maintenance, instead of engineering, conducted a PEP investigation into this matte The team concluded that repetitive failures of CHK-3-13C-38 were dispositioned without thorough, documented engineering investigation. Engineering support of plant operations and maintenance in resolving this primary containment isolation valve material probM was wea _

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- Oversosed Trio Assembly Troubleshootina and Desian Chance Analysis l A degraded mechanical overspeed trip and trip throttle valve linkage assembly rendered the Unit 3 RCIC system inoperable for over one month in May/ June 1998. The team noted that there were some deficiencies in the troubleshooting and the design change

, analysis for this condition, as documented la PEP # 8618. These problems caused the L inoperability period for the RCIC system to be extended. The team also noted that the engineering personnel were slow to investigate critical measurements associated with l the trip solenoid plunger travel. Although excessive arcing of the solenoid auxiliary.

l contacts was first observed during testing on June 26,1998, with additional problems

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during subsequent testing, the solenoid manufacturer was not consulted until June 30, l- 199 Subsequently, in response to the engineering performance issues, engineering management took a positive, self-critical approach and initiated a number of corrective l- actions, including briefings and changes to procedures and the Design Change l . Handbook. The team concluded that although initial actions were weak, the completed l and planned additional actions were comprehensiv Uodated Final Safety Anpivsis Revievy i

I The team reviewed applicable sections of the UFSAR to verify consistency between the UFSAR, Technical Specification, and design documentation. The team identified a

- discrepancy between the RCIC turbine exhaust pressure band specified in the UFSAR and the actual and acceptable values listed in quarterly surveillance tests. UFSAR Table 4.7.1, Pump Design Data, listed the steam exhaust pressure range as 20 to 25 psi However, in surveillance procedure ST-O-013-301-2(3), , the acceptable pressure ranges are specified as < 20 psig (<34.7 psia). The recorded values in October 1998 -

and Novonoer 1998 were 12 and 13 psig (26.7 and 27.7 psia) respectivel The discrepancy was that both the surveillance test acceptance range and the recorded values were higher than the pressure band listed in the UFSAR. PECO agreed that this was a non-conforming condition, since the UFSAR design data did not agree with plant operating data. Engineering management stated that this condition would be evalua'ed through the station non-conformance report process, which would include a 10 CFR 50.59 safety determination. Initial evaluations by engineering personnel concluded that RCIC operability was unaffecte The team independently verified that the discrepancy did not affect RCIC operability and concluded that this UFSAR discrepancy could reasonably be expected to be identified l through the PECO's ongoing UFSAR validation project. As such, the NRC is exercising

- enforcement discretion in accordance with Section Vll.B.3 of the NRC Enforcement l Policy and refraining from issuing a citation for this Severity Level IV vic!atio.n.

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8 Conclusions i

' The RCIC system was maintained operable and capable of performing its safety function. The existing procedures for operation, surveillance, and maintenance of system components were generally accurate and consistent with the licensing and design bases. However, weaknesses were found in dispositioning repetitive failures of primary containment isolation valve CHK-3-13C-38 without thorough documented l- engineering investigation. The failures remain a troubleshooting priority for the system

. manage The team identified two discrepancies involving the design basis stroke times for the torus suction valves in procedure ST-0-013-301-2 and the design basis torus water temperature in procedure EOP T-102, which represented a violation of 10 CFR 50, 1 Appendix B, Criterian 111, Design Control. PECO took appropriate actions to address the violation and also had ongoing actions, such as the calculation enhancement program, to l address the proble E1.2 4 Kv Electrical Distribution System l l \

l Insoection Scope (IPg3809)

. The team reviewed the design, operation, testing, and maintenance of the 4 Kv system of PBAPS Units 2 and 3 to ensure that power is delivered to those safety related  ;

components that are relied upon to remain functional during normal and abnormal plant ' '

operating conditions. The review included applicable sections of the UFSAR, Technical Specifications (TSs), the 4 Kv system Design Basis Document (DBD), electrical control l

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and schematic drawings, calculations, operating procedures, and selected design change The inspection also included a review of anely6es regarding support systems during degraded voltage and accKient conditions, walk-down of accessible portions of the system, and discussions with cognizant system and design engineers to verify the appropriateness and correctness of design assumptions. Also, the team reviewed corrective actions regarding emergent system component issue Observation and Findinas System Desian i

l The 4 Kv emergency auxiliary power system is designed to supply ac power to safely L shutdown the station from normal and abnormal operation. The 4 Kv system consists of eight emergency auxWy switchgear buses (four for each unit) with necessary l instrumentation and control and protective relay circuits to assure that the required

! power is supplied to class 1E and non-class E loads connected on these buses.

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Each emergency bus is equipped with incoming and feeder (GE Magne-Blast,250 MVA, 1200 A rated ) circuit breakers to receive and distribute offsite power. Each one of the '

two original offsite sources is normally connected to a set of four buses (two in each unit)

via an emergency auxiliary start-up transformer (OAX04 or OBXO4). The offsite source i which is not connected to the respective bus, acts as an attemate offsite power source to j the bus, in the event of a loss of pnmary offsite source or degraded voltage condition, j' protective relays detect this condition, and the attemate offsite power supply is

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transferred over. In addition, each bus is also backed up with one of the four emergency diesel generator (EDG) dedicated to the bus upon loss of total offsite power.

The team reviewed and verified the design of E12 emergency auxiliary switchgear

. 20A15 bus transfer logic control circuits and its interlocks with other feeder breakers, j under degraded and loss of voltage conditions. The design was consistent with that

described in the UFSAR and DBD.

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i The team reviewed several selected design calculations to assure that the system was  !

capable of performing its intended design function as described in the UFSAR. The team noted that the interrupting and momentary fault rating of 4Kv breakers were within the rated capability of the breakers. The review of AC Short Circuit Calculation, PE-192, Revision 1, indicated that under the worst-case loading scenario, (assuming LOCA on Unit 2, with Unit 3 in long term shutdown, only one offsite source available, and an EDG under test in Unit 2,) the 4 Kv breakers would have adequate interrupting and momentary fault margins of 16.6% and 20.3 % respectivel The team notad that the EDG loading data as shown in the EDG loading Calculation, PE-0166, revision 3, was consistent with the UFSAR Tables 8.5.2C through 8.5. The team reviewed Calculations PE-0121, Revision 5 and E-10, Revision 0 (V:,ltage Regulation Study) used for degraded grid relay setpoints. These calculatione were acceptable and provided the voltage regulation basis for the 4 Kv emergency buses to support LOCA load sequencin The team reviewed 125 Vdc system calculation PE-0017 revision 7 and PE-182 Revision 4, and confirmed that adequate de system voltages were available to operate the 4 Kv feeder and load breakers and control circuit devices of EDGs upon demand during worst-case loading and all plant operating condition Desian Modifications The team reviewed the following two major modifications to assure that they did not

. create any negative impact on the system functionality. The modifications were found adequately reflected on the controlled drawings and design was found consistent with the UFSAR, and DBD. The modifications reviewed were ap;ropriately supported by technically sound engineering analysis to improve the systea capabilit . _ _ _ _ . _

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Modification No. 5414,4 Kv Bus Transfer Flip-Flop Circuitry was designed to

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l enhance each safety related source breaker logic to prevent the repeated cycling l of source breakers occurrence due to a combination of marginal grid voltage and

a LOCA sequencing condition similar to the concem identified at Hope Creek Nuclear Statio Modification No. 2254, Third Offsite Source added a third offsite source for Peach i

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Bottom. In addition, this modification also readjusted the load tap changer values of 2SU and 2EA to optimize the voltages at 4 KV buse Ooerational Procedures Review l The team reviewed five system operating procedures to ensure that the 4 KV electrical l distribution system can be rearranged based on the availability of offsite power sources.

l The team determined that the procedures had adequate instructions in place to enable reconfiguration of the 4Kv system as neede Maintenance and Surveillance Testina

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The team reviewed the preventive maintenance (PM) and refurbishment program of 4 Kv l GE Magne-Blast circuit breakers and surveillance testing of undervoltage and degraded voltage protective relays, emergency auxiliary bus (EDG loads) sequential loading under LOCA and Loss of Offsite Power (LOOP) conditions to assure that all the critical components of the 4Kv system were appropriately maintained and tested in accordance j with manufacturer's recommendations and in accordoce with the TS requirement '

The team noted that an acceptable program existed to perform the routine preventive maintenance and refurbishment on all class 1E AKv breakers. The preventative maintenance was performed on each breaker every two years, and the refurbishment was performed at ten year interva The team reviewed the procedures for performing routine preventive maintenance inspection, and overhaul on 4 Kv and 13 Kv GE Magne-Blast circuit breakers. The team i found that sufficient details (such as acceptable clearances, tolerances and lubrication of l components) were included to satisfactorily conduct the above tasks. Review of the  ;

breaker performance records for the past two years found satisfactory performance.

l The team reviewed the surveillance procedure and test results for the f Jnctional tests of L the 4 Kv emergency bus under-voltage relays and LOOP LOCA every 24-months for bus l E-22. The emergency transformer under-voltage relays, the emergency bus under-

! voltage reisys, and the emergency bus sequential loading relays are tested by simulating i a loss of offsite power and LOCA condition. Although a setpoint calculation for the I I

I sequencing loading relays did not exist, testing was acceptable and sequence time l measurements were found to be well within TS limits.

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l The team reviewed the surveillance procedure and test results for the functional / calibration test of E12 4 Kv emergency bus degraded voltage (under-voltage)

relays associated with Technical Specification 3.3.8.1, Table 3.3.8.1-1 functions 3,4 and 5. On degraded bus voltages function 5 (98%), function 4 (89% with LOCA) and function 3 (89%), the bus is transferred from their normal supply source bus to the altemate supply source bus. If attemate supply bus voltage is not available, then EDGs are i signaled to start to supply the bu The team noted that as-found trip values for several of the function 3,4 and 5 relays l- ' were out of TS limits. LER 2-96-02 in January 96 had also reported the function 4 & 5 relays to be out of TS limits. Corrective actions had included (i) reducing test frequency from 18 months to 31 days and (ii) using high accuracy voltmeters (now i 0.02VAC j versus * 0.3 VAC previously). PECO also trended the instrument recalibration for the l degraded voltage relays. The team reviewed this recalibration trend and found that "as-l' found" degraded voltage trip values for several function 4 & 5 relays were outside of TS l limits. PECO had recalibrated these relays and "as-left" setpoints were brought within l required TS limit PECO initiated NCR PB 96-00403 on January 19,1996, which identified new degraded voltage limits (different than TS limits). These new limits were being used to detemiine

the 4Kv within the design basis with the relays being in the degraded condition. The j additional maigins in the NCR were based on an informal analysis performed by PECO ,

engineering and were stipulated based on the existing system calculations E-10 and  !

PE-0121. The team reviewed the calculations and found them to be accurat Nonetheless, the team noted that the calculations had not been independently reviewed ,

and approved, a poor practice given the significance of the calculation. However, NRC  !

Generic Letter 91-18 allows the licensee to determine operability based on analysis, test,  :

experience, engineering judgement, or a combination of these factors, taking into <

consideration equipment functional requirements. Subsequent to the inspection, the team reviewed the calculation and found that PECO had performed suitable independent reviews and approval to confirm the calculation's accurac :

The team noted that 7 - 9 % of the relays' "as-found" trip values were out of TS limit The degraded voltage relay recalibration trend data also revealed the fact that on occasions each Peach Bottom unit had degraded voltage relay trip va!ues drifting out of TS limits on more than one bus same time. For example, Unit 3 had Function 4 relays trip values out of TS limits on buses E13 (relay 127Y-1501) and E33 (relay 127Y-1701).

The team also noted that PECO prepared a TS amendment and backup documents for

!- submittal to IF'C. The team concluded that PECO was performing th? surveiilance of 4 L Kv system cor,monents testing. In addition, adequate steps were being taken to assure i performance of. egraded voltage relay .

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Review of 4Kv system related component issues The team reviewed the corrective actions for several components associated with 4 Kv system problems identified in operating industry communications. The team determined j that PECO had appropriately addressed the issue !

The team noted that PECO identified a hardened grease problem in the 4Kv breaker in ,

1994, when one of the EDG output breaker failed. As a result of assessment of this I breaker concern, PECO determined this concem to be a generic issue at Peach Botto ;

Based on discussion with the industry and manufacturer, PECO corrected the grease l hardening problem by completing the preventive maintenance on all breakers and l enhancing the preventive maintenance (PM) procedure to reflect the effect. Per discussion with PECO's system manger and review of the last two years failure history, the team determined that this grease hardening issue was properly addressed at Peach l Botto Another 4Kv system related component issue identified by PECO in 1995 (PEP l-0004530) was a concem with the calibration of loss of voltage relays on 4Kv buses (GE type HGA14 relay). The function of this relay is to detect a loss of voltage and shed load on bus and transfer to another source. The team noted that PECO had revised the calibration method to test these relays and provided training to the staff about the i sensitivity of testing associated with armature force measurement during test. PECO was planning to replace these relays with a more suitable type for this application in their long term action plan. The team found the corrective action satisfactorily addressed this issu The team reviewed the corrective actions associated with the Agastat relay replacement program and deiermined that PECO had replaced all the defective relays in the statio The concem with this relay was initially identified in a 10 CFR Part 21, dated l January 21,1998, when an insufficient solder was found on an Agastat relay at other plant. In addition, the team verified that similar relays were also being replaced on routine basis that were only qualified for ten years. The data search of work orders j indicated that PECO was appropriately replacing the relays prior to the end of life of i these relay The team also reviewed the concem identified with the start-up transformer load tap changer that affect the voltage on the 4Kv buses. As documented ir. LER 2-98-004, on June 22,1998, PECO found that the load tap changer on the 3 Startup (3SU)

transformer had not operated properly. Investigation revealed that the surge protective i devices (varistors) on the voltage regulating relay ground connections were shorted to ground. The source fuses were blown, disabling the control circuit, and therefore, the j tap changer was not capable of performing its function. PECO found the probable cause i

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PECO had identified that the 3SU transformer tap changer was inoperable while aligned to the 2 SUE start-up source on June 15,1998. The 2 SUE supplies emergency auxiliary 1 transformer OAX04. The 4Kv emergency buses E12 & E32 for Unit 2 and E23 & E43 for Unit 3 are normally supplied by emergency auxiliary transformer OAX04. Both Peach ,

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Bottom units were in the run mode at the time of this event. With the 3SU tap changer unable to perform automatic tap changes, Technical Specification (TS) 3.8.1.a was not mot and the offsite source was declared inoperabl The 3 SU tap changer circuitry was repaired, tested and returned to service. The associated electronic round sheets were revised to ensure positive verification of tap ;

changer operation during normal system alignment. In addition, the system operating '

l procedures for transferring start-up sources have been revised to functionally check the tap changer manually prior to having the transformer carry an emergency auxiliary transformer and 4 Kv loads. Additionally, PECO was considering initiating a mechanism l through its storm response procedure to detect such failures and also considering ;

installing supervisory monitoring capability for tap changer control failur i l

The team concluded that PECO's reporting and corrective actions for the event l addressed by the LER were satisfactor System Walkdowns The team did a plant walkdown on November 17,1998, to inspect the 4 Kv safety related i supply system and associated equipment to verify that the equipment, protective relays, and control equipment were calibrated and maintained in acceptable condition and consistent with design document The team concluded that the 4 Kv system equipment and associated equipment was in good condition and was being maintained appropriatel c. Conclusions

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The team concluded that the installed 4 Kv electrical distribution system was consistent with the design basis, and that this system was capable of performing its design function during normal and abnormal operating conditions. Also, the existing procedures for operation, surveillance, and maintenance of system components were accurate and

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consistent with the licensing and design base An analysis of degraded 4 Kv was performed in 1996 and used to demonstrate that the plant was within the design basis, but was not independently reviewed and approve The team reviewed the analysis and found it acceptable, and it was subsequently reviewed and approved by engineering management. (E1.2)

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, E3 Engineering Procedures and Documentation

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! E CFR 50.59 Safety Evaluation Proaram

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! Insoection Scooe (37001)

' The team reviewed selected procedures and interviewed PECO representatives to verify l that: (1) proper procedural guidance had been established for implementing the

requirements of 10 CFR 50.59 for proposed changes, tests, and experiments (CTEs),

including safety evaluations (SEs); and (2) procedural guidance had been established for updating the Final Safety Analysis Report (FSAR), as required by 10 CFR 50.71(e). Observations and Findinas The team reviewed 15 administrative, modification, and licensing procedures, that provided guidance and responsibilities related to 10 CFR 50.59 and 10 CFR 50.71(e)

- requirements. The team determined that program procedures, LR-C-13,10 CFR 50.59,

" Reviews and LR-CG-13,"" Performing 10 CFR 50.59 Reviews," were acceptable and corrent with regards to regulatory guidance. These procedures adequately delineated responsibilities for the various individuals who prepare, process and approve SEs, and provided proper guidance for determining when SEs are required to be completed and the process for preparing and approving determinations and SEs. The team further verified that the procedures for completing permanent modifications, temporary plant alterations, and procedures changes made reference to the 10 CFR 50.59 progra The team verified that procedure LR-C-09, " Control of Changes to the Updated Final Safety Analysis Report," provided guidelines and references for updating the FSA Conclusions The procedures supporting the 10 CFR 50.59 and FSAR updating processes were acceptable, providing comprehensive guidance and detailed responsibilities for implementing the requirements of 10 CFR 50.59 and 10 CFR 50.71(e).

E3.2 Implementation of 10 CFR 50.59 Proaram inspection Scope (37001)

The team examined the quality of safety evaluations (SEs) for 10 CFR 50.59 changes to determine if SEs for permanent plant' modifications, temporary plant alterations, and procedure changes addressed all safety issues pertinent to the associated CTE. The team also verified that the changes described in the SEs had been appropriately incorporated into the FSAR pursuant to the requirements of 10 CFR 50.71(e) or were being processed forincorporatio . - - - - . - - - - - .-

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15 Observations and Findinas l 50.59 Safety Evaluations - The team reviewed approximately 15 SEs at various depths and, in general, found the SEs to be in accordance with the requirements of 10 CFR i 50.59 and with applicable PECO procedures by trained, qualified personnel. The SEs

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were found to be of sufficient detail and contain sufficient references to allow a i knowledgeable person to reach a similar conclusions. No undocumented unreviewed safety question (USQ) was identified and the documented USQs detailed NRC j involvemen .59 Applicability Determinations - The team reviewed approximately 40 CTEs for

which 50.59 safety evaluations were not performed and verified that the applicability

determinations were made in accordance with 50.59 procedures and controls. In general, the applicability determinations were of sufficient detail to support the no SE conclusion and the team did not identify specific instances where SEs should have been j completed.

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FSAR Updates and CTE Report - The team reviewed the 1997 annual report of changes j

made under 10 CFR 50.59 and selected FSAR updates to verify that the changes and

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the associated 50.59 SEs were accurately described. The team did not identify instances where a 10 CFR 50.59 SE was completed and not listed in the annual repor The FSAR had been appropriately updated pursuant to the requirements of 10 CFR l 50.71(e). Conclusions PECO has implemented an acceptable 10 CFR 50.59 program that produced applicability determinations and safety evaluations of good quality, met regulations and applicable plant procedures, and provided sufficient details and references to support the conclusions draw ES Engineering Staff Training and Qualifications j E5.1 10 CFR 50.59 Safety Evaluations Proaram Traininc and Qualifications Inspection Scope (37001)

The team reviewed training material to determine the quality of training and evaluate the qualification status of 50.59 preparers and peer reviewers. In addition, the team attended a 50.59 training session, Observations and Findinas The team verified that training and qualification met commitments established in the oporational quality assurance program and were consistent with current 50.59 procedure guidance through review of initial and continuous training materials for 10 CFR 50.59 preparers and reviewers. The !ssson plans, classroom handouts, and classroom

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I 16-discussion were of the appropriate scope and depth to address the preparation of 50.59 determinations (to complete SEs, more training was required). The team noted that no

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i written test or examination was required to become qualified and that no specific requalification was required to remain qualified. Updates on changes to the 50.59 ]

program had been incorporated into required continuous training sessions. The team reviewed the training records of select reviewers and preparers and verified that 50.59 program updates were part of the continuous training program five times in the last seven year ; Conclusions The training to support the 10 CFR 50.59 safety evaluation program was acceptabl I I

E7 Quality Assurance in Engineering Activities j

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E Effectiveness in Identifyina. Resolvina. and Preventina Problems  !

l inspection Scope (IP40500) j The team evaluated the effectiveness of PECO's controls for identifying, resolving, and preventing issues that could affect the quality of plant operations or safety. The team reviewed the monthly performance indicator summary, licensee event reports (LERs),

independent safety engineering group (ISEG) reports, and the equipment performance and material condition (EP&MC) focus list used in identifying and monitoring plant issues. The team also assessed the timeliness and appropriateness of corrective  ;

actions taken for the identified issues, and engineering resource utilization and  :

communication. Results of an engineering performance self-assessment were examined  !

by the tea Observations and Findinos

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identification of Problems and Corrective Action Taken  !

The team reviewed the Monthly Update Report / Performance Indicator Summary for both i units and found 15 instances of power reductions over the period November 1997 through October 1998 due to equipment deficiencies requiring repair. The causes of the

. equipment deficiencies were identified and repairs made such that there were no  :

impacts on safety. In some cases, the diagnosis was not immediately successful in l determining root causes, but engineering ultimately determined the causes and '

corrective actions were implemented. Included in the Monthly Uposte r Report / Performance Indicator Summary are indicators of emergency core cooling system (ECCS) and emergency ac power system unavailability. These performance )

indicators for important safety related systems and equipment showed acceptable i availability, j

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The team reviewed 1119981.ERs and found each event reported to have resu!!ed in planned corrective action. However, in the case of LER 2-98-003, Main Control Room Emergency Ventilation Trip Relay, an operations turnover notice to verify that Procedure GP-25 trip actions perform the intended function did not remain in place until revision of GP-25 was completed. The notice was returned to the procedure, and the team judged the error to be a commitment tracking error. LERs are discussed at regular nuclear l review board (NRB) meetings, giving oversight of the LER issues by all plant senior management.

g The team reviewed 1998 ISEG enpering related reports and found that  ;

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.nna reviews of selected plant issues provided recommendations for action to '

, improve performance in admin!strative or technical matters. The reports reviewed were

technically sound and indicative of careful investigation. The team found evidence that ,

recommendations resulted in action requests that were systematically tracked within the !

j site computer control syste j

[ The team reviewed 18 EP&MC focus list problem areas and found engineering had

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participated fully in the resolution of the chronic plant issues affecting the facility.

f implementation of solutions to these problems was systematically monitored with a j reasonable time scal The team reviewed the NMCA project, an initiative to inject platinum (Pt) and rhodium l (Rh) into the reactor vessel to provide a surface coating to curtail intergranular stress I corrosion cracking (IGSCC). The team reviewed the extensive background to the J procedure and the 10 CFR 50.59 review of the project, and determined that the initiative had been comprehensively implemente Enaineerina Resource Utilization and Communication The team attended meetings including the daily leadership meeting, engineering leadership meeting, plant operations review committee (PORC) meetings, and NRB Meetings. The team observed that all meetings involved participation and/or representatior: of all plant functions. The daily leadership meeting informed all plant functions of issues as they arose, allowing cross-functional discussion of the implications of each issue and directing the use of resources to resolve the problems. The engineering leadership meeting monitored the EP&MC list of plant issues, with the othcr i functions represented for cross-functional discussion. The team judged that open discussion of issues existed at severallevels of management and enabled plant issue resolution, particularly regarding engineerin Self-Assessment by Enaineerina The team reviewed an engineering branch self-assessment which was self- critical, identified areas needing performance improvement, and provided a plan for improvement.

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18 Conclusions Problem identification and eva!aations for issues fo: rid in performance indicator summaries, LERs, ISEG reports, and the EP&MC fous list were generally effectiv The timeliness and appropriateness of corrective actiMs for identified issues in the team's review were generally goo V. Manaaement Meetinas X1 Exit Meeting Summary The team presented the inspection results to members of PECO management at the conclusion of the inspection on December 11,1998, at the Peach Bottom Atomic Power Station. PECO l acknowledged the findings presented. No information was identified that should be considered i proprietar l i

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l PARTIAL LIST OF PERSONS CONTACTED I i

Peach Bottom Atomic Power Station i M. Alderfor Senior Manager- Plant Engineering l

, M. ChoKran Manager- Reactor Engineering

S. Danehower Manager - High Pressure Coolant injection System P. Davison Senior Manager, Plant Engineering M. DeLowery Manager, Civil / Structural Design J. Doering Vice President, Peach Bottom Atomic Power Station

T. Geyer Manager, Plant Engineering M. Hammond Manager, Component Engineering

J. Heam Manager, Design Changes

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G. Johnson Director, Engineering J. Jordan Manager, Mechanical Design i D.Keene Manager, Design Engineering , instrumentation and Controls l M. Kelly independent Safety

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C. Kerr Engineer, Nuclear Engineering Division, Electrical Engineering J. Kozakowski Engineer, Nuclear Steam Supply Systems

. G.Lengyel Manager, Experience Assessment O. Limpias Senior Manager, P' ant Engineering

W. Nelle Lead Assessment, Nuclear Quality Atsurance T. Powell

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Acting Manager, Design Engineering, Electrical M. Taylor Acting Manager, Experience Assessment K. Tom Engineer, Plant Engineering, Nuclear Steam SW ply Systems l O. W arfel Senior Manager, Design Engineering

]' M. Warner Plant Manager  ;

C. Wiedersum Manager, Engineering Training  !

J. Zardus Engineer, Plant Engineering United States Nu.glear Reoulatory Commission

A. McMurtray Senior Resident inspector i G. Meyer Chief, Civil, Mechanical, and Metallurgical Branch J. Wiggins Director, Division of Reactor Safety I

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l INSPECTION PROCEDURES USED l

lP 37001 10 CFR 50.59 Safety Evaluation Program IP 40500 Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems l lP 93809 Safety System Engineering Inspection (SSEI)

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LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Open l

l VIO 50-277(278)/98-09-01 Failure to translate design basis information into l procedures for the RCIC system (E1.1)

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i LIST OF ACRONYMS USED A Amperes

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A/R Action Request l- ATWS Anticipated Transient Without Scram CST Condensate Storage Tank CTEs Changes, Tests, and Experiments DBD Design Basis Document 1- DVM Digital Volt Meter ECCS Emergency Core Cooling Systems ECR' Engineering Change Request EDG Emergency Diesel Generator EOP Emergency Operating Procedure FSAR Final Safety Analysis Report GE General Electric HPCI High Pressure Coolant injection IBLOCA Intermediate Break LOCA Ky Kilovolt LER Licensee Event Report LOCA Loss Of Coolant Accident LOOP Loss of Offsite Power MOD Modification

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- MSIV Main Steam Isolation Valve l MWt Megawatts Thermal

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NPSH Net Positive Suction head NPSHa Net Positive Suction Head Absolute MVA megavolt-amp PBAPS Peach Bottom Atomic Power Station PCIV Primary Containment Isolation Valve -

PECO Philadelphia Electric Company PM Preventative Maintenance PORC Plant Onsite Review Committee RCIC Reactor Core isolation Cooling

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SAMP Severe Accident Management Procedure SBLOCA Small Break LOCA

SE Safety Evaluation 1 SU Start Up -  !

TS Technical Specification i UFSAR Updated Final Safety Analysis Report USQ Unreviewed Safety Question i VDC Volts Direct Current L

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