IR 05000400/2006007

IR 05000400-06-007, on 11/03/2006, Carolina Power & Light Company

ML063400335
Person / Time
Site:	Harris
Issue date:	12/06/2006
From:	Freeman M NRC/RGN-II/DRS/EB1
To:	Gannon C Carolina Power & Light Co
References
IR-06-007
Download: ML063400335 (29)

Text

ber 6, 2006

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT- NRC INSPECTION REPORT NO. 05000400/2006007

Dear Mr. Gannon:

On November 3, 2006, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Shearon Harris Nuclear Power Plant. The enclosed inspection report documents the inspection findings which were discussed on November 3, 2006, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, the inspectors identified two findings of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because each was entered into your corrective action program, the NRC is treating the findings as non-cited violations consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you deny these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Shearon Harris Nuclear Power Plant.

CP&L 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs 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/

M. Scott Freeman, Acting Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-400 License Nos.: NPF-63

Enclosure:

NRC Inspection Report 05000400/2006007 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-400 License Nos.: NPF-63 Report No.: 05000400/2006007 Licensee: Progress Energy Facility: Shearon Harris Nuclear Power Plant Location: 5421 Shearon Harris Road New Hill, NC 27562-9998 Dates: October 2 - November 3, 2006 Inspectors: R. Moore, Lead Inspector H. Anderson, Contractor C. Peabody, Reactor Inspector M. Scott, Reactor Inspector S. Kobylarz, Contractor Approved by: M. Scott Freeman, Acting Chief, Engineering Branch 1 Division of Reactor Safety i

SUMMARY OF FINDINGS

IR05000400/2006007; 10/2/2006 - 10/6/2006, 10/16/2006 - 10/20/2006, 10/30/2006 -

11/3/2006; Shearon Harris Nuclear Power Plant; Component Design Bases Inspection.

This inspection was conducted by a team of three NRC inspectors and two NRC contractors.

Two green findings, all of which were non-cited violations, were identified during this inspection.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 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 NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion III, Design Control, for inadequate design control measures to assure the capability to identify and isolate a residual heat removal (RHR) system leak of 50 gpm in 30 minutes as stated in the Updated Final Safety Analysis Report (UFSAR). Specifically, the Reactor Auxiliary Building (RAB) safeguards sump level instrumentation and area radiation monitors were not capable of assuring detection and control room indication of a 50 gpm RHR leak within 30 minutes of leak initiation.

This finding was more than minor based on its association with the mitigation cornerstone aspect of design control. It impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events in that the purpose of 50 gpm/30 minute criteria was to assure the reliability of the RHR system to accomplish the safety function of long term recirculation cooling. This finding was of very low safety significance (Green)because the RHR leak detection indication available would detect and allow termination of inventory loss prior to significantly impacting the capability of the emergency core cooling system (ECCS) long term recirculation cooling function.

The licensee entered this finding in the corrective action program for resolution.

(Section 1R21.2.16)

Green.

The team identified a non-cited violation of 10 CFR 50, Appendix B,

Criterion III, Design Control for a non-conservative setpoint related to the low Reactor Coolant System (RCS) Standpipe level for mid-loop operations.

Specifically, the licensee failed to incorporate instrument uncertainty resulting in an inadequate margin for the onset of vortex conditions to the RHR pumps. The team identified that the alarm setpoint appeared to be inadequate to protect the Residual Heat Removal pumps with respect to air entrainment under vortex conditions.

ii

The finding was more than minor because it affected the design control attribute associated with the mitigating systems cornerstone as related to the availability, reliability, and capability of the RHR system. This finding was of very low safety significance (Green), because it was a design deficiency confirmed not to have resulted in the loss of safety function. This determination was based on the following factors: operators are trained to identify pump cavitation/loss of suction using diverse indications, standpipe levels are closely monitored during mid-loop operations, and low pressure, single stage centrifugal pumps such as the RHR pumps can sustain short periods of air entrainment or cavitation without loss of safety function. The licensee entered this finding into their corrective action program for resolution. (Section 1R21.2.17)

B. Licensee-identified Violations None iii

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Mitigating Systems and Barrier Integrity

1R21 Component Design Bases Inspection

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the licensees Probabilistic Risk Assessment (PRA). In general, this included components and operator actions that had a risk achievement worth factor greater than two or Birnbaum value greater than 1 X10-6. The components selected were primarily located within the emergency service water system (ESW),residual heat removal (RHR) system, emergency diesel generator (EDG) ventilation subsystem, and the reactor vessel level indication for shutdown operations. The sample selection included 17 components, 5 operator actions, and 5 operating experience items. Additionally, the team reviewed three modifications by performing activities identified in IP 71111.17, Permanent Plant Modifications, Section 02.02.a. and IP 71111.02, Evaluations of Changes, Tests, or Experiments.

The team 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 issues, margin reductions due to modification, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results, significant corrective action, repeated maintenance, maintenance rule (a)1 status, GL 91-18 conditions, NRC resident inspector input of problem equipment, system health reports, industry operating experience and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. An overall summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.

.2.1 ESW Intake Structure/Pit/Screens

a. Inspection Scope

The team reviewed the design base documentation, updated final safety analysis report (UFSAR), and station drawings to identify the design base requirements for the ESW intake structure, pump suction pit, and the pump suction filter screens, including seismic requirements, environmental protection requirements, and filtering capability. Periodic and post-maintenance testing was reviewed to verify that the design requirements were appropriately monitored and maintained. The structure and components were walked down to observe the general material condition and verify the configuration was consistent with station drawings.

b. Findings

No findings of significance were identified.

.2.2 ESW Reactor Auxiliary Building (RAB) Piping

a. Inspection Scope

The team reviewed design base documentation, system and isometric drawings, and the UFSAR to identify the design and licensing base requirements for the ESW piping in the RAB in relation to the potential for flooding from the ESW piping and normal service water piping. The team reviewed the licensees actions to maintain the chemistry of the ESW and normal service water systems to preclude piping degradation and the licensees actions to monitor degradation of piping. The results of periodic pipe wall thickness measurements were reviewed to verify that margins to design minimum pipe wall thicknesses were maintained. The team reviewed the licensee's design base calculations of postulated pipe breaks in the RAB, as well as the probabilistic risk assessment (PRA) calculations of assumed ESW and normal service water system guillotine pipe breaks in these buildings. The team reviewed the licensee's activities to remove and cap stagnant lines associated with the ESW system and to replace other ESW lines where degradation had been detected. Additionally, the team reviewed the licensees activities to inspect internal coating of large bore piping and to replace and repair coatings on ESW system piping. The team walked down selective accessible portions of the ESW piping in the ESW intake structure and portions of the ESW and normal service water piping in the RAB to observe the general material condition of the piping and associated components, as well as the location and condition of seismic supports for ESW and normal service water piping.

b. Findings

No findings of significance were identified.

.2.3 ESW Motor Operated Valves (MOVs) Discharge to Reservoirs (SW-270, -271)

a. Inspection Scope

The team reviewed MOV calculations to verify that design bases, system conditions, and allowable degraded voltage conditions were used as design inputs to size the actuators and establish set point values. Additionally, the translation of design information into MOV test procedure acceptance criteria was reviewed. Maintenance documentation was reviewed to verify that MOVs were periodically tested and that appropriate torque switch settings were maintained. Maintenance history, corrective action history, foreign material exclusion (FME) controls and design changes were reviewed to assess the potential for flowpath obstruction and material degradation. The MOVs and discharge canal were walked down to verify the discharge flowpath was consistent with station drawings. The team reviewed the elementary and schematic diagrams of the valve motor control circuit configurations to verify that the circuitry satisfied the logic presented in the design base documentation. The team reviewed the maintenance and testing for the design base related interlocks and the valve motor starters to assess equipment availability.

b. Findings

No findings of significance were identified.

.2.4 ESW RAB Flood Isolation Valves [ MOVs SW-274, 275, 276, 39, 40 and Manual Valve

SW 565]

a. Inspection Scope

The team reviewed MOV calculations to verify that design bases, system conditions, and allowable degraded voltage conditions were used as design inputs to size the actuators and establish set point values. Additionally, the translation of design information into MOV test procedure acceptance criteria was reviewed. Maintenance documentation was reviewed to verify that MOVs were periodically tested and that appropriate torque switch settings were maintained. Maintenance history, corrective action history, foreign material exclusion (FME) controls and design changes were reviewed to assess the potential for flowpath obstruction and material degradation. The operation and maintenance history of manual valve SW-565 was reviewed to verify the capability to operate the infrequently operated valve. The MOVs were walked down to observe the general material condition and verify the configuration was consistent with station drawings.

b. Findings

No findings of significance were identified.

.2.5 ESW Pumps

a. Inspection Scope

The team reviewed the design base documentation, pump vendor manual and related vendor correspondence, drawings, and the UFSAR to identify design, maintenance, and operational requirements related to pump flow and developed head, system flow, net positive suction head (NPSH), vortex formation and prevention, minimum flow requirements, and runout protection for the ESW pumps. These requirements were reviewed for pump operation with the source of water originating from the alternate reservoir and from the normal reservoir. Design calculations as well as documentation of in-service, periodic, and post-modification tests and flow balances were reviewed to verify that design performance requirements were met for the various operating configurations of the ESW system. Maintenance, in-service testing, corrective action, and design change histories were reviewed to assess the potential for component degradation and resulting impact on design margins or performance.

The team reviewed the elementary and schematic diagrams of the ESW pump motor control circuit configurations to verify that the circuitry satisfied the logic presented in the design base documentation. In addition, the team walked down portions of the ESW system to verify that the installed configuration was consistent with design base information and visually inspected the material condition of the pump motors. The team reviewed the calibration and testing of pressure instrumentation for the ESW headers and associated interlocks and pump start circuits to verify the adequacy of pump testing and to assess equipment availability.

b. Findings

No findings of significance were identified.

.2.6 RHR Pumps

a. Inspection Scope

The team reviewed the design base documentation to identify design, maintenance, and operational requirements related to flow and developed head, NPSH, vortex formation and prevention, minimum flow requirements, and runout protection for the RHR pumps.

These requirements were reviewed for pump operation with the suction source from the refueling water storage tank, containment recirculation sump, and reactor mid-loop conditions. The RHR flow assumptions in the UFSAR accident analysis were verified.

Design calculations and periodic in-service test results were reviewed to verify that design base performance requirements were met for the various operating configurations, including the respective pump suction sources as well as the high pressure recirculation (piggy back) configuration in which the RHR pumps provide flow to the suction of the charging and safety injection pumps (CSIPs). Maintenance, in-service test, periodic test, corrective action, and design change histories were reviewed to assess potential component degradation and corresponding impact on design margins or performance. The team reviewed the licensee's evaluation of the applicability of an industry operating experience issue related to the potential for reduced RHR pump shaft/bearing clearance and/or interference when higher temperature containment recirculation sump water is pumped during accident conditions to assess the rigor of the subject evaluation.

The team reviewed the elementary and schematic diagrams of the RHR pump motor breaker control circuit to verify that the circuitry satisfied the logic presented in the design base documentation. The team reviewed the maintenance and testing for the design base related interlocks and motor circuit breaker controls to verify the adequacy of interlocks and to assess equipment availability. The testing procedures were reviewed to verify that precautions such as restart restrictions and operating time limits at low flow rates were addressed.

b. Findings

No findings of significance were identified.

.2.7 RHR Mini-Flow MOVs (RH-31, -69)

a. Inspection Scope

The team reviewed the design base documentation, drawings, pump vendor manual and related vendor correspondence, valve vendor manual, and the UFSAR to identify design, maintenance, and operational requirements for the RHR pump mini-flow valves.

The team reviewed the MOV mechanical analysis calculation for mini-flow valve 1RH-31 to verify that design bases, system pressure conditions, and degraded voltage conditions were used as design inputs in developing and translating diagnostic setup requirements and diagnostic test acceptance criteria into the MOV test procedure. The results of diagnostic testing were reviewed to confirm the MOV test acceptance criteria were met. The vendor manual and periodic preventive maintenance documentation were reviewed to verify preventive maintenance inspection, actuator lubrication, and stem lubrication activities were consistent with vendor recommendations. Maintenance history and corrective action history were reviewed to assess the potential for the mini-flow valve to fail in an open or mid-travel position, thus diverting desired forward flow into the mini-flow path, or to fail in a closed position, thus failing to provide required minimum flow protection. The team reviewed the flow setpoints for the mini-flow valve opening and closing functions to provide minimum flow protection to the operating pump in accordance with the pump vendor manual and vendor correspondence. The MOV logic drawings were reviewed to identify valve control signals and verify logic was adequately tested. The MOV logic and elementary control wiring diagrams were reviewed to verify that the circuitry satisfied the logic presented in the design base documentation and that the design base related control logic was adequately tested.

b. Findings

No findings of significance were identified.

.2.8 RHR Containment Sump Suction MOVs (SI-300,- 310, -301, -311)

a. Inspection Scope

The team reviewed the design base documentation, drawings, valve vendor manual, and the UFSAR to identify the design requirements for the RHR containment recirculation sump suction MOVs. The team reviewed the MOV mechanical analysis calculation for valve 1SI-311 to verify that design bases, system pressure conditions, and degraded voltage conditions were used as design inputs in developing and translating the mechanical analysis results into the MOV diagnostic setup requirements and test acceptance criteria. The results of diagnostic testing were reviewed to confirm that the MOV test acceptance criteria were met. Maintenance history and corrective action history were reviewed to assess the potential material degradation associated with the valves. The vendor manual and documentation of preventive maintenance activities were reviewed to verify preventive maintenance inspection, actuator lubrication, and stem lubrication were consistent with vendor recommendations. The team reviewed the elementary and schematic diagrams of the valve motor control circuit configurations to verify that the circuitry satisfied the logic presented in the design basis documentation. The team reviewed the maintenance and testing for the design basis related interlocks and for the valve motor starters to assess equipment availability.

b. Findings

No findings of significance were identified.

.2.9 RHR Heat Exchanger Flow Control Air Operated Valves (AOVs) (RH-20, -58, -66, -30)

a. Inspection Scope

The team reviewed these AOVs to verify they were qualified to perform their safety-related function and their failure modes supported the design basis accident conditions.

Maintenance, modification, and corrective action history of the AOVs was reviewed to verify that component degradation would be identified. The team reviewed the design, operation, and routine maintenance of the valve positioners to assess their reliability to position the valves for decay heat removal. Additionally, the team reviewed the independence of the positioners air supply and control power to assess the potential for common cause failure of the positioners. The team reviewed AOV calculations which established the maximum expected differential pressure and surveillance procedures which implemented testing of this valve to assure that it can close under the accident conditions.

b. Findings

No findings of significance were identified.

.2.10 RHR Piggy Back MOVs (RH-63, -25)

a. Inspection Scope

The team reviewed the design basis documentation, drawings, valve vendor manual, and the UFSAR to identify the design and operational requirements for the RHR pump to CSIP "piggy back" MOVs RH-63 & 25. The team reviewed the MOV mechanical analysis calculation for valve 1RH-63 to verify that design bases, system pressure conditions, and degraded voltage conditions were used in developing and translating diagnostic setup requirements and acceptance criteria into the MOV diagnostic test.

Maintenance history and corrective action history were reviewed to assess the identification and resolution of equipment problems. The vendor manual and documentation of preventive maintenance activities were reviewed to verify preventive maintenance inspection, actuator lubrication, and stem lubrication were consistent with vendor recommendations.

The team reviewed the control circuits for these MOVs to verify that the interlocks and permissives for the high pressure recirculation mode of safety injection system operation would function as described in the design documentation. The logic testing results were reviewed to verify that the interlocks were functionally tested. The team reviewed the maintenance and testing for the design basis related interlocks and for the valve motor starters to assess equipment availability.

b. Findings

No findings of significance were identified.

.2.11 EDG E-86 Air Handling Unit (AHU) and Associated Dampers (DG-GD3A-1. DG-GD3B1)

a. Inspection Scope

The team reviewed the design basis documentation, specifications, drawings, exhaust fan and outlet damper vendor manuals, and the UFSAR to identify the design requirements and vendor recommended maintenance for the EDG E-86 AHUs and associated fan outlet dampers, as well as the fan interlocks associated with EDG operation. The team reviewed the equipment sizing calculations for the E-86 (1A-SA and 1B-SA) exhaust fans, equipment specifications, vendor test data, and the licensee's startup test data for the subject fans. The team walked down the accessible E-86 fan housings, fan outlet dampers, and the associated inlet and outlet ductwork to assess the material condition of the system components. The team reviewed documentation of periodic preventive maintenance to verify incorporation of measures for lubrication of the fan motor and periodic assessment of fan motor condition by electrical checks, visual inspection, and vibration monitoring. The team also reviewed recent changes to the preventive maintenance program wherein performance of periodic visual inspections of fan blade pitch and periodic inspection, cleaning, and lubrication of dampers is scheduled.

The associated exhaust fan and EDG interlocks and logic were reviewed to verify that testing demonstrated the design features. The team reviewed test documentation to verify that the backup E86 (1B-SA) fan is tested to demonstrate the automatic fan start function.

b. Findings

No findings of significance were identified.

.2.12 CSIP Discharge MOVs (SI-3, -4, 52, 86, 107)

a. Inspection Scope

The team reviewed the MOV calculations and testing results for the charging pump discharge MOVs to verify that appropriate design basis event conditions and degraded voltage conditions were used as inputs into the motor actuator set points and motor actuator sizing. MOV calculations and related testing documentation were reviewed to determine if valve performance was verified for anticipated maximum operating pressure conditions and to determine if appropriate torque switch settings were maintained.

Additionally, MOV test plans, as left test data, and valve margin calculation results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The team reviewed the maintenance history, corrective maintenance, ARs, to verify that identified equipment problems were appropriately resolved. A field walkdown of the MOVs was conducted to verify the material condition and proper positioning in accordance with station drawings. The team reviewed the elementary and schematic diagrams of the valve motor control circuit configurations to verify that the circuitry satisfied the logic presented in the design basis documentation.

The team reviewed the maintenance and testing for the design basis related interlocks and for the valve motor starters to assess equipment availability.

b. Findings

No findings of significance were identified.

.2.13 Start-up Transformer (SUT) 1A and 1B

a. Inspection Scope

The team reviewed the design basis documentation for the start-up transformer to identify the analyzed sizing for worst case load conditions and to verify the design base requirements were consistent with the equipment specifications. A field verification was performed to verify that the nameplate specified design data (capacity and impedance)was translated correctly into the load flow analysis. The protective relaying calculations were reviewed to verify setpoint determination and incorporation of setpoint information into calibration procedures. Relay calibration test results were reviewed to verify that out of tolerance conditions were identified and resolved. Maintenance and test activity was reviewed to verify that equipment degradation was monitored and to review equipment availability. A field walkdown of the transformers was conducted to observe general material conditions. Relay settings were verified in the field for consistency with the design calculations and the calibration test procedures.

b. Findings

No findings of significance were identified.

.2.14 Non-safety 125 VDC battery (1A NNS)

a. Inspection Scope

The team reviewed the design analyses for the capability of the non-safety 125 VDC battery and distribution equipment to support recovery of offsite power following a station blackout (SBO) event. The battery load profile calculation, the battery sizing and panel voltage calculation and the emergency operating procedures (EOPs) for recovering of offsite power were reviewed to identify the design requirements for the battery and support equipment. Battery testing and inspections were reviewed to assess the licensees actions to verify and maintain the design capability of the battery.

The maintenance history on the battery and support equipment was reviewed to verify the availability assumptions in the design and risk analysis were valid. A field verification was performed to assess the material condition of the battery and verify the battery load analysis designated loads were correct based on the arrangement of the distribution panels. Additionally, the alarms and indications for the chargers were reviewed to verify that a charger failure would be detected before the next surveillance.

b. Findings

No findings of significance were identified.

.2.15 RAB Flood Detection Instrumentation

a. Inspection Scope

The team reviewed the plant design drawings, alarm response procedures, EOPs and abnormal operating procedures (AOPs) to identify the instrumentation alarms and indications that would alert the control room to a flood condition in the RAB. These included the normal service water/emergency service water pressure and flow indications, RAB equipment sump level instrumentation, and the radiation monitors for inter system loss of coolant accident (LOCA). The team reviewed the instrumentation and setpoints associated with this equipment. The team observed the instrumentation and the control room operator response to a RAB flooding event at the plant simulator.

The team also reviewed the maintenance, testing, and calibration procedures to verify that they incorporated appropriate acceptance criteria, that adequate testing was accomplished and to verify the instrumentation availability and reliability was maintained.

b. Findings

No findings of significance were identified.

.2.16 Intersystem LOCA Detection Instrumentation

a. Inspection Scope

The team reviewed the design basis documentation, station procedures and drawings, and the UFSAR to identify the design requirements for detection of intersystem LOCA.

Plant layout and instrumentation drawings, alarm response procedures (ARPs), and EOP-EPP-013, Rev. 7, Response to LOCA Outside Containment, were reviewed to identify the instrumentation alarms and indications that would alert the control room to an intersystem LOCA condition. The detection instrumentation included the level instrumentation and associated alarms for the RAB equipment drain sumps and transfer tank, RAB floor drain transfer tank, RAB equipment A/B and C/D sump alert indications, and the RAB area radiation monitors. A field verification was performed to observe the material condition of the sumps and the related instrumentation. The team identified the setpoints and protection circuits associated with this equipment and reviewed the maintenance, testing, and calibration procedures to verify that they incorporated appropriate acceptance criteria and that adequate testing was accomplished to verify the instrumentation availability and reliability was maintained.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for inadequate design control measures to assure the capability to identify and isolate an RHR leak of 50 gpm in 30 minutes as stated in the UFSAR. The licensee entered this deficiency into their corrective action program for resolution.

Description:

UFSAR, amendment 51, Section 5.4.7.2.6, System Reliability Considerations, stated as a design criteria for the RHR system that a maximum leakage of 50 gpm could be detected and isolated within 30 minutes. The UFSAR further stated the occurrence of the leak would be indicated in the control room via safeguards sumps indicating lights and area radiation monitoring alarms. The team noted that the RAB RHR area safeguards sumps had sump pumps rated at 75 gpm. Sump high level alert indication was available in the control room, however sump pump start indication was not available. At a capacity of 75 gpm the sump pumps would pump any lesser leakage, such as the 50 gpm stated in the criteria, to the hold up tanks without the control room being able to detect the leakage, via level indication, and take action to isolate it within 30 minutes. The licensee indicated that coolant dose rates would be elevated during an event requiring RHR recirculation cooling and although area radiation alarm setpoints of 400 and 500 mrem could be reached, it would not be expected to occur within 30 minutes.

The basis for the 50 gpm/30 minute criteria was to assure that RCS inventory loss during long term recirculation cooling, due to intersystem LOCA, would be detected and isolated before the recirculation cooling function was significantly impacted. The 50 gpm value was based on a passive failure of the RHR pump seal. The team determined that the performance deficiency was inadequate design control during original station construction because the UFSAR intersystem LOCA leak detection capability design criteria was not sufficiently implemented.

During the inspection the licensee performed an analysis to assess an alternate method for control room indication, via the level alarm on the waste hold up tanks, of a 50 gpm leak and the related inventory loss and potential impact on the recirculation cooling function. Based on the pumps pumping 75 gpm to the waste hold up tanks and the level alarm set point of these tanks, the licensee determined that 12,000 gallons of containment/reactor coolant system (RCS) inventory could be lost in four hours before control room indication occurred, assuming the area radiation alarms did not identify the condition sooner. Compared to the volume of 279,000 gallons directed to containment from minimum RWST level this 4.3 per cent loss of inventory was determined to have no significant impact on the long term recirculation cooling function. This volume loss in the containment would reduce water level approximately 2 inches. The NPSH margin available to the RHR pumps was 3.2 feet, therefore there was no significant impact on the RHR pump capability. The team concurred with the licensees conclusion that the potential worst case loss of inventory before detection and isolation would not significantly impact the long term recirculation cooling function.

Analysis:

This finding was more than minor because it is associated with the mitigation cornerstone aspect of design control. It impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events in that the purpose of 50 gpm/30 minute criteria was to assure the reliability of the RHR system to accomplish the safety function of long term recirculation cooling. The finding was of very low safety significance (Green) because the RHR leak detection indication available would detect and allow termination of inventory loss prior to significantly impacting the capability of the ECCS long term recirculation cooling function.

Enforcement:

10 CFR 50 Appendix B, Criterion III, Design Control, requires that applicable regulatory requirements and design bases are correctly translated into specifications, drawings, procedures and instructions. Measures shall be established for the selection and review for suitability of application of materials, parts, equipment and processes that are essential to the safety related functions of structures, systems, and components. Contrary to the above, adequate design control measures were not established during the original plant design for the selection and review for suitability of equipment to assure the implementation of the design basis for the RHR system, in that the capability for the detection and isolation of a 50 gpm leak in 30 minutes as stated in UFSAR, amendment 51, Section 5.4.7.2.6, System Reliability Considerations was not provided. Because this finding is of very low safety significance (Green) and entered into the licensees corrective action program (AR 211012211012, this violation is being treated as a non cited violation (NCV) consistent with section VI.A.1 of the NRC Enforcement Policy: NCV 05000400/2006007-01, Inadequate Design Control to Assure UFSAR Requirement to Detect and Isolate an RHR leak of 50 GPM in 30 minutes.

.2.17 Reactor Vessel Level Indication Instrumentation - Shutdown Operation

a. Inspection Scope

The team reviewed the reactor vessel level standpipe system (RCS Standpipe),including the associated level transmitter, instrumentation, and alarm as well as the installed standpipe level gauge. The team reviewed design basis information, RCS drawings, standpipe system drawings, relative elevations, procedures, and calibration documentation as well as the calculation of RCS water level gradients at mid-loop conditions to verify that the use of standpipe readings (control room instrumentation and physical local standpipe readings) incorporated the level gradient or differential between the RHR elevations of interest and the standpipe level taps. The team reviewed the reactor vessel level standpipe indication identified in the UFSAR to ensure that level instrumentation and low level alarm setpoints had been properly incorporated. The team also reviewed the calibration procedures for the various sensing and signal processing components that were installed in the system to verify that instrument uncertainty had been included.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, for a non-conservative alarm setpoint for low reactor vessel standpipe level for mid-loop operations.

Description:

The team identified that the RCS standpipe low level alarm setpoint of -76.5 inches water column (INWC) was established without incorporating instrument loop uncertainty, resulting in an inadequate margin to the onset of vortex conditions of the RHR pumps during mid-loop operations. The required levels for RHR pump protection, Critical Analyzed Cavitation Levels were derived from WCAP-11916, Loss of RHRS Cooling While the RCS is Partially Filled, dated July, 1988. This WCAP determined the minimum water levels fo prevent vortex formation. The offset between the RCS standpipe level taps and the elevation of concern, the RHR pump suction, were added to the cavitation/minimum vortex prevention levels to establish the reference levels on the RCS standpipe corresponding to the levels necessary to assure pump protection in calculation NSSS-0047, Rev.1, RCS Mid-Loop Gradients. However, the licensee at that time appeared to incorrectly assume that the offset value was margin for pump operation and concluded that the instrument loop uncertainty was enveloped by this offset value. The RCS standpipe alarm setpoint of -76.5 INWC was established as the combination of the critical analyzed level and the offset, which did not include any margin to address instrument loop uncertainty. The licensees initial analysis during the inspection determined the loop uncertainty to be 2.2 INWC. The licensee entered this finding into their corrective action program and initiated action to revise the set point.

Analysis:

The team determined this issue was a performance deficiency since the established alarm setpoint of -76.5 INWC did not incorporate instrument loop uncertainty. This performance deficiency occurred in 1989 when PCR-4491 installed the RCS standpipe level transmitter. The finding was greater than minor because it affected the design control attribute associated with the mitigating systems cornerstone as related to the availability, reliability, and capability of the RHR system in that potential vortex formation could impact the reliability and capability of the pump and therefore the RHR mitigation system. The finding was of very low safety significance (Green),because it was a design deficiency determined not to have resulted in the loss of safety function. This determination was based on the following: operators are trained to identify pump cavitation/loss of suction using diverse indications; standpipe levels are closely monitored during mid-loop operations; and low pressure, single stage centrifugal pumps such as the RHR pumps can sustain short periods of air entrainment or cavitation without loss of safety function.

Enforcement:

10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that design control measures be established and implemented to assure that applicable regulatory requirements and the design basis for structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, at the installation of the RCS standpipe level transmitter via PCR-4491 in 1989, the established alarm setpoint of -76.5 INWC did not incorporate instrument loop uncertainty. This resulted in an inadequate margin to the onset of vortex conditions of the RHR pumps. Because this issue was of very low safety significance, and it was entered into the corrective action program (AR 211188211188, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000400/2006007-02, Inadequate Design Control for RCS Standpipe Low Level Setpoint.

.3 Review of Low Margin Operator Actions

a. Inspection Scope

The team performed a margin assessment and detailed review of five risk significant and time critical operator actions. Where possible, margins were determined by the review of the assumed design basis and UFSAR response times and performance times documented by job performance measures (JPMs). Control room (CR) and in-plant (IP)

JPMs were reviewed. For the selected components and operator actions, the team performed an assessment of the EOPs, AOPs, ARPs, and other operations procedures to determine the adequacy of the procedures and availability of equipment required to complete the actions. Operator actions were observed on the plant simulator and during plant walkdowns.

The following operator actions were observed on the licensees operator training simulator:

Recovery of offsite power w/o EDG or NNS battery:

CR-56 - manual alignment of SI post LOSP [EPP-3]

CR-59 - loss of all AC followup [EDG failed to start] - time critical High pressure recirculation:

CR-31 - transfer to cold leg recirculation - time critical CR-157 - post LOCA cool down and depressurization.

[Inspectors observed timing on suction source RWST to sump swap]

Response to ESW flood:

CR-151 loss of RAB ESW header - time critical.

Additionally, the inspectors walked down, table-topped and reviewed the following operational scenarios:

Gravity Feed from RWST to RCS on Loss of RHR Mitigation of Intersystem LOCA .

Further, the inspectors field verified the following critical non-licensed operator actions:

IP-82 secure battery charger at power at power, last NNS charger to be removed from service IP-83 start up a battery charger carrying loads IP-142 local restoration of off-site power to emergency bus A-SA [EPP-001, 2]

IP-148 perform EPP-001 DC load shed list (Attachment 3)

IP-172 local manual operation of the TDAFW pump

b. Findings

No findings of significance were identified.

.4 Review of Industry Operating Experience

a. Inspection Scope

The team reviewed selected operating experience issues that had occurred at domestic and foreign nuclear facilities for applicability at the Shearon Harris Nuclear Power Plant.

The team performed an independent applicability review and issues that appeared to be applicable to the Harris Plant were selected for a detailed review. The issues that received a detailed review by the team included:

NRC Information Notice (IN) 2005-25, Inadvertent Reactor Trip and Partial Safety Injection Due to Tin Whisker NRC IN 2006-003, Motor Starter Failure At Cooper NRC IN 2005-03, Butterfly Valve Vibration Induced Degradation NRC IN 2006-05, Possible Defect in Bussman KWN-R and KTN-R Fuses NRC IN 1997-78, Credit for Operator Actions in Place of Automatic Actions

b. Findings

No findings of significance were identified.

.5 Review of Permanent Plant Modifications

a. Inspection Scope

The team reviewed three modifications related to the selected risk significant components in detail to verify that the design bases, licensing bases, and performance capability of the components have not been degraded through modifications. The adequacy of design and post modification testing of these modifications was reviewed by performing activities identified in IP 71111.17, Permanent Plant Modifications, Section 02.02.a. Additionally, the team reviewed the modifications in accordance IP 71111.02, Evaluations of Changes, Tests, or Experiments, to verify the licensee had appropriately evaluated them for 10 CFR 50.59 applicability. The following modifications were reviewed:

EC 93911, 1A ESW Pump Refurbishment, Rev. 2 EC 60437, ESW Pump Wear Ring Material Change, Rev.1 EC 62479, Change in duty cycle for RHR Pump Motors, Rev 0

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4AO6 Meetings, Including Exit

Exit Meeting Summary

On November 3, 2006, the team presented the inspection results to Mr. B. Duncan, Director, Site Operations, and other members of the licensee staff. The team returned all proprietary information examined to the licensee. No proprietary information is documented in the report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Caves, Engineering Technical Services Superintendent

D. Corlett, Licensing/Regulatory Programs Superintendent

B. Duncan, Director, Site Operations

C. Erdac, Design Engineering Superintendent

K. Henderson, Maintenance Manager

L. Martin, Design Engineering Superintendent

S. McCoy, Licensing Engineer

K. Miller, Reactor System Supervisor

S. Oconnor, Engineering Manager

J. Pierce, NAS Superintendent

J. Warner, Shift Operations Manager

C. Williams, Mechanical/Civil Design Engineering Supervisor

NRC

S. Freeman, RII, Engineering Branch 1, Chief (acting)

M. Cain, Senior Reactor Inspector

ITEMS OPENED, CLOSED, AND DISCUSSED

Open/Closed

05000400/2006007-01 NCV Inadequate Design Control to Assure UFSAR Requirement to Detect and Isolate an RHR leak of 50 GPM in 30 minutes. (Section 1R21.2.16)

05000400/2006007-02 NCV Inadequate Design Control for RCS Standpipe Low Level Setpoint (Section 1R21.2.17)