IR 05000282/2010006

IR 05000282-10-006 & 05000306-10-006 on 06/28/2010 - 08/30/2010, Northern States Power Company, Prairie Island Nuclear Generating Plant, Units 1 and 2, Component Design Bases Inspection

ML102870281
Person / Time
Site:	Prairie Island
Issue date:	10/13/2010
From:	Ann Marie Stone NRC/RGN-III/DRS/EB2
To:	Schimmel M Northern States Power Co
References
IR-10-006
Download: ML102870281 (43)

Text

ober 13, 2010

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2 COMPONENT DESIGN BASES INSPECTION (CDBI)

05000282/2010-006(DRS); 05000306/2010-006(DRS)

Dear Mr. Schimmel:

On August 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed a component design bases inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on July 30, 2010, with you and on August 30, 2010, with Mr. Kevin Ryan 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, five NRC-identified findings of very low safety significance were identified. The findings involved violations 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 (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any 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 Prairie Island Nuclear Generating Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant. In accordance with 10 CFR 2.390 of the NRC's "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 System (PARS)

component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website 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. 50-282; 50-306 License Nos. DPR-42; DPR-60

Enclosure:

Inspection Report 05000282/2010006; 05000306/2010006 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306 License Nos: DPR-42; DPR-60 Report No: 05000282/2010-006(DRS); 05000306/2010-006(DRS)

Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: June 28 through August 30, 2010 Inspectors: A. Dahbur, Senior Reactor Inspector, Lead C. Brown, Reactor Engineer, Operations M. Munir, Reactor Engineer, Electrical D. Szwarc, Reactor Engineer, Mechanical J. Chiloyan, Electrical Contractor B. Sherbin, Mechanical Contractor Observer: D. Betancourt, Reactor Engineer Approved by: Ann Marie Stone, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000282/2010-006(DRS); 05000306/2010-006(DRS); 06/28/2010 -

08/30/2010; Prairie Island Nuclear Generating Plan, Units 1 and 2; Component Design Bases Inspection (CDBI)

The inspection was a 3-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 two consultants. Five Green findings were identified by the inspectors. The findings were considered Non-Cited Violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow,

Red) using Inspection Manual Chapter (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 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding having very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to ensure that the fuel oil storage capability for emergency diesel generators (EDGs) D5 and D6 maintained the minimum volume required to run under accident conditions for seven days as specified in Regulatory Guide 1.137 Fuel Oil Systems for Standby Diesel Generators. Specifically, with one tank out-of-service, as allowed per procedure, the licensee would not have enough fuel to meet the mission time for one diesel following a single failure of the opposite diesel during an accident conditions. This finding was entered into the licensees corrective action program and a Temporary Change Request was initiated by the licensee to update the procedure until all issues associated with EDGs fuel oil storage capabilities (i.e., common mode failure, single failure, etc.), are resolved.

The inspectors determined that this finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring availability of the EDG to respond to initiating events to prevent undesirable consequences. This finding was of very low safety significance (Green) because a single storage tank provided sufficient fuel for EDG operation under accident loads for a period greater than the 24-hour probabilistic risk assessment (PRA) mission time. This finding had a cross-cutting aspect in the area of Human Performance, Decision Making, because the licensee failed to thoroughly evaluate the impact of downgrading the interconnection between the tanks to non-safety-related and the scenarios and existing practices that it would affect. (IMC 0310,

Section 06.01.a.(2) H.1(b)) (Section 1R21.3.b.(1))

Green.

The inspectors identified a finding having very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, related to calculational errors found in the licensees relay setting analysis. Specifically, the protective relay setting calculation for Unit 2 4 KV safeguards switchgear failed to include the over-current relay setting calibration tolerance limits and failed to use the actual field measured value for offsite source transformer neutral grounding resistor in calculating the line to ground fault current. This finding was entered into the licensees corrective action program and a preliminary verification performed by the licensee concluded that the relay settings were still acceptable.

The inspectors determined that this finding was more than minor because it was associated with the Mitigating Systems cornerstone attribute of equipment performance and affected the cornerstone objective of ensuring availability and reliability of systems that respond to initiating events to prevent undesirable consequences. This finding was of very low safety significance (Green) because the licensee was able to demonstrate that the relay settings were still acceptable. The finding did not have a cross-cutting aspect because it was not reflective of current performance. (Section 1R21.3.b.(5))

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding having very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure to consider design basis accident temperature and voltage variations when performing an operability evaluation of safety-related equipment with very low voltage margin. Specifically, during the 2010 CDBI self-assessment, a licensees reviewer identified concerns regarding an operability evaluation that failed to consider the design basis accident temperatures and voltage. Although the licensee placed this issue in their corrective action program, the licensee failed to assess operability. After identification by the team, the licensee determined the associated equipment were operable or operable but non-conforming.

The inspectors determined that this finding was more than minor because it was associated with Barrier Integrity cornerstone attribute of design control and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. This finding was of very low safety significance (Green) because the finding was a not degradation of a boundary, was not an open pathway and did not impact the hydrogen igniters. This finding had a cross-cutting aspect in the area of problem identification and resolution in the component of self assessment because the 2010 CDBI self-assessment concerns were not evaluated and corrected. (IMC 0310, Section 06.02c.(3) P3(c))

(Section 1R21.3.b.(2))

Green.

The inspectors identified a finding having very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to have adequate calculation used to ensure reactor vessel 10 CFR Part 50, Appendix G limits are not exceeded. Specifically, the design calculation performed by Westinghouse to determine the pressurizer power operated relief valve (PORV) lift setting for low temperature overpressure protection (LTOP) analysis failed to include the correct inputs for mass addition transient, and also failed to consider the seismic and environmental terms in the instrument uncertainty calculations. The licensee subsequently entered this finding into their corrective action program and performed an operability evaluation and determined the PORVs remained operable and capable of performing their LTOP functions.

The inspectors determined that this finding was more than minor because it was associated with the Barrier Integrity cornerstone attribute of design control and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. This finding was of very low safety significance (Green) because it did not result in non-compliance with LTOP TS and the licensees operability evaluation concluded that based on the last testing of the PORV opening stroke time, the predicted peak pressure was determined to be below the adjusted Appendix G pressure limit. Therefore, the PORVs remained operable and capable of performing their LTOP functions.

The finding did not have a cross-cutting aspect because it was not reflective of current performance. (Section 1R21.3.b.(3))

Green.

The inspectors identified a finding having very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the licensees failure to ensure adequate acceptance limits were incorporated into test procedures. Specifically, the acceptance criteria for allowable pressurizer power operated relief valve (PORV) opening stroke time within the periodic test procedure was not consistent with the original design criteria for low temperature overpressure protection (LTOP) analysis. The acceptance criteria limits did not include the instrument response time. This finding was entered into the licensees corrective action program and a review of most recent tests showed the valves stroke time were acceptable and the valves were operable.

The inspectors determined that this finding was more than minor because it was associated with the Barrier Integrity cornerstone attribute of design control and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. This finding was of very low safety significance (Green) because the function of the PORV opening in the required time had always been maintained and the finding did not result in non-compliance with LTOP TS.

This finding did not have a cross-cutting aspect because it was not reflective of current performance. (Section 1R21.3.b.(4))

Licensee-Identified Violations

No violations of significance were identified.

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 inspectable 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 the report.

.2 Inspection Sample Selection Process

The inspectors selected risk significant components and operator actions for review using information contained in the licensees PRA and the Prairie Island Standardized Plant Analysis Risk (SPAR) Model, Revision 3.45. 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 inspectors selected operating experience issues associated with the selected components.

The inspectors performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design reductions caused by design 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 constituted 26 samples as defined in Inspection Procedure 71111.21-05.

.3 Component Design

a. Inspection Scope

The inspectors reviewed the Updated Safety Analysis Report (USAR), Technical Specifications (TS), design basis documents, drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The inspectors used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Code, 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 inspectors reviewed the maintenance history, system health reports, operating experience related information, vendor manuals, electrical and mechanical drawings, 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:

• Emergency Diesel Generator D5 (234-031): The inspectors reviewed selected mechanical support systems for the D5 diesel generator. These included diesel room cooling, lube oil, combustion air, and jacket water cooling (radiators). The inspectors evaluated filter replacement requirements for lube oil system. The inspectors also reviewed preventive maintenance requirements for the radiator and fans to ensure heat transfer was maintained. Maintenance history records were reviewed to ensure components were maintained. The inspectors also reviewed the D5 loading calculations including voltage, frequency and loading sequences during postulated loss of offsite power, and loss of coolant accidents to verify the capability of the EDG to perform their intended safety function.

Protective relay setpoint calculations and setpoint calibration test results were reviewed to assess the adequacy of protection during testing and emergency operations and to assure that excessive setpoint drift had not taken place. The inspectors also reviewed electrical drawings and calculations that described the generator output breaker control logic. The permissives and interlocks were reviewed to determine whether the breaker opening and closing control circuits were consistent with design basis documents. The inspectors also reviewed samples of electrical surveillance test results to verify that applicable test acceptance criteria and test frequency requirements for the EDG were satisfied.

In addition the physical and material condition of the EDG and its grounding resistor was visually inspected and corrective action documents were reviewed to verify identification of adverse trends.

• Emergency Diesel Generator D5 Fuel Oil System: The inspectors reviewed the system calculations including the storage and day tank set-points, loading and vortexing to ensure that the diesel fuel transfer pumps were capable of providing sufficient flow such that the day tanks remained filled during diesel operation.

The inspectors also reviewed calculations and drawings relating to fuel oil consumption and tanks sizing to ensure that the EDG fuel oil system was adequate to meet license and design basis requirements. The EDG fuel oil chemistry test results were reviewed to ensure the quality of the EDG fuel oil supply was being maintained and tested according to facility procedures and license requirements. The inspectors performed a review of system normal operating procedures and surveillance test procedures to ensure component operation and alignments were consistent with design licensing bases assumptions. In addition corrective action documents were reviewed to verify identification of adverse trends.

• Diesel Driven Cooling Water Pump (245-392): The inspectors reviewed the diesel driven cooling water (CL) pump to verify that the performance satisfied design basis flow rate requirements during postulated transient and accident conditions. To determine design basis performance requirements and operational limitations, the inspectors reviewed design basis documents including CL system hydraulic models, calculations, operating instructions and procedures, system drawings, surveillance tests, and modifications. Surveillance test results were reviewed to determine whether established test acceptance criteria were satisfied. The acceptance criteria were compared to design basis assumptions and requirements to verify there were adequate margins for allowable pump degradation limits, and strainer clogging. Net positive suction head (NPSH) and submergence requirements were reviewed to ensure satisfactory pump performance during transient and accident conditions. The inspectors also reviewed the diesel engine mechanical support systems including lube oil, fuel oil, and combustion air filter replacement records, fuel oil consumption calculations and fuel oil storage requirements, and engine cooling requirements.

The inspectors also reviewed seismic qualification documents for the engine fuel oil day tank, jacket water cooler, and pump mounting bolts. The inspectors reviewed factory acceptance testing for the pump/driver combination. In addition, the inspectors walked down the CL pump house area, interviewed system and design engineers, and reviewed system health reports and selected condition reports to assess the current condition of the pump and diesel engine driver.

• Charging Pump (22): The inspectors reviewed the charging pump to verify that the performance satisfied design basis flow rate requirements during postulated transients. The inspectors evaluated the recent modification number 06VC01 (EC 9451), which installed new variable frequency drive (VFD) charging pump motors. This evaluation included a review of motor ambient temperature limits, and seismic qualification of the VFD control cabinets. The inspectors reviewed factory acceptance testing for the VFD control cabinets. In addition, the inspectors walked down the charging pump rooms, interviewed system and design engineers, and reviewed system health reports and selected condition reports to assess the current condition of the pump and motor driver. The inspectors reviewed the analysis that was performed for LTOP related to the requirements for evaluating charging pump flow rate for mass injection transient into the reactor coolant system (RCS). The inspectors also reviewed the electrical schematic diagrams and evaluated the adequacy of voltage at the pump under design basis accident conditions. The inspectors verified the adequacy of the feeder circuits including the circuit breakers and its settings and cables.

• Pressurizer Power Operated Relief Valve (PORV) (CV 31234): The inspectors reviewed the licensees design basis analysis and testing of the PORVs for the low temperature overpressure (LTOP) mode of operation. The PORVs are required to open during mass addition and energy addition transients to protect the reactor vessel from brittle fracture while the RCS is water-solid during plant heat-up and cool-down. The inspectors reviewed LTOP PORV setpoint analysis performed by Westinghouse, which is used as the basis for PORV opening setpoint contained in the plants Pressure and Temperature Limits Report (PTLR). The inspectors also reviewed PORV air operated valve (AOV) actuator capability calculations, seismic calculations, actuation logic testing, and PORV setpoint instrument uncertainty calculations. Recent surveillance test results were reviewed to ensure the valve stroke timing limits were in accordance with LTOP analysis assumptions. The inspectors reviewed a recent modification that installed backup air bottles to increase the number of PORV actuation cycles required by LTOP analysis.

• 4.16 kV Switchgear (Bus 25): The inspectors reviewed the one-line diagrams, control schematics, and the design basis as defined in the USAR. The protective relay trip setpoints for selective loads were reviewed for design basis loading and protective relay setting requirements to evaluate the capability of the 4.16 kilovolt (kV) alternating current

(ac) bus to supply the voltage and current requirements to one train of essential safety feature loads. The inspectors reviewed the results of completed preventive maintenance and relay setpoint calibrations to verify that the test results were within their acceptable limits. The inspectors also reviewed vendor specifications, nameplate data, and calculations relating to the station auxiliary transformers and the unit auxiliary transformers to verify that the loading of the Prairie Island switchyard was adequate to provide the capacity and capability required by the 4.16 kV switchgear Bus 25. The inspectors interviewed system engineers and conducted a field walkdown of Bus 25 to verify that equipment alignment and nameplate data were consistent with design drawings, and that relay settings, relay targets, and breaker status lights were consistent with design basis records.

• Station Auxiliary Transformer (221M/XFMR): The inspectors reviewed the design basis description, equipment specifications, system one-line diagrams, voltage tap settings, nameplate data, short circuit and voltage drop calculations, and protective relay settings to determine whether the continuous and transient loadings of transformer 221M and that of the source feeder breaker

(12) were within equipment ratings. The inspectors performed independent short circuit and voltage drop calculations to verify the adequacy of the relay settings and equipment ratings. The inspectors reviewed sample of completed maintenance test records to verify that transformer 221 was capable of carrying its maximum design rating. The inspectors interviewed the system engineer and performed a visual inspection of the transformer to assess the installation configuration, material condition, and potential vulnerability to hazards.

• 480 V Switchgear (Bus 212): The inspectors reviewed the 480 V Bus 212 to ensure the bus was capable to perform its intended safety function under design basis conditions. The inspectors reviewed selected calculations for electrical distribution system load flow/voltage drop, degraded voltage protection, short-circuit, and electrical protection and coordination. This review was conducted to assess the adequacy and appropriateness of design assumptions, and to verify that the bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. In addition, the bus feeder breaker and loads feeder breakers ratings were reviewed to ensure that their ratings exceeded the protection duty requirements. Completed maintenance test records were reviewed to ensure the breakers were maintained in accordance with industry and vendor recommendations. The inspectors performed a walkdown of portions of the Bus 212 to assess the installation configuration, material condition, and potential vulnerability to hazards.

• Motor Control Center (MCC 2K1): The inspectors reviewed the 480 V Motor Control Center MCC 2K1 design basis descriptions, equipment specifications, vendor manuals, selected calculations for electrical distribution system load flow/voltage drop, degraded voltage protection, and short circuit studies. The review was conducted to assess the adequacy and appropriateness of design assumptions and that the bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. The inspectors also reviewed the adequacy of the molded case circuit breaker periodic testing program including the molded case circuit breaker replacement program. Completed maintenance test records were reviewed to ensure that MCC 2K1 contactors, and breakers were maintained in accordance with industry and vendor recommendations. In addition, the inspectors performed a walkdown of portions of MCC 2K1 to assess the installation configuration, material condition, and potential vulnerability to hazards.

• Unit 2 Refueling Water Storage Tank (RWST) and Instrumentation (253-081):

The inspectors reviewed calculations and drawings associated with the RWST, its level instruments, and its level alarms. The inspectors reviewed the set points for instrumentation as well as instrument uncertainties. The inspectors performed a field walkdown of the accessible portions of the RWST and evaluated the design of the tank against a seismic rupture. The inspectors reviewed the design basis documentation, USAR, and TS to ensure that design and licensing bases were met.

• RWST to Charging Pump Suction Motor Operated Valve (MV-32062): The inspectors reviewed motor-operated valve (MOV) calculations and analysis to ensure the valve was capable of functioning under design conditions. The inspectors reviewed the thrust, torque, differential pressure, and valve set-up calculations and weak link analyses. The inspectors conducted a field walkdown of the valve to verify the installed configuration, accessibility to operators for manual operation, ambient environmental conditions, and the material condition of the valve. The inspectors reviewed surveillance test results to determine whether testing, inspection, and maintenance were being performed in accordance with requirements. The inspectors also reviewed the electrical schematic diagrams and the degraded voltage calculations for both the power and control circuits of the MOV. The inspectors also verified the adequacy of the feeder circuits including the circuit breakers and its settings, the power cables, and the thermal overload relays.

• RHR Heat Exchanger Component Cooling Intake Motor Operated Valve (MV-32128): The inspectors reviewed MOV calculations and analysis to ensure the valve was capable of functioning under design conditions. The inspectors reviewed the thrust, torque, differential pressure, and valve set-up calculations and weak link analyses. The inspectors conducted a field walkdown of the valve to verify the installed configuration, accessibility to operators for manual operation, ambient environmental conditions, and the material condition of the valve. The inspectors reviewed in-service testing surveillance results to verify acceptance criteria were met.

• Component Cooling Heat Exchanger Cooling Water Inlet Motor Operated Valve (MV-32161): The inspectors reviewed MOV calculations and analysis to ensure the valve was capable of functioning under design conditions. The inspectors reviewed the thrust, torque, differential pressure, and valve set-up calculations and weak link analyses. The inspectors conducted a field walkdown of the valve to verify the installed configuration, accessibility to operators for manual operation, ambient environmental conditions, and the material condition of the valve. The inspectors reviewed surveillance test results to determine whether testing, inspection, and maintenance were being performed in accordance with requirements. The inspectors also reviewed the electrical schematic diagrams and the degraded voltage calculations for both the power and control circuits of the MOV. The inspectors also verified the adequacy of the feeder circuits including the circuit breakers and its settings, the power cables, and the thermal overload relays.

• Unit 2 Turbine Driven Auxiliary Feedwater Pump (245-201): The inspectors reviewed the turbine driven auxiliary feedwater pump to determine its ability to meet design basis head and flow requirements for injection into the steam generators. The inspectors reviewed the pump capacity, vendor pump curves, hydraulic analyses, pump cooling, vortexing in the condensate storage tank, and net positive suction head calculations. The inspectors conducted a field walkdown of the pump to verify that the installed configuration would support the pumps design basis function during transient and postulated accident conditions.

The inspectors verified the material condition of the pump and the ambient environmental conditions in the room. The inspectors reviewed the design basis documentation, USAR, and TS to ensure that design and licensing bases were met.

• 125 Vdc Station Battery (D12): The inspectors reviewed electrical calculation and analyses relating to battery sizing and capacity, hydrogen generation, station blackout (SBO), and battery room transient temperature. The inspectors also reviewed a sampling of completed weekly, monthly, semi-annual 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 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 TS. The inspectors performed a visual non-intrusive inspection of the battery to assess the installation configuration, material condition, and potential vulnerability to hazards.

• 125 Vdc Station Battery Charger (D12): The inspectors 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 charger met the TS 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 inspectors also performed a visual non-intrusive inspection of the battery chargers to assess the installation configuration, material condition, and potential vulnerability to hazards.

• 125 Vdc Distribution Panel (D12, D271): The inspectors reviewed 125 Vdc schematic and elementary diagrams, fuse and 125 Vdc molded case circuit breaker ratings, voltage drop and coordination calculations. This review was performed to confirm:

(1) sufficient coordination existed between various interrupting devices; and

(2) sufficient power and voltage was available at the safety-related equipment supplied by this bus to perform their safety function.

The inspectors 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 inspectors 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 inspectors also reviewed the 125 Vdc short circuit and coordination calculations to:

(1) assure coordination between the motor feed breaker open and close control circuit fuses and 125 Vdc supply breakers; and

(2) verify the interrupting ratings of the control circuit fuses and the 125 Vdc control power feed breaker. The inspectors also performed a visual non-intrusive inspection of the panels to assess the installation configuration, material condition, and potential vulnerability to hazards.

b. Findings

(1) Fuel Oil Storage Design Did Not Support EDGs 7-Day Supply

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the licensees failure to ensure that the fuel oil storage capability for D5 and D6 was adequate to their design and licensing basis. Specifically, the fuel oil storage capacity of one tank, assuming one tank out-of-service from the same division as allowed per procedure and a single failure of the opposite train, did not have enough fuel oil supply for 7 days to support EDG loads under accident conditions.

Description:

The diesel fuel oil systems consisted of four storage tanks that supplied fuel oil to D5 and D6 diesels. Each diesel had two fuel storage tanks. Fuel oil transfer capability from one storage tank to another storage tank and consisted of non-safety-related piping and valves. The fuel oil transfer piping and valves were reclassified from safety-related to non-safety-related per the Q-list Validation Project, Fuel Oil (FO)

System classification Verification, and EC-13908 in September of 2008. The change was effective on October 22, 2009.

The tanks were designed to meet Regulatory Guide 1.137. Section C.1.c of regulatory guide specified two acceptable methods for calculating the fuel oil storage minimum requirement for the standby diesel generators. The two methods were:

(1) calculation based on the assumption that the diesel generator operates continuously for seven days at its rated capacity; and

(2) calculation based on the time-dependent loads of the diesel generator. For the time-dependent load method, the minimum required capacity needed to include the capacity to power the engineered safety features for seven days. Each tank has the capacity to hold 30,500 gallons of fuel. Calculation ENG-ME-066 D5/D6 Fuel Oil Storage Requirement, determined that 39,000 gallons of fuel oil were required for each diesel to operate for seven days under load accident scenarios to meet the criteria specified in regulatory guide. This translated to each diesel being required to have two tanks operable to provide the required 39,000 fuel oil supply.

While reviewing Procedure 2C38 D5/D6 Fuel Oil System, Revision 25, the inspector noted that Section 4.1 Limitation, indicated that any one of the four fuel oil storage tanks could be out of service provided that the Technical Specification (TS) minimum requirement of at least 75,000 gallons of usable fuel oil was maintained available in the remaining three tanks. The TS value of 75,000 gallons was based on fuel oil supply for 14 days in the event of an external flood event. In an external event scenario, such as a flood, the licensee did not need to consider a single failure as stated in NRC Task Interfacing Agreement (TIA) 2001-20 Design Basis Assumptions for Ability of Prairie Island, Unit 2 Emergency Diesel Generators to meet Single Failure Criteria for External Events. However, the licensee still had to meet the single failure for fuel oil storage capability for the 7-day accident load conditions, using only safety-related equipment.

The inspectors were concerned that the licensee would not meet the 7-day fuel oil requirement considering one tank out-of-service, as stated by the procedure, and a single failure on the opposite division. Specifically, the capacity of 30,500 gallons for one tank was not adequate to support the diesel operation under accident loading scenarios for 7 days without crediting the transfer scheme between the storage tanks from the opposite division. The transfer capability between the two divisions could not be credited because it required using non-safety equipment.

The inspector questioned if this condition, one tank was taken out-of-service, existed since the fuel oil transfer piping and valves were reclassified as non-safety-related on October 22, 2009. The licensee response indicated that one of the tanks associated with D6 was taken out-of-service from March 22 thru May 25, 2010. Based on this information, D6 was inoperable for that specified period of time between March 22 and May 25, 2010. (Since May 25, 2010, the Unit 2 fuel oil supply was maintained at 39,000 gallons in each pair of storage tanks as part of the corrective action for a separate issue identified in operability evaluation OPR 1233935-01.) In response to the inspectors concerns, the licensee entered this issue into their corrective action program as CAP 01242670 and took immediate actions to place a temporary change request to update the procedure by revising/deleting the language pertaining to taking one tank out of service until all issues associated with the diesels fuel oil storage tanks capability are resolved and corrected.

Analysis:

The inspectors determined that the failure to ensure adequate fuel oil storage capability for D5 and D6 to support the EDG accident loads for seven days was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of design control and adversely affected the cornerstone objective of ensuring the availability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, with one tank out-of-service and assuming a single failure on the opposite division, the diesels would not have adequate fuel to support the accident loading. Also D-5 was found inoperable from March 22 thru May 25, 2010, because of these specific conditions.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Safety Significance Process. The inspectors determined that a Phase II evaluation was required because the finding represented an actual loss of safety function of a single train, for greater than its TS allowed outage time. The inspectors performed an SDP Phase II evaluation using the pre-solved SDP worksheets for Prairie Island. The Phase II SDP worksheets indicated a potentially greater than green finding because D6 was inoperable for a period of greater than 30 days. A Region III Senior Reactor Analyst (SRA) was contacted to perform an SDP Phase III analysis.

The SRA reviewed the finding and determined that although the EDG was inoperable during this period, it remained available to start and run for a defined 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> probabilistic risk assessment mission time because a single storage tank provided sufficient fuel for several days of operation. Since the EDG remained available, there was no change in core damage frequency for internal events, and the finding was determined to be of very low safety significance (Green).

The finding had a cross-cutting aspect in the area of human performance, decision making, because the licensee failed to thoroughly evaluate the impact of reclassification of the interconnection piping and valves between the tanks. Also there were multiple missed opportunities (including the identification of the issue identified in OPR 1233935-01) where the licensee failed to thoroughly evaluate the design basis of the EDGs fuel oil storage capability. (IMC 0310, Section 06.01.a.(2) H.1(b))

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements, and the design basis are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, from October 22, 2009 through May 25, 2010, the licensee failed to ensure that applicable regulatory requirements and design basis related to EDGs D5 and D6 correctly translated into specifications, procedures, and calculations.

Specifically, the licensee failed to ensure that adequate fuel oil storage capability was available to support the operation of the EDGs under loading accident conditions for seven days. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as AR 1242670, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2010006-01; 05000306/2010006-01, Fuel Oil Storage Design Did Not Support EDGs 7-Day Supply).

(2) Failure to Evaluate the Adequacy of Voltage for Safety-Related Equipment

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the licensees failure to evaluate the effect of the design basis accident temperature and voltage variations on the minimum voltage available for low voltage margin safety-related equipment. Specifically, the licensee failed to perform an operability evaluation to evaluate these concerns when they were identified during their 2010 CDBI Focused Self Assessment (FSA).

Description:

During the 2010 self-assessment, the licensee identified a concern about an operability evaluation that failed to consider the design basis accident temperatures and voltage variations when justifying the operability of safety-related 480 V MCC starters/contactors with very low voltage margin. The licensee initiated a corrective action program CAP 01219292 as result of this self-assessment; however, the licensee failed to address these concerns and consequently the licensee failed to ensure that adequate voltage was available for the 480 V MCC contactors to pick up under design basis accident conditions.

In May 2000 the licensee performed calculation 12911.6249-E-002, MCC 120 V Control Circuit Voltage Drop Calculation, Revision 1, and determined that for four safety-related loads, the control circuit contactors did not have adequate voltage for pick up under accident conditions. In order to further evaluate these failed circuits the licensee performed another calculation 1291.6249-E-003, Evaluation of Unacceptable MCC Breakers for Calculation 1291.6249-E-001, Revision 1. The results of this calculation again indicated the four safety-related loads did not have sufficient voltage for pick up under accident conditions. Subsequently, in 2001 the licensee performed a General Condition Report (GEN) 200186598 to support the operability of these four circuits that failed the maximum acceptable voltage drop criteria of the calculation. The operability evaluation was based on test data obtained between 1996 and 2001, which demonstrated a very small margin existed for these components.

During the 2010 CDBI FSA performed by the licensee, a number of concerns were raised by the licensee reviewer regarding the operability evaluation that was performed as part of GEN2001186598. Among the concerns raised by the reviewer, the most prominent was the issue of not considering the impact of design basis accident temperatures and voltage variations on the operability of the 480 V motor control center (MCC) starters/contactors with very low voltage margin. Since these factors were not taken into account when evaluating the operability of the contactors, the reviewer questioned the viability of the evaluation. The licensee issued CAP 01219292 as result of the FSA; however, the licensee failed to address the reviewers concerns about the impact of design basis accident temperatures and voltage variations and, therefore, there was no assurance about the adequacy of voltage at the MCC for the contactors to pick up under design basis accident conditions.

Following the inspectors questions about what had been done in regard to the reviewers concerns, the licensee issued CAP 01243406 to re-evaluate the operability of the four MCC control circuits under the conditions of design basis accident temperatures and voltage variations. The licensee performed evaluation EC 16567, Evaluation of Unacceptable Breakers in 12911.6249-E-002 Using New Degraded Voltage Analysis and Higher Ambient Temperatures. The new evaluation indicated of the four circuits shown to have very low margin earlier, only one circuit did not pass the acceptance criteria for maximum acceptable voltage drop. The affected circuit was the 22 shield building ventilation recirculation fan, which was powered from MCC 2M2. The evaluation further determined in order to ensure adequate voltage for the contactor of this fan motor to pick up, the ambient temperature at MCC 2M2 had to be maintained below 114.62 degrees Fahrenheit (o F). Consequently, the licensee issued Operating Information No. 10-74 to monitor the ambient temperature in the vicinity of MCC 2M2 every six hours to make sure that it remained below 114.62 o F. The licensee also performed an operability recommendation OPR 01 for this circuit and declared the circuit as operable but non-conforming. The inspectors reviewed this operability recommendation and found it to be reasonably acceptable.

Analysis:

The inspectors determined that the failure to ensure that adequate voltage was available for the 480 V MCC contactors to pick up under design basis accident conditions was a performance deficiency. Specifically, the licensee failed to evaluate/include the affect of terms (i.e., temperature and voltage variations) in calculating the minimum voltage available at the 480 V contactors. The performance deficiency was determined to be more than minor because it was associated with the Barrier Integrity cornerstone attribute of design control and adversely affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, the operability of 22 Shield Building Recirculation Fan was in question due to the inadequacy of voltage for the 480 V MCC contactor associated with this fan motor to pick up. This fan was part of the Shield Building Ventilation system and performed an important safety function in the collection, recirculation and filtration of the fission-product leakage from the reactor containment vessel following a design basis accident.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase I -

Initial Screening and Characterization of findings, Table 4a for the Cornerstone of Containment Barrier. The inspectors answered no to the questions in Column 4 because the finding did not:

(1) represent a degradation of the radiological barrier function provided for the control room, or auxiliary building, or spent fuel pool; (2)represent a degradation of the barrier function of the control room against smoke or a toxic atmosphere;

(3) represent an actual open pathway in the physical integrity of reactor containment; and

(4) involve an actual reduction in function of hydrogen igniters in the reactor containment. Therefore, the finding screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution in the component of self assessment, because the licensee failed to take corrective actions to address issues resulted from assessments. Specifically, the licensee failed to evaluate and correct concerns identified during the 2010 self-assessment related to the minimum voltage available for 480 V MCC contactors to pick up under design basis accident conditions. (IMC 0310, Section 06.02c.(3) [P.3.(c)])

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected.

Contrary to the above, from April 25, 2010, until August 2, 2010, the licensee failed to promptly correct a condition adverse to quality. Specifically, a licensee reviewer identified concerns related to the operability of four MCC contactors, which supplied power to four safety-related components. However, the licensee failed to address the concerns such that the impact of design basis accident temperatures and voltage variations on the operability of the MCC contactors was not evaluated or corrected.

Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 01243406, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2010006-02; 05000306/2010006-02, Failure to Evaluate the Adequacy of Voltage for Safety-Related Equipment).

(3) Inadequate Analysis Used to Determine Pressurizer PORV/LTOP Setpoint

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the licensees failure to adequately analyze the pressurizer PORVs lift setting while in LTOP mode of operation. Specifically, the design calculation performed by Westinghouse to determine the PORV lift setting for LTOP analysis failed to include the correct inputs for mass addition transient, and also failed to consider the seismic and environmental terms in the instrument uncertainty calculations.

Description:

In February 1998 Westinghouse performed the Cold Overpressure Mitigating System (COMS) setpoint development report for Prairie Island Units 1 and 2, as documented in Westinghouse Report NSP-98-0120. The purpose of the report was to determine the PORV lift setting when COMS was enabled. The lift setting was determined by the reactor coolant system (RCS) pressure increase and the amount of mass injection into the RCS. The mass injection was based on the allowable number of charging/safety injection pumps that can be operable when COMS was enabled. This transient was considered more limiting than the heat input transient due to reactor coolant pump (RCP) operation, which caused RCS pressure to increase due to thermal expansion of the fluid. The proper lift setting of the PORV ensured that the reactor vessels 10 CFR Part 50, Appendix G, pressure/temperature limits were not exceeded.

The inspectors reviewed the UFSAR to determine the licensing requirements for the LTOP system. In particular, UFSAR Section 4.4.3.3 stated the LTOP setpoint was based, in part, on the maximum injection flow from the charging/safety injection pumps.

The inspectors reviewed the LTOP analysis performed by Westinghouse, and noted that the analysis value for the charging pump flow rate for the mass injection transient was 60.5 gallon-per-minute (gpm) per pump, or 181.5 gpm for all three pumps. The inspectors reviewed the charging pump variable frequency drive modification EC 9451, Variable Frequency Drives (VFDs) Charging Pump Replacement. The VFD modification estimated flows for each charging pump were as follows:

• Normal upper pump flow (1850 rpm) = 62.8 gpm

• Hi charging pump flow (1900 rpm) = 64.5 gpm

• Hi-Hi charging pump flow (1950 rpm) = 66.2 gpm The normal upper pump flow was limited by the normal pump speed setting controller.

The Hi charging pump flow was limited by the software in the VFD, the Hi-Hi flow was limited by over-speed hardware in the VFD controls. Hence, the charging pump flow limits exceeded the LTOP analysis assumed flow rate of 60.5 gpm per pump.

In addition, per Section 4.4.3.3 of the USAR, The electrical portions of the Low Temperature Overpressure Protection System have been designed to IEEE 279-1971 and seismic category I criteria with the exception of the position alarm on the enable/disable switch The inspectors reviewed the instrument uncertainty calculation contained in the Westinghouse COMS Report NSP-98-189 and determined that neither a seismic term, nor an environmental term (i.e., temperature and radiation) were included in the instrument uncertainty calculation performed as part of the analysis.

The inspectors determined that the Westinghouse analysis for determining the PORV lift setting while in LTOP mode of operation was not conservative because it did not include the maximum charging pump flow rate, nor did it account for seismic and environmental terms in the instrument uncertainty calculation.

In response to inspectors concerns, the licensee initiated CAP 01241086 and 01243381 and performed an immediate operability recommendation and evaluation (CAP 01241086, OPR-02, Revision 1 and EC 16714) to evaluate the aggregated affect of the inspectors concerns (charging pump flow and seismic uncertainty). Initially, the licensees operability recommendation evaluated the first concern related to the charging pump flow, the licensee concluded that using the actual PORV stroke time of 2 seconds determined by the last test and assuming 0.5 second for instrumentation delay. The EC evaluation 16714 concluded that 1.6 psi of margin existed to the Appendix G pressure limit for a mass injection transient with three charging pumps injecting a 66.2 gpm. The licensee revised the operability recommendation to evaluate the effect of the second inspectors concern related to seismic uncertainty effect. The operability recommendation determined that the change in instrument uncertainty due to seismic effects was an increase of 1.94 psi. Since the seismic uncertainty (1.94 psi) exceeded the margin of 1.6 psi, the licensee evaluated sources of additional margin, (i.e., the 2.5 seconds PORV stroke time in EC assumed 0.5 second for instrumentation delay), was conservative. The actual delay time was 0.2 second (transmitter response time) + 0.07 second (bounding value from reactor protection logic time response testing in SP 1008/2006) = 0.27 second. Thus, PORV stroke time was reduced from 2.5 seconds to 2.27 seconds. Using 2.27 seconds, the predicted peak pressure was calculated to be 534.2 psi which remained below the adjusted Appendix G pressure limit with seismic uncertainty included (536.7 psi). Based on this data, the licensee concluded that the amount of available margin to the Appendix G limits exceeded 1.94 psi for all other analysis of record for mass injection and heat input LTOP cases. The inspectors estimated that the instrument uncertainty due to environment affects was bounded by the seismic uncertainty, since the loss of coolant accident is not predicted to occur at the same time as a seismic event. So both seismic and environmental uncertainties would not have to be evaluated concurrently. Thus, the PORVs remained capable of performing their LTOP function.

Analysis:

The inspectors determined that the licensees failure to have adequate analysis for the pressurizer PORVs lift setting under postulated transient condition was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. Specifically, the licensee failed to use the correct values for the maximum charging pumps flow rate for mass addition and also failed to account for additional terms (i.e., seismic and environmental) in the instrument uncertainty for the pressurizer PORVs lift setting setpoint calculation. The performance deficiency was more than minor because the finding was associated with the Barrier Integrity cornerstone attribute of design control and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. The design calculation which formed the basis for the pressurizer PORV lift setting during LTOP mode of operation did not ensure that the reactor vessels 10 CFR Part 50, Appendix G, pressure/temperature limits would not be exceeded.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 2, PWR Cold Shutdown Operation: RCS Closed and SGs available for Decay Heat Removal, because the LTOP condition is only of concern during periods where the reactor is in cold shutdown. The finding screened as very low safety significance (Green) because the finding did not result in non-compliance with LTOP TS, it did not meet the criteria for requiring a Phase II or Phase III SDP analysis.

Specifically, the licensee operability evaluation concluded that based on the last testing of the PORV opening stroke time, the predicted peak pressure remained below the adjusted Appendix G pressure limit assuming a mass injection transient with three charging pumps injecting a 66.2 gpm and with seismic uncertainty included. Therefore, the PORVs remained operable and capable of performing their LTOP functions.

The inspectors determined there was no cross-cutting aspect associated with this finding because the deficiency was not reflective of licensees current performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design 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 the above, from 1998 until present, the licensee design control measures failed to verify or check the adequacy of the design basis used in calculating the pressurizer PORV lift setting during the LTOP mode of operation. Specifically, the licensee failed to ensure that Westinghouse Report NSP-98-0120 used the correct value for maximum possible charging pump flow rate and adequately calculate the instrument uncertainty. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 01241086 and 01243381, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2010006-03; 05000306/2010006-03, Inadequate Analysis Used to Determine Pressurizer PORV/ LTOP Setpoint).

(4) PORV Stroke Timing Acceptance Criteria Failed to Include Instrument Response Time

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, was identified by the inspectors for the licensees failure to include adequate acceptance limits in test procedure. Specifically, the licensee failed to incorporate the requirements and acceptance limits contained in applicable design documents related to Unit 2 pressurizer PORVs opening stroke time into test procedure. The acceptance limit of 3 seconds to stroke the valve did not account for the instrument response time.

Description:

In February 1998, Westinghouse developed the Cold Overpressure Mitigating System (COMS) setpoint development report for Prairie Island Units 1 and 2, as documented in Westinghouse letter number NSP-98-0120. The purpose of the report was to determine the PORV lift setting when in the LTOP mode of operation. One of the inputs used in the analysis was the time it took to fully stroke open the PORV. Reactor Cooling System (RCS) pressurization increases with increased valve opening time.

The inspectors reviewed surveillance test procedure SP-2291 Pressurizer PORV Cold Shutdown Stroke Time Test, Revision 11. The PORV open Limiting Stroke Time (LST)acceptance limit per the procedure was 3 seconds, which was based on the stroke time used in Westinghouse Letter NSP-98-0120. Procedure SP-2291 performed stroke timing using the control room hand switch. Actuation of the valve to perform the LTOP function occurred through the LTOP actuation circuitry, which includes time delays. It was noted by the licensee that the Unit 1 PORV LST acceptance limit per SP-1291 was 2.0 seconds, which provided sufficient margin.

Calculation ENG-ME-334,Section XI Valve Limiting Stroke Time Basis Design Basis Limiting Stroke Times, Revision 5A provided the basis for Inservice Test (IST) limiting stroke times for the pressurizer PORVs. The calculation stated that a PORV must be capable of passing full flow within 3 seconds, based on the Westinghouse Letter mentioned above. No actuation circuitry time delay was included. The inspectors were concerned that the acceptance limits specified in the test procedure were not conservative.

In response to the inspectors concern, the licensee initiated CAP 01241337 and reviewed the most recent SP-2291 tests to determine if sufficient margin existed between the actual stroke times and the limiting stroke time of 3 seconds. The results of completed test procedures indicated that the open stroke time for Unit 2 PORVs had been less than 2 seconds. The expected actuation circuitry delay would be approximately 0.5 seconds and therefore, the licensee concluded that there was sufficient margin and the PORVs remained operable. The CAP also indicated that the licensee will revise the stroke time test acceptance criteria to be consistent with the original stroke time assumed in the analysis. The inspectors reviewed the CAP and had no further concerns.

Analysis:

The inspectors determined that the licensees failure to have adequate stroke time test acceptance criteria limits in surveillance procedure SP-2291 was contrary to 10 CFR Part 50, Appendix B, Criterion XI, Test Control, and was a performance deficiency. Specifically, the licensee failed to include the instrument response time in the stroke time test acceptance criteria for the Unit 2 PORVs. The performance deficiency was determined to be more than minor because the finding was associated with the Barrier Integrity cornerstone attribute of design control and affected the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Also, the inspectors determined that if the acceptance criteria limit in the procedure was left uncorrected, the operability of the PORVs could not be assured. Specifically, the maximum stroke time allowed by the current acceptance band could result in a loss of function during a design basis accident and LTOP conditions.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, because the LTOP condition is only of concern during periods where the reactor is in cold shutdown. The finding screened as very low safety significance (Green) because the function of PORV opening stroke time while in the LTOP mode of operation had always been maintained and therefore, the finding did not result in non-compliance with LTOP TS. Specifically, the results of completed test procedures indicated that the open stroke time for Unit 2 PORVs had been less than 2 seconds and were operable.

The inspectors determined there was no cross-cutting aspect associated with this finding because the deficiency was not reflective of licensees current performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XI, Test 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, from 1998 until present, the licensee failed to incorporate adequate acceptance limits in test procedure SP-2291. Specifically, the licensee failed to include the instrument response time in the stroke time test acceptance criteria for the Unit 2 PORVs to assure that the acceptance criteria limits were bounded by the LTOP analysis. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CAP 01241337, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000282/2010006-04; 05000306/2010006-04, PORV Stroke Timing Acceptance Criteria Failed to include Instrument Response Time)

(5) Errors Found in the Electrical Relay Setting Calculation

Introduction:

A finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors for the licensees failure to have adequate protective relay setting calculation.

Specifically, the inspectors identified two calculational errors in ENG-EE-162 Unit 2-4KV Safeguards Switchgear Protective Relay Settings and Coordination, which impacted the assurance that adequate coordination existed for the available fault current when considering the lower resistor size and the allowed calibration tolerance limits.

Description:

The inspectors identified two examples of calculational errors while reviewing calculation ENG-EE-162, Unit 2-Safeguards Switchgear Protective Relay Settings and Coordination.

The first example was related to the licensees failure to ensure that the relay setting calibration tolerance limits were adequately specified in the related design calculation and test procedure. Specifically, the relay calibration procedure for the 4.16 KV Safeguards Bus 25 contained instructions that were not in support of the design calculation assumptions. The inspectors reviewed calculation ENG-EE-162 which determined the phase and the ground overcurrent relay settings for the plant Electrical 4-KV safeguard buses. This calculation determined that the relay settings should maintain a minimum of 0.3 second of coordination time margin between upstream and downstream relay trip times but did not identify the limits of acceptable relay setting calibration tolerances to assure the relay setpoint calibration test accuracy requirements met the relay coordination requirements. In addition, the relay calibration procedures for the 4.16 KV Safeguards Bus 25 contained instructions that were not consistent with the calculation assumptions. Specifically, procedure PE 0025-06C 4.16KV Bus 25 Cubicle 6 Bus 25 Feed to 211M XFMR Relay Calibration, stated, in part, that

(1) relay calibrations were to be within +/- 5 percent of desired setpoints as specified on the relay cards; and

(2) if the As Found setpoint deviation exceeded +/- 10 percent for overcurrent relays, the condition should immediately be reported to the System Engineer for evaluation. The inspectors were concerned that these non-conservative relay setting calibration acceptance criteria specified in the procedure were not consistent with the calculation assumptions; therefore; the licensee failed to ensure adequate electrical coordination existed for the 4 KV safeguard buses. The licensee subsequently entered this issue into their corrective action program as CAP 01243015, reviewed all coordination curves in the affected calculation and verified that the relay settings were still acceptable assuming the non conservative relay setting calibration tolerances.

The second error was related to the licensees failure to verify the size of the offsite source transformer neutral grounding resistor in calculating the available short circuit current for the relay settings. Specifically, ENG-EE-162 also calculated the magnitude of single line to ground fault current assuming the neutral grounding resistor size for each offsite source transformers (CT-11, CT-12, IR, 2RY) was approximately 1.6 ohms.

Contrary to this calculation assumption, the field measured value of the offsite source transformer neutral grounding resistor size ranged from 1.1 ohm to 1.8 ohm. The field measurements were obtained from procedures PE 6037, Revision 0, 34.5/4.16 KV 2RY Transformer Maintenance, PE 6035, Revision 0, 161/4.16 KV 1R Transformer Maintenance, PE 6036, Revision 0,34.5/4.16 KV 2RX Transformer Maintenance, and PE 6038, Revision 0, CT11/XFMR Periodic Maintenance.

The inspectors determined that the available ground fault current could go as high as 2300 amperes if the actual field measured ground resistor value was used. This was deemed to be a significant increase from the calculated value of 1500 amperes currently used in calculation ENG-EE-162. The inspectors were concerned that the calculation did not assure that adequate electrical coordination existed between the safety-related buses upstream and downstream protective components for the maximum available fault current. As a result of this concern, the licensee entered this issue into their corrective action program as CAP 01242997, reviewed all coordination curves in the affected calculation and verified that the ground over-current relay settings using the measured lower grounding resistor ratings were still adequate to ensure electrical coordination.

The inspectors also verified that although, the available fault current have increased, the measured value of 1.1 ohm was still enough to limit the time-current duty imposed on the grounding resistor to within its acceptable time-current rating.

Analysis:

The inspectors determined that the failure to have an adequate relay setting calculation was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. Specifically, ENG-EE-162 included calculational errors that affected the magnitude of the available short circuit current. The performance deficiency was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of design control and affected the cornerstone objective of ensuring the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the protective relay settings and coordination calculation for the 4 KV safeguard switchgears did not ensure that adequate coordination existed for the available fault current when considering the lower resistor size and the allowed calibration tolerance limits.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significant Determination Process, Attachment 0609.04, Phase I-Initial Screening and Characterization of Findings, Table 4a for the Mitigating System cornerstone. The finding screened as very low safety significance (Green) because the finding was a design deficiency confirmed not to result in loss of operability or functionality. Specifically, the licensee was able to verify that the relay setting for the 4 KV safeguard buses were acceptable.

The inspectors determined there was no cross-cutting aspect associated with this finding because the deficiency was not reflective of licensees current performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires in part, that measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, as of July 30, 2010, the licensee failed to ensure that adequate design basis values related to the protective relay settings and electrical coordination for Unit 2 - 4KV Safeguards buses were correctly translated into calculations. Specifically, calculation ENG-EE-162 failed to include the over-current relay setting calibration tolerance limits and also failed to use the actual field measured value for the offsite source transformer neutral grounding resistor in calculating the line to ground fault current. Because this violation was of very low safety significance and was entered into the licensees corrective action program as CAP 01243015 and CAP 01242997, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2010006-05; 05000306/2010006-05, Errors Found in the Electrical Relay Setting Calculation)

(6) No Full Flow Testing of PORV Air Supply Check Valves

Introduction:

The inspectors identified an unresolved issue (URI) related to full flow testing of a safety-related air supply check valve to demonstrate that it will perform satisfactorily in service. Specifically, the licensee has not performed initial or periodic flow testing of the opening function of a check valve installed as part of a backup air supply system for operating pressurizer PORVs.

Description:

The pressurizer PORVs are spring loaded closed. The PORVs were designed to fail closed upon loss of power or control air to prevent loss of RCS inventory. Air to open the valves was normally supplied by a control air source. To assure the ability of the valves to open on loss of control air, a backup air supply was provided. It consisted of a passive air accumulator for each PORV, which was supplemented by temporary compressed air bottles when the plant was in the LTOP mode of operation. In 2004, Westinghouse performed an analysis Westinghouse COMS Transient Analysis, Report. No. NSP-04-189 which determined that the PORVs would need to stroke 143 times in ten minutes in order to provide sufficient LTOP protection during mass addition transient. In 2005, the licensee installed Temporary Modification 04T175, Pressurizer PORV Air Accumulator Supplementation.

The inspectors reviewed Temporary Modification 04T175, and noted that no post modification testing of the system was performed to ensure the system would deliver the required amount of air flow rate assumed in the analysis. Calculation ENG-ME-584, Sizing of Supplemental Air Supplies for Pressurizer PORV Air Accumulators, Revision 0 determined how much air would be needed to stroke the PORVs during the LTOP licensing basis mass injection event (143 strokes in ten minutes). The calculation stated that approximately 2430 standard cubic feet per hour (scfh) of air, or about 41 standard cubic feet per minute (scfm) was needed for ten minutes. A check valve was installed in the piping system between the temporary air supply, after the air regulator, and the PORVs. The inspectors questioned if the check valve was initially tested, or periodically tested to ensure the valve would pass full design flow. The inspectors were informed that the valve was never tested to ensure it could pass full flow.

Subsequently, the licensee entered this issue into their corrective action program as CAP 01242980 to develop test criteria to full flow test the system to ensure the design flow rate assumed in the analysis would be available to the PORVs. On August 30, 2010, the licensee performed a flow testing of the LTOP temporary modification check valve per work order WO 0411821 to demonstrate that the check valve was able to open and pass flow under simulated LTOP design basis conditions. During testing, the test rig was unable to establish a differential pressure across the check valve that was high enough to demonstrate the required flow because the 3/8 to 1/4 ID tubing used in the test rig resulted in higher system resistance than the actual LTOP backup air system.

However, the licensee concluded that the flow tests demonstrated that the valve was capable of passing at least as much air as an open in-line fitting in the test rig line. The licensees conclusion was based on the check valve manufacturer data and discussion with the site check valve Program Engineer. The inspectors reviewed the test results and the licensees conclusion and determined that the licensees justification for operability was inadequate. Specifically, the licensee performed six tests/scenarios for the backup air supply system, two tests with the check valve installed, and 4 tests with the check valve removed. During all six tests, the licensee was not able to establish the design flow value of 2430 scfh required per the design calculation to support the operability of the pressurizer PORV under simulated LTOP design basis conditions.

This issue is considered unresolved pending the licensees further evaluation or retesting of the check valve to demonstrate that the valve is able to open and pass the required flow under simulated LTOP design basis conditions. (URI 05000282/2010006-06; 05000306/2010006-06, No Full Flow Testing of PORV Air Supply Check Valves).

.4 Operating Experience

a. Inspection Scope

The inspectors reviewed three 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:

• Information Notice 2006-22, New Ultra-Low-Sulfur Diesel Fuel Oil Could Adversely Impact Diesel Engine Performance;

• Information Notice 2006-26, Failure of Magnesium Rotors in Motor-Operated Valve Actuators; and

• Information Notice 2010-03, Failures of Motor-Operated Valves Due to Degraded Stem Lubricant.

b. Findings

No findings of significance were identified.

.5 Modifications

a. Inspection Scope

The inspectors reviewed two permanent plant modifications and one temporary plant modification 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:

• T-MOD 04T175, Pressurizer PORV Air Accumulator Supplementation;

• EC 9451, Variable Frequency Drives Charging Pump Replacement; and

• 94L453, New 12 SR Battery Charger.

b. Findings

No findings of significance were identified.

.6 Risk Significant Operator Actions

a. Inspection Scope

The inspectors performed a margin assessment and detailed review of six risk significant, time critical operator actions. These actions were selected from the licensees 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 USAR response times and performance times documented by job performance measures results. For the selected operator actions, the inspectors performed a detailed review and walk through of associated procedures, including observing the performance of some actions in the stations simulator and in the plant for other actions, with an appropriate plant operator to assess operator knowledge level, adequacy of procedures, and availability of special equipment where required.

The following operator actions were reviewed:

• Operator fails to perform RCS cooldown and depressurization on small LOCA;

• Operator fails to initiate high-head recirculation conditional on failure of RCS cooldown and depressurization;

• Operator fails to reestablish feedwater following a transient;

• Operator fails in use of ECA-3.1/3.2 following S/G overfill (SGTR);

• Operator fails to perform alternate methods to shutdown the reactor after an ATWS; and

• Operator fails to start the standby charging pump.

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 inspectors reviewed a sample of the selected component problems that were identified by the licensee and entered into the corrective action program. The inspectors reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions related to design issues. In addition, 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 inspectors are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

4OA6 Meeting(s)

.1 Exit Meeting Summary

The inspectors presented the inspection results to Mr. M. Schimmel and to Mr. Mr. Kevin Ryan and to other members of the licensee staff on July 30, 2010, and on August 30, 2010 respectively. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. Several documents reviewed by the inspectors were considered proprietary information and were either returned to the licensee or handled in accordance with NRC policy on proprietary information.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

M. Schimmel, Site Vice President

B. Sawatzke, Director Site Operations

K. Ryan, Plant Manager

M. Cabiro, System Engineering

J. Anderson, Regulatory Affairs Manager

J. Connors, Fleet Design Engineering

B. Horner, System Engineering

B. Johnson, Operations Shift Manager

J. Loeffler, Mechanical Design Engineering

K. Mews, Licensing Engineer

M. Mill, Maintenance Manager

S. Myers, Engineering Support Manager

S. Northard, Recovery Manager

K. Peterson, Check Valve Engineer

T. Roddey, Design Engineering Manager

M. Shirey, MOV System Engineer

S. Skoyer, Engineering Performance Manager

B. Stephens, Senior Engineer

K. Vincent, Programs Engineer

P. Zamarripa, EIC Design Supervisor

Nuclear Regulatory Commission

K. Stoedter, Senior Resident Inspector

A. Stone, Branch Chief, Division of Reactor Safety

K. OBrien, Deputy Director, Division of Reactor Safety

P. Zurawski, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000282/2010006-06; URI No Full Flow Testing of PORV Air Supply Check

05000306/2010006-06 Valves

Opened and Closed

05000282/2010006-01; NCV Fuel Oil Storage Design Did Not Support EDGs 7-Day

05000306/2010006-01 Supply

05000282/2010006-02; NCV Failure to Evaluate the Adequacy of Voltage for

05000306/2010006-02 Safety-Related Equipment

05000282/2010006-03; NCV Inadequate Analysis Used to Determine PORV/LTOP

05000306/2010006-03 Setpoint

05000282/2010006-04; NCV PORV Stroke Timing Acceptance Criteria Failed to

05000306/2010006-04 Include Instrument Response Time

05000282/2010006-05; NCV Errors Found in the Electrical Relay Setting Calculation

05000306/2010006-05

Discussed

None.

Attachment