IR 05000440/1999013

Insp Rept 50-440/99-13 on 990712-30.Violations Noted. Major Areas Inspected:Effectiveness of Pnpp Program for Identification,Resolution & Prevention of Technical Issues & Problems That Could Degrade Quality of Plant Operations

ML20212A862
Person / Time
Site:	Perry
Issue date:	09/13/1999
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
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ML20212A842	List: IR 05000440/1999013 ML20212A837 ML20212A853
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50-440-99-13, NUDOCS 9909170147
Download: ML20212A862 (44)

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l U. S. NUCLEAR REGULATORY COMMISSION REGIONlli

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l Docket No: 50-440

' License No: NPF-58 l Report No: 50-440/99013(DRS)

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Licensee: FirstEnergy Nuclear Operating Company

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P.O. Box 97 A200 l Perry, OH 44081

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I Facility: Perry Nuclear Power Plant

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! Location: Perry, OH l Dates: July 12 through July 30,1999 ;

i inspectors: G. Hausman, Team Leader K. Green-Bates, Team Member D. Jones, Team Member D. Prevatte,- Team Member (Contractor)

G. O'Dwyer, Team Member R. Winter, Team Member Approved by: R. N. Gardner, Chief Electrical Engineering Branch l

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p 9909170147 990913 PDR ADOCK 05000440 G PDR l

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EXECUTIVE SUMMARY Perry Nuclear Power Plant NRC Inspection Report 50-440/99013(DRS)

An announced Nuclear Regulatory Commission (NRC) team inspection was conducted from July 12 through July 30,1999, to assess the effectiveness of the Perry Nuclear Power Plant's (PNPP's) engineering organization to perform routine and reactive site activities, including the identification and resolution of technical issues. The inspection team also assessed the effectiveness of PNPP's program for the identification, resolution and prevention of technical issues and problems that could degrade the quality of plant operations or safet Overall, engineering personnel dc.nonstrated a questioning attitude, a commitment to safety, and were knowledgeable, dedicated, and professional. However, some weaknesses were observed with attention-to-detail, timeliness of corrective actions, adequacy of documentation, and depth of technical reviews, in two particular instances, engineering personnel did not exhibit a complete understanding of the importance of compliance with licensing commitments and design bases, as described in Sections E1.5 and E2.2.b.1 of the repor The engineering organization was effectively performing routine and reactive site activities, including the identification and resolution of technical issues. Design change and modification packages, for the most part, were well-planned, comprehensive and technically correc However, specific examples where inattention-to-detail, lack of documentation to support engineering conclusions, and deficient technical depth were observed. Modification packages that contained risk and core damage assessment analyses demonstrated a sound safety focu Safety evaluations performed in accordance with 10 CFR Part 50.59 were thorough and showed improvement from previous assessments periods. Operability determinations were usually detailed and well documented, except for a few examples where inattention-to-detail and deficient technical depth were observe The corrective action program (CAP) was effective in identifying, resolving and preventing the recurrence of issues that could degrade the quality of plant operations or safety. The CAP was implemented with a low threshold for problem identification, the CR backlog was appropriately prioritized, and the use of CR trending to detect repetitive problems was well establishe However, the use of non-CAP tracking databases (e.g., ACTON) to manage organization work activities resulted in some conditions adverse to quality being entered into these databases without proper and timely corrective action resolution. Operating experience program material was appropriately incorporated into plant activities. Inter-departmental communications were successfulin promoting active staff participation in the CAP. Quality assurance audits and engineering self-assessment activities were thorough and identified performance based concerns. The following statements summarize the inspection results:

• Although instances where a lack of attention-to-detail were identified, in general, the modification packages reviewed by the inspectors were of good technical quality, well planned, and comprehensive. Modification safety evaluations and screenings were

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reasonable and clearly described the proposed design change. The inspectors concluded that design configuration controls were properly maintained throughout the modification process and were effective. (Section E1.1)

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The inspectors concluded that the 10 CFR Part 50.59 applicability checks and safety evaluations were thorough and appropriate for the plant changes reviewed. In addition, 10 CFR Part 50.59 procedures and training were consistent with commitments made to the NRC. (Section E1.2)

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The inspectors concluded that temporary modifications (TMs) were being controlled in an acceptable manner. Existing TMs were appropriately installed and tested. However, a NCV was identified involving the failure of Document Control Department personnel to follow written procedures in posting a TM on control room, TSC, and EOF facility drawings and controlling a safety evaluation. (Section E1.3)

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In most cases, the methods used in performing and revising design calculations for recent design changes were correct and appropriate. Documentation of the calculation purpose, assumptions, and design inputs had improved from previous inspection However, the inspectors identified one NCV where a calculation had not been revised in j a timely manner which resulted in a TS surveillance not being conducted utilizing conservative criteria. (Section E1.4)

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The inspectors concluded that the failure to correctly derive ECCS pump TS surveil!ance !

requirements from the USAR was a violation of 10 CFR Part 50.36. The violation was cited and a response required as a result of the failure to submit the required TS amendment in a timely manner. (Section E1.5)

. The inspectors concluded that acceptable engineerir aff support was provided during the modification closeout process. (Section E2.1)

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Overall, Engineering's support of the facilities and equipment, and its involvement with ;

and contributions to the plant's day-to-day operations, were satisfactory. (Section E2.2) i

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The licensee's operability determination process was effective. Operability determinations and the supporting evaluations were acceptable. However, a NCV was ;

identified due to the licensee's use of an unapproved accident dose calculation method, j which resulted in not meeting the requirements of 10 CFR Part 50.72 and Part 50.73 for leakage outside containment. In addition, the licensee's use of regulatory limits in place

~ of design basis limits during an operability determination resulted in an unresolved item ;

pending further NRC review. (Section E2.2)  !

- The inspectors concluded that the operating experience program was effectively ,

implemented. (Section E2.3)

- Two examples y ere identified where the document authors were not attentive to assuring that the documents contained the appropriate details. A CR did not discuss the relevance of iemoving the control. complex chillers' high temperature senor trip on the chillers' safety function and no bases were provided in the ECCS strainer debris i calculation for the engineering judgement used. (Section E3)

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The inspectors concluded that the system and des'ign engineering staff interviewed were qualified and knowledgeable about their systems and system design issue (Section E4)

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The engineering training and qualification program appeared satisfactory. (Section ES)

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The inspectors concluded that, in general, the system engineers were providing good plant technical support and were knowledgeable about Maintenance Rule requirement The inspectors also concluded that plant housekeeping and material condition of safety-related equipment observed was good; there were a few areas where a lack of attention-to-detail was noted. A procedural weakness for monitoring safety significant hangers was identified by the inspectors. (Section E6.1)

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The inspectors concluded the review committees effectively performed their duties of maintaining periodic review of activities, safety issues and evaluations. The inspectors concluded inter-departmental communications were effective in promoting active staff participation. The inspectors also concluded that the establishment of the Continuous improvement Group (CIG) demonstrated a rigorous attempt by the licensee to improve the plant CAP. (Section E6.2)

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The inspectors concluded that the majority of plant problems were identified, assessed, and had appropriate corrective actions assigned. Establishment of the CIG, recent efforts to prioritize the "CR database" backlog, and the trending and binning of reports demonstrated that effective methods were being applied by the licensee to improve the CR action item program. (Section E7.1) l

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The inspectors concluded that the ACTON database was not under effective management review and control. Therefore, there appeared to be a lack of an integrated, well managed program with management overview for all past and present plant action items contained in this database. The inspectors concluded that continued I effort would be required by the licensee to address and resolve this issu l (Section E7.1)  !

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The inspectors concluded that appropriate mechanisms were in place for self-assessments and quality assurance trending activities and that a number of plant and organizational problems were being identified. The licensee's trending program and effectiveness reviews contributed to identifying repetitive problems and inspectors !

concluded that QA investigations were accurate and thorough. (Section E7.2)

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The inspectors concluded that the audit process met 10 CFR Part 50, Appendix B, requirements. The QA audits were identifying problems and the licensee was taking appropriate corrective actions. (Section E7.3)

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Report Detalis The purpose of this inspection was to assess the effectiveness of the Perry Nuclear Power

- Plant's (PNPP's) engineering organization to perform routine and reactive site activities, including the identification and resolution of technicalissues and problems. In addition, the inspection team assessed the effectiveness of PNPP's processes that provided the controls for the identification, resolution and prevention of technical issues and problems that could degrade the quality of plant operations or safet To accomplish this the inspectors evaluated whether engineering was appropriately identifying problems, implementing adequate and timely corrective actions, as well as providing the appropriate depth and attention-to-detail of the engineering work being performed. The inspectors' primary focus was on engineering products completed during the previous year, which were considered representative of the current performance of the engineering organization. The inspectors reviewed engineering processes, which included engineering's involvement in and contributions to condition reports (CRs), modifications (both permanent and temporary), calculations, safety evaluations, operability assessments and responses to generic industry and NRC concern . Engineering E1 Conduct of Engineering Overall, the modification packages reviewed by the inspectors were acceptable. Although instances of lack of attention-to-detail were identified, in general, the modifications reviewed by the inspectors were of good technical quality, well-planned, and comprehensive. Calculations developed to support the modifications adequately supported the design change Post-modification efforts were correctly implemented in that: in-service test (IST) and in-service inspection (ISI) programs were changed appropriately; the Operations staff received training on

' the modification where necessary; and the simulator staff was notified of plant changes Drawings requiring revision due to modifications installed during Refueling Outage (RFO) 7 (March 27-May 3,1999) were generally revised within the 45 day limit specified in modification procedures. Of the 2220 drawings requiring revision during RFO7 (720 safety-related system critical), only 6 still required further revision. A CR (99-1698) had been generated for the unrevised drawings to_ document the problems. This demonstrated a rigorous effort by the licensee to maintain safety-related drawings as current and accurate as possible. A sample of affected drawings was reviewed by the inspectors and found to be appropriately revise l Safety evaluations and screenings for plant modifications were reasonable and clearly

described the proposed design change. For the most part,10 CFR Part 50.59 screenings and !'

safety evaluations for the modifications reviewed were appropriately prepared, of good quality, and were consistent with regulatory requirements and licensee procedures. The inspectors

' independently reviewed safety evaluation reference documents and determined that the evaluations appropriately addressed the review questions. Where unreviewed safety questions were identified, license amendments had been submitted and approved. The inspectors did not identify any unreviewed safety questions for the plant modifications reviewe l

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~ E Desion Chances and Modifications Insoection Scooe (37550: 37700: 40500)

The inspectors reviewed plant changes against the licensee's procedures and verified conformance with applicable installation and testing requirements. Accessible portions of the modifications were walked down and material condition of the surrounding areas were observed. The inspectors discussed the changes with the cognizant engineer when necessary to determine the rationale and extent of the chang ; Observations and Findinos The inspectors observed that the. licensee used the Design Change Package (DCP), the Simple Modification Request Form (SMRF), and the Equivalent Change Package (ECP)

for controlling plant modifications. The DCP controlled major system modifications, the SMRF was a streamlined process used for simple modifications, and the ECP was used to expedited component level plant modification Containment' Penetration Relief Valves' Radiation Endurance Evaluation l Modification SMRF 97-5088, "Over-pressure Protection for Containment Penetrations,"

Revision 0, dated November 14,1998, was developed to install relief valves at six containment penetrations to avoid over-pressurization that would result from heating and thermal expaneN of water trapped between the isolation valves as a result of a Loss of Coolant Accidein sOCA). Five of the six valves contained teflon-coated Viton stem seals. The teflon coating was provided for lubricatio Calculation EQ-154, " Service / Qualified Life of Nupro & Swagelock Valves When Used for Pressure Relief in Containment," Revision 1, dated May 4,1998, evaluated the ability of the valves' stern seals to withstand the radiation conditions associated with normal operation and LOCA, and still perform their design safety functions (i.e., open to relieve excess pressure and re-close to maintain the containment boundary). The calculation determined that the valves would be exposed to 1.94x10' rads gamma, that the radiation threshold of teflon was 2.7x10' rads, and breakdown of the teflon, with a resultant loss of tensile strength, would be expected. However, the calculation concluded that the teflon breakdown was acceptable, since the loss of tensile strength for this coating would not jeopardize the valves' operability. No evaluation was made of the potential loss of the teflon coating's lubricating qualities, and whether this could prevent the valves from opening at the correct pressure, or closing once they had opened. Failure by any of the five valves to operate in either direction could result in ,

significant containment degradatio ]

The licensee generated CR 99-1870, dated July 27,1999, and immediately contacted l the teflon manufacturer.' The manufacturer provided information which appeared to j support an operability determination for the teflon lubricating qualities at 2.7x10' rads; l

. however, it did not resolve the operability concems regarding the expected plant l radiation levels of 1.94x10' rads gamma. Based on the information provided, the J licensee determined that the valves were operable without reconciling the conflicting radiation level i i

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i The inspectors were concemed that the licensee made non-conservative operability and environmental qualification determinations in the face of conflicting manufacturer information. Subsequent to this inspection, the licensee again contacted the manufacturer's representative for additional information on the teflon's lubricity. The representative stated that the original communicationt had been in error, that the teflon had been tested at radiation levels well above those that would be experienced by the valves, and that no reductions in lubricity had beu observed. However, no actual test data on this property at these higher exposure levels could be provided. Based on this information, the licensee documented this conversation, determined that the teflon was qualified, and concluded that the valves were operable. The inspectors had no further questions regarding this issu This issue was an example of inadequate depth of engineering. First, the licensee did not adequately consider all of the possible failure modes of teflon. Then, after having this concern raised by the inspectors, the licensee did not thoroughly evaluate all of the manufacturer's information in the attempt to demonstrate that the valves were qualified for their intended servic b.2 Hiah Pressure Core Sorav (HPCS) Caosbility As Reactor Core isolation Coolina (RCIC)

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Design Change Control (DCC) 004 to E51-25, " Minimum Required Delta P Across the RCIC Pump For a Flowrate of 700 GPM," Revision 2, dated May 2,1999, was generated to support a potential operability determination for a surveillance test of the RCIC pump. The calculation determined that a RCIC flow rate of 670 gpm would i stabilize reactor level at 2 feet above L1 (the level at which the ADS system was actuated) for a reactor isolation event. It also determined that under the same conditions, HPCS would provide 517 gpm and stabilize RPV level at L1. The calculation concluded that RCIC performance was more limitin ,

The inspectors recognized that this conclusion was incorrect. If HPCS would not stabilize reactor level until it reached L1 and there was no margin, then ADS could actuate and the core could be uncovered. Consequently, HPCS would have failed to fulfill its design function as RCIC backup. The calculation did not recognize the HPCS system's performance was more limiting than RCIC's; it also did not identify that HPCS performance was unacceptable as describe Discussion with the licensee revealed that another analysis, NEDC-31984P (July 1991), j addressed the capabilities of both systems to meet the reactor level stabilization requirements for loss-of-feedwater events. Unlike DCC-004, it used lower reactor pressures corresponding to SRV electrically actuated relief setpoints. With this lower reactor pressure, both pumps would deliver higher flow rates to the vessel, which would

provide substantial margins to the L1 ADS actuation setpoint. Therefore, there was no '

actual HPCS operability concer Subsequent to this inspection, the inspectors discovered this same error in another calculation, E22-29," Evaluate HPCS Pump Performance Acceptance Cri?

Associated With the Higher Potential Reactor Pressure," Revision 4, DCC-073, dated April 19,1999. This calculation used the 517 gpm HPCS flow rate, shown above to be

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inadequate, as a basic assumption. In response to this finding, the licensee generated CR 99-189 Both of these calculations were examples of inadequate depth of engineering review and a lack of attention-to-detai Diesel Generator Exhaust Back-oressure Due to Testable Ruoture Disks SMRF 97-5078, * Latching Mechanism for the Testable Rupture Disk," Revision 0, dated March 8,1999, changed the design of the diesel generator testable rupture disks (TRDs). Calculation R48-8, "EDG Exhaust Vent Valve Size," Revision 1, dated February 3,1999, was generated to show that the back-pressure produced by the TRDs would not degrade the diesel generators' performanc The inspectors found that although the calculation did use a flow resistance coefficient I to represent the TRDs, it did not appear to adequately account for all of the resistance factors (e.g., shape, momentum loss due to direction change, etc). A second calculation reviewed by the inspectors, R48 20, " Redesign of the Latching Mechanism for Testable Rupture Disk," Revision 0, dated May 15,1998, DCC-01, dated September 16,1998, also addressed back-pressure due to the TRDs. However, it only considered the TRD flow area, and it made no adjustments for flow coefficient or other resistance factors. Therefore, both of these documents calculated non-conservative back-pressures associated with the TRDs. Further review revealed that the level of non-conservatism in both cases was small when compared to the conservatism built-in to the calculations and the margin in the design. Therefore, there were no operability concerns associated with this observation. Both these calculations were examples on inattention-to-detail in the performance of engineering. In response to this finding, the

. licensee initiated CR 99-187 Inadeauate Evaluation of Holes in Valve Seat Rinas

In 1985, a modification was performed on valve 1E12F009 to drill a 1/8" diameter relief hole in one of the valve's seat rings to prevent pressure locking. While drilling the hole,

, 4 it was discovered that the downstream seat ring was being drilled instead of the upstream seat ring. The hole was not completed and NR COC-3672 was generated. It

_ was resolved use-as-is based on

(1) the seat not being a pressure retaining part; and

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(2) the 150 psid design. In January 1999, during a review of past work documents, the licensee discovered that both of these reasons were incorrect and generated CR l 99-0015 to document the discovery. The CR acknowledged that the incorrectly drilled seat ring was in fact a pressure retaining part and evaluated it at a differential )

pressure (dp) of 1,500 psid, substantially above the maximum dp the seat ring would

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experience. This CR was also resolved use-as-is based on the fact that even with this

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higher dp, there would only be 20 pounds of force exerted on the area of a 1/8" diameter hol i l

The inspectors' review of this CR found that it had not addressed a more significant aspect of both the aborted and the completed holes on the seat rings' integrity - the seating and pressure forces applied to the seat ring by the valve disk. These forces would create stresses in the seat rings, and these holes would tend to increase the j 8 i

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stresses due to reduction in load bearing area and the potential for stress concentratio Therefore, the licensee's disposition of the second CR also did not adequately address the effects of the hole This was an example of lack of attention-to-detailin engineering. As a result of the inspectors' concern, the licensee generated CR 99-1807 dated July 16,1999. It properly addressed the effects on the seat ring stresses which were found to be satisfactory, b.5 Miscellaneous Modifications ,

Modification DCP 98-0052, "Feedwater Leakage Control System (FWLCS) Single Feedwater MOV Improvements," was developed to suspend seat leakage and seat leakage hydrostatic testing of four feedwater check valves as well as implement a number of measures to improve the overall reliability of the penetration and improve the safety of the plant. The inspectors observed that the modification was of good technical quality, well planned, and comprehensive. Safety evaluations and screenings for the modification were reasonable and clearly described the proposed design change. The licensee's 10 CFR Part 50.59 safety screening and evaluation process identified a plant l change described in the Updated Safety Analysis Report (USAR) and an Unreviewed l Safety Question (USO). Amendment No.105 to the facility was filed on March 26, ,

1999, to address the issue. During the review, the inspectors noted that the l modification package contained rigorous risk and core damage assessment analyses for the actions being taken. When it was noted that operator action was involved in the Probalilistic Risk Analysis (PRA) models, a thorough human interactions evaluation was performed based on EPRI industrial standard DCP 98-05023, " Replace Existing Gearing w/ higher Gearing to increase the MOV Actuator Degraded Voltage Capability as Required by GL (Generic Letter] 89-10,"

Revision 0, was developed to obtain an acceptable motor operated valve (MOV) margin as specified by GL 89-10. During the review the inspectors noted an example where inter-departmentaf communications were effective in assuring that the valve stem received the proper lubricant. Recent MOV Users Group testing showed Mobil 28 grease provided better in-service results than the previously recommended greas Although the Lubrication Manual update was not complete, active staff participation correctly identified that the previously specified grease was no longer authorized and applied the correct lubrican DCP 96-04070,"Agastat F7000 Series Time Delay Relay No Longer Available Replace With 2 Relays to Provide Time Delay & Instantaneous Contacts," Revision 0, was developed because the installed relay originally qualified by General Electric was no longer available. The modification installed two new relays to provide time delay and instantaneous contacts. The SMRF package's engineering evaluations clearly described the proposed design change, addressed the equipment qualification evaluation, setpoint changes, the 10 CFR Part 50.59 applicability check, and provided acceptable post-modification testing. No deficiencies were note Equivalent Change Package (ECP) 99-08043 added a metal oxide varistor to the K49G relay that provided an actuation signal to the reactor protection system (RPS) from the

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main turbine stop valve closure. The varistor provided a dampening effect on transient pulses. The ECP's engineering evaluations clearly described the proposed design

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change; the design checklints were appropriately completed; the 10 CFR Part 50.59 applicability check was performed; and post-modification testing of the RPS was completed satisfactorilyi Overall, the SMRF and the component level ECP modification packages reviewed by the inspectors were acceptabl c. Conclusions Overall, the quality of engineering activities reviewed was good. The engineering products and the inspectors' interactions with the engineering staff indicated a commitment to safety at all organizational levels. However, several examples indicated that the depth of engineering reviews and the attention-to-detail were not always at acceptable level Although instances where a lack of attention-to-detail were identified, in general, the modifications reviewed by the inspectors were of good technical quality, well planned, and comprehensive. Modification safety evaluations and screenings were reasonable and clearly described the proposed design change. The inspectors concluded that design configuration controls were properly maintained throughout the modification process and were effectiv E1.2 10 CFR Part 50.59 Evaluations and Screeninas a. Inspection Scooe (37001)

The inspectors reviewed the licensee's program for 10 CFR Part 50.59 safety evaluations and applicability checks. The review emphasized design changes and modifications to verify adequacy of controls and compliance with regulatory requirements. The inspectors discussed 10 CFR Part 50.59 applicability checks and safety evaluations with cognizant licensee personne ' b. Observations and Findinas The inspectors verified that formal procedural guidane,e, including assignment of responsibility, was established for implementing 10 CFR Part 50.59 requirement Implementing procedures appropriately described the methods for controlling and performing 10 CFR Part 50.59 applicability checks. The 10 CFR Part 50.59 applicability checks and safety evaluations reviewed were appropriately prepared, of good quality, and were consistent with regulatory requirements and licensee procedures. In addition, the inspectors verified that 10 CFR Part 50.59 safety evaluations had been submitted to the NRC as require The inspectors verified that the licensee's training and qualification program was consistent with commitments made to the NRC. The inspectors reviewed the training materials to verify consistency with the controls, procedures, and guidance for 10 CFR Part 50.59 preparation. The inspectors verified that trained and qualified personnel performed the necessary applicability checks and evaluations. In addition,

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the inspectors reviewed two recent 10 CFR Part 50.59 applicability self-assessment reports to verify that a feedback process was in plac Conclusions The inspectors concluded that the 10 CFR Part 50.59 applicability checks and safety evaluations were thorough and appropriate for the plant changes reviewed. In addition, 10 CFR Part 50.59 procedures and training were consistent with commitments made to the NR E1.3 Temocrary Modifications Inspection Scope (37550)

The inspectors reviewed the methods used to control temporary modifications. This review included the controlling procedure, selected open temporary modification packages, and associated 10 CFR Part 50.59 safety evaluations or applicability check Temporary modifications were discussed with cognizant licensee personne Observations and Findinos The inspectors determined that the temporary modification (TM) process provided acceptable controls for installing temporary materials and equipment. All TMs required an open Work Order for implementation, functional testing, removal and post-maintenance testing. A 10 CFR Part 50.59 applicability check and safety evaluation, if applicable, were completed prior to TM installation. The inspectors determined that the applicability checks appropriately addressed the plant change. The use of a TM for longer than one operating cycle was strongly discouraged and required the General Manager, PNPP Department's approval to be extended. The inspectors verified that the three (3) open TMs were properly installed. Although, the TM process was implemented as written, the methodology used to control certain TMs (e.g., out-of-service annunciator windows) was unique and different from other plants. However, no compromise of regulatory requirements were identifie Two issues were identified during review of the TMs. Temporary Modification 1-99-0002 was not posted on drawing D-302-643 in the control room, Technical Support Center (TSC), and Emergency Operations Facility (EOF) during the implementation of the tag order. The second issue involved a missing Safety Evaluation (SE) (98-0003) for TM 1-97-0026. The SE and applicability check were not micro-filmed with the T Technical Specification 5.4.1.a requires written procedures to be implemented covering the applicable procedures in RG 1.33. Procedures for documentation control and procedure adherence are specified in RG 1.33, Appendix A. The failure to follow Perry Administrative Procedure (PAP)- 1402, " Temporary Modification Control,"

Paragraphs 6.7.5.c. and 6.11.1.1, were examples where the requirements of TS 5.4. were not met and was a violation. However, this Severity Level IV violation is being treated as a Non-Cited Violation (NCV), consistent with Appendix C of the Enforcement Policy. The licensee promptly initiated CRs 99-1802 and 99-1876 to address these issues and corrected the affected drawings. (NCV 50-440/99013-01(DRS))

J C Conclusions The inspectors concluded that TMs were being controlled in an acceptable manne Existing TMs were appropriately installed and tested. However, a NCV was identified involving the failure of Document Control Department personnel to follow written

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procedures in posting a TM on control room, TSC, and EOF facility drawings and controlling a S E1.4 Calculations 1 Insoection Scope (37550)

The inspectors reviewed selected design calculations that were important to plant safety or had significance to probabilistic risk assessment (PRA) issues. The calculations were reviewed for accuracy and to verify that appropriate design inputs, assumptions, and calculation methods were use Observations and Findinas The inspectors reviewed several mechanical and welding calculations for adequacy of assumptions, completeness, and accuracy of conclusions. Although minor examples of a lack of attention-to-detail were observed, the methods used in performing and revising I design calculations were generally correct and appropriate. Methods, references, and inputs were clearly stated and open assumptions for new calculations were controlle The inspectors observed good documentation practices, such as, clearly stating the calculation purpose, listing verifiable design inputs, appropriate completion of calculation checklists, use of design review or alternate calculation, specifying verification methods, and resolving verifier comment b.1 Enaineerina Calculations to suoport TS SR 3.6.3. Mechanical calculation M51-013 calculated required compressor output to assure that containment hydrogen concentration levels remain below design basis. As described in TS bases B 3.6.33 and USAR Section 6.2.5.2.2, the M51 combustible gas mixing system was designed to operate following a LOCA. Technical Specification SR 3.6.3.3.2 required that surveillance tests be performed to verify that the M51 hydrogen gas mixing compressors can discharge a flow rate of 500 scfm into the drywell following a LOC As discussed in Section E7.1.b.2 of this report, the inspectors identified that calculation .

M51-013 had not been revised in a timely manner and incorporated into quarterly TS !

surveillance instructions (SVis) M51-T2003A and B. The calculation did not incorporate the results of flow measurement uncertainty and Calculation M51T09's potential diesel i generator (DG) frequency deviations. Because Calculation M51-013 had not been revised and incorporated into the current compressor performance test criteria, the test criteria was non-conservative. The licensee promptly issued CR 99-1892 dated July 29, 1999, and performed an operability determination (OD). In adoition, the required quarterly TS surveillance tests were placed on " hold" until the calculation could be revised and results incorporated into the surveillance tes I

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the TS surveillances was considered a violation of 10 CFR Part 50, Appendix B,

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Criterion XVI. However, this Severity Level IV violation is being treated as a NCV,

! consistent with Appendix C of the Enforcement Policy. This violation is in the licensee's l corrective action program as CR 99-1892. (NCV 50-440/99013-02(DRS)) Other Calculations The inspectors reviewed electrical and instrument and control calculations for adequacy ;

of assumptions, completeness, and accuracy of conclusions. An earlier NRC inspection l and a PNPP self-assessment had previously identified electrical calculation weaknesses in terms of a lack of rigor in design inputs and conclusions. The inspectors observed that the licensee had taken several steps toward long term resolution. Improvements

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were noted, as recent electrical calculation revisions, such as, PRDC-0006/02 (DCC-02)

showed improved documentation, clearly stating the calculation purpose, listing assumptions and verifiable design inputs, and specifying the verification metho Conclusions in most cases, the methods used in performing and revising design calculations for recent design changes were correct and appropriate. Documentation of the calculation purpose, assumptions, and design inputs had improved from previous ;

inspections. However, the inspectors identified one NCV where a calculation had not been revised in a timely manner which resulted in a TS surveillance being conducted utilizing non-conservative criteri E1.5 Surveillances Inspection Scope (37550)

The inspectors reviewed the most recent emergency core cooling system (ECCS)

pumps' surveillance tests, TS surveillance requirements, performance requirement calculations, USAR Section 6.3, CR 98-0568, " Deficient ECCS Technical Specifications," dated March 24,1998, and CR 99-1567, "HPCS Pump Failed Surveillance Test," dated June 7,199 _O_bservations and Findinas On July 26,1999, the inspectors observed that the design analysis in the USAR required significantly higher HPCS and Low Pressure Core Spray (LPCS) pump performance than that specified by TS Surveillance Requirement 3.5.1.4. When questioned by the inspectors, the licensee provided CR 98-0568 dated March 24,1998, which identified that the minimum performance requirements specified for all the ECCS pumps in TS Surveillance Requirements 3.5.1.4 and 3.5.2.5 were below the USAR design requirements. The licensee confirmed that the USAR design requirements were the appropriate requirement The inspectors' reviews of the ECCS pump performance calculations determined that surveillance test acceptance criteria were significantly higher than the TS surveillance

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requirements and met the USAR design requirements. The inspectors also verified that l the latest performances of the surveillance tests documented that all of the ECCS l

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pumps met both surveillance test acceptance criteria and design requirement Discussions with the operators revealed that the Operations staff had not been informed of the deficient TS surveillance requirements. Consequently, the inspectors concluded l

that administrative controls were not adequate to formally notify the operators of l deficient TS surveillance requirement l l

The inspectors were also concerned that the deficient TS surveillance requirements, which were initially identified on March 24,1998, had not been corrected in a timely manner. On January 14,1999, the corrective actions for CR 98-0568 were documented as complete based on preparation of a TS change request and supporting calculations, !

and the TS change request was ready for submittal to the NRC. However, the licensee l was not planning on submitting the TS change request until after August 1999, approximately 17 months from initial identification. The licensee's failure to correctly derive the TS surveillance requirements from the USAR analyses to assure that the necessary quality of systems and components was maintained as required by 10 CFR Part 50.36 was a violation. This Severity Level IV Violation was issued because the licensee failed to restore compliance by correcting the deficient TS surveillance requirements within a reasonable time frame after the deficient condition was identified, )

as required by Appendix C of the Enforcement Policy. (VIO 50-440/99013-03(DRS) l Conclusions j The inspectors concluded that the failure to correctly derive ECCS pump TS surveillance requirements from the USAR analyses was a violation of 10 CFR Part 50.36. The violation was cited and a response required as a result of the failure to submit the required TS amendment in a timelv manne E2 Engineering Support of Facilities and Equipment E2.1 Modification Supoort and Closecut Inspection Scope (37550)

The inspectors reviewed the methods used by the engineering staff to support the modification process. This included modification final review and closeout control Relevant procedures and records were discussed with cognizant licensee personne Observations and Findinos A review of the completed modification packages indicated that ample review was performed prior to preparing the design change, that satisfactory controls were evident in implementing design changes, and that final closeouts were completed in a timely manne .

4 Conclusions The inspectors concluded that acceptable engineering staff support was provided during the modification closeout proces E2.2 Operability Determinations Insoection Scoce (37550)

The inspectors reviewed PAP-1608, " Corrective Action Program," dated June 3,199 The methods used to perform operability determinations were reviewed to verify the adequacy of controls and compliance with regulatory requirement The inspectors focused on engineering activities that provided direct support of plant facilities and equipment, and Engineering's support of the day-to-day activities of the plant's Operations and Maintenance staff. Examples of the types of activities reviewed included providing inputs to operability determinations, assisting in the resolution of CRs, providing acceptance criteria for surveillance testing, and providing technical -

consultation on maintenance activities, Observations and Findinas The inspectors found that PAP-1608 adequately described methods for controlling operability determinations. The Shift Supervisor (SS) made the initial operability determination on the CR initiation form. Subsequent evaluations to provide further analysis of the conditions were usually completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The inspectors found that operability determinations were generally acceptable with sufficient detail, although two specific exceptions were noted, Unacoroved Accident Dose Calculation Method Used in Operability Determination On February 17,1999, the licensee identified a 135 gallons per hour (gph) leak outside containment from RHR relief valve 1E12-F036. Condition Report 99-0367 was initiated and immediate corrective action was taken by gagging the valve. Subsequently, the valve was removed as a part of a modification that removed the steam condensing mode of RHR from the plant desig The initial operability evaluation determined that the containment was inoperable because this leakage rate would cause all of the regulatory limits on accident exposure to be exceeded. The licensee had calculated that the control room limit would be reached at 60 gph, the offsite low population zone (LPZ) limit would be reached at 86 gph, and the site boundary dose limit would be reached at 100 gph. Based on this evaluation, the licensee reported this condition in a 1-hour phone call to the NRC per 10 CFR Part 50.7 Subsequent to the 1-hour phone call, the licensee performed new accident dose calculations for the as-found leakage based on the source terms and methodology contained in NUREG-1465, " Accident Source Terms for Light-Water Nuclear Power Plants." This new methodology removed much of the conservatism of Regulatory Guide 1.3. . These calculations showed that for the as-found leak rate, the accident

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exposures would be below all of the regulatory limits. Based on these new analyses, the licensee retracted the 1-hour phone call report on March 18,199 At the time the leak was discovered, the plant's approved design and licensing bases methodology for determining source terms and calculating accident exposures, as described in USAR Section 15.6.5.5.1, was GL 1.3. Although the new methodology of NUREG-1465 was endorsed by the NRC, and there was a pending license change request to adopt the new methodology, at the time of discovery of the leak the design and licensing basis for the plant was still GL 1.3. At the time the 1-hour report was retracted and at the end of the 30-day time limit after discovery for submitting a Licensee Event Report, the license amendment still had not been approved. Therefore, the plant was "in a condition that was outside the design basis of the plant." In response to this discovery, the licensee initiated CR 99-1918 dated August 2,199 CFR Part 50.72 required that for "Any event or condition during operation that results in the condition of the nuclear power plant, including its principle safety barriers, being seriously degraded; or results in the nuclear power plant being:...(B) In a condition that is outside the design basis of the plant..." a licensee shall notify the NRC within one hour of its occurrence.10 CFR Part 50.73 required that for these same conditions, a licensee shall submit a Licensee Event Report within 30 days after the discovery of the condition. On February 17,1999, the licensee discovered a leak outside containment from the RHR system that constituted a serious degradation of the containment, a principle safety barrier. This was a condition outside the plant's design basis. Although a 1-hour notification to the NRC was initially made, the subsequent retraction was contrary to 10 CFR Part 50.72. The licensee's failure to submit a Licensee Event Report within 30 days of the discovery of this condition was contrary to 10 CFR Part 50.73. This is an example where the requirements of 10 CFR Part 50.72 and 10 CFR Part 50.73 were not met and was a violation. However, this Severity

_ Level IV violation is being treated as a NCV, consistent with Appendix C of the Enforcement Policy. This violation is in the licensee's corrective action program as CR 99-1918 dated August 2,1999. (NCV 50-440/99013-04(DRS))

b.2 Reoulatory Limits Used in Place of Desian Basis Limits Durina Ooerability Determination A program to limit leakage outside containment was required by TS 5.5.2, " Primary Coolant Sourcer Outside Containment." This program was implemented by PAP-1111

" Primary Containment Leakage Reduction for Systems Outside Containment,"

Revision 1, dated December 15,1992, Procedure / Instruction Change (PIC) No. 4, dated September 3,1998. The licensee's PAP-1111 identif;ed the administrative and analytical leakage limits as 5 gph and 10 gph, respectively. Both the administrative and analytical limits were described in USAR Section 15.6.5.5.1.2; the analytical limit (10 gph) was described as one of the bases (the leakage rate assumed for dose calculations purposes) for the design basis analyses of control room and offsite accident radiation exposure limits that were contained in USAR Table 15.6-1 On January 25,1999, the licensee discovered that RCIC relief valve 1E51-F017 was leaking outside containment at a rate of 36 gph. The licensee evaluated the RCIC relief valve leak and determined that the leakage was above the analytical limit (10 gph) for leakage outside containmen _ _ _ _ _ _ _ _ _ _ _ _ _ _

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In performing the operability determination, the licensee compared the as-found leakage outside containment (36 gph) to the leakage rates which corresponded to the regulatory limits rather than the USAR design basis limits. The licensee had previously calculated the amount of leakage outside containment that would cause accident exposure to exceed the regulatory limits contained in 10 CFR Part 50, Appendix A, Criterion 19 and 10 CFR Part 100.11. The limiting exposures in all cases were for thyroid exposure. The control room 30 rem limit was reached at 60 gph leakage. The low population zone (LPZ) 300 rem offsite dose limit was reached at 86 gph leakage and the 300 rem site boundary dose limit was reached at 100 gph. Since the as-found leakage outside containment was less than any of the regulatory limits, the containment was considered operable and no reports were made per the requirements of 10 CFR Part 50.72 and 10 CFR Part 50.73. Condition Report (CR) 99-0174 was issued and the valve was promptly replace The inspectors questioned whether the operability determination should have been made comparing the as-found leakage rate to the USAR design basis limit of 10 gph (the analytical limit assumed in dose calculations) contained in USAR Section 15.6.5.5.1.2 and Table 15.6-15. Such a comparison would have shown the containment leakage to exceed the plant design basis and a 10 CFR Part 50.72, one hour notification to the NRC would have been require The inspectors' concern was based on specific statements identified in the Code of Federal Regulations, where 10 CFR Part 50.72(b)(1)(ii) requires that for "Any event or condition during operation that results in the condition of the nuclear power plant, including its principle safety barriers, being seriously degraded; or results in the nuclear power plant being:...(B) In a condition that is outside the design basis [ emphasis added]

of the plant..." a licensee shall notify the NRC within one hour of its occurrence. The term " design basis" was defined in 10 CFR Part 50.2 as "...that information which identifies the specific functions to be performed by a structure, system, or component of a facility, and the specific values [ emphasis added] or ranges of values chosen for controlling parameters as reference bounds for design. These values may be...(2) requirements derived from analyses (based on calculation and/or experiments)

of the effects of a postulated accident for which a structure, system, or component must meet its functional goals." in this instance, the " design basis", i.e., the " requirements derived from analyses...of the effects of a postulated accident", were the calculated accident dose limits or " specific values" in USAR Table 15.6-15, and the " functional goals" were the above described regulatory limits these values were required to mee Within this definition, the leakage condition discovered by the licensee was outside the design basis, and the containment leakage should have been reporte Generic Letter 91-18, "Information to Licensees Regarding NRC Inspection Manual Section on Resolution of Degraded and Nonconforming Conditions," Revision 1, dated October 8,1997, gave further guidance on making operability determinations that was consistent with the regulations. It referenced NRC Inspection Manual, Part 9900,

" Operable / Operability: Ensuring the Functional Capability of a System or Component",

which in Section 5.3, stated, "According to the definition of operability, a safety or safety support system or structure must be capable of performing its specified function (s) of prevention or mitigation as described in the current licensing basis, particularly the TS bases or FSAR." " Current licensing basis" was defined in Section 2.1 as "...the set of

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NRC requirements applicable to a specific plant, and a licensee's written commitments (emphasis added] for assuring compliance with and operation within applicable NRC requirements and the plant-specific design basis [ emphasis added]..." In this case, the

" written commitments" to the " plant specific design basis" were the accident dose limits committed to in USAR Table 15.6-15 and the leakage limits upon which they were '

base i in response to the inspectors' concem, the licensee generated CR 99-1888 dated July 28,1999, which documented both the licensee's and the inspectors' concerns. The licensee's position, as stated in this document, was that the containment design basis and the associated "specified safety function" were to limit doses to 10 CFR Part 100, as described in USAR Section 6.2.1.1, No mention was made in this document of the 10 CFR Part 50, Appendix A, Criterion 19 control room dose limits. However, Regulatory Guide 91-18 defined "specified safety function"in Section 3.3 as follows,

"The definition of operability refers to capability to perform the "specified functions." The specified function (s) of the system, subsystem, train, component, or device (hereafter referred to as system) is that specific safety function (s) in the current licensing basis

[ emphasis added] for the facility." As previously described, the " current licensing basis" is also defined in this document as the " licensee's written commitments for assuring compliance with and operation within applicable NRC requirements and the plant-specific design basis." The analyzed dose limits contained in USAR Table 15.6-15 and their corresponding leakage limit,10 gph, were the " plant-specific design bases for assuring compliance with NRC requirements" of 10 CFR Part 100.11 and 10 CFR Part 50, Appendix A, Criterion 1 In addition to the January 25,1999, RCIC relief valve leakage event, a second example occurred at PNPP where operability and reportability were evaluated against the accident dose regulatory limits rather than the design basis limits contained in the USAR. This event occurred on February 17,1999, and is described in Section E2.2. of this repor The NRC has decided to further evaluate this issue and sp'ecifically address:

(1) whether the licensee's use of accident regulatory limits contained in 10 CFR Part 50, Appendix A, Criterion 19 and 10 CFR Part 100.11, which were used in place of the licensing commitments of the USAR during an operability /reportability assessment complies with NRC regulations; and (2) to address whether the licensee complied with NRC regulations 10 CFR Part 50.72 and 10 CFR Part 50.73 when they failed to notify '

i the NRC that they were outside the USAR specified design basis limits. Pending completion of the NRC's review, this concern is considered an unresolved ite (URI 50-440/99013-05(DRS))

b.3 Verification of HPCS Pumo's Dual Role Caoability The HPCS system was designed to inject to the reactor for two basic functions. The first function was injection over the full spectrum of LOCA breaks, including large break LOCA, where the reactor pressure would be low. The second function was as backup for the RCIC system for loss-of-feedwater (reactor isolation) events, where the reactor pressure could be as high as the main steam safety / relief valves' (SRVs') setpoin .

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Amendment No.101 to the Perry Technical Specifications authorized a relaxation of the SRV setpoint tolerance from 1% to 3% As a result, there was the potential that the reactor could be at even higher pressure for reactor isolation events. The licensee recognized that the HPCS pump ASME Code Section XI surveillance testing that was being performed represented only its low pressure performance requirement by using a reference point at the low pressure end of the pump curve. In order to assure that the testing would also verify HPCS's capability to fulfill its RCIC backup role, the licensee generated Calculation E22-29," Evaluate HPCS Pump Performance Acceptance Criteria Associated With the Higher Potential Reactor Pressure," Revision 4, DCC-003, dated April 19,1999, which demonstrated that if the low pressure surveillance test acceptance criteria were met, the pump would also be capable of meeting,the RCIC backup high pressure performance requirement Conclusions Overall, Engineering's support of the facilities and equipment, and its involvement with and contributions to the plant's day-to-day operations, were satisfactor Although two specific exceptions were identified, the inspectors concluded that the licensee's operability determination process was effective. Operability determinations and the supporting evaluations were acceptable. However, a NCV was identified due to the licensee's use of an unapproved accident dose calculation method, which resulted in not meeting the requirements of 10 CFR Part 50.72 and Part 50.73 for leakage outside containment. In addition, the licensee's use of regulatory limits in place of design basis limits during an operability determination was considered an unresolved item pending further NRC revie E2.3 Operatina Experience Proaram Inspection Scope (40500)

The inspectors reviewed the methods for obtaining and using industry operating experience. This included industry information obtained from outside sources including the NRC, industry groups, vendors and other licensees for the operating experience program. The inspectors interviewed cognizant licensee personnel about the industry experience progra Observations and Findinos The licensee's PAP-1607, " Operating Experience Reports (OER) Program," Revision 1, assigned responsibilities for the receipt, assessment, dissemination, and the initiation of corrective actions for industry experience information. The inspectors verified the dissemination and availability of operating experience (OE) by interviews with the electrical maintenance manager and other observations. The inspectors verified that the licensee adequately implemented corrective actions for operational experience feedback as outlined in the procedure. The inspectors also verified that OE was incorporated into the operator training program as evidenced by the usage of current industry events into the lesson plan (OER 15-96, inappropriate Operator Actions During Low-Power Operations).

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. i l Conclusions The inspectors concluded that the operating experience program was effectively implemente E3 Engineering Procedures and Documentation J Inspection Scoce The inspectors reviewed procedures and documentation that both controlled and directed the conduct of engineering. The inspection focused on the validity, completeness, and quality of the procedures and documents themselves, rather than the technical aspects of engineering product Observations and Findinas ,

i b.1 incomplete Control Comolex Chiller Trio CRs Evaluation Condition Report 98-2649, " Control Complex Chiller Motor Trip on High Temperature,"

dated December 25,1998, documented a trip of control complex chiller A on January 13,1999, due to a high motor temperature. This was the fourth occurrence of this trip in thirteen months. The cause was identified as a failed motor temperature j sensor The remedial action was to remove the motor temperature sensor trip from both the A and the B chillers' control logic, thereby restoring their reliabilit ]

Extensive documentation was provided in the CR package that addressed the mode of failure, cause of failure, maintenance rule applicability, and the proposed corrective action. However, none of the documentation discussed the relevance of this trip function to the safety function of the control complex chillers, or how removing this function from the control logic would affect the chillers' safety functio Through discussion with the responsible engineer, it was determined that the equipment in question was commonly used in commercial applications, and that this trip was a standard vendor-supplied feature intended to protect the equipment. While this trip function would be desirable for most commercial applications, in this safety-related application, it was counter to the system's safety function. Therefore, from a safety system reliability perspective, it was not only permissible to remove this trip function, but ,

desirable. However, the documentation was incomplete in that it did not address this I most pertinent point. This was an example of inattention-to-detail in the CR documentatio j Incomolete ECCS Strainer Debris Calculation Documentation i

Calculation T23-010, " Cable, Coating, Misc. Debris Quantities-ECCS Strainer,"

Revision 0, DCC-01, dated April 22,1999, was generated to evaluate the ECCS pump strainer, and determine the quantities of debris that would be generated in the drywell '

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and washed down into the suppression pool as a result of a LOCA. Several of the calculation's assumptions concerning the percentages of material affected were based

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on " engineering judgement," but no bases were provided for these judgement Procedure NEl-0341, " Calculations," Revision 6, required that the bases for such assumptions be provide As a result of the inspectors' observation, the licensee generated CR 99-1853 dated July 23,1999. This document indicated that all of these assumptions were actually supported by other calculations or by testing; therefore, there were no operability concerns. The licensee verbally committed to revising the calculation to include these bases for the assumptions. This was considered an example of inattention-to-detail in generating engineering documentatio c. Conclusions Two examples were identified where the document authors were not attentive to assuring that the documents contained the appropriate details. For example, a CR did not discussed the relevance of removing the control complex chillers' high temperature senor trip on the chillers' safety function and no bases were provided in the ECCS strainer debris calculation for the using engineering judgemen E4 Staff Knowledge and Performance I a. Inspection Scooe (37500: 40500)

The inspectors assessed engineering staff knowledge of their systems and system design issue b. Observations and Findinas The inspectors interviewed several system and design engineers as well as other plant staff during plant walkdowns and modification reviews. Both the system and design engineering staff were found to be knowledgeable about their systems and system design issues. System engineers could readily provide the top priority concerns for their system along with the corrective actions being taken. The design engineers were able to discuss the reason and effectiveness for each modification they were involved wit Most of the engineering staff had seven or more years of plant experienc c. Conclusions The inspectors concluded that the system and design engineering staff interviewed were qualified and knowledgeable about their systems and system design issue l

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E5.1. Review of Enaineerina Trainina Insoection Scope (40500)

' The training and qualification of engineers were reviewed. The training records of five'

engineers wore reviewed and discussions held with cognizant licensee personnel about

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. the training progra Observations and Findinas -

The implementing procedure described methods for controlling the adequacy of the engineering training. The training records for each section were maintained by that section. The inspectors reviewed the training records for five engineers and found them -

to be up-to-date. The licensee controlled the number of personnel trained to perform

operability evaluations and root cause evaluations. Only personnel that had been trained were allowed to perform the evaluations. The inspectors confirmed for several individuals that they had been trained to perform and review operability determinations, safety screenings and safety evaluation During this review, the inspectors noted that there were some weaknesses with record-keeping, e.g., the inspectors found that an engineer's qualification card was issued before the Perry Training Section Manager signed as required. However, the inspectors noted that the engineer's supervisor and engineering manager had both .

signed as required previous to issuance. The licensee entered the weakness into the corrective action program (CAP) by initiating CR 99-1822 on July 19,199 . Conclusions The engineering training and qualification program appeared satisfactor E6' Engineering Organization and Administration E System Enaineerina Proaram . . Insoection Scone (37550) 1 The inspectors reviewed the system engineering program to ensure the system engineers were maintaining their systems and providing good support to other plant organizations. In addition, the inspectors interviewed several system engineers, b.' Observations and Findinas b,1 System Enaineerina -

. The inspectors interviewed three system engineers. The system engineers were knowledgeable about their systems, were qualified for their assignment and in most

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cases exhibited ownership of their assigned systems. System engineers were knowledgeable about Maintenance Rule requirements and provided input into plant schedules for what plant system items should be fixed and when. The inspectors noted that the system engineers maintained good communications with other departments, particularly maintenanc b.2 Plant Walkdowns After review of the PNPP risk significant areas provided by the licensee, the inspectors and appropriate system engineer walked down portions of the Emergency Service Water (ESW) system and the Division 1 & 3 emergency diesel generator rooms (EDG)

as these systems were rated among the top seven train contributions to plant ris The inspectors observed that the safety-related areas and equipment material condition were good. However, the inspectors noted the following three conditions that existed for long periods indicating some lack of attention-to-detail on the part of plant staf Safetv-Related Eauioment Labelina: The safety-related HPCS ESW pump strainer imtrument valve No.1P45-F563 had been identified on March 2,1996, as missing it's identification label and a temporary paper tag had been affixed to the valve bonnet. The valve was entered into the plant tag corrective action process program as 1-96-189, in order to install a metal component label as required by plant label procedure PAP-1407. However the inspectors identified that the permanent label for this valve had not been installed in over 3 year The inspectors interviewed staff and found that it was generally common knowledge that permanent labels were expected to be installed in a timely manner of less than 6 months (PAP-1404, Section 6.1.1.2, "Information Tagging Rules"). Licensee personnel informed the inspectors that the label had been lost from their label replacement database tracking system and therefore the routine bi-annual safety label audits had not captured this issue. Licensee personnel informed the inspectors that the ESW label would be replaced into their label monitoring database and installed at the earliest opportunit Unsecured Eauioment in ESW Safety Sianificant Area: During the welkdown of ESW equipment in the safety-related ESW pump house, inspectors noted that an air compressor was not secured to prevent it from sliding into safety-related equipment in the event of a seismic event. The inspectors determined that the equipment had baon there for 5 days and considered that because routine plant personnel walkdowns of the safety-related ESW pump house on a daily / shift basis did not identify this highly visible piece of equipment and promptly correct this situation, that this indicated a lack of attention-to-detail on the part of the Operations personnel. The inspectors observed that the system engineer took i prompt action to identify this situation to the control room and correct the situatio l

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Hanaer Deficiencies: During the walkdown of the EDG rooms, the inspectors observed two safety-related hangers that had grout missing and a gap between ;

the hanger baseplate and wall to which the hanger was anchored, i

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On reviewing plant ISI Procedure NQl-1042 to monitor safety significant support hangers and Procedure SP-2450 to install safety support anchors, the inspectors noted that the installation acceptance criteria for the anchor bolts (1/16") and baseplate (1/4") distance from the anchoring cement wall were not incorporated into plant monitoring procedures and questioned the licensee as to how I degradation of the clearances / tolerances due to water hammer, etc., would be l monitore '

Although the gaps found during the walkdown were not a concern at this time, a weakness in plant safety significant hanger monitoring procedures was identified by the inspectors. There did not appear to be sufficient quantitative evaluation criteria to assure that the plant criteria contained in design basis calculations for ,

safety significant hanger supports was met. The licensee issued CR 99-1981 !

dated August 11,1999, to address the issue, Conclusions The inspectors concluded that, in general, the system engineers were providing good plant technical support and were knowledgeable about Maintenance Rule requirement The inspectors also concluded that plant housekeeping and material condition of safety-related equipment observed was good; there were a few areas where a lack of attention-to-detail was noted. A procedural weakness for monitoring safety significant hangers was ider,tified by the inspector E6.2 Review Committee Activities Inspection Scoce (40500) l

The inspectors evaluated the review committees' implementing procedures, minutes, audits, and followup actions of items identified by the committees. The inspectors j discussed the functions, findings and activities of these committees with cognizant i licensee personnel. In addition, the inspectors attended several review committee meeting Observations and Findinas The inspectors reviewed PAP-0103, * Plant Operations Review Committee," Revision 6, which defined the activities and responsibilities of PNPP's On-site Review Committe The inspectors also reviewed " Company Nuclear Review Board Policies and Practices,"

dated March 9,1999, which defined the activities and responsibilities of PNPP's Offsite Review Committee. The inspectors reviewed recent minutes of each review committee's meetings to evaluate the activities and decisions made. The licensee's Quality Assurance group periodically audited both the Plant Operations Review Committee and the Company Nuclear Review Board; however, no significant issues were identified during recent audits. Additionally, the inspectors observed the morning management meeting where management reviewed recently issued CRs. The management review generally addressed the relevant issues and reevaluated the category level. The format of the meeting encouraged inter-departmental communications that were effective in promoting active staff participatio r

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b.1 Corrective Action Review Board The inspectors reviewed the controlling procedure for the Corrective Action Review Board (CARB), selected records of meeting minutes, and a trending corrective action performance indicator for plant CRs. The inspectors attended a CARB meeting held on July 14,1999, and observed that this meeting was conducted in accordance with procedural requirements and in a professional manner. CARB members raised pertinent questions and exchanged real time knowledge about issues that were discussed. After an in-depth discussion, the committee identified areas where a CR required further development. The CARB rejected the submitted CR until the identified areas were completed, b.2 Corrective Action Proaram (CAP) Continuous Imorovement Group The inspectors observed that a CAP Continuous improvement Group (ClG) had recently been established at PNPP to improve the effectiveness and efficiency of the CAP. The inspectors reviewed the CIG charter and attended a CIG Committee meeting during the inspection. The issues addressed in the meeting indicated the committee reviewed substantial corrective action issues in depth, such as CR quality, and provided greater efficiency in monitoring plant problems by improving CR trend codes processes. In order to evaluate CR quality, the CIG developed a CR quality index scorecard and graded 20 randomly chosen safety CRs against the desired criteria. Five of the CRs were also cross graded by more than one supervisor and the generated scores ,

compared to monitor whether CR expectations were consistent across plant discipline { Conclusions '

The inspectors concluded the review committees effectively performed their duties of maintaining periodic review of activities, safety issues and evaluations. The inspectors concluded inter-departmental communications were effective in promoting active staff participation. The inspectors also concluded that the establishment of the CIG demonstrated a rigorous attempt by the licensee to improve the plant CA E7 Quality Assurance in Engineering Activities E7.1 Corrective Action Proaram Inspection Scoce (40500)

The inspectors assessed the CAP through CR reviews and by interviewing cognizant personnel about the corrective action and CR processe Observations and Findinas A detailed review of CRs, problem identification forms (PlFs) and ACTON ("act on")

engineering actions items was performed. The inspectors determined that the CRs provided a clear problem description and, in most cases, corrective actions were appropriate for the problem significance. Overall, the inspectors found that the

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threshold for identifying problems was relatively low and that personnel interviewed .

appeared willing to identify problems through the CR process. The establishment of the

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ClG, recent efforts to prioritize the CR database backlog and the trending /binning of '

CRs demon,strated that effective methods were being applied by the licensee to improve the CA The licensee stated that engineering work load was higher than desired and timeliness of issue resolution within the engineering organization was a known weaknes Although actions were being taken to improve the process, the inspectors observed I some instances where attention-to-detail, stand-alone documentation (without requiring l recourse to the originator), depth of corrective action investigation and timeliness of !

fixing identified plant problems were found. These areas were considered by the ;

inspectors to be known problem areas that will require a continued management effort i for resolution and are discussed in Section E7.2 of this repor I Use of Alternative Databases The licens"o assigned CR backlog reduction a high priority and had recently completed a signific effort to re-prioritize all open action items in the CR database. However, the inspectors determined that the licensee also used other databases (e.g., the ACTON and the Operations Label Replacement databases)in addition to the CR dat@e to track and manage work items. The inspectors identified some examples wheie, the use of the ACTON database resulted in items with conditions adverse to quality being entered into the database without the proper CAP resolution. Although a significant effort to re-prioritize the CR database was completed, the licensee could not demonstrate to the inspectors that the other databases were effectively managed and controlled. As a result, the inspectors were concerned that the other databases could contain additional examples of conditions adverse to quality that were not appropriately identified and that adequate management overview of all past and present action items contained in these databases were not effectively manage Based on inspectors' questioning, the licensee investigated five NSSS ACTON items, it was found that two of the items had been completed but had not been closed out and two were considered safety-related enhancements to the plant rather than required items. The remaining item was safety significant and had not been corrected in a timely manner (see Section E7.1.b.2). Although most of these ACTON database items were identified as not safety significant, the fact that neither plant management or the cognizant engineer assigned to the ACTON item knew this prior to the inspectors'

questioning was considered a weakness in the program. As a result, the licensee issued CR 99-1892 dated July 29,1999, to address action items within the ACTON database. The inspectors were satisfied that this matter would be addressed; however, the inspectors concluded that to ascertain, monitor and track the total backlog of action items established at the plant, management attention was required to ensure that only appropriate issues were entered into the attemative database b.2 Timeliness of Revisino Calculation M51-013 & Associated Values in SVis M51-T2003A/B On February 19,1987, a field change request was generated that stated the acceptance criteria for SVis M51-T2003A/B did not meet the GE specification. The licensee did not

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initiate any changes to the calculations or associated SVI values. As a result of the licensee researching similar calibration issues identified by an NRC Inspection conducted in 1997 (Inspection Report 50-440/97201), PIF 97-0165 was generated but was closed out as ACTON database item 97-050 without revising the calculation and associated SVis. This issue was placed into the ACTON database in 1997 without the calculation's associated SVis being placed on hold. At the time of this inspection, the inspectors observed that work had not been initiated on the ACTON database item. As a result, an identified safety-related calculation was not corrected in a timely manner and was considered a NCV as described in Section 1.4.b.1 of this repor RFO7 Modifications & CRs Closed Out to the ACTON Action Item Database Under the current safety-related DCP modification process, a modification may be closed if the remaining items such as non-critical procedure revisions are placed within the ACTON database as action items. As a result, if the original CR initiating the modification was written in a manner such that the completion and closure of the modification satisfies the action item, in essence the CR becomes closed out to the ACTON system without allitems completed. The inspectors noted that plant modification procedures did not state that safety-related modifications could be closed out to the ACTON database prior to completion of all ancillary plant change action item After discussion with licensee staff a desktop administrative guide was produced which indicated that this was an acceptable program practice. Because the modification program procedures did not specifically address what DCP items could or could not be placed into the ACTON system prior to plant change closure, and as ACTON items were not closely tracked and prioritized, the inspectors considered this another example of corrective action items that were not presently under close management review and contro Conclusions The inspectors concluded that the majority of plant problems were identified, assessed, and had appropriate corrective actions assigned. Establishment of the CIG, recent efforts to prioritize the "CR database" backlog, and the trending and binning of reports demonstrated that effective methods were being applied by the licensee to improve the CR action item program. The inspectors concluded that the ACTON database was not under effective management review and control. Therefore, there appeared to be a lack of an integrated, well managed program with management overview for all past and present plant action items contained in this database. The inspectors concluded that continued effort would be required by the licensee to address and resolve this issu E7.2 Corrective Action Trendina i Inspection Scope (40500)

The inspectors assessed the licensee's program for trending plant problems and reviewed selected trend report j i

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. Observations and Findinos Plant personnel generating a CR were required to chose a trending code most applicable to the CR. The QA trend coordinator then tracked, searched and sorted CRs by codes to identify plant trends. Upon identification of an adverse trend, an adverse trend CR was issued to identify if additional corrective actions were necessary. The inspectors reviewed several trend reports and determined that the reports were of good quality. This was due, in part, to having a QA trend coordinator that was knowledgeable about the plant and in.timately involved in site corrective action panels. Staff commitment to the value added by trending CRs was demonstrated by the fact that both operations and maintenance management had started proactively trending department CRs on a weekly basis. By alerting work crews to trends and lessons leamed from the previous weeks CRs, management anticipated quicker turn-a-rounds in averting negative practices and trends within these department The inspectors also noted that during RFO7, site and human performance error CRs had been graphed and used to determine when plant stand-downs to address significant 1 issues should be deployed. The effectiveness of the stand-down was assessed by tracking when issue CRs returned to baseline. The licensee also planned to use the RFO7 identified contractor human performance error trends for future outages by preplanning plant stand downs for identified issues into the upcoming RFO8 outage schedul The inspectors reviewed several QA effectiveness reviews. The licensee had identified i several instances where corrective actions were ineffective and additional actions were l assigned to these problems. The inspectors determined that the QA reviews were a I good tool for identifying additional corrective actions that may be warranted,

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i From its review of self-assessment recommendations and audit findings, the inspectors noted some general themes which paralleled the inspectors findings on corrective j actions. Attention-to-detail problems, stand alone documentation without requiring 1

, recourse to the individual originator, and timeliness of fixing identified plant problems ,

l were areas that will require continued effort for resolution.

, Conclusions

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The inspectors concluded that appropriate mechanisms were in place for self-assessments and quality assurance trending activities and that a number of plant and I crganizational problems were being identified. The licensee's trending program and j effectiveness reviews contributed to identifying repetitive problems and inspectors l concluded that QA investigations were accurate and thoroug E7.3 Audits and Surveillances Inspection Scope (40500)

The inspectors reviewed the methods used to perform and control the QA audits of engineering. The review included the controlling procedures, the results of the Design Control Audits numbered PA-97 and PA-99, discussions with site senior management 2d

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and the Perry Plant Program Audit Schedules for 1997,1998,1999, and 2000. The attacned document list identifies the other quality assurance audits that were reviewe Observations and Findinas The inspectors found acceptable Nuclear Quality Instruction NQl-1801," Audit Program Control," Revision 1, which specified the process for the QA program to accomplish the audits. The inspectors' review of selected QA engineering audits revealed that audit findings and recommendations were entered into the CAP by the proper initiation of CRs. The Company Nuclear Review Board was the licensee's offsite safety review committee which reviewed all QA audit schedules and the resulting audit The inspectors conducted interviews with the QA manager, the Directors of the Nuclear Engineering Department, Perry Services Department, and the Perry Power Plant Department. These individuals stated that the QA program was effective in identifying problems and recommending corrective actions, and that line organizations such as engineering did not minimize QA findings. These individuals also stated that line organizations worked well with QA sometimes nequesting QA audits, in problem area Conclusions The inspectors concluded that the audit process met 10 CFR Part 50, Appendix B, requirements. The QA audits were identifying problems and the licensee was taking appropriate corrective action E8 Miscellaneous Engineering issues (92903)

. E8.1 - LClosed) Violation (50-440/98011-01(DRSik The instantaneous trip function for the emergency closed cooling pump motor's circuit breaker (EF1804) was not tested in-accordance with design requirements. The as-tested acceptance criteria values were calculated by the technician performing the test at values higher than the allowable band. This resulted in the breaker's instantaneous pick-up value not being tested within the required design parameters. The inspectors reviewed the licensee's corrective actions addressed in letter Number PY-CEl/NRR-2311L dated August 13,199 i Corrective actions included the following: an engineering evaluation determined that the as-tested values were satisfactory and the breaker would operate as required; a review was conducted of similar tests and no additional discrepancies of this type were identified; electrical maintenance personnel completed generic electrical instruction (GEI) training on the requirements of breaker testing; and the associated gel was scheduled to be revised to include a table of acceptance criteria test values for testing the instantaneous trip function. The inspectors concluded that the licensee's corrective actions were acceptable. This item is close ,

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O V. Manaaement Meetinas XI Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on July 30,1999. The licensee acknowledged the findings presented. The inspectors questioned the licensee as to the potential for proprietary I

. information being included or retained in the inspection report as discussed at the exit, No

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proprietary information was identified as included or retained at the completion of the inspectio j

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l PARTIAL LIST OF PERSONS CONTACTED Licensee C. Angstadt, Design Engineering Assurance H. Bergendahl, Services Department Director B. Boles, Plant Engineering Manager R. Cherlick, l&C Design Engineer R. Collings, Quality Assurance Manager D. Gudger, Compliance Engineer - Regulatory Assurance Section R. Haynes, NSSS Plant Engineering Supervisor H. Hegrat, Manager - Regulatory Affairs T. Hilston, Design Engineer- Design Engineering Section '

I J. Hubbartt, Corrective Action Group W. Kanda, Plant Manager J. Kloosterman, CAP /ISEG Supervisor j T. Lentz, Supervisor, Design Engineering {

R. Lockwood, Corrective Action Specialist R. Mackowski, Design Engineer - Design Engineering Sectic,a

. P. Nichols, Supervisor, Mechanical Design Engineering J. Powers, Design Engineering Manager T. Rausch, Operations Manager R. Schrauder, Director of Engineering S. Seaman, IST Engineer T. Stear, Design Engineer

' R. Tadych, Project Manager - Design Engineering Section R. Tanney, Supervisor Electrical Design Unit B. Todd, EQ Engineer F. Von Ahn, Configuration Mariagement Information Technology Manager NRC R. Gardner, Chief - Electrical Engineering Branch C. Lipa, Senior Resident inspector - Perry Nuclear Power Plant

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INSPECTION PROCEDURES USED IP 37001: 10 CFR Part 50.59 Safety Evaluation Program IP 37550: Engineering .

IP 40500: Effectiveness of Licensee Controls in identifying, Resolving and Preventing Problems IP 92903: Followup - Engineering I

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ITEMS OPENED, CLOSED, AND DISCUSSED Opened 50-440/99013-01(DRS) NCV Failure to Follow Procedure - Two Examples 50-440/99013-02(DRS) NCV Inadequate Timeliness for Corrective Actions 50-440/99013-03(DRS) VIO Failure to Restore TS Compliance in a Reasonable Time 50-440/99013-04(DRS) NCV Failure to Report Leakage Outside Containment 50-440/99013-05(DRS) URI Regulatory Limits Used in Place of Design Basis Limits Closed 50-440/98011-01(DRS) VIO Inadequate Testing 50-440/99013-01(DRS) NCV Failure to Follow Procedure - Two Examples 50-440/99013-02(DRS) NCV Inadequate Timeliness for Corrective Actions 50-440/99013-04(DRS) NCV Failure to Report Leakage Outside Containment Discussed None

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LIST OF ACRONYMS USED ANSI American National Standards Institute ASME American Society of Mechanical Engineers

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. CAP Corrective Action Program CFR Code of Federal Regulations ClG Continuous Improvement Group CR Condition Report DCP Design Change Package DG Diesel Generator DRS Division of Reactor Safety ECCS Emergency Core Cooling System ECP Equivalent Change Package EHC Electro-Hydraulic Control EOF _ Emergency Operations Facility EOP Emergency Operating Procedure ES Emergency Service Water System GPH Gallons Per Hour HPCS High Pressure Core Spray IFl Inspection Followup Item INPO Institute of Nuclear Power Operations ISI Inservice inspection IST. . Inservice Test JUMA - Joint Utilities Management Assessment LPCS Low Pressure Core Spray MOV NCV Motor Operated Valve Non-cited Violation

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NRC Nuclear Regulatory Commission OSS Operations Shift Supewisor PAP Perry Administrative Procedure PMT Post-Modification Test ,

PNPP Perry Nuclear Power Plant  !

PRA Probable Risk Analysis l QA Quality Assurance- l RCIC ' Reactor Core Isolation Cooling I RFO Refueling Outage RHR Residual Heat Removal System RPS Reactor Protection System ,

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SE Safety Evaluation SMRF Simple Modification Request Form SS Shift Supervisor STP Surveillance Test Procedure SVI Surveillance Instruction TM Temporary Modification TS Technical Specification TSC Technical Support Center USAR Updated Safety Analysis Report USQ Unreviewed Safety Question VIO- Violation

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PARTIAL LIST OF DOCUMENTS REVIEWED The following is a list of licensee documents reviewed during the inspection, including documents prepared by others for the licensee. Inclusion on this list does not imply that NRC inspectors reviewed the document in its entirety, but rather that portions or selected portions of the documents were evaluated as part of the overallinspection effort. NRC acceptance of the documents or any portion thereof is not implie ~

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PNPP Document Revision /

Number Des @ n '

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Audits and Assessments'

076DE98 Electrical Power Calculations Self-Assessment Report 8/6/98 ISEG Valuation Operating Experience Effectiveness Review - -

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(IV #98-008) 1 PA-97-08 Design Control Audit Apr-June I 1997 PA-98-03 Joint Utility Management Assessment PA-98-10 Effectiveness of Corrective Action 10/28/98 PA-99-04 Effectiveness of Corrective Action 04/30/99 PA 99-11 Design Control Audit July 1999 POS 1/99-4/99 Operations Section, Condition Report Binning 1/99-4/99 6/22/99

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10CFR50.59 Applicability Self-Assessment Report Sep -Oct 1998 10CFR50.59 Applicability Self-Assessment Report Feb - Mar

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1999 ;

Calculations CALC N27-45 Flow Requirement for Feedwater Leakage Control 2/8/99 2 CALC P-1176 Pipe Break Exclusion Pipe Stress Analysis for Feedwater 2 l Leakage Control System N27 CALC P-1176 FW Check Valve 1821-F032A Leak Rate Determination 0 I C41-016 C41-C001 A/B SLCS Injection Pump Performance Acceptance 0 l Criteria l C41-T04 1C41N0600 High & Low Alarm Setpoints - SLCS Tank Level 2 l E12-78 Surveillance instruction SVI-E12-T2002 RHR A/B Pump 1 ;

Performance Acceptance Criteria  !

E12-79 Surveillance Instruction SVI-E12-T2003 RHR C Pump 3 Performance Acceptance Criteria E12-95 RHR B/D Heat Exchanger Test Results (11/18/98) 0 E21-14 Surveillance instruction SVI-E21-T2001 LPCS Pump 1 Performance Acceptance Criteria E22-29 Evaluate HPCS Pump Performance Acceptance Criteria 4 Associated With the Hiaher Potential Reactor Pressure

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E22-29 _ Surveillance Instruction SVI-E22-T2001 HPCS Pump 4 Performance Acceptance Criteria E22-34 ' Support Response to CREA 98-2124-001, Flow Rate and 0 Differential Pressure Test Points for Bench Test Acceptance Criteria E51-05 E51 Reactor Core Isolation Cooling Overpressure Protection 2 Analysis E51-11 Correct Elevation Error in Rev 1 and Check NPSH for Pump 1 Speed increase to 4,600 RPM E51-25 Instrument C34EA030 Loop Error Determining the Acceptance 02 Criteria for Low Pressure RCIC Pump Test E51-25 Minimum Required Delta P Across the RCIC Pump For a 2 Flowrate of 700 GPM EA-154 Weld Overlay Design & Thermal Sleeve Integrity Evaluation for 1 Perry Weld 1B13-N4C-KB, Doc SIR-99-038 EPGSAG-WS06 Minimum Debris Retention Injection Rate (MDRIR) 1 EQ-154 Service / Qualified Life of Nupro & Swagelock Valves When Used 1 for Pressure Relief in Containment MOVC-0042 Degraded Voltage Torque / Thrust Calc for SMRF 98-5023, R/1 04 MOVC-0063 Calculation increases Close Direction Differential Pressure for 0 MOV 1E51F019 Thrust MOVC-0079 Calculation for Design Modification per SMRF 98-5023 1 PRDC-0005 Load Evaluation & Batt Sizing of Div i & 11 DC Systems 4 PRDC-0006 Modify The Design input And References And Modify The First 2 Minute of Battery Load Profile Description PRDC-0006 Increased Electrical Load in Division 3 Due to implementation of 2 DCP 95-00039 '

PRDC-000 DC Control Circuit Voltage For The Rx Recirc Pump Isolation 5 Breakers And The Division i And 11 ATWS Inverter DC Supply Voltage PRMV-0020 Setting For The Degraded Voltage Timers Using PNPP Setpoint 2 Calc Methodology (EDG #97-021/05E)

PSAT 8401T.03 Perry Plant Total Effective Dose Equivalent (TEDE) Calculation 4 PSAT 0402H.13 Offsite and Control Room Dose Calculation 06/14/96 P42-042 ECC B Heat Exchanger Performance Test Evaluation (9/1/1998) 0 P45-064 Latest Date to Remove Silt From the Altemate ESW Intake 0 Tunnel R48-08 EDG Exhaust Vent Valve Size 1 R48-12 Setpoint Calculation for the Divisions 1-3 Diesel Generator 2 Testable Rupture Discs R48-18 Div 1 and 2 Exhaust Vent Valve Max. Back-pressure 0

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Date R48-20 Redesign of the Latching Mechanism for Testable Rupture Disk 0 T21-004 ECCS Suppression Pool Suction Strainer Hydraulic Losses 0 Evaluation T23-010 Cable, Coating, Misc. Debris Quantities-ECCS Strainer 0 1P73-201 1998-00688, Pipe Support Qualification for HWC 0 Modifications

DCP 96-00044 Main Steam Isolation Valve Leakage Control System Elimination 0 '

and associated 10CFR50.59 Safety Evaluation DCP 96-04070 Agastat F7000 Series Time Delay Relay No Longer Available 0 Replace With 2 Relays to Provide Time Delay & Instantaneous Contact DCP 97-00055 Reduce Pressure Pulsations in The Turbine Control EHC 2 System Hydraulic Fluid Actuating Supply Header Supplying Turbine Control Valve DCP 98-00003 PNPP Hydrogen Water Chemistry Project 0 DCP 9.8-00052 Feedwater MOV Modification - FWLCS 0&1 DCP 98-05013 Customized Temper Bead Weld Overlay Repair for N4C 0 Feedwater Nozzle DCP 98-05022 Eng to Approve Lifting of Appropriate Leads & Spare in Place to 2 Disconnect the interlock Between the Local Breaker & Cab Doors DCP 98-05023 Replace Existing Gearing W/ higher Gearing to increase the 0 MOV Actuator Degraded Voltage Capability as Required by GL 89-10 DCP 98-08013 Modify the Wiring to the Annunciator Isolation Test Switches to 0 Maintain Proper Circuit Continuity DCP 99-05004 Steamline Resonance Compensation for Power Uprate, O Harmonic Filters Added to Prevent Resonance DCP 99-08043 Add Metal Oxide Varistor to Relay K49G on B-208-040-A07 0 EC 99-8004 Change Position of Refueling Bridge Air Receiver Drain Valve 0 ECP 98-08024 Engineering to Perform Wiring Change for MOV Valve 0 OP61F0040B ECP 99-08032 Modify Yokes MOV 1821F0065A/B 0 SMRF 97-5078 Latching Mechanism for the Testable Rupture Disk 0 SMRF 97-5088 Overpressure Protection for Containment Penetrations 0 SMRF 99-5007 Remove Components Associated With Decommissioned Steam 0 Condensing Mode Procedures NEl 0331 Design input 4 I NEl 0341 Calculations 6 NEl 0352 Desian Drawinos 8 I

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NEl 0361 Design Verification 3 1 NEl 0362 Engineering Design Guides 0 NEl 0363 Drawing Changes 8 NEl 0373 initiating, Developing and Processing Design Modifications

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NEl 0374 Simple Modification Requests 2 NEl-0375 Equivalent Replacements and Equivalent Changes 0 NEl 0701 Equipment Qualification Process 7 NQl-1801 Audit Program Control 1

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PAP-0103 -

Plant Operations Review Committee 6 j PAP 0305 Safety Evaluations 8 Processing Plant Modificatiora

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PAP-0309 3 l PAP-0507 Preparation, Review And Approval Of Procedures And 12 i instructions I PAP-0520 Changes To The Updated Safety Analysis Report And Other 4 )

Licensing Documents PAP-0522 Changes To Procedures And Instructions 9 PAP-1111 Primary Containment Leakage Reduction for Systems Outside 1 Containment  !

PAP-1121 Conduct Of infrequently Performed Tests Or Evolutions 1 PAP-1402 Temporary Modification Control 10 PAP-1403 Control of Setpoints 6 PAP-1607 Operating Experience Reports (OER) Program 1 PAP-1608 Corrective Action Program 5 PRI-TSR Technical Specification Rounds 6 ISI-N27-T1101-2 Feedwater Inservice Inspection 4 Surveillances '

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SVI-821-T9000 Type C Local Leak Rate Test of 1821 MSL Penetrations (P122, 2 P124, P415 and P416)

SVI-C41-T1026 Standby Liquid Control Boron Concentration 2 SVI-E12-T2002 Surveillance Instruction RHR A/B Pump and Valve Operability 9 Test (performed on A RHR pump on 05/25/99)

SVl-E12-T2002 Surveillance Instruction RHR A/B Pump and Valve Operability 8 Test (performed on B RHR pump on 07/01/99)

SVI-E12-T2003 Surveillance Instruction RHR C Pump and Valve Operability 8 Test (performed on 07/03/99)

SVI-E21-T2001 Surveillance Instruction LPCS Pump and Valve Operability Test 7 (performed on 05/26/99)

SVI-E22-T2001 Surveillance Instruction HPCS Pump and Valve Operability Test 8 (performed on 06/07/99)

10 CFR Part 50.59 Safety Evaluations (SE's)

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s Date 98-0037 DCPs to Replace Spring Loaded Latch Mechanism on the EDGs --

Testable Rupture Discs 98-0040 USAR change, HCS Igniter Glow Plugs -----

98-0041 TM 1-98-0004, Freeze Sea!

98-0051 Reload Analysis, Core Operating And Safety Limits -- -

98-0054 SMRF 98-5040, Plant Underdrain System 98-0061 DCP 97-5078, Spring Latch Replacement -

98-0069 USAR C/R, Chemical Addition 98-0072 USAR C/R 98-0064, TS Bases C/R 98-0068 and DCN 98-0074 USAR C/R, Unit 2 Fire Dampers -----

99-0002 CST Level Channel 99-0004 DCP 98-0052, Revision 0 Safety Evaluation 02/4/99 99-0005 Shift Staffing USAR Figure Change - -

99-0009 Post Accident Sampling 99-0013 Temp Mod E12F0036 99-0016 USAR Change -----

99-0019 Elimination of RHR Heat Exchanger Wet Lay-up --- - ----

99-0022 USAR C/R to Delete HB Ventilation Details - -

99-0024 Fuel Sipping Equipment Installation -

99-0025 GE Post Irradiation And Examination 99-0027 Hydrogen Water Chemistry 99-0032 RCIC Injection Pressure Changes 99-0044 Single Feedwater MOV Revision 1 Modifications 04/29/99 10 CFR 50.59 Applicability Checks CR 99-0603 Design Basis Tornado Compensatory Actions 4 CR 98-1635 Hardware Disposition --

CHI-013 Revised Chemistry Lab Gas Chromatograph Procedure 1 DCN 5811 Alternate RCIC Turbine Governor Valve Nut -

DCN 5819 Stainless Steel Groove Pins as Preferred vs. Roll Pins DCN 5843 ESW Pump Alternate Pump Impeller Material - - - -

DCN 5807 Lockset As-Found Condition - - - - - - - - -

GMI-0042 RCIC Pump Overhaul 2 GMI-0182 RCIC Turbine Trip And Throttle Valve Maintenance 0 ONI-R10 Loss of AC Power 4 PAP-0227 Foreign Material Exclusion Program 1 PAP-0523 Maintenance Activities 3

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SCR 1-99-1000 Diesel Jacket Water Standpipe Level Alarm Setpoint Change -- ;

Request i

SMRF 96-4038 SLC system drain valve replacement 0 SMRF 97-5002 Check valve internals removal 0 SMRF 97-5028 Valve installation on hotwell pump motor upper bearing housing -

oil drain connections SMRF 99-5013 Design Tolerance Increase on Axial Length for FW Nozzel 1 Safe-end Weld 04/19/99 DCP 99-0003 Hydrogen Water Chemistry Modifications 0 06/11/98 Operability Determinations

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J CR 99-1501 SLC Pump Oil Level Out-of-Spec -----

CR 99-1428 B21 Valve Cover Washer Not Installed i CR 99-1454 Erratic APRM B Trip Function -

CR 99-1346 E12F08 Over-Torqued CR 99-0653 ASCO Actuators CR 99-0542 C51 Alarms - --

CR 99-0523 HELB discrepancy -

CR 99-0522 Form OPL 4A Discrepancies -

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CR 99-0417 Feedwater Nozzle Flaws Re-evaluation -

CR 99-0412 Calc E51-25 Discrepancy ----

ACTON Database items 91-0001 Required Design Change Identified as a Result of the Reference -

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Analysis Will Be Completed Prior to RFO3. This is an j Acknowledgment of [NRC] CAL Commitment J 95-0006 Revise Calc to Resolve Concerns identified in NRC Report - -

94010 97-0250 Eval Required Performance Criteria from FCR 06565 &

Incorporate into TS SVI-M51-T2003 98-0126 USAR Table 8.3-7 SE Comment incorporation ---

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98-0931 Respond to Penetration Seal Questions From NRC - --

I 98-1127 Complete Calc as Design Basis of Table 5:13. I 99-0577 Evaluate Jet Pump Set Screw Gaps. Track Cumulative Fatigue ---- - ---

Usage Factor for Jet Pump Riser Brace Revise Ell-B33 Per DCP 91-00099 99-1197 Revise ONI P54-3& SSCR/5 Per DCP 98-00013 at DCP Closure -

99-1382 Revise Spec 810 at Closure of DCP 99-5007 Condition Reports (CRs)

CR 98-0568 ECCS TS Surveillance Requirements Did Not Meet Design Reauirements

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Number Date

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CR 98-1936 SCRAM  !

CR 98-1985 Core Flow l

CR 98-2103 ESW Alternate intake Tunnel Silting 10/01/98 CR 98-2186 Division 1 Diesel Generator Air Start Valve Did Not Open 10/15/98 CR 98-2246 Fuses Blew after Indicating Lights Were Replaced CR 98-2276 Unable to reach the minimum 15 psid for CRD cooling pump CR 98-230? ECCS Suction Strainer Debris 11/02/98 I CR 98-2312 Division 3 Diesel Generator Environmental Qualification 01/03/98 CR 98-2351 Servo Error Meter Oscillating +/- 2% for Reactor Recirculation - --

FCV CR 98-2361 Drywell Penetration Pressurization Relief 11/11/98 CR 98-2378 ESW Loop A Surveillance Testing Procedural Inadequacies 11/13/98 CR 98-2390 Division 1 Control Complex Chiller Failure To Start 12/02/98 CR 98-2471 HPCS Pump Suction Valve Transfer 11/20/98 )

CR 98-2537 Division 1 Diesel Generator Air Start Stuck Purge Valve 12/10/98 j CR 98-2566 Standby Liquid Control Pump B Pressure Excursion 12/14/98 j

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CR 98-2649 Control Complex Chiller Motor Trip on High Temperature 12/25/98 CR 99-0015 Partially Drilling RHR Valve Disk Seating Surface 01/05/99 CR 99-0086 Service Water Pump "C" No Seal Leakage 01/13/99 q CR 99-0124 ESW Pump "A" Discharge Vacuum Breaker Check Valve 01/19/99 j CR 99-0174 RCIC System Relief Valve Leaking 01/25/99 f CR 99-0314 During Performance of PTI-E22-P0010, Motor Operated Valve -- l 1E22F0011 Failed to Stroke Open CR 99-0367 RHR Relief Valve Leaking Outside Containment 02/17/99 CR 99-0376 Error in SLC System Safety Evaluation Report 02/17/99 CR 99-0412 RCIC Pump Surveillance Test Acceptance Criteria Error 02/24/99 CR 99-0417 Feedwater Nozzle Flaw Depth CR 99-0574 Drawing Discrepancies -

CR 99-0752 SRV Air Supply Flex Hose Jacket Damage 03/29/99 CR 99-0753 SRV Air Supply Flex Hose Jacket Damage 03/29/99 )

CR 99-0757 DCP 98-0052 Steam Tunnel Walkdown Feedwater MOV leak-off 03/29/99 l Ports l CR 99-0809 Change in Valve Stem Lubrication Now Mobil Grease 28 Used -

Not Never-Seez l CR 99-0847 Relief Valve Disc Possibly Stuck to Seat 04/02/99 CR 99-0848 Relief Valve Did Not Lift Within Acceptable Range 04/03/99 CR 99-0929 ECCS Suction Strainer Design Did Not Consider Cal-Sil 04/07/99 Insulation CR 99-0965 Inspection of Diesel Generator Heat Exchanaers 04/07/99

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Description Date CR 99-1011 ESW Relief Valve Did Not Pass Setpoint Test 04/11/99 CR 99-1057 Division 3 Diesel Generator Overspeed 04/13/99 l

CR 99-1069 Division 3 Diesel Generator Overspeed 04/13/99 CR 99-1083 Steam Cutting Indications on Valve 1821F0019 04/14/99 CR 99-1084 ECP 98-8031 Incorrect Close Out --

1 CR 99-1149 Request for information WO B21-F065A/B stated Div.1 and Div.

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3 must be declared inoperable prior to performing PMT CR 99-1160 ESW Relief Valve Did Not Pass Setpoint Test 04/11/99 CR 99-1202 Request for information for field welds for LLRT connections to -

main steam system '

CR 99-1267 Containment Penetration Relief Valve Lifting 04/26/99 CR 99-1390 NCC verification not completed prior to refurbished SRVs being -

installed in plant CR 98-1418 Inadvertent SCRAM RCIC CR 98-1421 Following SCRAM TS Limits for Brittle Fracture SVI --

CR 99-1567 HPCS pump slightly missed acceptance criteri CR 99-1630 Service Water instrument Lines Filled With Silt 06/15/99 CR 99-1630 Service Water Instrument impulse Lines Silting 06/11/99 CR 99-1668 Common Resolution for 302 & 320 Drawing Discrepancies against ASME Design Specs CR 99-1689 Trends identified from Audit - -

CR 99-1694 WO Did Not Control Max Interpass Welding Temperature CR 99-1698 SMRF 99-5014 As-Built Discrepancies with IDCN's CR 99-1726 Design Process improvement Recommendations CR 99-1736 Timeliness of issue Resolution by PNED -- -

CR 99-1807 Inadequate Evaluation of Hole Drilled in Valve Seat Ring 07/16/99 CR 99-1870 Inadequate EQ Review of Relief Valve Materials 07/27/99 CR 99-1853 ECCS Pumps' Stralner DP Calculation Weakness 07/23/99 CR 99-1888 Leakage Outside Containment Operability Determinations 07/28/99 CR 99-1981 VT-3 Inservice inspection Safety Support Hanger Procedure -

PlF 96-0212 SOI-E12 to Assure that RHR is Filled and Vented -

PlF 96-2971 USAR Validation Effort PlF 96-3587 ESW Intake Tunnel Sedimentation Buildup 12/02/98 Temporary Modifications 1-99-0001 Jumper Control Circuit for the Control Complex Chiller "A" to Disable Trip 1-99-0002 Gag Closed 1E12F036 to Reduce / Eliminate Leakage Outside 02/19/99 Containment and associated 10CFR50.59 Safety Evaluation 1-99-0006 Evaluation of a Test Actuator Controller in Radiation Field -

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Drawings 4 D-302-643 Residual Heat Removal System Piping Diagram FF

' ISO 1-P45-2 Emergency Service Water Auxiliary Building 4 P&lD 302-0631 Reactor Core Isolation Cooling System V {

P&lD 302-0632 : Reactor Core Isolation Cooling System CC P&lD 302-0641 Residual Heat Removal System NN P&lD 302-0642 - Residual Heat Removal System V i P&lD 302-0653 Residual Heat Removal System GG P&lD 302-0355 HPCS and Standby Diesel Generator K )

Drawing of Storage Tank, Standby Liquid Control 7 I work orders (wo)-

WO 98-1984 Weld History Records for Joint ID Nos 98-1984-A-001 -020 10/99 WO Work Order Package; Permanent Structural Repair of 06/25/99 99-004000-000 Feedwater Nozzle Safe - end to Nozzle Weld RMscellaneous Docuenents GE FDDR SLC System Design Spec. Data Sheet 0 KL1-7075 Scientech, In Human Interactions Evaluaten Failure to Isolate Main Rev 0 Project 6566-005 Feedwater 08/99 Charter for Conduct of the Engineering Review Board's Critique 02/98 of 10 CFR Part 50.59 Safety Evaluations Company Nuclear Review Board Policies & Practices 03/04/99 Corrective Action Program Continuous improvement Group 05/99 Mission Statement & Charter

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Extended installation Memorandum (EIM) for TM 1-99-002 --

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Initiation Report for Project 94-0099-01 " Main Steam Line 0 Isolation Valve Leakage Control System Elimination Through Use of Revised Accident Source Term Methodology"

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OperatorWork Around 06/28/99

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Report of Facility Changes, Tests, and Experiments, For The 04/10/96- !

Perry Nuclear Power Plant 10/23/97

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Trend Code Matrix 6 !

Licensing Docuenents  ;

QA Plan Section 8 Audits and Surveillances 9 QA Plan Section 3 Design Control 5 QA Plan Section 5 Procedures, Instructions, And Drawings 8 TS 3.5. Surveillance Requirement and Bases TS 3.5. Surveillance Requirement and Bases -------

USAR Section Emeroency Core Coolina System 9

f i9

,s PNPP Document ,

y Revision /

% s Description Date USAR Loss-of-Coolant Accidents (Resulting from Spectrum of Section 15. Postulated Piping Breaks within the Reactor Coolant Pressure Boundary)- Inside Containment USAR Reactor Core isolation Cooling System Section 5. USAR High Pressure Core Spray System -

Section 6.3. USA Nuclear Plant Safety Operational Analysis -

Appendix 15A

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Amendment No.103 to Facility Operating License N N.F.-58-Perry Nuclear Power Plant, Unit 1 (TAC No. M96931),

03/26/99, Revision to TS 3.6.1.3, Primary Containment Isolation Valves, and 3.6.1.9, Main Steam Isolation Valve Leakage Control System and related Safety Evaluation Report

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Issuance of Exemption from 10 CFR Part 50, Appendix A, General Desian Criterion 19 - Perry Nuclear Power Plant Unit 1 I

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