IR 05000220/2006008

IR 05000220-06-008, 05000410-06-008, on 09/11/2006 - 10/20/2006, Nine Mile Point, Units 1 and 2, ,Component Design Bases Inspection

ML063350016
Person / Time
Site:	Nine Mile Point
Issue date:	12/01/2006
From:	Doerflein L Engineering Region 1 Branch 2
To:	O'Connor T Nine Mile Point
References
IR-06-008
Download: ML063350016 (40)

Text

ber 1, 2006

SUBJECT:

NINE MILE POINT NUCLEAR STATION - NRC COMPONENT DESIGN BASIS INSPECTION REPORT 05000220/2006008 and 05000410/2006008

Dear Mr. OConnor:

On October 20, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Nine Mile Point Nuclear Station, Units 1 and 2. The enclosed inspection report documents the results of the inspection, which were discussed on October 20, 2006, with you and other members of your staff.

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

In conducting the inspection, the team examined the adequacy of selected components and operator actions to mitigate postulated transients, initiating events, and design basis accidents.

The inspection also reviewed Constellations response to selected operating experience issues.

The inspection involved field walkdowns, examination of selected procedures, calculations and records, and interviews with station personnel.

This report documents two NRC-identified findings which were of very low safety significance (Green). The findings were determined to involve violations of NRC requirements. However, because of the very low safety significance of the findings and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest any of the NCVs in this report, 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, D.C. 20555-0001, with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspectors at the Nine Mile Point Nuclear Power Station.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Docket No. 50-220, 50-410 License No. DPR-63, NPF-69

Enclosure:

Inspection Report 05000220/2006008 and 05000410/2006008

REGION I==

Docket Nos.: 50-220, 50-410 License Nos.: DPR-63, NPF-69 Report Nos. 05000220/2006008 and 05000410/2006008 Licensee: Nine Mile Point Nuclear Station, LLC (NMPNS)

Facility: Nine Mile Point, Units 1 and 2 Location: Lake Road Oswego, NY Dates: September 9 to October 20, 2006 Inspectors: F. Arner, Senior Reactor Inspector (Team Leader)

P. Finney, Reactor Inspector J. Josey, Reactor Inspector J. Lilliendahl, Reactor Inspector H. Jones, Reactor Engineer (Trainee)

J. Tomlinson, Reactor Inspector (Trainee)

C. Baron, NRC Mechanical Contractor R. Cooney, NRC Electrical Contractor Approved by: Lawrence T. Doerflein, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000220/2006008, 05000410/2006008; 09/11/2006 - 10/20/2006; Nine Mile Point, Units 1 and 2; Component Design Bases Inspection.

The report covers the Component Design Basis Inspection conducted by a team of six NRC inspectors and two NRC contractors. Two findings of very low risk significance (Green) were identified, and considered to be non-cited violations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

Reactor Oversight Process, Revision 3, dated July 2000.

NRC-Identified and Self-Revealing Findings

.

Cornerstone: Mitigating Systems

Green.

The team identified a green, non-cited violation of 10CFR50, Appendix B,

Design Control, in that measures had not been established to verify or check the adequacy of the Unit 1 Emergency Diesel Generator (EDG) cooling water design.

Specifically, the EDG cooling water system hydraulic calculation did not account for flow resistance due to degradation of strainers or friction losses in the common return piping from the EDG 102 and 103 coolers. Additionally, the minimum acceptable pump performance allowed during testing, when combined with allowable system losses, did not ensure the design basis minimum flowrate would be provided to the EDGs under the most limiting conditions. Constellation performed an operability determination, initiated a standing order to monitor strainer differential pressure during EDG operation, and entered the strainer differential pressure and degradation of the common discharge piping issues into the corrective action program for resolution.

The finding is more than minor because it is associated with the design control attribute of the Mitigating System cornerstone and inadequate design control measures affect the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance (Green) since it did not result in a loss of safety system function. (Section 1R21-.2.1.11)

Green.

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

Criterion III, Design Control, for Constellations failure to ensure that adequate design control measures existed to verify the adequacy of the design capacity for the Unit 1 Battery 11. This resulted in non-conservative design inputs and a potential reduction in the batterys expected life. Constellation entered the concerns identified with the battery analysis of record into their corrective action program for resolution.

The finding is more than minor because it is associated with the design control attribute of the Mitigating System cornerstone and inadequate design control measures affect the objective to ensure the availability, reliability, and capability of the 125 VDC system ii

which responds to initiating events to prevent undesirable consequences. Although the errors did reduce the design margin in all event scenarios, (Loss of Coolant Accident/Loss of Offsite Power, SBO & Appendix R) the impact was greatest for the Appendix R scenario.

The finding was determined to be of very low safety significance (Green) since it did not result in a loss of safety system function. While the expected life of the battery was reduced it was still determined to be operable. With respect to Appendix R, the issue was determined to be associated with the finding category of Post-Fire Safe Shutdown with a low degradation. (Section 1R21-.2.1.22)

B. Licensee-identified Violations.

None.

iii

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R21 Component Design Bases Inspection (IP 71111.21)

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the Nine Mile Point (NMP) Probabilistic Risk Assessment (PRA)and the U.S. Nuclear Regulatory Commissions (NRC) Standardized Plant Analysis Risk (SPAR) models. Additionally, the NMP Unit 1 and Unit 2 Significance Determination Process (SDP) Phase 2 Notebooks, Revision 2, were referenced in the selection of potential components and actions for review. In general, the selection process focused on components and operator actions that had a risk achievement worth (RAW) factor greater than 2.0 or a Risk Reduction Worth (RRW) factor greater than 1.005. The components selected were located within both safety-related and non-safety related systems, and included a variety of components such as turbines, pumps, valves, generators, transformers and batteries. There were 12 mechanical and 13 electrical components selected for review, 10 from Unit 1 and 15 from Unit 2.

The team initially compiled a list of a nominal 50 components and 10 operator actions based on the risk factors previously mentioned. The team performed a margin assessment to narrow the focus of the inspection to 25 components and 6 operator actions. The teams evaluation of possible low design margin included consideration of original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition/equipment reliability issues. The assessment included items such as failed performance test results, corrective action history, repeated maintenance, maintenance rule (a)1 status, operability reviews for degraded conditions, NRC resident inspector input of equipment problems, plant personnel input of equipment issues, system health reports and industry operating experience. The margin review of operator actions included complexity of the action, time to complete action and extent of training on the action.

Consideration was also given to the uniqueness and complexity of the design and the available defense-in-depth margins. This inspection effort included walk-downs of selected components, including a review of selected simulator scenarios, interviews with operators, system engineers and design engineers, and reviews of associated design documents and calculations to assess the adequacy of the components to meet both design bases and risk informed beyond design basis requirements. A summary of the reviews performed for each component, operator action, operating experience sample, and the specific inspection findings identified are discussed in the following sections of the report. Documents reviewed for this inspection are listed in the attachment.

.2.1.1 Emergency Core Cooling System (ECCS) Suction Strainers, 2RHS*STR1A,B,C;

2CLS*STR1 and 2CSH*STR1 (Unit 2)

a. Inspection Scope

The team inspected the ECCS suction strainers to ensure the adequacy of their design and their ability to perform as required during both normal and design bases accident conditions. The team reviewed piping and instrument diagrams (P&IDs), strainer design calculations, system flow calculations and net positive suction head calculations related to the ECCS pump operation during accident conditions. The team reviewed the maintenance and functional history of the strainers and pumps by sampling corrective action reports, work orders and system health reports. The team interviewed operators and design engineers to gain an understanding of the overall reliability of the components.

b. Findings

No findings of significance were identified.

.2.1.2 Containment Vent Valve, 2CPS*AOV111 (Unit 2)

a. Inspection Scope

The team inspected valve 2CPS*AOV111 to verify the capability of the valve to perform as required during both design and beyond design bases accident conditions. The valve has an active safety function in the closed position to isolate the primary containment, and has a risk significant function in the open position to support primary containment pressure control as directed by the station Emergency Operating Procedures (EOPs).

The team reviewed piping and instrumentation diagrams, component calculations, system calculations and design specifications. The team reviewed the maintenance and functional history of the valve by sampling corrective action reports, work orders, system health reports, and inservice testing (IST) results. The team interviewed operators and the air operated valve engineer to gain an understanding of the overall reliability of the valve.

b. Findings

No findings of significance were identified.

.2.1.3 Residual Heat Removal Pump B Minimum Flow Valve, 2RHS*MOV4B, (Unit 2)

a. Inspection Scope

Valve 2RHS*MOV4B was selected as a representative sample of the residual heat removal (RHR) system minimum flow valves. The team inspected the valve to verify that it was capable of meeting its design basis requirements. The valve had active safety functions in both the open and closed positions. The team reviewed P&IDs, component calculations, system calculations and thrust calculations to verify that thrust and torque limits, and actuator settings, were correct. The team reviewed the maintenance and functional history of the valve by sampling corrective action reports, work orders, system health reports, and IST results. The team interviewed operators, the system engineer and the motor operated valve engineer to gain an understanding of the overall reliability of the valve.

b. Findings

No findings of significance were identified.

.2.1.4 High Pressure Core Spray (HPCS) Injection Valve, 2CSH*MOV107 (Unit 2)

a. Inspection Scope

The team inspected the Unit 2 High Pressure Core Spray (HPCS) Injection Valve, 2CSH*MOV107 to verify that it was capable of meeting its design basis requirements.

This alternating current (AC) motor operated valve (MOV) had a function to automatically open to provide HPCS injection during accident events. The review included system calculations and motor operated valve calculations to verify that thrust and torque limits, and actuator settings, were correct. Inservice testing results were reviewed to verify that the stroke time acceptance criteria were in accordance with the Updated Final Safety Analyses Report (UFSAR) and accident analysis assumptions.

Additionally, condition reports related to the valve were reviewed to ensure conditions did not exist which would invalidate previous assumptions for the capability of the valve.

The team verified the system operating conditions and terminal voltage values used in the valve analyses were bounding. The team also verified that the HPCS system was not vulnerable to water hammer transients due to opening this valve.

b. Findings

No findings of significance were identified.

.2.1.5 RCIC Turbine Steam Supply Valve, 2ICS*MOV120 (Unit 2)

a. Inspection Scope

The team inspected the Unit 2 reactor core isolation cooling (RCIC) system Turbine Steam Supply Valve to verify that it was capable of meeting its design basis requirements. This direct current (DC) valve was the RCIC turbine driver steam supply and had a function to automatically open to provide motive steam to the turbine driver associated with the RCIC pump during transient events, including station blackout. The review included system calculations and motor operated valve calculations to verify appropriate thrust and torque limits, and actuator settings. Inservice testing results were reviewed to verify that the stroke time acceptance criteria were in accordance with the Updated Final Safety Analyses Report (UFSAR) and accident analysis assumptions.

The review specifically was performed to verify the capability of the valve to perform its function under transient conditions, including station blackout (SBO) events. The team verified the system operating conditions and terminal voltage values used in the valve analyses were bounding. The team also reviewed the control logic associated with this valve to verify it would perform its design basis functions.

b. Findings

No findings of significance were identified.

.2.1.6 RCIC Turbine Driven Pump, 2ICS*P1 (Unit 2)

a. Inspection Scope

The team inspected the Unit 2 RCIC Turbine Driven Pump to verify it was capable of meeting its design basis requirement of automatically providing high pressure cooling water to the reactor vessel under transient conditions, including station blackout events.

This review included various RCIC system calculations, instrument setpoint calculations, summaries of in-service testing results, and condition reports related to the pump and turbine. The team verified the capability of the RCIC pump to provide its design flowrate to the reactor vessel. In addition, the team verified the basis for the pump inservice testing acceptance criteria, the basis of various setpoints associated with the pump and turbine, the availability of adequate net positive suction head (NPSH) during RCIC pump operation, and the control logic associated with pump operation and the transfer of the suction source from the condensate storage tank to the suppression pool. The team also observed a partial station blackout scenario in the Unit 2 simulator to gain a perspective of turbine operation given this condition.

b. Findings

No findings of significance were identified.

.2.1.7 Reactor Building Closed Loop Cooling Temperature Control Valve, TCV-70-137 (Unit 1)

a. Inspection Scope

The team inspected valve TCV-70-137 to verify it was capable of performing as required during normal and accident conditions. The team reviewed P&IDs, control system diagrams and vendor manuals. The team reviewed the maintenance and functional history of the valve by sampling corrective action reports, work orders and system health reports. The team interviewed operators and the system engineer to gain an understanding of the overall reliability of the valve.

b. Findings

No findings of significance were identified.

.2.1.8 Electromatic Relief Valve (ERV), ERV-01-102A (Unit 1)

a. Inspection Scope

Valve ERV-01-102A was selected as a representative sample of the electromatic relief valves (ERV). The valve was inspected to verify its ability to meet its design basis requirements in response to transient and accident events. The team reviewed P&IDs, component calculations and system calculations to verify calculation assumptions were accurate and justified. The team reviewed the maintenance and functional history of the valve by sampling corrective action reports and reviewing the system health report. The inspector reviewed the ERV drawing regarding pilot valve seating surface to ensure that all design requirements were met.

b. Findings

No findings of significance were identified.

.2.1.9 Emergency Condensers Division I, 11 Loop (Unit 1)

a. Inspection Scope

The Division I emergency condensers were selected as a representative sample of the emergency condenser system. The team evaluated the adequacy of the system design and ability to perform as required during transient and accident conditions, including a review of past performance of the condensers in response to historical transient events.

The team reviewed P&IDs, component calculations and system calculations. The team reviewed the maintenance and functional history of the emergency condenser by sampling corrective action reports, work orders, system health reports and operability evaluations. The team interviewed operators, design engineers and the system engineer to gain an understanding of the overall reliability of the condensers.

b. Findings

No findings of significance were identified.

.2.1.1 0 Diesel Driven Fire Pump, PMP-100-02 (Unit 1)

a. Inspection Scope

The team reviewed the design of the Unit 1 Diesel Driven Fire Pump, PMP-100-02, to verify its capability to provide backup water to the Unit 1 emergency service water (ESW) and emergency diesel generator (EDG) cooling water systems. The team also reviewed the pumps capability to provide makeup water to the reactor vessel under accident conditions. This review included various system calculations, system operating procedures, pump test procedures, summaries of pump test results, and condition reports related to the pump and diesel driver. The team also performed a walkdown of the pump and associated equipment. The team verified the capability of the pump to provide the required flow under transient and accident conditions.

b. Findings

No findings of significance were identified.

.2.1.1 1 EDG Cooling Water Pump, PMP-79-53 (Unit 1)

a. Inspection Scope

The team reviewed the design of the Unit 1 EDG 102 cooling water pump, PMP-79-53.

This pump was designed to supply water from the Unit 1 screenhouse to the EDG 102 heat exchangers, removing heat from the EDG engine during operation. The pump was designed to automatically start and run when the EDG was started. The teams review included EDG cooling water system flow calculations, system operating procedures, pump test procedures, summaries of pump test results, heat exchanger performance calculations, and condition reports related to the pump. This review was performed to verify that the pump would be capable of supplying the required cooling water flowrate to the EDG under the most limiting conditions.

b. Findings

EDG Cooling Water Capacity

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that measures had not been established to verify or check the adequacy of the EDG cooling water design. Specifically, the EDG system hydraulic calculation did not account for flow resistance due to degradation of system strainers or friction losses in the common return piping from the EDG 102 and 103 coolers. Additionally, the minimum acceptable pump performance allowed during testing, when combined with allowable system losses, did not ensure the design basis minimum flowrate would be provided to the EDGs under the most limiting conditions.

Description:

The team reviewed Unit 1 EDG cooling water Calculation S15-79-F002, Revision 3, including Dispositions 03A, 03B, and 03C. This system analysis developed a hydraulic resistance curve for the EDG cooling water system based on past test data.

This system resistance curve was used to predict the cooling water flow to the EDG heat exchangers under the most limiting conditions, including pump degradation. This analysis supported the minimum pump performance acceptance criteria included in the pump surveillance test procedure, N1-ST-Q25, Revision 09.

Based on system design, the team had two concerns with this calculation. First, the calculation did not include any additional allowance for pressure drop across the strainer installed on the discharge of the pumps. The EDG surveillance test procedure stated that the dirty strainer should be switched to the standby strainer at 10 psid, and that the EDG should be declared inoperable if the strainer pressure drop could not be maintained below 20 psid. The calculation did not appear to support these pressure drop values. In addition, the operating procedure for the EDGs did not include direction to monitor the strainer pressure drop when the system was in service.

The teams second concern was that the calculation did not include any additional allowance for the potential clogging or degradation of the common discharge piping from the EDG heat exchangers. The team noted that the quarterly pump surveillance test acceptance criteria was based on operation of only one EDG cooling water pump, and that this test may not detect degradation of the common piping. The test procedure, N1-ST-Q25, Revision 09, did include a two raw water pump operation test section. However, this test was for trending only and did not include acceptance criteria.

This two pump trending test had been added in response to previous issues with this common piping, and two sets of data had been collected in 2005 and 2006. Based on a review of available data, it appeared that the piping had become more restrictive since testing performed in the 1990's.

In response to these concerns, the Constellations design engineering personnel performed informal evaluations during the inspection. Based on the most recent two pump test data (May 2006) and an assumed 6 psid of pressure drop due to strainer clogging, the analysis indicated that the EDG cooling system would not be capable of providing the design flowrate to the EDG jacket water heat exchangers under the most limiting conditions. However, based on this recent EDG cooling water pump test results and additional margin in the EDG heat exchanger thermal performance analyses, the licensee concluded that the EDGs would still be operable with the reduced cooling water flow. The evaluation concluded that the EDGs would remain operable with up to 8 psid of pressure drop due to strainer clogging.

During the inspection, the licensee initiated condition report 2006-4599 to address the strainer differential pressure issue, and condition report 2006-4596 to address monitoring degradation of the common discharge piping from the EDG heat exchangers.

In addition, the licensee initiated Special Order N1-SO-06-08, Revision 00 on October 13, 2006. The special order included direction to monitor the strainer differential pressure hourly during EDG operation, it also included direction to switch to the standby strainer at 5 psid, and to either perform an operability evaluation or declare the EDG inoperable at 8 psid. Based on these activities, along with the cooler ultimate heat sink temperatures which existed at the time of the inspection, the team concluded that the EDGs remained operable.

Analysis:

The team determined this issue was a performance deficiency since the EDG cooling water pump surveillance test acceptance criteria when considering allowable system resistance, would not ensure that the design cooling water flowrate would be provided to the EDGs under the most limiting conditions. A reduction in raw water flowrates could challenge EDG operation depending on loading and cooling water temperature conditions due to the subsequent elevated jacket water and lube oil temperatures.

The finding is more than minor because it is associated with the design control attribute of the Mitigating System cornerstone and inadequate design control measures affect the objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

In accordance with Inspection Manual Chapter 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the team conducted a SDP Phase 1 screening and determined the finding was of very low safety significance (Green) because it did not represent an actual loss of system safety function. Based on the licensees evaluation, this deficiency would not have resulted in the EDGs becoming inoperable under the most limiting conditions.

Enforcement:

10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that design control measures provide for verifying or checking the adequacy of design.

Contrary to the above, measures had not been established to ensure that the design basis minimum cooling water flowrate would be provided to the EDGs under the most limiting conditions. Because this violation is of very low safety significance and has been entered into the licensee's corrective action program (Condition Reports 2006-4596 and 2006-4599), this violation is being treated as a non-cited violation consistent with Section VI.A of the NRC Enforcement Policy. NCV 05000220/2006008-01, Inadequate Design Control for Unit 1 EDG Raw Water Cooling System.

.2.1.1 2 Screenhouse Intake and Discharge, Gate-74-124 (Unit 1)

a. Inspection Scope

The team reviewed the design of the Unit 1 Screenhouse to verify adequate supply and discharge flowpaths for plant cooling water systems under various conditions. This review included the gates used to direct supply and discharge flow through tunnels to and from the lake. The team reviewed the design and operation of the gates used to reverse the tunnel flow in the event of ice buildup on the intake from the lake. This review included a walkdown of the screenhouse and associated equipment, review of drawings and operating procedures, and interviews with engineering and operations personnel. The team also reviewed various condition reports associated with screenhouse components.

b. Findings

No findings of significance were identified.

.2.1.1 3 DC A Battery, 2BYS-BAT1A (Unit 2)

a. Inspection Scope

Battery 2BYS-BAT1A is a non-safety related battery, but is risk significant because it provides the 125Vdc control power necessary for operation of several 115kV switches required for realignment of offsite power. In selecting this component, the team considered the potential failure of battery 2BYS-BAT1A and the resulting consequences for mitigating a loss-of-offsite-power or SBO event.

The team reviewed the battery calculations to verify that the battery sizing would satisfy the requirements of the risk significant loads and that the minimum possible voltage was taken into account. Specifically, the evaluation focused on verifying that the battery and battery chargers were adequately sized to supply the design duty cycle of the 125Vdc system for the loss-of-coolant accident/loss-of-offsite power (LOCA/LOOP) and station blackout (SBO) loading scenarios, and that adequate voltage would remain available for the individual load devices required to operate during a four-hour SBO coping duration.

In addition, a walkdown was performed to visually inspect the physical condition of the battery and battery chargers. During the walkdown, the team also visually inspected battery 2BYS-BAT1A for signs of degradation such as excessive terminal corrosion and electrolyte leaks. The battery chargers were observed to be properly aligned with acceptable indicated voltage and current.

The team reviewed battery surveillance test results to verify that applicable test acceptance criteria and test frequency requirements specified for the battery were met.

The cognizant design and system engineers were interviewed regarding design aspects and operating history for the battery.

b. Findings

No findings of significance were identified.

.2.1.1 4 Residual Heat Removal B Flow Transmitter, 2RHS*FT86B, (Unit 2)

a. Inspection Scope

The RHR pumps are protected against damage from a closed discharge valve by means of automatic minimum flow valves that open on low main line flowrates and close on high main line flowrates. Flow transmitter, FT-86B, automatically controls the operation of RHR pump B minimum flow valve based on these flow signals. Failure of the minimum flow line can result in failure of the RHR pump. The team reviewed calculations, drawings, and maintenance procedures and interviewed station personnel to determine whether the transmitter was adequately designed and maintained.

b. Findings

No findings of significance were identified.

.2.1.1 5 115 kV Switchyard Circuit Breaker, R225 (Unit 2)

a. Inspection Scope

The team selected the 115kV insulated circuit breaker R225 which is used on the 115kV side of 345kV Transformer TB2. The breaker protects offsite power line 6, which is one of the two credited independent offsite power sources for Unit 2. The team reviewed the adequacy and appropriateness of design assumptions related to breaker protection.

The team reviewed the vendor operating manual and several condition reports to determine whether any adverse conditions could affect the breaker operation under normal and transient conditions. The team also reviewed the weekly switchyard walkdown procedure.

b. Findings

No findings of significance were identified.

.2.1.1 6 Division III AC Power Stepdown Transformer, 2EJS*X2 (Unit 2)

a. Inspection Scope

2EJS*X2 is a 4160/600 volt 225 Kilovolt-Ampere (kVA) transformer fed from 2ENS*SWG102 and supplies 600 volt components of the high pressure core spray (HPCS) system. The team reviewed calculations and drawings to identify downstream equipment to determine if the size of the transformer was adequate to support the operation of the equipment. The team reviewed calculations associated with 4kV breaker coordination design to verify the adequacy of protective relay equipment. The team reviewed the basis for the tap settings and the adequacy to support selected valves within the HPCS system. Additionally, the team reviewed the normally scheduled maintenance procedure for the transformer to verify the adequacy of maintenance practices.

b. Findings

No findings of significance were identified.

.2.1.1 7 115-13.8&4kV Reserve Station Transformer, 2RTX-XSR1A (Unit 2)

a. Inspection Scope

The team reviewed the associated Auxiliary Power System Transformer Loading calculation to verify the capacity of the three winding transformer. The loading was reviewed to verify margin existed under accident conditions. The team reviewed overcurrent and differential protective relaying for the transformer to ensure that settings were appropriate. The team reviewed the design of the load tap changer including selected associated condition reports. The team also reviewed condition reports associated with the transformer to verify that the transformer remained capable of performing its function.

b. Findings

No findings of significance were identified.

.2.1.1 8 345kV-115kV A Transformer, TB1 (Unit 2)

a. Inspection Scope

The team reviewed calculations, drawings, maintenance procedures and interviewed station personnel to determine whether the transformer was adequately designed and maintained to supply power from offsite to safety related busses. This included a review of the voltage profile study and load tap changer (LTC) settings and maintenance as well as operation of the LTC in manual mode. The team also reviewed protective relay schemes to determine the adequacy of protection provided for the transformer.

b. Findings

No findings of significance were identified.

.2.1.1 9 115 kV Switchyard Switcher, 2YUC-MDS5 (Unit 2)

a. Inspection Scope

The team reviewed the operation of 115kV circuit switchers. There are three identical switchers (2YUC-MDS3, 2YUC-MDS5 and 2YUC-MDS4), which are used to connect the 115 kV incoming power to downstream transformers. The team reviewed the interlocks associated with switcher operation which prevent switching into a faulted condition. The team reviewed the elementary diagrams of the upstream 115kV disconnect switches (2YUL-MDS1, 2YUL-MDS2, 2YUC-MDS10 and 2YUC-MDS20) to assure appropriate interlocks were provided to prevent misoperation. The team verified that adequate 125Vdc control power was available to operate the switches and switchers considering worst case voltage drop and minimum required voltages provided in the vendor manual.

The 115kV Switchyard was walked down to observe the condition of the Circuit Switchers and Reserve Station Service transformers.

b. Findings

No findings of significance were identified.

.2.1.2 0 600 Volt Emergency Load Center, 2EJS*US1 (Unit 2)

a. Inspection Scope

2EJS*US1 is a 600 Volt power bus that is supplied by transformers 2EJS*X1A and X1B.

The Auxiliary Power System analysis was reviewed to determine that margin would exist under the worst case loading conditions. The team reviewed the calculations associated with determining the load center breakers closing and trip coil voltage drop. This value was compared against vendor recommendations for minimum voltage along with historical field tests which had been performed. The team also reviewed analyses to determine that acceptable voltages were available at the emergency distribution panels fed by this power board.

b. Findings

No findings of significance were identified.

.2.1.2 1 4 kV Safety Bus, 2ENS*SWG101 (Unit 2)

a. Inspection Scope

The team reviewed the arrangement of the bus and verified that it is normally fed from Reserve Station Transformer A but can be supplied from the Auxiliary Boiler Transformer by inserting a breaker into an empty cubicle under administrative controls.

The Auxiliary Electrical System Performance Calculation (ELMSAC) was reviewed to determine that all associated breakers for this bus were within their current ratings and that all breakers were within their short circuit capability. Protective relaying was reviewed to ensure bus protection was adequate and calculations were reviewed to verify the bus and feeders were coordinated. The team reviewed the calculation for Class 1E switchgear closing coil DC voltage drops against the minimum required voltage to ensure switchgear operation at postulated worst case voltage conditions.

Calculations associated with both undervoltage and degraded voltage setpoints were reviewed to ensure their adequacy. The team also reviewed the procedure for a quarterly channel test of the low pressure core spray system including operation of the breaker. The team reviewed vendor maintenance procedures to verify they addressed key operating experience issues such as lubrication practices, auxiliary switch measurements and close and trip coil voltage measurements. Additionally, the team performed a walk-down of switchgear 2ENS*SWG101 and 600 Volt load center 2EJS*US1.

b. Findings

No findings of significance were identified.

.2.1.2 2 Battery 11 (Unit 1)

a. Inspection Scope

The team reviewed the battery calculations to verify that the battery sizing would satisfy the requirements of the safety related and risk significant DC loads and that the minimum possible voltage was taken into account. Specifically, the evaluation focused on verifying that the battery and battery chargers were adequately sized to supply the design duty cycle of the 125Vdc system for the LOCA/LOOP, SBO, and Appendix R loading scenarios, and that adequate voltage would remain available for the individual load devices required to operate during the scenario durations. In addition, a walkdown was performed to visually inspect the physical condition of the battery and battery chargers. During the walkdown, the team also visually inspected Battery 11 for signs of degradation such as excessive terminal corrosion and electrolyte leaks. The battery chargers were observed to verify acceptable indicated voltage and current.

The team reviewed battery surveillance test results to verify that applicable test acceptance criteria and test frequency requirements specified in the Technical Specifications for the battery were met. The team also verified that testing was performed in accordance with applicable IEEE guidance. The cognizant design and system engineers were interviewed regarding design aspects and operating history for the battery.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion III, Design Control, in that Constellations measures for verifying the adequacy of design with respect to the Battery 11 sizing calculation were inadequate. Specifically, non-conservative design inputs were used for the safety related Battery 11 sizing calculation which reduced the battery capacity margin.

Description:

The team identified that several non-conservative assumptions in the Battery 11 sizing calculation resulted in significant reduction in the battery capacity margin. The most significant errors were: 1) modeling the Uninterruptible Power Supply (UPS) loads as constant current rather than constant power, which neglected the rising current draw to the UPS as the battery voltage decreases during the analyzed events; 2) inrush currents were not modeled for several DC motors; and 3) the Emergency Core Cooling System (ECCS) loads were assumed to sequence onto the safety buses after the battery chargers were restored during an SBO or Appendix R event, but based on plant procedures and operator training the loads would sequence on prior to the battery chargers being restored.

The result of these errors was that as the battery aged, its actual capacity would have become insufficient; and since the battery sizing calculation was the basis for the acceptance criteria of the battery service and performance tests, there would not have been indications of inadequate capacity during testing.

Preliminary evaluations performed by Constellation during the inspection revealed the need to reduce the battery aging margin to ensure capacity does not become insufficient. Reducing the aging margin requires replacing the battery earlier than previously recognized under the same design assumptions. Reducing the aging margin along with earlier replacement of the battery would provide reasonable assurance that there was sufficient capacity to show operability going forward for all the applicable events the battery is credited for. Constellation engineering personnel initiated condition report 2006-4735 during the inspection in order to address this issue.

Analysis:

The performance deficiency associated with this finding was that Constellation had failed to ensure that adequate design control measures existed to verify the adequacy of the design capacity for Battery 11. This resulted in non-conservative design inputs and a potential reduction in the batterys aging margin. The finding was greater than minor because it affected the design control attribute associated with the mitigating systems cornerstone as related to the objective of ensuring the availability, reliability, and capability of the 125Vdc system. Although the errors did significantly reduce the design margin in all event scenarios, (Loss of Coolant Accident/Loss of Offsite Power, SBO & Appendix R) the impact was greatest for the Appendix R scenario.

The team assessed this finding in accordance with NRC Manual Chapter 0609, Appendix A, Attachment 1, Significance Determination Process (SDP) for Reactor Inspection Findings for At-Power Situations, and determined that it was of very low safety significance (Green) since it did not result in a loss of any safety system function.

Specifically, while the life of the battery was reduced it was still found to be currently operable. Additionally due to the impact on the Appendix R analysis, the issue was evaluated in accordance with NRC Manual Chapter 0609, Appendix F, Fire SDP. The finding was determined to be of very low safety significance (Green) because it was associated with the finding category of Post-Fire Safe Shutdown with a low degradation rating.

Enforcement:

10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part, that design control measures provide for verifying or checking the adequacy of design.

Contrary to the above, design control measures had been inadequate and had not prevented non-conservative assumptions from being used for the Battery 11 sizing calculation. Because the finding was of very low safety significance and has been entered into Constellations corrective action program (CR 2006-4735), this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A of the NRC Enforcement Policy. NCV 05000220/2006008-02, Non-Conservative Assumptions in Safety Related Battery Sizing Calculation Adequacy of Probabilistic Risk Assessment (PRA) Assumptions Regarding SBO Coping Timeframe The team identified an issue with an assumption relative to the capability of Battery 11, in the Nine Mile Point Unit 1 PRA regarding the ability to cope with an SBO from 4 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Although the Unit 1 licensing basis commitment to the SBO rule is a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping time, the PRA analysis assigns a 96% probability that load shedding actions will be performed within 15 minutes, which will allow sufficient battery capacity for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

The team determined that assigning a high probability of shedding (de-energizing) loads within 15 minutes was questionable for three reasons. First, the Unit 1 SBO procedure, N1-SOP-33A.2, Station Blackout, outlines the time requirements for shedding most of the loads as within 30 minutes and the rest of the loads within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Secondly, the SBO procedure directs the load shedding after several other significant actions such as activating the emergency plan, concurrently performing the emergency operating procedures, and opening all instrument cabinet doors in the control room. Constellation had previously identified that once the action is targeted for completion, the load shedding would take approximately 12 minutes to complete, so the preceding steps would need to be completed within only 3 minutes, which the team determined to be highly unlikely. Finally, interviews with a few operators implied that, due primarily to control room indications and alarms which the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loads provide, the operators may not attempt to de-energize all of these loads within the first 15 minutes of an SBO, when 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> was provided as an acceptable time-frame.

Based on the teams review of available battery sizing design calculations and the fact that loads likely would not be shed within 15 minutes, it appears that the Battery 11 would last greater than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> but less than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Constellation is evaluating a reasonable estimate of when the loads will actually be shed, the subsequent actual affect on battery capacity, and the impact, if any, that this will have on the PRA accuracy. If the incorrect assumption does affect the PRA results, the most significant impacts would likely be for the Mitigating Systems Performance Indicator and Maintenance Rule a(4) risk assessments, along with the overall accuracy of the baseline core damage frequency for Unit 1.

The extent that the incorrect PRA assumption regarding load shedding within 15 minutes affected the PRA conclusions is unresolved pending further NRC review URI 05000220/2006008-03, PRA Assumptions Regarding SBO Coping Time.

.2.1.2 3 Battery Board 12 (Unit 1)

a. Inspection Scope

The team reviewed calculations and drawings to determine if the loading of Battery Board 12 was within equipment ratings. The team reviewed the adequacy and appropriateness of design assumptions and calculations related to short circuit analyses, protection coordination, and voltage drop calculations. Bounding loads were sampled to verify the adequacy of the equipment. The team reviewed ground detection design and ground isolation procedures to determine capability of rapidly identifying grounds in the ungrounded 125Vdc system. The team conducted a walkdown of Battery Board 12 to determine if the material condition and operating environment were consistent with the design basis.

b. Findings

No findings of significance were identified.

.2.1.2 4 600 Volt Bus, PB-17B (Unit 1)

a. Inspection Scope

The team reviewed calculations to verify that Power Board 17B had acceptable loading margin. The team reviewed analyses to verify that all vital 600 Volt motors would start under degraded voltage conditions. Additionally, the power board coordination study was reviewed to ensure coordination existed between the 4kV bus and the 600V bus including the loads fed by PB-17B. The team reviewed samples of condition reports to determine the impact on the functionality of the bus under transient or accident scenarios. The team also performed a walk-down of the bus.

b. Findings

No findings of significance were identified.

.2.1.2 5 4.16 kV Power Board, 103 (Unit 1)

a. Inspection Scope

The team reviewed calculations to verify that Power Board 103 had acceptable loading margin along with margin for interruption of short circuit currents. The team reviewed the rating of associated circuit breakers for the bus to ensure the ampere rating exceeded the worst case conditions. The team reviewed the degraded voltage relay setpoint to ensure it allowed for proper operation of downstream loads. The team also reviewed the applicable coordination and protection study for Power Board 103.

b. Findings

No findings of significance were identified.

.2.2 Review of Low Margin Operator Actions (6 samples)

The team performed a risk assessment of expected operator actions, and selected a sample of operator actions for detailed review based upon potential low margin for successful completion of the action. Low margin issues were generally characterized as having one or more of the following attributes:

• Low margin between the time required and time available to perform the actions;

• Complexity of the actions;

• Reliability or redundancy of the components associated with the actions;

• Procedure or training challenges that may impact the operators' ability to perform the actions; and

• Extent of actions to be performed outside of the control room

.2.2.1 Utilization of the East/West Instrument Rooms during a Fire or SBO (Unit 1)

a. Inspection Scope

The team selected the operator action to use the East/West Instrument Rooms to control reactor conditions in the case of a fire in the main control room or during a Station Blackout (SBO). In both scenarios, if DC power becomes unavailable it results in the necessity to use static reactor and drywell indications for control. The incorporation of this action into site procedures, JPMs (Job Performance Measures) and training, both simulation and classroom, was reviewed. Further, the team conducted interviews with licensed operators and engineering staff and walked down the indications to be used.

b. Findings

No findings of significance were identified.

.2.2.2 Control Emergency Condenser (EC) Makeup during a SBO (Unit 1)

a. Inspection Scope

The team selected the operator action to control makeup to the Emergency Condensers within the first 30 minutes of a SBO initiating event in response to the associated loss of control/instrument air. The potential consequence of failure of this action is a potential, earlier loss of EC cooling which would require vessel depressurization. The team verified the activity through a walkdown of the procedural step to throttle the makeup valves to the EC condenser shells. The incorporation of this action into site procedures, JPMs and training, both simulation and classroom, was also reviewed. The team additionally conducted interviews with licensed operators and engineering staff, reviewed the Human Reliability Analysis for this basic event and observed EC response to an SBO in the Unit 1 simulator. Finally, the team reviewed EC inventory calculations to ensure that plant response and operator actions would ensure that this activity would be completed in the time required.

b. Findings

No findings of significance were identified.

.2.2.3 Alignment of Fire Water during a Transient (Unit 1)

a. Inspection Scope

The team selected the operator action to align the fire water system to the common feedwater injection path during a transient event. Credit for the diesel driven fire pump is taken for the SBO event and under other Emergency Operating Procedure scenarios.

The alternate injection systems such as fire water, are identified to mitigate significant reductions in reactor water level. In this scenario, the alignment is required within 25 to 45 minutes depending on the initiating event. The potential consequences of failure of this action were loss of vessel level, loss of core cooling and core damage. The team reviewed the incorporation of this action into site procedures, JPMs and training, both simulation and classroom. The feedwater (FW) and fire protection water (FPW) victaulic fittings were inspected and the dedicated toolbox for spool-piece installation was inventoried. The team also conducted interviews with licensed operators and engineering staff regarding the concurrent depressurization actions expected to be conducted by operators.

b. Findings

No findings of significance were identified.

.2.2.4 Isolation and Mitigation of Internal Flooding in the Control Building (Unit 2)

a. Inspection Scope

The team selected the operator action to isolate and mitigate internal flooding from a postulated service water or fire water rupture in the Control Building. The potential consequence of failure of this action is the flooding of the Division I and II emergency switchgear rooms resulting in an unrecoverable SBO and core damage. The incorporation of this action into site procedures, JPMs and training, both simulation and classroom, was reviewed. The team also conducted area walkdowns and interviewed licensed operators and engineering staff.

b. Findings

No findings of significance were identified.

.2.2.5 Align Containment Venting (Unit 2)

a. Inspection Scope

The team selected the operator action to align containment venting when instrument air and Division I AC power are unavailable. The potential consequence of failure of this action is containment failure. Procedures and equipment required to align the containment vent path were verified via both walkdowns and interviews with licensed operators and engineering staff. The incorporation of this action into site procedures, JPMs and training, both simulation and classroom, was also reviewed and verified.

b. Findings

No findings of significance were identified.

.2.2.6 Alternate Emergency AC Power Alignment during a partial Loss of Offsite Power

Event (Unit 2)

a. Inspection Scope

The team selected the operator action to align alternate emergency AC power via the Auxiliary Boiler transformer. The most significant potential consequence of failure of this action is a partial failure of the service water system with the reduced AC system redundancy. The incorporation of this action into site procedures, JPMs and training, both simulation and classroom, was reviewed. The team also walked down the breaker cubicles where the activity would occur with a licensed operator. Finally, the team reviewed recent breaker evolutions that mirrored this basic event for capability.

b. Findings

No findings of significance were identified.

.3 Review of Industry Operating Experience (OE) and Generic Issues (6 Samples)

a. Inspection Scope

The team reviewed selected OE issues for applicability at the Nine Mile Point Nuclear Station. The team performed a detailed review of the OE issues listed below to verify that NMP had appropriately assessed potential applicability to site equipment.

NRC Information Notice (IN) 1983-44: Potential Damage to Redundant Safety Equipment as a Result of Backflow through the Equipment and Floor Drains The team reviewed the applicability and disposition of IN 83-44. This notice described a condition where an area of the plant that contained both trains of redundant safe shutdown equipment were cross connected by the floor drain system in such a way that gravity draining from another area of the plant could back up into the area that contained the redundant safe shutdown equipment. With inoperable check valves in the drain line, flooding may also affect redundant safe shutdown equipment.

NRC Information Notice (IN) 1989-16: Excessive Voltage Drop in DC Systems The team reviewed the applicability and disposition of IN 89-16. The team reviewed the licensees response to the information notice, selected DC voltage drop calculations, and sampled voltage drops to several risk significant components, (diesel generators, electromagnetic relief valves, and offsite power breakers) to verify adequate voltage existed under the most challenging conditions for the equipment to perform their function.

NRC Bulletin 95-02: Unexpected Clogging of a Residual Heat Removal (RHR) Pump Strainer while Operating in Suppression Pool Cooling Mode The team selected this operating experience due to its applicability to the stations emergency core cooling pumps. The team reviewed the licensees analysis of this operating experience and the actions taken to address this concern. The team selected Unit 2 to review applicable station analysis regarding assumptions utilized to determine the operability of pumps associated with the strainers. This included a review of assumed debris loading and the affect on the friction loss across the strainers.

NRC Generic Letter (GL) 1995-07: Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves The team reviewed the applicability and disposition of GL 95-07. The Commission issued this letter to request that licensees perform or confirm that they previously performed

(1) evaluations of operational configurations of safety-related, power-operated gate valves for susceptibility to pressure locking and thermal binding, and (2)further analyses and any needed corrective actions to ensure that those valves which were susceptible were capable of performing the safety functions within the current licensing bases of the facility. The team sampled a few risk significant valves, RCIC injection isolation valve 2ICS*MOV126 and EC isolation valve IV-39-07R, to review the licensees applicability review and any related corrective actions. This review included verifying that previous assumptions utilized in the screening evaluations remained valid.

NRC Information Notice 1998-24: Stem Binding in Turbine Governor Valves in RCIC and Auxiliary Feedwater (AFW) Systems.

The team reviewed the potential of a design oversight that prevented operation of a safety-related system at three domestic nuclear power stations. This issue involved stem binding in the turbine governor valves due to carbon spacers fitting too tightly on the stem. The licensee had initiated corrective action to address the issue when this information came out. The team reviewed the corrective actions initiated along with the information notice to assess and verify that the operating experience issue had been addressed adequately.

NRC Information Notice 1995-37: Inadequate Offsite Power System Voltage during Design Bases Events The team reviewed the applicability and disposition of IN 95-37. The team selected the licensees response for Unit 2 which was provided in CR-NM-1995-3072. This condition report identified that a Grid Stability study was performed in 1995 which determined that the offsite electrical supplies were adequate to support all the unit loads after a turbine generator trip and still have sufficient voltage levels on the safety related distribution system. The licensees response for Unit 1 was found in Deviation Event Report (DER) 1-95-3242 and was supplemented by condition report NM-1998-2229.

The review of this issue included sampling degraded voltage calculations associated with this issue.

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

a. Inspection Scope

The team reviewed a sample of 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 or qualification issues. In addition, CRs written on issues identified during the inspection were reviewed to verify adequate problem identification and incorporation of the problem into the corrective action system. 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.

4AO6 Meetings, Including Exit

Exit Meeting Summary

On October 20, 2006, the team presented the inspection results to Mr. Timothy J.

OConnor, Site Vice President and Acting Plant Manager, Nine Mile Point Nuclear Station, and other members of Constellations staff. The team verified that no proprietary information is documented in the report.

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

T. OConnor Site Vice President

M. Schimmel Manager, Engineering

M. Alvi Engineering

P. Bartolini Senior Engineer

K. Engelmann Licensing Engineer

S. Dhar Senior Engineer

G. Inch Design Engineer

N. Kabarwal Senior Engineer

T. Kulczycky Probabilistic Risk Assessment

NRC Personnel

W. Schmidt Region 1 Senior Risk Analyst

L. Cline NMP Senior Resident Inspector

E. Knutson NMP Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000220/2006008-03 URI NRC to review adequacy of licensee PRA assumption for potential for 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> battery life under SBO conditions (Section .2.1.22)

Opened and Closed

05000220/2006008-01 NCV Inadequate Design Control for Unit 1 EDG Raw Water Cooling System

05000220/2006008-02 NCV Non-Conservative Assumptions in Safety Related Battery Sizing Calculation