IR 05000440/2006009

IR 05000440-06-009(DRS); 01/17/2006 - 03/23/2006; Perry Nuclear Power Plant; Component Design Bases Inspection

ML061250451
Person / Time
Site:	Perry
Issue date:	05/05/2006
From:	Ann Marie Stone NRC/RGN-III/DRS/EB2
To:	Pearce L FirstEnergy Nuclear Operating Co
References
IR-06-009
Download: ML061250451 (38)

Text

May 4, 2006Mr. L. William PearceVice President FirstEnergy Nuclear Operating Company Perry Nuclear Power Plant 10 Center Road, A290 Perry, OH 44081SUBJECT:PERRY NUCLEAR POWER PLANT NRC COMPONENT DESIGN BASES INSPECTION (CDBI) INSPECTION REPORT 05000440/2006009(DRS)

Dear Mr. Pearce:

On March 23, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed a baselineinspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on March 3, 2006, with you, and on March 23, 2006, with Mr. J. Shaw, and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and tocompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Specifically, this inspection focused on the design of components that are risk significant and have low design margin.Based on the results of this inspection, three NRC-identified findings of very low safetysignificance, which involved violations of NRC requirements were identified. However, becausethese violations were of very low safety significance and because they were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations in accordancewith Section VI.A.1 of the NRC's Enforcement Policy. Additionally, a licensee identifiedviolation is listed in Section 4OA7 of this report.If you contest the subject or severity of a Non-Cited Violation, you should provide a responsewithin 30 days of the date of this inspection report, with the basis for your denial, to the U.S.

Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -

Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Perry Nuclear Power Plant.

W. Pearce-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/Ann Marie Stone, ChiefEngineering Branch 2 Division of Reactor Safety Docket No. 50-440License No. NPF-58Enclosure:Inspection Report 05000440/2006009(DRS) w/Attachment: Supplemental Informationcc w/encl:G. Leidich, President - FENOCJ. Hagan, Chief Operating Officer, FENOC D. Pace, Senior Vice President Engineering and Services, FENOC Director, Site Operations Director, Regulatory Affairs M. Wayland, Director, Maintenance Department Manager, Regulatory Compliance T. Lentz, Director, Performance Improvement J. Shaw, Director, Nuclear Engineering Department D. Jenkins, Attorney, FirstEnergy Public Utilities Commission of Ohio Ohio State Liaison Officer R. Owen, Ohio Department of Health

SUMMARY OF FINDINGS

IR 05000440/2006009(DRS); 01/17/2006 - 03/23/2006; Perry Nuclear Power Plant; ComponentDesign Bases Inspection.The inspection was a 4-week onsite baseline inspection that focused on the design ofcomponents that are risk significant and have low design margin. The inspection was conducted by regional engineering inspectors and two consultants. Three Green Non-Cited Violations were identified. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance Determination Process (SDP)." Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors, is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,Criterion III, "Design Control," having very low safety significance (Green) involving aninadequate stress analysis performed for the automatic depressurizati on system (ADS)air accumulators. Specifically, the licensee failed to account for all the related stresses in the ADS accumulator stress analysis calculation. Inclusion of these additional stresses resulted in a higher stress than allowed by the American Society of Mechanical Engineers Code. Additionally, the accumulators' certification of design, as required by the Code,Section III, was incorrect as it was not based on the maximum designpressure the accumulators would be subject to under accident conditions. The licensee's corrective actions included performing an operability determination thatconcluded the ADS accumulators would not fail structurally under design conditions. The finding was more than minor because the failure to adequately evaluate the designrequirements of the accumulators could have led to structural failure of the tanks, which would have prevented the ADS valves from functioning as designed and could have affected the mitigating systems cornerstone objective of design control. The finding wasof very low safety significance based on the results of the licensee's analysis and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.3.b.1)Green. The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,Criterion III, "Design Control," having very low safety significance (Green) involving thesizing of the main steam isolation valve and automatic depressurization system (ADS)air storage tank. The inspectors identified that the licensee failed to correctly specify in a design calculation the required minimum differential air pressure required to actuate the ADS valves when manually operated. This resulted in a safety-related air systemcalculation that was non-conservative when determining the long-term air volume requirements in the air storage tank. The licensee's corrective actions included verifying that adequate design margin existed for the air tank capacity and entered thisperformance deficiency into their corrective action program for resolution.

3The finding was more than minor because the failure to adequately evaluate air storagetank sizing could result in over-predicting the tank's capacity as verified by the surveillance test's acceptance criteria (i.e., creating design margin capability that wouldnot exist) and could have affected the mitigating systems cornerstone objective ofdesign control. The finding was of very low safety significance based on the results of the licensee's analysis and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.3.b.2)Green. The inspectors identified a Non-Cited Violation of Technical SpecificationRequirement 5.4.1, which requires, in part, that written procedures/instructions be established, implemented, and maintained covering the emergency operatingprocedures required to implement the requirements of NUREG-0737 and NUREG-0737,Supplement 1. The anticipated transient without scram (ATWS) special plant instructions issued to provide for injection outside the shroud were inadequate because the procedures inappropriately limited the ability to control reactor water level (or reactorpressure if reactor water level is unknown). The licensee entered this performance deficiency into their corrective action program for resolution.This finding was more than minor because the procedure deficiency affected the abilityof the licensee to use the low pressure coolant injection sub-systems to prevent undesirable consequences of large power excursions associated with an ATWS, and was associated with the mitigating systems procedure quality attribute of the mitigatingsystems cornerstone objective. The finding was of very low safety significanc e becauseno actual initiating event or transient occurred and screened as Green using the SDP Phase 1 screening worksheet. (Section 1R21.6.b.1)

B.Licensee-Identified Violations

One violation of very low safety significance, which was identified by the licensee, hasbeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

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REPORT DETAILS

1.REACTOR SAFETYCornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity1R21Component Design Bases Inspection (71111.21).1Introduction The objective of the component design bases inspection is to verify that design baseshave been correctly implemented for the selected risk significant components and that operating procedures and operator actions are consistent with design and licensing bases. As plants age, their design bases may be difficult to determine and an important design feature may be altered or disabled during a modification. The Probabilistic RiskAssessment (PRA) model assumes the capability of safety systems and components toperform their intended safety function successfully. This inspectible area verifies aspects of the initiating events, mitigating systems and barrier integrity cornerstones forwhich there are no indicators to measure performance. Specific documents reviewed during the inspection are listed in the attachment to the report..2Inspection Sample Selection ProcessThe inspectors selected risk significant components and operator actions for reviewusing information contained in the licensee's PRA and the Perry Standardized Plant Analysis Risk (SPAR) Model, Revision 3.21. In general, the selection was based upon the components and operator actions having a risk achievement worth of greater than2.0 and/or a risk reduction worth of greater than 1.005. The operator actions selectedfor review included actions taken by operators both inside and outside of the control room during postulated accident scenarios. Since all plant components were not modeled in the licensee's PRA, additional resources were used in the selection process such as the licensee's maintenance rule program, where an expert panel identified additional systems/components that also were considered risk significant.The inspectors performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design, reductions caused by design modifications or power uprates, or reductions due to degraded material conditions. Equipment reliability issues were also considered in the selection ofcomponents for detailed review. These included items such as failed performance test results, significant corrective action, repeated maintenance activities, maintenance rule (a)(1) status, components requiring an operability evaluation, NRC resident inspectorinput of problem equipment, system health reports, and the plant health committeeissues list. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. As practical, the inspectors performed walkdowns of the components to evaluate the as-built design and material condition. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.

5.3 Component Design

a. Inspection Scope

The inspectors reviewed the Updated Safety Analysis Report (USAR), TechnicalSpecifications (TS), com ponent/system design basis documents, drawings, and otheravailable design basis information, to determine the performance requirements of the selected components. The inspectors used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Code and the Institute of Electrical and Electronics Engineers (IEEE) Standards, to evaluate acceptability of the systems'design. The review was to verify that the selected components would function as required and support proper operation of the associated systems. The attributes thatwere needed for a component to perform its required function included process medium, energy sources, control systems, operator actions, and heat removal. The attributes toverify that the component condition and tested capability were consistent with the designbases and were appropriate may include installed configurati on, system operation,detailed design, system testing, equipment/environmental qualification, equipmentprotection, component inputs/outputs, operating experience, and componentdegradation.For each of the components selected, the inspectors reviewed the maintenance history,system health report, and condition reports (CRs). Walkdowns were conducted for allaccessible components to assess material condition and to verify the as-built condition was consistent with the design. Other attributes reviewed are included as part of the scope for each individual component. The components (17 samples) listed below were reviewed as part of this inspectioneffort:High Pressure Core Spray (HPCS) Pump: The inspectors reviewed vortexingcalculations for HPCS pump suction alignment to the suppression pool and condensate storage tank. Hydraulic calculations were reviewed to ensure design requirements for flow and pressure were translated as acceptance criteria for pump in-service testing (IST). The inspectors reviewed calculations related to pump's net positive suction head (NPSH) to ensure the pump was capable of functioning as required. The pump motor's calculations for voltage/frequency, current ratings, protective relaying settings, and cable feeder size were reviewed to ensure the motor was able to drive the associated pump. Design change history and IST results were reviewed to assess potential component degradation and impact on design margins. In addition, the licensee responses and actions to Bulletin 88-04, "Potential Safety-Related Pump Loss," were reviewed to assess implementation of operating experience. A modification to replace the pump breaker was also reviewed.Division 3 Diesel Generator (DG) for HPCS: The inspectors reviewed electricalloading calculations, including voltage and frequency, current ratings, and short circuit ratings for all operating modes. Protective relaying calculations were reviewed to assess adequacy of protection during test mode and during emergency operation. Test results were reviewed to ensure the adequacy of 6current ratings for full loading and emergency loading. Operating andsurveillance test procedures were reviewed to assess whether component operation and alignments were consistent with design and licensing bases assumptions. HPCS Minimum Flow Valve: The inspectors reviewed the motor-operated valve(MOV) calculations, including required thrust, degraded voltage, maximum differential pressure, setpoint, and valve weak link analysis, to ensure the valve was capable of functioning under design conditions. Diagnostic and IST results were reviewed to verify acceptance criteria were met and performance degradation would be identified.Division 3 Essential Service Water (ESW) Pump: The inspectors reviewedcalculations related to pump flow, head, and NPSH requirements to ensure the pump was capable of functioning as required. Design change history and IST results were reviewed to assess potential component degradation and impact on design margins. The inspectors reviewed the control and power design drawings to verify the availability of both control and power required for operability. Inaddition, the licensee responses and actions to Generic Letter (GL) 89-13, "Service Water System Problems Affecting Safety-Related Equipment," were reviewed to assess implementation of operating experience. A modification to change pump shaft materials and other design improvements for this pump was reviewed to ensure the change did not adversely affect the design function of the pump.HPCS DG Heat Exchanger: The inspectors reviewed the ESW hydraulicanalysis that verified the DG jacket water heat exchanger would receive minimum design cooling water flow, in accordance with the flow value specified in the thermal evaluation of the heat exchanger. The inspectors reviewed thermal performance testing, and trending of data, that was performed to verify heat transfer capability. The inspectors interviewed maintenance personnel toascertain whether the condition of the heat exchanger and attached piping was meeting the guidance of GL 89-13. The inspectors reviewed periodic surveillance tests to verify coolant temperatures were within acceptable limits and performance degradation would be identified.Swayle Manual Valves: The inspectors reviewed the seismic and hydrauliccalculations for the ESW function using the Swalye valves, IST program, operator rounds, and test procedures to ensure the manual Swayle valves were capable of functioning as required. Maintenance activities were reviewed to verify the periodic operation of the valve. Operator actions and operatingprocedures were reviewed as the Swayle valves' operation was necessary with opening of the intake bay sluice gates under certain conditions to allow the ESW system to continue it's safety-related function. A modification to the sluice gatesto install an air seal system was reviewed based on this inter-related function.Residual Heat Removal (RHR) Cross-tie to ESW Valves: The inspectorsreviewed the hydraulic calculation to verify decay heat can be removed by ESW in the emergency lineup when injecting into the reactor vessel. Since the cross-7tie valves were not normally used, the inspectors verified that the cross-tie valvesand associated connecting pipe were inspected to verify that the system wouldpass design flow. The inspectors performed a walk through of the emergency operating procedures associated with these valves to assess operator knowledge level, adequacy of procedures, and availability of special equipmentwhere required. Additionally, the inspectors performed an assessment of the radiological conditions to be expected during the performance of the above emergency operating procedures. Reactor Core Isolation Cooling (RCIC) Pump: The inspectors reviewedvortexing calculations for the RCIC pump suction alignment to the suppression pool, and condensate storage tank. The inspectors reviewed hydraulic calculations to ensure design requirements for flow and pressure were translated as acceptance criteria in IST pump testing. The inspectors reviewed calculations related to the pump's NPSH requirements and minimum flow requirements to ensure the pump was capable of functioning as required. Testing was reviewed to assess potential component degradation and impact on design margins. In addition, the licensee responses and actions to Bulletin 88-04 was reviewed to assess implementation of operating experience. A modification to raise the setpoint of the pump's suction relief valve as corrective action to inadvertent valve lifting events was reviewed.RCIC Room Cooler: The inspectors reviewed the RCIC room cooler thermalsizing and the loss of ventilation calculations to ensure that the heat gains in theroom were properly accounted for and that a conservative starting temperature was used. The inspectors reviewed data to ensure that the room temperature was within acceptable limits. A walkdown was performed to verify cleanliness of the air filters, and preventive maintenance work orders were reviewed to ensure filters were changed on an appropriate frequency.RCIC Test Return Valve: The inspectors reviewed MOV calculations, includingrequired thrust, degraded voltage, maximum differential pressure, and valve weak link analysis, to ensure the valve was capable of functioning under design conditions. Diagnostic and IST test results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The inspectors reviewed test results to verify the valve would receive an automatic close signal during a RCIC pump test if the system received an initiation signal. Regulatory Information Summary (RIS) 2001-15, "Performance of DC-Powered Motor-Operated Valve Actuators," was reviewed to ensure it was properly evaluated and implemented as appropriate. Automatic Depressurization System (ADS) Valves: The inspectors reviewedcalculations used for sizing of the air storage tank, structural support capability ofthe individual safety relief valve (SRV) accumulators, ASME Code stress analysis, solenoid valve operating current and voltage, and associated circuit protection to ensure the ADS valves were capable of functioning under design conditions. The inspectors reviewed vendor design specifications for the SRV accumulators to verify compliance with Code requirements. The inspectors also reviewed the air leak rate testing procedure, and recently completed leak rate 8testing performed for the air system c onnected to the accumulators to verify thatthe acceptance criteria were appropriate and data was within the defined criteria.Reactor Water Cleanup Suction Inboard Isolation Valve: The inspectorsreviewed the MOV calculations, including required thrust, degraded voltage, maximum differential pressure, and valve weak link analysis, to ensure the valve was capable of functioning under design conditions. Local leak rate, diagnostic, and IST test results were reviewed to verify acceptance criteria were met and performance degradation would be identified.Division 2 Diesel Generator: The inspectors reviewed calculations for dieselloading, fuel oil consumption, and vortexing for the fuel oil tanks. Seismic qualification documents for the E22-S001 electrical cabinets were also reviewed.

The inspectors performed a review of system normal operating procedures andsurveillance test procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.Diesel Generator Output Breakers: The inspectors reviewed the electricaldrawings that described the circuits used to control the generator outputs bymeans of the DG output breakers. Corrective actions for DG output breaker problems were reviewed. Division 1 and 2 DG Air Start Check Valves: The inspectors reviewed the airleak rate testing procedure and recently completed leak rate testing performed for the diesel generator air start check valves to verify acceptance criteria were met and performance degradation would be identified.4.16 kV 1E Bus EH12: The repair and replacement program established as partof the corrective actions for 4.16 kV breakers problems was reviewed. Unit 1 and 2 Safety-Related Batteries: The inspectors reviewed electricalcalculations, including voltage at the valve terminals under various accident scenarios, battery float and equalizing voltages, and overall battery capacity.

The inspectors performed a walk through of the off-normal operating procedures associated with cross-tying Unit 1 and 2 safety-related batteries to assess operator knowledge level, adequacy of procedures, and availability of specialequipment where required. The following review did not constitute an inspection sample:

Unit 1 and 2 Non-Safety Related Battery: These batteries were initially selectedbased on an initial review of the licensee's PRA, which indicated a high risk ranking. Subsequent questioning by the inspectors determined that the riskranking was in error (high ranking was mis-identified, should have been identified as the safety-related batteries), such that inspection activities were limited and this component will not be counted as a completed sample. The inspectors didwalkdowns of the non-safety related batteries, reviewed maintenance and surveillance schedules and records, and performed a walk through of the off-normal operating procedures associated with cross-tying Unit 1 and 2 non-safety related batteries.

b. Findings

Two findings of very low safety significance associated with Non-Cited Violations(NCVs) were identified. b.1ADS and MSIV Air Accumulators Stress Analysis DeficienciesIntroduction: The inspectors identified a Non-Cited Violation (NCV) of 10 CFR Part 50,Appendix B, Criterion III, "Design Control," having very low safety significance (Gr een)involving the stress analysis performed for the ADS backup air accumulators.

Specifically, the licensee failed to account for all the related stresses in the ADS accumulator stress analysis calculation. Inclusion of these additional stresses resulted in a higher stress than allowed by the American Society of Mechanical Engineers (ASME) Code. Additionally, the accumulators' certification of design, as required by the Code,Section III, was incorrect as it was not based on the maximum design pressurethe accumulators would be subject to under accident conditions.

Description:

The ADS used a number of the reactor SRVs to reduce reactor pressureduring a small break loss-of-coolant-accident (LOCA) in the event of a HPCS failure.

Each ADS valve has a backup accumulator to store air to provide the motive force to stroke the valve if the normal non-safety related air system was unavailable. Therewere no relief valves on the air accumulators to relieve internal pressure, which also have check valves to prevent flow out of the accumulators back into the air system.

Since this created a closed volume, any increase in ambient temperature would result in a corresponding increase in internal pressure. The accumulators were designed per the requirements of ASME Code,Section III,Division 1, 1974 Edition, up to and including the Winter, 1975 Addenda. The inspectors reviewed the original stress analysis performed for the tanks (accumulators) GAI Vendor Print 4549-94Q-76-1-0, "Final Report on the ASME Section III Analysis of Class 3Nuclear Safety Related Shop Fabricated Tanks for Perry Nuclear Power Plant." This analysis used an accumulator pressure of 150 pounds per square inch (psi) for internal pressure. The inspectors noted that the certification of design, and the vesselnameplate information for the accumulators listed a maximum ambient temperature of 330 degrees Fahrenheit (F), and a vessel design pressure of 180 pounds per squareinch gauge (psig). The internal pressure used in the stress analysis, however, did not take into account the affect of heating the enclosed air volume due to the maximum ambient drywell temperature. The licensee provided Calculation P52-003, "Overpressurization of Isolated Piping andComponents," which evaluated the affect of the pressure increase on the ADS accumulators during a thermal overpressure event caused by a rapid increase in drywell temperature up to 330 F. This calculation was completed prior to initial plant startupwhen this issue was initially identified, however, the actions taken did not adequately resolve the concern. The calculation determined that for an ambient drywelltemperature of 330 F the accumulators should have been designed to withstand aninternal pressure of 308.4 psig.The certification of design for the accumulators listed an internal design pressure of 180psi at a temperature of 330 F, with a hydrostatic test pressure of 270 psi. Because the 10maximum pressure of 308.4 psig was not specified in the ASME certification of designand the vessel nameplates as a design condition, the inspectors determined that the airaccumulators were not in compliance with ASME Code,Section III. Paragraph NA-3252of the ASME Code, "Contents of Design Specification", item

(b) required, in part that thedesign requirements shall be included in design specification. The licensee initiated CR 06-01044 to address this issue.

The tank specification for the accumulators, SP-504-4549-00, "Conformed Specification for the Tanks," had design requirements in paragraph 2:06.3.1.a.(2) for accelerationloading requirements and combined loading design limits for safe shutdown building acceleration. The paragraph stated that the tanks located inside the reactor buildingshall withstand the maximum acceleration created by safe shutdown earthquake combined with SRV discharge and small break accident loads. The inspectors noted that the ASME Code,Section III, Division I, Class 3 Stress Report, supplied by the ADSaccumulator vendor as part of original construction, performed an analysis that evaluated loading conditions that included both the design pressure of the tanks and themaximum allowable nozzle loads consisting of axial loads and bending moments caused by seismic plus operating loads, as required by the tank specification. The inspectors noted that the stress analysis contained in Calculation P52-003 was non-conservative asit only considered the hoop stresses in the accumulator caused by the increase in internal pressure, but did not include the maximum allowable nozzle loads when calculating the maximum stresses the accumulators would be subject to under design conditions. The licensee subsequently performed an operability determination that evaluated theeffect of not including the nozzle loads in the stress analysis. The operabilitydetermination concluded that the accumulators would maintain pressure integrity using the Level D stress criteria for Class 3 vessels from the 2004 Edition of ASME Code.

Level D rules were intended to maintain pressure boundary integrity, but will permitstructural deformation. The licensee determined that Calculation P52-003 needed to be revised to include all required stresses and issued CR 06-00974 to track resolution. The inspectors and the Office of Nuclear Reactor Regulation reviewed the licensee's operability determination and concluded that there would be no affect on operability ofthe ADS system when accounting for the higher stresses in the accumulators. The useof the Level D stress criteria was acceptable for operability, however, the accumulatorswere considered nonconforming that would require further action by the licensee to return them to within Code compliance. Since Calculation P52-003 also evaluated the pressure integrity of the main steamisolation valve (MSIV) accumulators, the inspectors had similar concerns with the stress analysis for these accumulators. As a result, the licensee issued CR 06-00997 and an operability determination that concluded the MSIV accumulators were structurallyqualified to ASME Code Level D faulted limits. The inspectors reviewed the operabilitydetermination, and agreed with the licensee that the accumulators were operable, butnonconforming. The operability determination discussed the piping systems attac hed tothe accumulators, and determined that they would maintain structural integrity as well.Analysis: The inspectors determined that the failure to account for the stresses relatedto the dynamic structural loading in the accumulators was a performance deficiency and a finding. The inspectors determined that the finding was more than minor in 11accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor InspectionReports," Appendix B, "Issue Dispositioning Screening," because it was associated with the attribute of design control, which affected the mitigating systems cornerstoneobjective of ensuring the availability and reliability of the ADS valves to res pond toinitiating events to prevent undesirable consequences. Specifically, the failure to account for all the stresses related to the dynamic structural loading in the accumulators resulted in not knowing that the material yield stresses exceeded the ASME Code allowable stress limits.The inspectors evaluated the finding using IMC 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," Phase 1 screening, and determined that the finding screened as Green because it was not adesign issue resulting in loss of function per Part 9900, Technical Guidance, "OperabilityDeterminations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety," did not represent an actual loss of a system's safety function, did not result in exceeding a TS allowed outage time,and did not affect external event mitigation. The basis for this conclusion was that despite the loss of design margin in the ADS accumulator structural capability tomaintain pressure integrity, the ADS system would have performed its safety function asconcluded in the operability determination.Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control,"required, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.Contrary to the above, as of February 28, 2006, the licensee's design control measuresfailed to provide for verifying or checking the adequacy of design by validating that the calculated stress value for ADS air accumulators would be higher than that assumed by the structural analysis. Specifically, Calculation P52-003 did not evaluate the increasedpressure stress in the accumulators in combination with stresses due to seismic plus operating loads, and only considered the hoop stresses in the accumulator caused by the increase in internal pressure resulting from an ambient temperature increase. This resulted in the accumulator's structural analysis being non-conservative, and not in accordance with the requirements of ASME Code,Section III, Paragraph NA-3252. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000440/2006009-01(DRS)). The licensee entered the finding into their corrective action program as CR 06-00974 to revise the affected calculation, and CR 06-01044 to evaluate ASME Code requirements for the accumulators. The licensee performed an operability determination andconcluded that the accumulators, while currently nonconforming, will remain operable.

b.2Non-conservative Safety-Related Air Storage Tank Sizing CalculationIntroduction: The inspectors identified a Non-Cited Violation (NCV) of 10 CFR Part 50,Appendix B, Criterion III, "Design Control," having very low safety significance (Gr een)involving the sizing of the P57 air storage tank. Specifically, the inspectors identified 12that the licensee failed to correctly specify the minimum differential air pressure requiredto actuate the ADS valves when manually operated.Description: The inspectors reviewed Calculation P57-13, "Required Air Volume forMSIV and ADS Accumulators," whose purpose was to determine the long-term air volume in the P57 air storage tank required for the ADS and MSIV air actuators. The accumulator sizing calculation was based on 90 psig, the minimum air pressure to stroke the valve. However, General Electric (GE) Design Specification Data Sheet stated in paragraph 3.1.18.2.2, that for the ADS function, the differential air pressurerequired to stroke the valve at 0 psig inlet pressure was 95 psid to account for drywell backpressure. Drywell pressure would be elevated above ambient pressure during accident conditions and a station blackout event where ADS was credited with manual vessel depressurization. Since drywell pressure during an accident could be as high as 30 psi, 125 psi would be required to operate the valves as they must overcome the exhaust pressure, which would be exposed to the elevated drywell pressure. By not accounting for the drywell backpressure and the use of a lower minimum air pressure (90 versus 95) when evaluating the accumulator capacity, the inspectors determined that the calculation was non-conservative when calculating the long-term air volumerequirements in the P57 air storage tank. Although the licensee indicated there may bea supportable basis for the use of the lower minimum air pressure, the inspectors concluded the calculation must account for the backpressure in containment when determining the minimum actuation pressure of the valve.Additionally, calculation P57-13 determined the leakage rate acceptance criteria forprocedure PTI-P57-P0001, "Loss of Air Test for Safety Related Instrument Air System."

Since the calculation assumed that only 90 psi were required to stroke an ADS valve, the acceptance criteria would be non-conservative. Since a higher pressure was required to operate the valves, the licensee reviewed the last several completed tests to ensure that sufficient air pressure remained in the tanks to stroke the valves as required during a design basis event. The review determined that the indicated leakage rates were well below the leakage rate acceptance criteria. Based on the normal 150 psig of air maintained in the P57 storage tank and the low indicated leakage rates, the inspectors concluded that the ADS air system had sufficient capacity for operability.Analysis: The inspectors determined that failure to correctly specify the minimumdifferential air pressure required to actuate the ADS valves when manually operated was a performance deficiency and a finding. The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, "Issue Dispositioning Screening," because it was associated with the attribute of design control, which affected the mitigating systems cornerstone objective of ensuring the availability andreliability of the ADS valves to respond to initiating events to prevent undesirableconsequences. Specifically, the failure to properly account for minimum air pressure in the calculation that was used as the basis of ADS air system testing could result inover-predicting the air storage tanks' performance (i.e., creating design margin capability that would not exist), which could potentially render the ADS valves incapableof performing its required safety function.The inspectors evaluated the finding using IMC 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," Phase 1 screening, and determined that the finding screened as Green because it was not a 13design issue resulting in loss of function per Part 9900, Technical Guidance, did notrepresent an actual loss of a system's safety function, did not result in exceeding a TSallowed outage time, and did not affect external event mitigation. The basis for this conclusion was that despite the loss of design margin in the air storage tanks' capacity, the ADS system would have performed its safety function as the P57 air storage tankwas maintained at 150 psig and recent testing indicated low leakage from the air system.Enforcement: 10 CFR Part 50, Appendix B, Criterion III, "Design Control," required, inpart, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions.Contrary to the above, as of February 17, 2006, the licensee failed to assure that theADS minimum air pressure operability limits were correctly translated into specifications,drawings, procedures, and instructions. Specifically, the minimum air pressure requirements as specified in the GE Design Specification Data Sheet for SRVs were not incorporated into Calculation P57-13, which in turn resulted in non-conservative acceptance criteria for PTI-P57-P0001 air storage tank pressure drop test. Because this violation was of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000440/2006009-02(DRS)). The licensee verified the air storage tank contained a sufficient volume and air pressure to support ADS operation and initiated CR 06-00817 to revise the affected documents.

.4 Operating Experience

a. Inspection Scope

The inspectors reviewed four operating experience issues (4 samples) to ensure theseissues, either NRC generic concerns or identified at other facilities, had been adequatelyaddressed by the licensee. The operating experience issues listed below were reviewed as part of this inspection effort:Gas voids due to improper venting or gas intrusion in emergency core coolingsystems and other safety related piping systems such as RCIC and RHR. Responses to related experience at Beaver Valley and Limerick were also reviewed for applicability;RIS 2001-05, "Performance of DC-Powered Motor-Operated Valve Actuators";Bulletin 88-04, "Potential Safety-Related Pump Loss"; andGL 89-13, "Service Water System Problems Affecting Safety-RelatedEquipment."

b. Findings

One unresolved item was identified associated with NRC Bulletin 88-04 concerningminimum flow for safety-related pumps.

14 b.1Inadequate Response for Minimum Pump Flow SettingsIntroduction: The inspectors identified an unresolved item (URI) concerning thelicensee's response to Bulletin 88-04, "Potential Safety-Related Pump Loss," regarding establishing minimum flow requirements for the safety-related pumps. The licensee recognized that the conditions reported in the bulletin were present in safety-related pumps, but did not determine appropriate minimum pump flow values to minimize and manage, or to eliminate, the potential for pump damage. At the end of the inspection,the licensee was evaluating current minimum flow values with the pump manufacturer.

The inspectors needed this information to complete the assessment of this issue.

Description:

Bulletin 88-04, in part, identified a concern regarding the adequacy ofminimum flow capacities for safety-related centrifugal pumps. The Bulletin required licensees to evaluate the capability of safety-related pumps to run long-term at minimumrecirculation flow rates. The Bulletin stated that many licensees had accounted for thermal considerations in setting the minimum recirculation flow rates, but had failed to consider flow instability effects. The latter consideration could necessitate a considerable increase in minimum flow settings, especially for pump operation for extended periods of time. This potential increase occurred because centrifugal pumps demonstrated a flow condition described as hydraulic instability or impeller recirculationat some flow point below approximately 50 percent of the best efficiency point on the characteristic pump curve. These unsteady flow phenomena become progressively more pronounced if flow was further decreased, and could result in pump damage when operated for extended periods of time. The inspectors reviewed the licensee's responses to Bulletin 88-04, which were described in four letters to the NRC; one in1988, one in 1989, and two in 1990. The latter three responses were specific to the RCIC pump, where no concerns were identified by the inspectors.The inspectors identified two concerns with the licensee's 1988 response to the Bulletin:

The licensee did not properly verify the minimum flow settings with the pumpmanufacturer in accordance with what was stated in their response to the Bulletin. The licensee had concluded that the original, manufacturer-supplied minimum recirculation flows contained in the pump purchase specifications were adequate to meet the issues discussed in Bulletin 88-04. The licensee stated on page 2 of the response, "In all cases but one, theminimum flow capacities exceeded the values specified by the manufacturer.

The exception is the minimum flow capacity provided for the RCIC pump." The inspectors verified that the licensee had adequately addressed minimum flow for the RCIC pump. The inspectors requested documentation to establish the technical bases for the current minimum flow settings for the RHR, low pressure core spray (LPCS), and HPCS pumps, particularly how they accounted for flow instability. The licensee was unable to provide any documentation thataddressed this issue during the inspection. The adequacy of RHR, LPCS, andHPCS pumps' minimum flows was provided to the licensee by GE, as part of the original plant design, and since the licensee had been assigned these settings prior to Bulletin 88-04, it was likely that these settings did not account for flow instability considerations. With the exception of the RCIC pump, the inspectors 15concluded that the existing minimum flow settings for the safety-related pumpsaccounted only for thermal effects. The inspectors questioned whether the current minimum flow settings werereviewed and approved by the pumps' manufacturer (Byron-Jackson), asspecified in the licensee's response to the Bulletin. The licensee had not contacted the pump manufacturer and relied upon information provided by GE to conclude that no changes were needed for pumps in these three systems. Thelicensee contacted the pumps' manufacturer (now Flowserve) to perform a new analysis of the RHR, LPCS, and HPCS pumps' minimum flow settings inresponse to Bulletin 88-04. This issue was entered into the licensee's corrective action program as CR 06-00813.In the licensee's response to the Bulletin, it was stated "SOI/SVI procedurerevisions will be provided for those systems which do not presently containadequate caution. These cautions will limit pump minimum flow operation to amaximum of 30 minutes and assure that pump discharge is transferred to the full flow test line whenever possible." The licensee further stated that the review and approval of necessary procedure changes will be completed by October 5, 1988. When the inspectors reviewed the safety-related pump procedures, there was no evidence that any precautions related to minimum flow were ever implemented in the appropriate RHR, LPCS, or HPCS pump procedures. There were, however,precautions related to minimum flow incorporated into the RCIC pump procedure, which were considered appropriate by the inspectors. This issue was entered into the licensee's corrective action program as CR 06-00703 to determine if the 30 minute limitation still needed to be incorporated into therespective pump procedures.In response to these concerns, the inspectors prompted the licensee's engineeringdepartment to issue on March 2, 2006, a standing order to control room operators to be aware of the concerns for operation of safety-related pumps for extended periods of time while on minimum flow. Since operating a pump on minimum flow was considered a long-term degradation mechanism, issuance of the standing order provided confidence that the pumps would not be damaged prior to the pump manufacturer completing their analysis.As a result of the response to Bulletin 88-04, the RHR, LPCS, and HPCS pumps wereoperated since original plant start-up with an increased potential for unusual wear and aging. Based on the licensee's discussion with the pump manufacturer, the NRC concluded that additional review and evaluation were required to assess whether or not the licensee has established adequate minimum flow requirements for the RHR, LPCS,and HPCS pumps since they may operate at minimum flow conditions for extended periods of time under accident conditions. Therefore, this issue is considered an unresolved item (URI 05000440/2006009-03(DRS)) pending completion of an analysis to assess the pumps minimum flow requirements and subsequent NRC review.

16.5Modifications

a. Inspection Scope

The inspectors reviewed four permanent plant modifications related to the selected risksignificant components to verify that the design bases, licensing bases, and performance capability of the components have not been degraded throughmodifications. The Engineering Change Packages (ECPs) listed below were reviewed as part of this inspection effort:ECP 00-5013, "Safety-Related Upgrade of the ESW Sluice Gate SealingSystem";ECP 02-0283, "RCIC High Pressure Alarm Setpoint 1E51N0852"; ECP 03-0013, "High Pressure Core Spray Pump Breaker Modification"; andECP 04-0263, "Emergency Service Water (ESW) "C" Pump UpgradeModification (1P45C0002)."

b. Findings

No findings of significance were identified..6Risk Significant Operator Actions

a. Inspection Scope

The inspectors performed a margin assessment and detailed review of five risksignificant, time critical operator actions (5 samples). These actions were selected from the licensee's PRA rankings of human action importance based on risk achievement worth and Birnbaum values. Where possible, margins were determined by the review of the assumed design basis and USAR response times and performance times documented by job performance measures results. For the selected operator actions, the inspectors performed a walk through of associated procedures with a plant operator to assess operator knowledge level, adequacy of procedures, and availability of specialequipment where required. The following operator actions were reviewed:*Actions to terminate and prevent injection into the reactor pressure vessel (RPV)during an anticipated transient without scram (ATWS);*Actions to prepare for injection into the RPV during an ATWS;

• Actions to lineup and inject into the RPV with alternate injection systems duringan ATWS;*Actions to initiate standby liquid control during an ATWS; and

• Actions to initiate suppression pool cooling.

b. Findings

One finding of very low safety significance associated with a NCV was identified. b.1Inadequate Procedures for Controlling Flow into Reactor VesselIntroduction: The inspectors identified a NCV of Technical Specification 5.4.1, havingvery low safety significance (Green), for failing to maintain adequate procedures and/orinstructions for controlling injection into the reactor pressure vessel under conditions where the reactor would not shutdown without relying on the injection of boron.Description: Plant Emergency Instruction (PEI) flowcharts (RPV Control - ATWS andRPV Flooding) align low pressure coolant injection (LPCI) to inject through the RHR shutdown cooling return path (outside the shroud injection) to control either reactor water level or reactor pressure under conditions when the reactor was not shutdown without relying on the injection of boron. Procedures PEI-SPI 6.1(6.2), "LPCI A(B)

Outside the Shroud Injection," provided the necessary instructions for controlling thisinjection flow-path. These procedures were revised in January of 2003 to address corrective actions specified by CR 01-02848. The corrective actions were meant to address the incorrect assumption in Calculation EPGSAG-WS10, "RPV Variables," that the RHR pump minimum flow valves would be closed over the range of reactorpressures used in the calculation. To address this issue, the procedures established a flow band, with a minimum value of 2100 gallons per minute (gpm) to ensure the pumps' minimum flow requirement was met with the minimum flow valves closed, and a maximum value (dependent on whether the flow path was through the RHR heatexchanger or not) of either 7800 or 8500 gpm. There were no provisions in the procedure for reducing flow below 2100 gpm. The establishment of a minimum injection flow rate of 2100 gpm forced the operator intoan "on/off" level control strategy that would lead the operator to terminate flow when flowrates less than 2100 gpm were needed (e.g., RPV level or pressure was at the top of the desired control band) and reestablish flow when RPV level approached -25 inches or RPV pressure approached the minimum steam cooling pressure. This stopping and restarting of injection flow could cause rapid changes in the temperature of the coolant entering the core region, thus increasing the potential for large power excursions thatcould damage the fuel. The BWR Owner's Group Emergency Procedure and Severe Accident Guidelines as well as the Perry Specific Technical Guidelines specify that injection, into a reactor that is not shutdown without relying on boron injection, must becontrolled so as to minimize boron dilution and changes in core inlet subcooling, thus preventing the undesirable consequences of large power excursions. By allowing a continuous injection at flow rates that would maintain RPV water level in the desired level band, colder water entering the RPV would mix with the warmer water in the region outside the shroud. This slow, relatively constant injection rate would minimize the temperature changes of the water entering the core region thus preventing large powerexcursions.Analysis: The inspectors determined that the establishment of a minimum injection flowrate, contrary to both the Boiling Water Reactor (BWR) Owner's Group Emergency Procedure and Severe Accident Guidelines as well as the Perry Specific Technical Guidelines, was a performance deficiency and a finding. The inspectors determined 18that the finding was more than minor in accordance with IMC 0612, Appendix B, "IssueDispositioning Screening," because it was associated with the attribute of procedure quality, which affected the mitigating systems cornerstone objective of ensuring theability of the licensee to use the LPCI sub-systems to prevent undesirableconsequences associated with an ATWS. Specifically, the procedure's "on/off" level control strategy may not prevent large power excursions caused by rapid changes in the temperature of the coolant entering the core region.The inspectors evaluated the finding using IMC 0609, "Significance DeterminationProcess," Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," Phase 1 screening, and determined that the finding screened asGreen because it was not a design issue resulting in loss of function per Part 9900, Technical Guidance, did not represent an actual loss of a system's safety function, didnot result in exceeding a TS allowed outage time, and did not affect external event mitigation.Enforcement: Technical Specification 5.4.1, required, in part, that writtenprocedures/instructions be established, implemented, and maintained covering the emergency operating procedures required to implement the requirements of NUREG-0737, "Clarification of TMI Action Plan Requirements," and NUREG-0737,Supplement 1. The BWR Owner's Group Emergency Procedure and Severe Accident Guidelines as well as the Perry Specific Technical Guidelines specify that injection, into a reactor that is not shutdown without relying on boron injection, must be controlled soas to minimize boron dilution and changes in core inlet subcooling, thus preventing the undesirable consequences of large power excursions. Contrary to the above, in January of 2003, the licensee revised the procedures andinstructions for controlling injection into the reactor pressure vessel under conditions where the reactor is not shutdown without relying on the injection of boron by establishing a level control strategy that did not minimize changes in core inlet subcooling, thus increasing the potential for large power excursions that could damagethe fuel. Because this violation was determined to be of very low safety significance and it was entered into the licensee's corrective action program, this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000440/2006009-04). The licensee entered the finding into their corrective action program as CR 06-00872 to assess the affected documents.

OTHER ACTIVITIES (OA)

4OA2Problem Identification and Resolution.1Review of Condition Reports

a. Inspection Scope

The inspectors reviewed a sample of the selected component problems that wereidentified by the licensee and entered into the corrective action program. The inspectors reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions related to design issues. In addition, condition reports written on issues identified during the inspection were reviewed to 19verify adequate problem identification and incorporation of the problem into thecorrective action program. The specific corrective action documents that were sampled and reviewed by the inspectors are listed in the attachment to this report.

b. Findings

No findings of significance were identified.4OA6Meetings, Including Exits.1Exit MeetingThe inspectors presented the inspection results to Mr. W. Pearce and other members oflicensee management at the conclusion of the inspection on March 3, 2006, and withMr. J. Shaw on March 23, 2006. Proprietary information was reviewed during the inspection and will be handled in accordance with NRC policy.4OA7Licensee-Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meet the criteria of Section VI ofthe NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV. Cornerstone: Mitigating Systems Criterion III, "Design Control," of 10 CFR Part 50, Appendix B requires, in part, thatmeasures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The licensee did not adequately translate design basis information into a HPCS system calculation. Specifically, Calculation E22-029, "SVI-E22-T2001- HPCSPump Performance Test Acceptance Criteria," had an error in its methodology as the latest revision of the calculation did not properly account for the Division III, dieselgenerator governor +/- 2 percent droop adjustment (frequency). The licensee failed to consider how the frequency adjustment could affect the design and licensing basis of the HPCS pump's capability to perform under reduced DG frequency. This wasidentified in the licensee's corrective action program as CR 06-00184 and CR 06-00296.

The inspectors reviewed the licensee's operability determination and verified that theHPCS pump remained capable of performing its design function. The inspectors determined that the finding was more than minor because if the licensee had notrecognized the error, the pump could have degraded below its' design requirement. The inspectors determined that the finding was of very low safety significance because it did not represent an actual loss of system safety function since the HPCS pump met its design requirement.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

W. Pearce, Site Vice President

P. Chatterjee, Electrical Engineer

H. Conrad, Nuclear Engineer

D. Gartner, Lead Instrumentation Engineer

J. Hagan, Senior Vice President Operations

T. Hilston, Design Engineering Supervisor

K. Howard, Design Engineering Manager

D. Jondle, Probabilistic Risk Assessment

J. Lausberg, Regulatory Compliance Manager

D. Pace, Senior Vice President Engineering

J. Powers, Fleet Engineering Director

J. Rinckel, Vice president Oversight

K. Russell, Regulatory Compliance

J. Shaw, Engineering Director

S. Seman, NSSS Supervisor

R. Siembor, Mechanical Engineer

J. Tufts, Operations Superintendent

F. Von Ahn, Plant Manager

J. Zarea, Lead Electrical EngineerNuclear Regulatory Commission

C. Pederson, Director, Division of Reactor Safety

A. M. Stone, Chief, Engineering Branch 2, DRS

R. Powell, Senior Resident Inspector

M. Franke, Resident Inspector

2

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000440/2006009-01NCVADS and MSIV Air Accumulators Stress AnalysisDeficiencies (Section 1R21.3.b.1)05000440/2006009-02NCVNon-conservative Safety-Related Air Storage Tank SizingCalculation (Section 1R21.3.b.2)05000440/2006009-03URIInadequate Response for Minimum Pump Flow Settings(Section 1R21.4.b.1)05000440/2006009-04NCVInadequate Procedures for Controlling Flow into ReactorVessel (Section 1R21.6.b.1)

Closed

05000440/2006009-01NCVADS and MSIV Air Accumulators Stress AnalysisDeficiencies (Section 1R21.3.b.1)05000440/2006009-02NCVNon-conservative Safety-Related Air Storage Tank SizingCalculation (Section 1R21.3.b.2)05000440/2006009-04NCVInadequate Procedures for Controlling Flow into ReactorVessel (Section 1R21.6.b.1)

3

LIST OF DOCUMENTS REVIEWED

The following is a list of licensee documents reviewed during the inspection, includingdocuments prepared by others for the licensee.

Inclusion on this list does not imply that NRCinspectors reviewed the documents in their entirety, but rather that selected sections or portionsof the documents were evaluated as part of the overall inspection effort.

Inclusion of a