IR 05000266/2008009

IR 05000266-08-009, 05000301-08-009(DRS), on 06/23/2008 B 07/25/2008, Point Beach Nuclear Plant, Units 1 & 2; Component Design Bases Inspection (CDBI)

ML082520769
Person / Time
Site:	Point Beach
Issue date:	09/08/2008
From:	Ann Marie Stone NRC/RGN-III/DRS/EB2
To:	Meyer L Florida Power & Light Energy Point Beach
References
IR-08-009
Download: ML082520769 (39)

Text

ber 8, 2008

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 COMPONENT DESIGN BASIS INSPECTION (CDBI) REPORT 05000266/2008009 AND 05000301/2008009 (DRS)

Dear Mr. Meyer:

On July 25, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed a component design bases inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the inspection results, which were discussed on July 25, 2008, with you and members of your staff.

The inspection examined activities conducted under your license, as they relate to safety, and to compliance 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, five NRC-identified findings of very low safety significance were identified. The findings involved a violation of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of this NCV, you should provide a response within 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 of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), 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, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27 Enclosure: Inspection Report 05000266/2008009; 05000301/2008009 w/Attachment:

Supplemental Information cc w/encl: M. Nazar, Senior Vice President and Nuclear Chief Operating Officer J. Stall, Executive Vice President, Nuclear and Chief Nuclear Officer A. Khanpour, Vice President, Engineering Support Licensing Manager, Point Beach Nuclear Plant M. Ross, Managing Attorney A. Fernandez, Senior Attorney M. Warner, Vice President, Nuclear Plant Support M. Gettler, Vice President, New Nuclear Projects W. Maher, Licensing Director, New Nuclear Projects K. Duveneck, Town Chairman Town of Two Creeks Chairperson Public Service Commission of Wisconsin J. Kitsembel, Electric Division Public Service Commission of Wisconsin P. Schmidt, State Liaison Officer

SUMMARY OF FINDINGS

IR 05000266/2008009, 05000301/2008009(DRS); 06/23/2008 B 07/25/2008; Point Beach

Nuclear Plant, Units 1 & 2; Component Design Bases Inspection (CDBI).

This report covers a three-week onsite baseline inspection that focused on the design of components that are risk significant and have low design margin. The inspection was conducted by regional engineering inspectors and three consultants. Five findings of very low safety significance were identified, all with associated Non-Cited Violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, ASignificance 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 safe operation of commercial nuclear power reactors is described in NUREG-1649, AReactor Oversight Process,@ Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion III, ADesign Control,@ was identified by the team for the failure to ensure that the design limit established in a design basis calculation, used to determine SR batteries hydrogen generation rate, bounded the value used in a maintenance procedure for a safety related component. During the inspection, the licensee evaluated and determined that the effect of the higher hydrogen gas generation did not have an impact on the operability of the batteries and the ventilation system.

The finding was greater than minor because the lack of adequate design control process resulted in increase of hydrogen generation levels and in a reasonable doubt of operability of the 125Vdc system. The finding was determined to be of very low significance, because it was a design deficiency that did not result in actual loss of safety function. This finding does not have a cross-cutting aspect because it is not indicative of current performance. (Section 1R21.3.b.1)

Green.

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, ADesign Control,@ was identified by the team for the failure to verify the accuracy of design using alternative or simplified calculational methods or by the performance of a suitable testing program. Specifically, the licensee used non-conservative field test data as a basis for the design temperatures given in the equipment qualification (EQ) manual for components in the Primary Auxiliary Building (PAB), resulting in specified design temperatures for some safety related components that may be as much as approximately 40 oF less than calculated worst case accident condition temperatures. The licensee re-evaluated the consequences of the higher temperatures and concluded the equipment remained operable.

The finding was determined to be more than minor because, if the EQ design temperatures were left uncorrected, this deficiency could lead to inadequately qualified replacement parts or inadequately designed plant modifications in the future. The finding was determined to be of very low significance because, by the end of the inspection, the licensee was able to show that all affected components were capable of performing their safety related functions under the higher than previously anticipated temperatures. The team did not identify a cross-cutting aspect associated with this finding.

(Section 1R21.3.b.2)

Green.

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XI, ATest Control,@ was identified by the team for the failure to test the components used for transfer of fuel oil between two underground storage tanks that support EDG operation. Specifically, the licensee has not demonstrated the transfer of fuel between tanks T-175A and T-175B as credited in the Technical Specification (TS) Basis and UFSAR. The licensee entered this issue into its corrective action and prepared to test these components.

This finding was determined to be more than miner because the failure to verify the transfer capability affected the ability to ensure emergency power availability for greater than two days. This finding was screened as very low safety significance because it was a deficiency that did not result in the loss of safety function. This finding does not have a cross-cutting aspect because it was not indicative of current performance. (Section 1R21.3.b.3)

Green.

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XII, AControl of Measuring and Test Equipment,@ was identified by the team for the failure to correct a known trend of out of tolerance (OOT) test pressure gauge which were used in a critical In Service Test (IST)

Program performance test of the residual heat removal (RHR) pumps for Units 1 and 2.

The licensee entered this issue into its corrective action and confirmed operability of the RHR pumps.

The finding was determined to be more than minor because, if left uncorrected, it could become a more significant safety concern. Specifically, since the cause of the high frequency OOT conditions for these pressure gauges has not been identified, it could be assumed that this instrumentation could be out of tolerance in a non-conservative manner. The finding was determined to be of very low significance because the comprehensive IST performance test conducted during the 2008 refueling outage showed that the actual test results were within the acceptable band, thereby confirming that operability and functionality of the RHR pumps had not been lost. This finding has a cross-cutting aspect in the area of Human Performance, Resources because the licensee did not ensure adequate resources were available to minimize long-standing equipment issues. (H.2(a)) (Section 1R21.3.b.4)

Other:

• Severity Level IV. The inspectors identified a Severity Level IV NCV, having very low safety significance, of 10 CFR 50.59, AChanges, Tests, and Experiments@, for the licensee=s failure to provide documented basis for determining that changes to procedures did not require prior NRC approval. Specifically, the licensee incorrectly concluded that a 10 CFR 50.59 screening was not required when procedures were revised to eliminate the practice of back-seating normally open gate/globe valves even though the UFSAR stated that normally open gate/globe valves in the Safety Injection (SI) system are back-seated to limit valve stem leakage.

The finding was determined to be more than minor because the team could not reasonably determine that the change to the plant procedure which had removed a barrier to release radioactivity into the PAB would not have ultimately required NRC prior approval. The finding was determined to be of very low safety significance because it only represented a degradation of the radiological barrier function provided for the auxiliary building. This finding has a cross-cutting aspect in the area of Human Performance, Decision Making, because during performance of the 10 CFR 50.59 applicability determination for a procedural change, in March 2008, the licensee made an inappropriate decision by failing to require a screen or full 50.59 evaluation. (H.1.(a)).

(Section 1R21.3.b.5)

Licensee-Identified Violations

None

REPORT DETAILS

1R21 Component Design Bases Inspection

.1 Introduction

The objective of the component design bases inspection is to verify that design bases have 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 Risk Assessment (PRA) model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectible area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance. Specific documents reviewed during the inspection are listed in the Attachment to this report.

.2 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the licensee=s PRA and the Point Beach Nuclear Plant, Standardized Plant Analysis Risk (SPAR) Model, Revision 3P. In general, the selection was based upon the components and operator actions having a risk achievement worth of greater than 1.3 and/or a risk reduction worth greater than 1.005. The operator actions selected for review included actions taken by operators both inside and outside of the control room during postulated accident scenarios. In addition, the team selected operating experience issues associated with the selected components. 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 reductions caused by design modification, or power uprates, or reductions due to degraded material condition. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as performance test results, significant corrective action, repeated maintenance activities, maintenance rule (a)(1)status, components requiring an operability evaluation, NRC resident inspector input of problem areas/equipment, and system health reports. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report. This inspection constitutes 27 samples as defined in Inspection Procedure 71111.21-04.

.3 Component Design

a. Inspection Scope

The team reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), design basis documents, drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The team used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Code, Institute of Electrical and Electronics Engineers (IEEE) Standards and the National Electric Code, to evaluate acceptability of the systems= design. The NRC also evaluated licensee actions, if any, taken in response to NRC issued operating experience, such as Bulletins, Generic Letters (GLs) Regulatory Issue Summaries (RISs), and Information Notices (INs). The review was to verify that the selected components would function as designed when required and support proper operation of the associated systems. The attributes that were needed for a component to perform its required function included process medium, energy sources, control systems, operator actions, and heat removal. The attributes to verify that the component condition and tested capability was consistent with the design bases and was appropriate may include installed configuration, system operation, detailed design, system testing, equipment and environmental qualification, equipment protection, component inputs and outputs, operating experience, and component degradation. For each of the components selected, the team reviewed the maintenance history, system health reports, operating experience-related information and licensee corrective action program documents. Field walkdowns were conducted for all accessible components to assess material condition and to verify that the as-built condition was consistent with the design.

Other attributes reviewed are included as part of the scope for each individual component. The following 17 components were reviewed:

• Service Water Pump (P-32C): The team reviewed the service water (SW) system hydraulic calculations including available net positive suction head (NPSH) and required level to prevent vortex formation to verify that the pump has the capability to deliver the minimum required system flow and flow rate to each component at all modes of operation. The team reviewed the recent in-service testing (IST) and performance trend data to verify acceptable pump performance. The circulating water and service water pump house heat-up Gothic model calculation was reviewed that determined room heat-up during a loss of offsite power and operating procedures were reviewed to confirm compensatory measures during this same event. In addition the team reviewed compliance with GL 89-13, AService Water System Problems Affecting Safety Related Equipment.@ The team reviewed electrical calculations, drawings and equipment specifications to determine whether adequate voltage and current would be available at the pump motor terminals for starting and running under worst case design basis loading and grid voltage conditions. Protective relay settings, motor feeder cable ampacity and cable short circuit current capability were also reviewed as part of the electrical review to determine whether appropriate electrical protection coordination margins had been applied and whether the power supply feeder cables had been properly sized for the maximum available short circuit current capability requirements. In addition, the team reviewed a sample of system operating, abnormal operating, alarm response, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 4.16kVac Switchgear Bus (2-A05): The team reviewed selected calculations and procedures for the electrical distribution systems, including load flow/voltage drop, short-circuit and electrical protection coordination. This review was conducted to verify the adequacy and appropriateness of design assumptions, and to verify that bus capacity was not exceeded and bus voltages remained above minimum and below maximum acceptable values under design basis conditions. The team reviewed the electrical overcurrent, undervoltage, differential and ground protective relay settings for selected circuits to verify that the trip setpoints would not spuriously interfere with the equipment fulfilling its safety function, and secondarily, that adequate protection was provided. The loss of voltage and degraded voltage relay settings were also reviewed to verify that they satisfied the requirements of the Technical Specifications. Records of offsite grid and 4.16 kV bus voltage profiles were reviewed to verify that they were consistent with the design basis assumptions.

The control logic design drawings of the 4.16 kV supply breaker to bus 2A05 (2A52-76) were reviewed to verify the appropriateness of the breaker closing and opening circuits interlocks. Additionally, the 125 Vdc voltage drop calculations were reviewed to ensure that adequate voltage would be available for the breaker control circuit components as well as for the breaker opening and closing coils and spring charging motor under all design basis conditions. In addition, the team reviewed a sample of system operating, abnormal operating, alarm response, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 4.16kV/480Vac Station Service Transformer (2-X13): The team reviewed the system one-line diagram, nameplate data and design basis descriptions to verify that the loadings of the Station Service Transformer 2-X13 and associated 4.16kV breaker 2A52-75 and 480V breaker 2B5240B were within the corresponding transformer and switchgear ratings. The team reviewed design assumptions and calculations related to short circuit currents, voltage drop and protective relay settings associated with transformer 2-X13 and the feeder cables to verify that they were appropriate. The team reviewed a sample of completed maintenance and functional verification testing results to verify that the high and low voltage cable feeders associated with transformer 2-X13 were capable of supplying the power requirement of the 480V load center bus 2B03 during normal and postulated accident conditions. The team performed a sample of independent short circuit and voltage drop calculations to verify that the values stated in design basis documents were appropriate. The team reviewed health reports, maintenance test results, interviewed system engineers and conducted a field walkdown of the load center transformer 2-X13 to verify that equipment alignment and nameplate data were consistent with design drawings and to assess the material condition of 2-X13.

• 480Vac Load Center (2-B03): The team reviewed the adequacy of the 480V load center to supply the voltage and current requirements during design basis events.

The team reviewed selected calculations for electrical distribution system load flow, voltage drop and short circuit calculations to verify that the capacity of the bus and breakers is not exceeded and bus voltages remained within acceptable values under design basis conditions. The load center protective device trip settings were also reviewed to ensure that adequate breaker coordination was provided for protection of connected equipment and for guarding against spurious tripping during electrical switching transients. Completed maintenance test records and breaker trip setpoint calibration data sheets were reviewed to verify that the test results were satisfactory.

• Residual Heat Removal Pump (2P-10B): The team reviewed hydraulic calculations and other analyses to verify selected calculation inputs, assumptions, and methodologies were accurate, justified and consistently applied. Available net positive suction head was verified for consistency with design assumptions.

Vortexing calculations were reviewed to ensure adequate design/operational measures have been incorporated to prevent vortexing. The IST reference values were reviewed against the basis documents/calculations for these values. The IST results were reviewed to assess potential component degradation and impact on design margins. The pump room heat-up basis for EQ design temperature was evaluated. Pump oil sample test results were reviewed for compliance with requirements. The vendor manual requirements were reviewed for agreement with plant operating and maintenance procedures/records. The team reviewed the current system health report, history of corrective actions, trending data, applicable operating experience (OE) and any related cause evaluations for impact on design basis margin.

The team reviewed electrical calculations, drawings and equipment specifications to determine whether adequate voltage and current would be available at the pump motor terminals for starting and running under worst case design basis loading and grid voltage conditions. Protective relay settings, motor feeder cable ampacity and cable short circuit current capability were also reviewed as part of the electrical review to determine whether appropriate electrical protection coordination margins had been applied and whether the power supply feeder cables had been properly sized for the maximum available short circuit current capability requirements. In addition, the team reviewed a sample of system operating and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• Residual Heat Removal Heat Exchanger (2HX-11B): The team reviewed the RHR heat exchanger specifications and heat removal calculations to ensure that design basis heat removal requirements were met. The review included conformance to Generic Letter (GL) 89-13 thermal performance verification methodology against the plant=s commitment to clean and inspect. The team also reviewed the plant operating procedures for long term safety related cooling and normal shutdown.

• HX-11B RHR HX Outlet to P-15B Pump Suction Isolation Valve (2SI-857B): The team reviewed the motor operator calculations for this valve, including required thrust and maximum differential pressure, to ensure the valve is capable of performing its design functions under accident conditions. The IST results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The team reviewed electrical calculations, drawings and equipment specifications to determine whether adequate voltage and current would be available at the terminals of the valve actuating motor for starting and running under worst case design basis loading and grid voltage conditions and whether the power supply feeder breaker and thermal overload heaters were adequately sized for the duty requirements. In addition, the team reviewed a sample of system operating and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• Reactor Trip and Bypass Breakers (2RTA, 2RTB, 2BYA, 2BYB): The team reviewed completed maintenance, and surveillance procedures to assess whether activities performed using these procedures were consistent with the design and licensing bases requirements. The team reviewed engineering trending and operating experience activities including vendor Information and maintenance recommendation for the reactor trip breakers (RTBs) to ensure that the breakers have been tested and maintained in accordance with applicable design requirements. The team reviewed the system health report and corrective action documents to determine if potential adverse trends have been identified and corrected.

• Emergency Diesel Generator (G-02): The team reviewed jacket water cooler HX calculations that addressed required flow requirements and thermal performance as well as recent modifications that replaced the original two heat exchangers with one new HX. The review included conformance to Generic Letter (GL) 89-13 thermal performance verification methodology against the plant=s commitment to clean and inspect. The team reviewed design basis documentation, the UFSAR, TS and associated bases, and system drawings for the EDG fuel oil storage and day tank components. The team reviewed fuel availability and quantity and conformance to RG 1.137 and original licensing commitments and approvals. The team reviewed modifications that added new EDG storage tanks and two new EDGs.

The team also reviewed the EDG start logic and plant operating procedures to include fuel transfer from one tank to the other. The team reviewed drawings, design basis descriptions, vendor manuals and generic communications to identify the design and licensing basis requirements for the Emergency Diesel Generator (EDG)

G-02. The electrical drawings and calculations that describe the EDG output breaker control logic and interlocks were reviewed to determine whether the breaker opening and closing control circuits were consistent with design basis documents.

Additionally, the 125 Vdc control voltage drop calculations were reviewed to ensure that adequate voltage would be available for the EDG breaker control circuit components as well as for the breaker opening and closing coils under all design basis conditions. The team also reviewed surveillance test results to verify that applicable test acceptance criteria and test frequency requirements were satisfied.

Protective relay setpoint calculations and setpoint calibration test results were reviewed to assess the adequacy of electrical protection during testing and emergency operations and to ensure that excessive setpoint drift had not taken place. The team conducted a field walkdown of the EDG G-02 room and the electrical relay cabinets to verify that the installed configuration was consistent with system drawings and to observe the material condition. In addition, the team reviewed a sample of system operating, abnormal operating, surveillance/test, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• @B@ High Head Safety Injection Pump (2P-15B): The team reviewed the SI pump to verify its capability to meet design basis criteria with respect to pump flow and pressure. The team reviewed hydraulic calculations and other analyses to verify selected calculation inputs, assumptions, and methodologies were accurate, justified and consistently applied. (Note: review of hydraulic calculations was limited to those revised or added since the review of this pump during the 2006 CDBI). Available net positive suction head was verified for consistency with design assumptions.

Vortexing calculations were reviewed to insure adequate design/operational measures have been incorporated to prevent vortexing. The IST reference values were reviewed against the basis documents/calculations for these values. The IST results were reviewed to assess potential component degradation and impact on design margins. The pump room heat-up basis for EQ design temperature was evaluated. Pump oil sample test results were reviewed for compliance with requirements. The vendor manual requirements were reviewed for agreement with plant operating and maintenance procedures/records. The team reviewed the current system health report, history of corrective actions, trending data, applicable OE, and any related ACE=s/RCA=s for impact on design basis margin.

The team reviewed electrical calculations, drawings and equipment specifications to determine whether adequate voltage and current would be available at the pump motor terminals for starting and running under worst case design basis loading and grid voltage conditions. Protective relay settings, motor feeder cable ampacity and cable short circuit current capability were also reviewed as part of the electrical review to determine whether appropriate electrical protection coordination margins had been applied and whether the power supply feeder cables had been properly sized for the maximum available short circuit current capability requirements In addition, the team reviewed a sample of system operating and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 125 Vdc Station Battery Charger (D-07): The team reviewed electrical calculation relating to sizing and current limit setting and also reviewed a sampling of completed battery charger surveillance tests. The review was performed to ascertain the adequacy and appropriateness of design assumptions, and to verify that the charger was adequately sized to support the design basis duty cycle requirements of the 125 Vdc safety related loads and the associated battery under both normal and design basis accident conditions. The review also verified that the battery met the Technical Specification requirements. In addition, the test procedures were reviewed to determine whether maintenance and testing activities for the battery charger were in accordance with vendor=s recommendations. The team also performed a visual non-intrusive inspection of the battery chargers to assess the installation configuration, material condition, and potential vulnerability to hazards. In addition, the team reviewed a sample of system operating, abnormal operating, alarm response, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 125 Vdc Distribution Panel (D-01): The team reviewed 125 Vdc schematic and elementary diagrams, fuse and 125 Vdc molded case circuit breaker ratings, voltage drop and coordination calculations to confirm that sufficient coordination existed between various interrupting devices and sufficient power and voltage was available at the safety related equipment supplied by this bus to perform their safety function.

The team reviewed 125 Vdc short circuit calculations and verified that the interrupting ratings of the fuses and the molded case circuit breakers were well above the calculated short circuit currents. The 125 Vdc voltage calculations were reviewed to determine if adequate voltage would be available for the breaker open and close coils and spring charging motors. The team reviewed the motor control logic diagrams and the 125 Vdc voltage drop calculation to ensure adequate voltage would be available for the control circuit components under all design basis conditions. The team also reviewed the 125 Vdc short circuit and coordination calculations to assure coordination between the motor feed breaker open and close control circuit fuses and 125 Vdc supply breakers and to verify the interrupting ratings of the control circuit fuses and the 125 Vdc control power feed breaker. In addition, the team reviewed a sample of system operating, abnormal operating, alarm response, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 125 Vdc Station Battery (D-05): The team reviewed electrical calculation and analyses relating to battery sizing and capacity, hydrogen generation, station black out (SBO), and battery room transient temperature. The team also reviewed a sampling of completed weekly, quarterly, yearly, eighteen monthly surveillance tests.

Also included in the review were a sampling of completed service tests, performance discharge tests, and modified performance tests. The review was performed to ascertain the adequacy and appropriateness of design assumptions, and to verify that the battery was adequately sized to support the design basis required voltage requirements of the 125 Vdc safety related loads under both Design Basis Accident (DBA) and SBO conditions. Additionally, a review of the various discharge tests was performed to verify that the battery capacity was adequate to support the design basis duty cycle requirements and to verify that the battery capacity meets the requirements of the Technical Specification. The team performed a visual non-intrusive inspection of the battery to assess the installation configuration, material condition, and potential vulnerability to hazards. The team also witnessed a weekly surveillance test. In addition, the team reviewed a sample of system operating, abnormal operating, alarm response, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• 13.8/4.16kVac Low Voltage Station Auxiliary Transformer (2-X04): The team reviewed the design basis descriptions, equipment specifications, drawings, equipment nameplate data, voltage drop calculations and short circuit and load flow calculations to evaluate the capability of transformer 2-X04 to supply the voltage and current requirements to Unit 2 station safeguard loads. The review was also conducted to verify that the 13.8kV and 4.16kV feeder cables and breakers associated with transformer 2X-04 were adequately sized. Protective relay trip setting calculations were reviewed to verify whether adequate protection coordination margins were provided. The relay settings review included the transformer overall differentials and ground overcurrent relays. The team also reviewed the rating of the transformer neutral grounding resistor to verify that the ground relay trip settings were coordinated with the 4.16kV feeder ground relays to prevent inadvertent tripping. The team reviewed the results of completed transformer preventive maintenance and relay calibrations to verify that the test results were satisfactory. The team performed a visual inspection of the observable portions of the Low Voltage Auxiliary Transformers 1X-04 and 2X-04 and their associated neutral grounding resistor bank to assess the installation configuration and material condition. In addition, the team reviewed a sample of system operating, abnormal operating, and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• P-10B RHR Pump Sump Suction Isolation Valve (2SI-850B): The team reviewed the hydraulic operator calculations for this valve, including required thrust and maximum differential pressure, to ensure the valve is capable of performing its design functions under accident conditions. The IST results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The team reviewed electrical calculations, drawings and equipment specifications to determine whether adequate voltage and current would be available at the terminals of the valve actuating motor for starting and running under worst case design basis loading and grid voltage conditions and whether the power supply feeder breaker and thermal overload heaters were adequately sized for the duty requirements. In addition, the team reviewed a sample of system operating and emergency operating procedures to assess whether component operation and alignments were consistent with design and licensing bases assumptions.

• P-38A Minimum Recirculation Flow Control Valve (AF-4007): The team reviewed the air operated valve (AOV) calculations for AF-4007, including required thrust and maximum differential pressure, to ensure the valve was capable of functioning under design conditions. The team reviewed the sizing calculations for the nitrogen backup system receiver tanks to ensure sufficient volume and pressure of backup nitrogen existed if normal air supply was lost. Periodic Verification Diagnostic and IST results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The team also reviewed the control logic schematic diagrams, the system description, and flow control diagrams to verify the adequacy of valve control logic design and to ensure that the valve was capable of functioning under design conditions.

• P-32C discharge check valve (0SW-00032C): The team reviewed the UFSAR, TS, component and system design basis documents, drawings, and other available design basis information, to determine the performance requirements of the selected components. The review included installed configuration, system operation, detailed design, system IST testing, and operating experience.

b. Findings

(1) Equalizing Charge Voltage Not Bounded by Battery Room Hydrogen Generation Calculation

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, ADesign Control,@ was identified by the team for the failure to ensure that the design limits in electrical calculations bound values used in maintenance procedures.

Description:

During this inspection, the team identified that the licensee failed to ensure that the design limit established by a calculation bound the value used to perform a maintenance activity on a safety related component. Specifically, calculation N-93-041, Hydrogen Buildup in Battery Rooms, Revision 2, calculated hydrogen generation rate for batteries D-05, D-06, D-105, and D-106. For batteries D-105 and D-106, the calculation used the maximum equalizing voltage of 2.33 volt per cell (VPC) to determine the hydrogen generation rate. The calculation also determined the required ventilation rate to prevent hydrogen build-up in each of the battery rooms and evaluated it against the designed airflow rate to ensure that there was sufficient airflow being supplied to each of the rooms during normal ventilation system operation. Routine Maintenance Procedures RMP 9200-3 and 9200-4 for batteries D-105 and D-106 respectively indicated that these batteries were being equalized at a higher equalizing voltage of 2.38 VPC instead of 2.33 VPC as indicated in the calculation. Batteries produce hydrogen gas whenever current is flowing through them. Gases are generated primarily during battery charging; the rate of gas evolution depends on the charge voltage and the charge current that is not absorbed by the battery. The excess charge current causes electrolysis of the water in the electrolyte into hydrogen and oxygen. The worst condition for hydrogen generation exists when maximum current is forced into a fully charged battery. Charging voltages at or above equalizing charge level encourage gas evolution. In rooms containing large banks of batteries, the build-up of hydrogen to the lower explosive limit during loss of ventilation or low ventilation can be a concern for explosion and fire. As such, National Fire Protection Association (NFPA) Article 69 requires that hydrogen concentration in the battery rooms be maintained within 2% by volume whereas Occupational Safety and Health Administration (OSHA) Standard 29 CFR 1926.57 mandates a lower hydrogen concentration limit of 1 percent. Per Electrical Power Research Institute (EPRI)

Technical Report 100248, Revision 2, potential for maximum gas emission exists during equalizing charge and near end of recharge. This report further states that each

.05 V

increase in equalizing voltage will double the generation of hydrogen gas. Both batteries D-105 and D-106 are being equalized at 2.38 VPC as indicated in RMP 9200-3 and RMP 9200-4 respectively and therefore there is a concern that the hydrogen concentration in the battery rooms might exceed the 2% limit of NFPA and 1 percent limit of OSHA Standard 29. In view of the condition discussed above, the licensee took immediate steps to put a stop order on performing procedures RMP 9200-3 and RMP 9200-4 for batteries D-105 and D-106 respectively. The licensee also performed a calculation to determine the extent to which hydrogen concentration in the battery rooms was affected because the batteries were equalized at 2.38 VPC. The initial results indicated that the hydrogen concentration in the battery rooms would still be within 2 percent limit of NFPA but will exceed (1.8 percent) the OSHA limit of 1 percent. The licensee entered this finding into their corrective action program as AR 01131014 and consequently revised RMP 9200-3 and RMP 9200-4 for batteries D-105 and D-106 respectively to modify the equalizing charge voltage from 2.38 VPC to 2.33.

Analysis:

The team determined that the failure to ensure that the design limit established in a design basis calculation bounded the value used in the procedure to perform a maintenance activity on a safety related component was a performance deficiency warranting a significance evaluation. The team concluded that the finding was greater than minor in accordance with IMC 0612, APower Reactor Inspection Reports,@

Appendix B, AIssue Disposition Screening,@ issued on September 20, 2007. The finding involved the attribute of design control and affected the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined that the lack of adequate design control process resulted in increase of Hydrogen generation levels and in a reasonable doubt of operability of the 125Vdc system.

The team determined that the finding could be evaluated using the SDP in accordance with IMC 0609, ASignificance Determination Process,@ Attachment 0609.04, APhase 1 -

Initial Screening and Characterization of Findings,@ Table 4a for the Mitigating Systems Cornerstone. The finding screened as AGreen@ because it was a design deficiency that did not result in actual loss of safety function. During the inspection, the licensee evaluation determined that the effect of the higher hydrogen gas generation did not have an impact on the operability of the batteries and the ventilation system. This finding has a cross-cutting aspect in the area of Human Performance, Work Practices component because during the preparation of the calculation, there licensee failed to follow Procedures Manual FP-E-CAL-01, Revision 3, requirements to review and update the affected procedures to ensure they agree with the latest calculated values.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, ADesign Control,@ required, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis, as defined in ' 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to July 25, 2008, the licensee failed to perform an adequate design review to ensure that the design basis for the safety-related 125 Vdc batteries was correctly translated into the applicable maintenance procedures.

Specifically, the design basis calculation value of 2.33 VPC was different from the 2.38 VPC value used in the maintenance procedures for equalizing charge voltage. The licensee entered this performance deficiency into the corrective action program as AR 01131014.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 an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000266/

2008009-01;05000301/2008009-01 (DRS)).

(2) Non-Conservative Design Basis for Primary Auxiliary Building (PAB) Heat-up

Introduction:

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, ADesign Control,@ was identified by the team for the use of non-conservative field test data as a basis for the equipment design temperatures specified in the site equipment qualification (EQ) manual for the PAB.

Description:

The PAB ventilation system was classified as non-seismic, non-safety related. If available following a concurrent loss of offsite power (LOOP) and LOCA, it would be loaded onto the emergency diesel generator (EDG) bus once all safety related and other more critical demands for emergency power are met. Until this could be done, a certain amount of heat-up of the PAB will occur. Given this arrangement and noting that the EQ manual listed the entire PAB as a Amild environment@ (for which the long term normal temperature limit is 85 oF, long term design temperature is 105 oF and short term accident condition temperature limit is 130 oF), the inspection team requested the licensee to provide the basis for the current EQ design temperatures being used for the RHR/SI pump motors and SI-857 A/B valve motors. In response, the licensee stated that no formal heat-up calculation existed for the PAB. However, the team noted that the design worst case heat-up value for the PAB was based primarily on the results of a special maintenance procedure test conducted in 1988.

The results of this test were reviewed by the team and questions/concerns were raised about how conservatively the test simulated heat-up conditions in the RHR pump cubicles under an actual LOOP/LOCA scenario. For example, during the test, forced supply of chilled air to the other RHR pump cubicles and the PAB supply and exhaust fans were not turned off. In an attempt to simulate expected reduction in circulation between the test pump cubicle and common access area outside the RHR pump cubicles on loss of building ventilation, forced chilled air supply to the common area had been shut off. However, since forced chilled air supply to the other three pump cubicles was not shut off, the only major exit path for that cold air during the test was through the common area. During the test, this temperature differential would have resulted in significant heat transfer through the concrete walls and by means of natural air circulation through the pump cubicle=s 4 ft x 4 ft access opening that would have been much less during an actual event. In response to the inspection team=s questions about the test, the licensee performed a preliminary check using the NRC accepted formulas in Nuclear Management and Resource Council, Inc. (NUMARC) Report 87-00, AGuidelines and Technical Basis for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors@, Revision 1, and determined by calculation the maximum RHR pump cubicle temperature to be 143oF, compared to a maximum cubicle temperature of 94oF measured during the test. Since this was a significant difference of approximately 50 oF, the licensee then ran a GOTHIC computer code heat-up model of the PAB that was in the process of being finalized at the time of the CDBI inspection. The GOTHIC model yielded a value of 138 oF for the RHR pump cubicle. The GOTHIC model output also showed that in several other areas of the PAB containing safety related MOVs or instrumentation required to operate post-LOCA, the accident temperature would exceed the existing EQ limit of 130 oF by a significant amount. The highest calculated temperature was found to occur in the RHR pipe way (167 oF), where several MOVs were located. Although the GOTHIC results were preliminary, pending final verification of the model and formalization of the calculation, these results led the licensee to complete an operability recommendation under engineering task EC 12466. This evaluation determined that all of the safety related components in these areas would be capable of performing their safety related functions in the higher than previously expected temperature environments.

The team reviewed evaluation N-90-004, ASeismic Classification Discrepancies of Auxiliary Building Ventilation,@ completed in 1995 that showed that all safety related components in the PAB could perform their required post-LOCA functions if the ventilation system failed. Although this evaluation referred to the 1988 test as the basis for expected post accident temperatures, it used generic electrical/mechanical equipment qualification data from NUMARC 87-00 to conclude that there was margin between the expected maximum temperatures for the PAB. However, the team noted that this evaluation failed to recalculate maximum expected PAB temperatures using the methodology in NUMARC 87-00 or to consider changing the EQ manual design temperatures.

As a result of these inspection findings, CAPs 01130724, 01130726, 01130936, 01131593 and 01131989 were issued to: a) update the EQ manual; b) correct discrepancies/errors in building design drawings; c) correct errors/make enhancements to the site procedure governing work in a heat stress environment; d) make enhancements to the EOPs regarding the sequence of post accident operator actions in the PAB and restart of the building ventilation system; and e) correct statement in Probability Risk Assessment ( PRA) Notebook 6.2 regarding commitment time for completing operator actions in the PAB .

Analysis:

The team determined that the use of non-conservative test data as the basis for determining design temperatures in the PAB was contrary to the requirements of 10 CFR Part 50, Appendix B, Criterion III, and was a performance deficiency.

This finding was determined to be more than minor because it was similar to IMC 0612, Appendix E, Example 3j. The difference between the design temperature then in place for the PAB (130 oF) and that predicted by the NUMARC methodology (143 oF for the RHR pump cubicles) and those predicted by the preliminary GOTHIC results (as high as 167 oF in some pipe chases containing safety related components) was significant enough for the licensee to perform an operability review. Although, by the end of the inspection, the licensee was able to demonstrate operability, at the time of discovery the licensee determined that there was reasonable doubt on the operability of the RHR pumps, several MOVs and several instruments. In addition, if the EQ design temperatures were left uncorrected, this deficiency could lead to inadequately qualified replacement parts or inadequately designed plant modifications in the future. Therefore, this performance deficiency also impacted the Mitigation Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

The team determined the finding could be evaluated using the SDP in accordance with IMC 0609, ASignificance Determination Process,@ Attachment 0609.04, APhase 1 - Initial Screening and Characterization of Findings,@ Table 4a for the Mitigating Systems Cornerstone. The finding screened as AGreen@ because it was confirmed not to result in loss of operability or functionality. The team did not identify a cross-cutting aspect associated with this finding.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, ADesign Control,@ requires, 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 this requirement, during the CDBI conducted in July, 2008, the team determined that the licensee had failed to verify the adequacy of a design by alternative or simplified calculational methods or by suitable testing program. Specifically, the licensee had used a field test as the basis for setting the design EQ temperature for components in the PAB for which suitable qualifications testing of a prototype unit under the most adverse design conditions had not been performed, as required by Criterion III.

Because this violation was of very low safety significance and it was entered into the licensee=s corrective action program as CAP 01130726, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2008009-02; 05000301/2008009-02 (DRS)).

(3) Ability to Transfer Fuel Oil Between EDG Fuel Oil Tanks T-175A/B Not Demonstrated

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, ATest Control,@ was identified by the team related to the design basis requirement of the transfer of fuel oil between two underground storage tanks that supports EDG operation. Specifically, the licensee has not demonstrated the capability to transfer fuel between tanks T-175A and T-175B as credited in the TS Basis and UFSAR.

Description:

The team identified that the licensee had not tested, nor established periodic surveillances to demonstrate the transfer capability of diesel fuel between the two underground storage tanks. This is contrary to design basis requirements cited in FSAR Section 8.8.3 that credited transfer by either fuel transfer pump by use of manual cross-connect valves between the Train A and Train B fuel oil systems and that any of the four pumps would be capable of serving any of the four EDGs. Technical Specification Bases 3.8.3 stated that fuel oil is transferred from storage tank to day tank by either of two transfer pumps associated with each storage tank and that redundancy of pumps and piping precludes the failure of one pump. To address this concern, the licensee committed to conduct a transfer test in September 2008. The licensee informed the team that the transfer test will be preceded by a system flush.

Analysis:

The team determined that the failure to demonstrate the ability to transfer EDG fuel between the Train A and Train B fuel oil tanks was contrary to the design basis requirement as stated in Section 8.8 of the UFSAR and was a performance deficiency and a finding.

This finding was determined to be more than minor because this finding was associated with the Mitigating Systems cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability, reliability, and capability of the EDGs to respond to initiating events to prevent undesirable consequences. Specifically, failure to verify the transfer capability affected the ability to ensure emergency power availability for greater than two days. The team determined the finding could be evaluated using the SDP in accordance with IMC 0609, ASignificance Determination Process,@ Attachment 0609.04, APhase 1 - Initial Screening and Characterization of findings,@ Table 4a for the Mitigating System Cornerstone. The team determined the finding was of very low safety significance (Green), because it did not result in the loss of safety function and was not risk significant due to external events. The team did not identify a cross-cutting aspect associated with this finding because the cause of the performance deficiency occurred several years ago and was not reflective of current performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XI, ATest Control,@ requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptable limits contained in applicable design documents. Contrary to the above, as of July 25, 2008, the licensee failed to conduct tests that demonstrate the ability to transfer EDG fuel between the Train A and Train B fuel oil tanks. Because this violation was of very low safety significance and it was entered into the licensee=s corrective action program as AR- 01130360, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV05000266/2008009-03; 05000301/2008009-03 (DRS)).

(4) RHR Pump Suction Pressure Gauges Repeatedly Found To Be Out Of Tolerance

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion XII, AControl of Measuring and Test Equipment (M&TE),@

was identified by the team for the licensee=s failure to follow established M&TE procedures for correcting a long standing problem with test gauges repeatedly found out of tolerance (OOT).

Description:

The installed low range (0-60 psig) RHR pumps suction pressure gauges (1/2 PI-653 A/B) were classified non-safety related because they were valved out and vented during normal plant operation. However, because these gauges were used in performance of a safety related IST test, they were calibrated on an 18 month frequency in accordance with a safety related calibration procedure. The team noted that on numerous occasions, while performing quarterly IST testing on the RHR pumps, the licensee questioned the accuracy of the pressure gauges and found these OOT high.

American Society of Mechanical Engineers (ASME) Code allowable instrument tolerance for the quarterly IST testing is " 2 percent, or 1.2 psi for these gauges. The team noted that between Units 1 and 2, one or more of these gauges had been found to be OOT an average of 2 to 3 psi nine times within the last 24 months, with one unusually high OOT reading of 14 psi. The gauges were found to be reading high, which resulted in a conservative underestimate of pump total developed head (TDH). However, because the cause(s) for this high frequency of OOT conditions could not be explained (no cause analysis was performed), and because the licensee checked the calibration after an unexpected TDH result, it could be assumed that the gauges could also be giving erroneously low readings. For that situation the OOT condition would lead to non-conservative test results since the indicated pump TDH would be higher than the actual TDH. However, it should be noted that the comprehensive IST performance test for the RHR pumps performed during the 2008 outage confirmed both pumps were performing within acceptable range. Special high accuracy pressure gauges were temporarily installed during that test, giving assurance that test results were an accurate indication of actual pump TDH performance.

Procedure NP 8.7.1, AMeasurement and Test Equipment,@ required the licensee to assess equipment with high rates of failure or when excessive maintenance was performed. This procedure also required that for M&TE found to be out of tolerance, a Measuring and Test Equipment Evaluation Record (Form PBF-9191) shall be initiated.

Procedure NP 7.1.4, ASpecial Use Instruments,@ required the licensee to analyze the effect of error(s) on any test completed since the last calibration, including operability determinations, if necessary. Procedure NP 8.3.5, AMachinery History (Instrument and Control),@ further required the licensee to perform history reviews for these instruments when entries have been made since the last review. The licensee determined that one or more of these steps had not been performed for the CAPs documenting these repeated OOT conditions. The licensee initiated CAPs 01130431 and 01130751 to address these problems. The licensee planned to perform an analysis to determine the cause(s) of the multiple procedural failures and to determine the root cause of the multiple instrument OOT conditions.

Analysis:

The team determined that failure to correct a known trend of OOT gauges was contrary to 10 CFR Part 50, Appendix B, Criterion XII and was considered a performance deficiency. The finding was determined to be more than minor because, if left uncorrected, it could become a more significant safety concern. Specifically, since the cause of the high frequency OOT conditions for these pressure gauges has not been identified, it could be assumed that this instrumentation could be out of tolerance in a non-conservative manner. That is, it could provide a false indication of positive margin on RHR pump TDH performance that would be masking actual degradation of the pump=s ability to perform its safety related functions following a LOCA.

The team determined the finding could be evaluated using the SDP in accordance with IMC 0609, ASignificance Determination Process,@ Attachment 0609.04, APhase 1 - Initial Screening and Characterization of Findings,@ Table 4a for the Mitigation Systems Cornerstone. The finding screened as very low safety significance (Green) because the comprehensive IST performance test conducted during the 2008 refueling outage showed that the actual TDH was within the acceptable band and therefore the RHR pumps remained operable.

This finding has a cross-cutting aspect in the area of Human Performance, Resources because the licensee did not ensure adequate resources were available to minimize long-standing equipment issues. Specifically, as stated in the closure of previous CAPs, the licensee did not complete the actions as directed in the M&TE program due to inadequate resources. (H.2(a))

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XII, AControl of Measuring and Test Equipment,@ requires, in part, that measures be established to assure that tools, gauges, instruments, and other measuring and testing devices used in activities affecting quality are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy within necessary limits.

Contrary to the above, during the two year period prior to this inspection, the licensee failed to maintain required accuracy of test instrumentation, 1/2 PI-653A/B, on numerous occasions. Specifically, the licensee failed to ensure that gauges 1/2 PI-653A/B which had a significant history of being OOT, would be in a known state of required accuracy when used for scheduled in-service testing of safety related equipment. Because this violation was of very low safety significance and it was entered into the licensee=s corrective action program as CAPs 01130431 and 01130751, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000266/2008009-04; 05000301/2008009-04 (DRS)).

(5) Failure to Perform a 10 CFR 50.59 Evaluation for Changes Made to SI System Valve Back-Seating Procedures

Introduction:

The inspectors identified a finding and associated Severity Level IV Non-Cited Violation (NCV) of 10 CFR 50.59, AChanges, Tests, and Experiments for the licensee=s failure to provide a documented basis for determining that changes to procedures for controlling when to back-seat valves did not require prior NRC approval.

Description:

In response to the team=s request for verification that the UFSAR commitment to minimize SI system leakage by back-seating normally open gate/globe valves was being met, the licensee reviewed the governing procedure for general valve manipulation number OM 3.20, AMOV/AOV/Manual Valve Operating Requirements@,

Revision 10. The team identified that this procedure had been revised in March, 2008 to direct operators to ensure 1/4 turn off the back-seat when placing manual gate or globe valves in the open position. The team noted that this practice was in direct conflict with Section 6.2.2 of the UFSAR. Further investigation identified that valve back-seating practices at Point Beach Nuclear Plant (PBNP) were first changed as a result of the response to IN 87-040, which primarily dealt with valve stem failures in motor operated valves (MOVs) due to over-stress conditions caused by excessive force being applied by the motor operators during remote manual back-seating operations. The change to eliminate back-seating, as first recommended in memo NEPB-87-1160, was initially implemented in Operations Standing Order PBNP 4.12.14, Revision 7, dated March 9, 1990. The licensee was unable to demonstrate that a 50.59 safety evaluation had been performed.

The team determined that when the standing order was converted to Procedure OM 3.20 in September, 1993, the change documentation indicated that a 50.59 screening was not required, with no reason given. The licensee noted that in lieu of back-seating, the Leakage Reduction and Preventive Maintenance Program (LRPM) was relied upon to minimize leakage and offsite dose via this pathway. Furthermore, as stated in DBD-10 AResidual Heat Removal System Design Basis Document@, Revision 7, the Containment Leakage Rate Testing (CLRT) Program ensured that total emergency core cooling system (ECCS) leakage in portions of the system covered by the CLRT program was maintained less than 400 cc/min. The most recent CLRT measurements taken in April, 2008 documented zero atmospheric leakage from the SI valves covered by this program.

The team determined that if the UFSAR commitment in place at the time of this inspection, were applied, the post accident leakage from a typical 1.5 inch stem diameter valve would be limited to 0.025 cc/min. In that there are at most 10 manual or motor operated gate/globe valves that would be open during long term recirculation following a LOCA, under this criterion total leakage via this pathway would be limited to less than 0.25 cc/min. On this basis, the total valve stem leakage for the SI system was expected to be very small in comparison with the current accident analysis assumption that total post-LOCA SI system leakage in the PAB, would not be more than 50 gpm (assumed in the LOCA analysis to be from RHR pump seals). During the inspection, the licensee initiated AR01130282 and AR01131220 to revise the UFSAR to be in agreement with Procedure OM 3.20 and to perform a 50.59 evaluation for this change.

Analysis:

The team determined that failure to perform a 50.59 safety evaluation for a revised procedure was a performance deficiency warranting a significance evaluation.

The finding was determined to be more than minor because the team could not reasonably determine that the change made would not have ultimately required NRC prior approval.

Because violations of 10 CFR 50.59 are considered to be violations that potentially impede or impact the regulatory process, they are dispositioned using the traditional enforcement process instead of the significance determination process (SDP). However, if possible, the underlying technical issue is evaluated under the SDP to determine the severity of the violation. The team completed a significance determination of the underlying technical issue using Inspection Manual Chapter 0609.04, APhase 1 B Initial Screening and Characterization of Findings.@ Under the Containment Barrier Cornerstone Column of Table 4a, the team determined this finding only represented a degradation of the radiological barrier function provided for the auxiliary building.

Therefore, the finding screened as having very low safety significance.

This finding has a cross-cutting aspect in the area of Human Performance, Decision Making, because in March, 2008, the licensee made an inappropriate decision not to require a screen or full 10 CFR 50.59 evaluation for a change made in the valve manipulation procedures. In addition, the team noted that the same inappropriate decision had been made in the past, on at least two separate occasions, for changes to this specific aspect of the plant procedure. (H.1.(a))

Enforcement:

Title 10 CFR 50.59(d)(1) states, in part, that the licensee shall maintain records of changes in the facility, of changes in procedures, and of tests and experiments as described in the UFSAR. These records must include a written evaluation which provides a basis for the determination that the change, test, or experiment does not require a license amendment.

Contrary to the above, on March 13, 2008, the licensee made changes pursuant to 10 CFR 50.59(c) to the plant procedures as described in the UFSAR and had not performed a written evaluation to provide the bases for determining that the changes did not require a license amendment. Specifically, via Revision 10 to Procedure OM 3.20 the licensee gave directions to Operations personnel to position normally open gate/globe valves 3 turn off the back-seat, in direct conflict with Section 6.2.2 of the UFSAR, which stated that normally open SI system gate/globe valves not used for control function were to be fully back-seated. Once identified, the licensee initiated corrective actions by placing the issue into their corrective action program. Because this violation was of very low safety significance and it was entered into the licensee=s corrective action program (AR01130282 and AR01131220), and was not repetitive, this Severity Level IV violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000266/2008009-05; 05000301/2008009-05 (DRS)).

(6) Concerns with Analysis Supporting the EDG Tank Fuel Volume of 11,000 Gallons

Introduction:

The team identified an unresolved item relating to the licensee=s analysis to support the minimum fuel oil for the EDGs. Specifically, the analysis considered only one EDG running; however, it is possible that two EDGs could be operating

Description:

The team reviewed calculation N-94-142, Revision 4, entitled AEmergency Diesel Generator, Gas Turbine, and Fire Pump Diesel Engine Fuel Oil Systems.@ The team identified that the calculation did not consider the most limiting condition of operation when it concluded that 11,000 gallon quantity of fuel was necessary for one EDG operation for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> at rated load. The team noted that the calculation used design inputs of fuel consumption for only one EDG running which is contrary to the plant=s design operational logic for a loss of offsite power that requires all EDGs to start and run. The two Train A EDGs are G-01 and G-02 and are normally aligned as standby emergency power: G-01 to the Unit 1 Train A bus (1A-05) and G-02 to the Unit 2 Train A bus (2A-05). Both G-01 and G-02 draw fuel oil from tank T-175A. Therefore, on a loss of offsite power, both of these EDGs will draw fuel from tank T-175A. The team determined that this more limiting scenario was not used to determine the LCO acceptance criteria. Subsequent to a loss of offsite power, both EDGs will continue to run until offsite power is restored and/or conditions permit securing an EDG train with no load demand. AR 01132085 was initiated to address this issue.

This issue is unresolved pending further NRC review of the licensing basis for the 11,000 gallon limiting condition for operation. Specifically, the team was concerned that the analysis for the limiting condition for operation as defined in TS 3.8.3 was not the limiting condition. (URI 05000266/2008009-06; 05000301/ 2008009-06 (DRS)).

(7) Technical Specification Bases and the Design Basis Were Not Consistent with the Technical Specification Regarding EDG Onsite Fuel Oil Storage

Introduction:

The team identified an unresolved item related to the onsite availability of EDG fuel oil. Specifically, the Technical Specification LCO was not consistent with the Technical Specification Bases and the UFSAR with regard to the EDG onsite fuel oil storage requirement.

Description:

The team determined that the current UFSAR, previous TS Bases, and TS LCO for EDG fuel storage volume were not consistent, Specifically, Technical Specification 3.8.3 LCO stated that a minimum fuel inventory of 11,000 gallons was required. However, UFSAR Section 8.8 stated that sufficient fuel is normally maintained between the two underground fuel oil storage tanks to allow one EDG to operate continuously at the required load for 7 days. In addition, the team noted that operators would not declare the EDGs inoperable unless the fuel oil level was below 11,000 gallons. The team questioned whether the minimum required fuel should be 11,000 gallons or a value representing 7 days of operations as described in previous TS Bases and UFSAR. The licensee initiated ARs 01131288 and 01131143 were initiated to address this issue.

This issue is unresolved pending further NRC review of the licensing basis for the EDG fuel storage volume and to determine NRC courses of action for resolution of this issue.

(URI 05000266/2008009-07; 05000301/2008009-07 (DRS)).

.4 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues to ensure that NRC generic concerns had been adequately evaluated and addressed by the licensee. The operating experience issues listed below were reviewed as part of this inspection:

• IN 2002-012, ASubmerged Safety-Related Electrical Cables@;

• GL 2007-01, AInaccessible or Underground Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients@;

• IN 2005-21, APlant Trip and Loss of Preferred AC Power From Inadequate Switchyard Maintenance@;

• IN 2007-11, ARecent operator Performance Issues at Nuclear Power Plants@;

• IN 2006-29, AMOV Failure Due to Stem Wear@; and

• IN 2008-02, AFindings Identified During Component Design Bases Inspections@.

b. Findings

No findings of significance were identified

.5 Modifications

a. Inspection Scope

The team reviewed four permanent plant modifications related to selected risk significant components to verify that the design bases, licensing bases, and performance capability of the components had not been degraded through modifications. The modifications listed below were reviewed as part of this inspection effort:

• EC 4934, 4.16 kV 2A05 2/3 Loss of Voltage Logic;

• EC 1466, Aux Feed Min Flow Recirc. Office;

• MOD MR 05-006, G-01 and G-02 Emergency Diesel Generator Heat Exchanger; and

• MOD MR 02-039 Aux. Feedwater Pump P-38A/B Recirculation Line Orifice.

b. Findings

No findings of significance were identified

.6 Risk Significant Operator Actions

a. Inspection Scope

The team performed a margin assessment and detailed review of four risk significant, time critical operator actions. These actions were selected from the licensee=s PRA rankings of human action importance based on risk achievement worth values. 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 results. For the selected operator actions, the team performed a detailed review and walk through of the associated procedures, including observing the simulated performance of the actions in the plant with an appropriate plant operator to assess operator knowledge level, adequacy of procedures, and availability of special equipment where required.

The following four operator actions were reviewed:

• Gagging of Auxiliary Feed Pump Minimum Flow valves, and manual control of MDAFW Discharge Pressure Control Valves, in response to a prolonged (> 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />)loss of Instrument Air System pressure;

• Restore a Battery Charger to service following recovery of AC power;

• Restore an Instrument or Service Air Compressor to service following a complete loss of plant air system pressure; and

• Locally start an Emergency Diesel Generator.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of items Entered Into the Corrective Action Program

a. Inspection Scope

The team reviewed a sample of the selected component problems that were identified by the licensee and entered into the corrective action program. The team 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, corrective action documents written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the corrective action program. The specific corrective action documents that were sampled and reviewed by the team are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 25, 2008, the team presented the inspection results to Mr. L. Meyer, and other members of the licensee staff. The licensee acknowledged the issues presented. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

J. Bjorseth, General Plant Manager

F. Flentje, Regulatory Affairs Manager

C. Hill, System Engineering Manager

K. Locke, Licensing Engineer

D. Lowens, Nuclear Oversight Manager

M. Millen, Manager Work Control Center

L. Meyer, Site Vice President

L. Peterson, Design Engineer Manager

S. Pfaff, Interim Performance Improvement Manager

T. Staskal, Licensing Engineer

D. Tomaszewski, Engineering Director

B. VanderVelde, Maintenance Manager

Nuclear Regulatory Commission

A. M. Stone, Chief, Engineering Branch 2

R. Krsek, Senior Resident Inspector

M. LeMay, Observer

LIST OF ITEMS

Opened and Closed

05000266/2008009-01; NCV Equalizing Charge Voltage Not Bounded by Battery

05000301/2008009-01 Room Hydrogen Generation Calculation (Section 1R21.3.b.1).

05000266/2008009-02; NCV Non-Conservative Design Basis for Primary Auxiliary

05000301/2008009-02 Building Heat-up (Section 1R21.3.b.2).

05000266/2008009-03; NCV Ability to Transfer Fuel Oil between EDG Fuel Oil Tanks

05000301/2008009-03 T-175A/B has not been demonstrated by Testing (Section 1R21.3.b.3).

05000266/2008009-04; NCV RHR Pump Suction Pressure Gages Repeatedly Found

05000301/2008009-04 To Be Out Of Tolerance (Section 1R21.3.b.4).

05000266/2008009-05; NCV Failure to Perform a 10 CFR 50.59 Evaluation for

05000301/2008009-05 Changes to SI System Valve Back-Seating Procedures (Section 1R21.3.b.5)

Attachment

Opened

05000266/2008009-06; URI Concerns with Analysis Supporting the EDG Tank Fuel

05000301/2008009-06 Volume of 11,000 Gallons (Section 1R21.3.b.3).

05000266/2008009-07; URI Technical Specification Bases and the Design Bases are

05000301/2008009-07 not Consistent with the Technical Specification Regarding EDG Onsite Fuel Oil Storage (Section 1R21.3.b.7).

Attachment