IR 05000461/2007008

IR 05000461-07-008 on 10/15/07 - 11/16/07 for Clinton, Component Design Bases Inspection

ML080350693
Person / Time
Site:	Clinton
Issue date:	02/04/2008
From:	Julio Lara Engineering Branch 3
To:	Pardee C AmerGen Energy Co
References
IR-07-008
Download: ML080350693 (39)

Text

ary 4, 2008

SUBJECT:

CLINTON POWER STATION, NRC COMPONENT DESIGN BASES INSPECTION REPORT (CDBI) 05000461/2007008(DRS)

Dear Mr. Pardee:

On December 19, 2007, the U. S. Nuclear Regulatory Commission (NRC) completed a biennial component design bases baseline inspection at your Clinton Power Station. The enclosed report documents the inspection findings, which were discussed during an initial exit meeting on November 16, 2007, and during the final exit telecon on December 19, 2007, with Mr. F. Kearney, and other members of your staff.

This inspection examined activities conducted under your license as they relate to safety, and to compliance with the Commissions Rules and Regulations, and with the conditions of your license. The inspectors reviewed selected calculations design bases documents procedures and records, observed activities, and interviewed personnel. Specifically, this inspection focused on the design of components, that were risk significant and had low margin.

Based on the results of this inspection, five NRC-identified findings of very low safety significance were identified, all of which involved violations of NRC requirements. However, because these violations were of very low safety significance and because they were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest any finding or the subject or severity of any NCV 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 DC 20555-0001, with copies 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 NRC Resident Inspector Office at the Clinton Power Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Julio Lara, Chief Engineering Branch 3 Division of Reactor Safety Docket No. 50-461 License No. NPF-62 Enclosure: Inspection Report 05000461/2007008(DRS)

w/Attachment: Supplemental Information cc w/encl: Site Vice President - Clinton Power Station Plant Manager - Clinton Power Station Regulatory Assurance Manager - Clinton Power Station Chief Operating Officer and Senior Vice President Senior Vice President - Midwest Operations Senior Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Director - Licensing and Regulatory Affairs Manager Licensing - Clinton, Dresden and Quad Cities Associate General Counsel Document Control Desk - Licensing Assistant Attorney General State Liaison Officer Illinois Emergency Management Agency Chairman, Illinois Commerce Commission Illinois Emergency Management Agency

SUMMARY OF FINDINGS

IR 05000461/2007008; 10/15/07 - 11/16/07; Clinton Power Station; Component Design Bases

Inspection.

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 findings of very low safety significance were identified, all with associated Non-Cited Violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3; dated July 2000.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, having very low safety significance involving inadequate cable design.

Specifically, the team identified that the licensee failed to incorporate appropriate licensing and design basis requirements reflecting worst case environmental conditions for power and control safety related cables. Incorporation of these requirements would have ensured that the cables were designed for the continuous submerged conditions that are experienced at Clinton. The issue was entered into the licensees corrective action program to initiate a review of the current cable monitoring programs, and to initiate long-term corrective actions.

The issue was more than minor because if left uncorrected it could result in the loss of safety related and non-safety related power and control cables including cables providing offsite power to the safety related buses. The issue was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A,

"Significance Determination of Reactor Inspection Findings for At-Power Situations, because of lack of evidence, so far, of cable degradation or of past failures of these and similar other energized cables. This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because the licensee did not thoroughly evaluate problems such as the resolutions, address causes, and extent of condition (P.1 (c)). (Section 1R21.3.b.1)

Green.

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, having very low safety significance involving inadequate equipment design. Specifically, the Division 3, emergency diesel generator (EDG) neutral ground resistor was found to be in a non-ventilated enclosure contrary to the USAR, which called for a ventilated housing. The issue was entered into the licensees corrective action program to address this non-conforming condition and develop a design change to enhance ventilation for the resistor.

The finding was more than minor because if left uncorrected the failure of the grounding resistor could adversely impact availability of the Division 3, high pressure core spray (HPCS) EDG. The issue was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations, because of the very low probability of the scenario involving a ground fault in conjunction with a loss of offsite power and a loss of coolant accident. The team determined that there was no cross-cutting aspect to this finding. (Section 1R21.3.b.2)

Green.

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, having very low safety significance involving inadequate design of the emergency diesel generator (EDG) exhaust sub-systems. Specifically, the licensee failed to properly account for severe weather in the design of the exhaust ducts for the EDGs. Consequently, during severe weather conditions, icing or glazing could potentially result in blockage of the exhaust ducts screens located at the duct outlet and in exceeding the backpressure requirements of the ducts. Once identified, the licensee initiated a prompt operability evaluation to verify system operability and an Issue Report which included appropriate compensatory actions.

The finding was more than minor because the licensee failed to properly account for external factors including severe weather conditions as discussed in the Clinton UFSAR.

The issue was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations, because the licensee provided information to support the EDGs operating for short periods of time at elevated back pressures. The team determined that there was no cross-cutting aspect to this finding. (Section 1R21.3.b.3)

Green.

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, having very low safety significance involving a temporary installation that added lead shielding to the Unit 1 residual heat removal (RHR) piping. Specifically, the team identified numerous non-conservative technical errors and calculation omissions in seismic design basis analysis calculations that supported this temporary installation. Once identified, the licensee initiated a prompt operability evaluation to verify system operability and an Issue Report which included appropriate compensatory actions.

The finding was more than minor because the presence of these non-conservative calculational deficiencies resulted in the need to re-perform the seismic design basis analysis calculations and in the removal of temporary lead shielding to assure that pipe supports would function as required during the design basis seismic event. The finding screened as having very low significance because the inspectors answered no to all five questions under the Mitigating Systems Cornerstone Column of the Phase 1 worksheet. After re-performing the calculations, the licensee was able to demonstrate that sufficient margin was available to support the loads that would be seen during the design basis seismic event. The cause of the finding is related to the cross-cutting element of Human Performance Resources, because the licensee did not provide complete, accurate and up-to-date design documentation to assure nuclear safety (H.2(c)). Specifically, the licensee had the temporary installation of lead shielding in place since 2002 and did not formally update the associated pipe support calculations in a timely manner. (Section 1R21.3.b.4)

Green.

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion XI, ATest Control,@ having very low safety significance, in that, the shutdown service water (SX)pump tests conducted did not appropriately demonstrate that the SX pumps met design basis accident requirements. Specifically, the pump test acceptance criteria allowed the pump performance to degrade below the performance assumed by the design analysis.

Once identified, this finding was entered into the licensees corrective action program and the licensee completed an evaluation and retesting that demonstrated the pumps capacity to perform required safety functions.

This issue was more than minor because the test allowed the A SX pump to degrade below the analyzed design limit and required a prompt operability assessment to demonstrate that the pump performance was above the reanalyzed limits. The finding was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, because on re-evaluation, the design safety function was found to have been maintained. The team determined that there was no cross-cutting aspect to this finding. (Section 1R21.3.b.5)

Licensee-Identified Violations

None

REPORT DETAILS

1R21 Component Design Bases Inspection

.1 Introduction

The objective of the component design bases inspection is to verify that design bases have been correctly implemented for the selected risk significant components and that operating procedures and operator actions are consistent with design and licensing bases. As plants age, their design bases may be difficult to determine and an important design feature may be altered or disabled during a modification. The Probabilistic Risk Assessment (PRA) model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectible area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance.

Specific documents reviewed during the inspection are listed in the attachment to the report.

.2 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the licensees PRA and the Clinton Standarized Plant Analysis Risk (SPAR) Model, Revision 3.31. In general, the selection was based upon the components and operator actions having a risk achievement worth of greater than 2.0.

The operator actions selected for review included actions taken by operators both inside and outside of the control room during postulated accident scenarios.

The team performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design reductions caused by design modification, or power uprates, or reductions due to degraded material condition. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as performance test results, significant corrective action, repeated maintenance activities, maintenance rule (a)(1) status, components requiring an operability evaluation, NRC resident inspector input of problem areas/equipment, and system health reports. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.

.3 Component Design

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), design basis documents, drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The 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)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 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 19 components (inspection samples) were reviewed:

Residual Heat Removal (RHR) Pump 1A (1E12 C002A): The team reviewed piping and instrumentation diagrams, pump line up, pump capacities, surveillance procedures, test data and test results for the RHR pumps. Design calculations related to pump head, minimum required flow, and net positive suction head (NPSH) were reviewed to ensure the pumps were capable of providing their accident mitigation function during all required conditions.

The team also reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device relay settings were reviewed to ensure that adequate margin existed. For the RHR pump motor, the team assessed the bases for brake horsepower values used as design inputs to the licensees electrical calculations. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The team reviewed the breaker closure and opening control logic diagrams and the 125Vdc voltage calculations to ensure adequate voltage would be available for the control circuit components. Design change history was also reviewed to assess potential component degradation and impact on design margins. The team also reviewed pipe stress design basis analysis and pipe support design basis calculations for the addition of temporary lead shielding.

2. RHR Pump 1A Minimum Flow Valve (1E12 F064A): The team reviewed the

one-line and schematic diagrams. The team reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The team reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. The team also reviewed pipe stress design basis analysis and pipe support design basis calculations for the addition of temporary lead shielding.

3. RHR HX 1A Shell Side Bypass Valve (1E12 F048A): The team reviewed the

one-line and schematic diagrams. The team reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The team reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. The team also reviewed pipe stress design basis analysis and pipe support design basis calculations for the addition of temporary lead shielding.

4. 4160 VAC Switchgear 1C1 (1E22 S004): The team reviewed the one-line diagrams

and the switchgear purchase specification to verify acceptable equipment ratings.

The bus loading calculations were reviewed to assure that worst case loads had been applied and that the switchgear rating had not been exceeded, and that the bus duct ratings were equal to the switchgear continuous rating as required. The short circuit and voltage calculations were reviewed to verify that they were representative of the worst case line-up of power sources and bus configurations, and that sufficient margin existed. The 5 kV cables used for distribution of power to and from the switchgear were reviewed to assure they were designed for the worst case service conditions. Breaker coordination plots were reviewed to assure selective breaker tripping. System grounding calculations were reviewed to assure optimum functionality of the grounding system. The switchgear maintenance program was also reviewed to ensure conformance with industry and vendor recommendations. A walkdown of the switchgear and diesel generator was performed to assess material condition.

5. 480 VAC Switchgear and Motor Control Center (MCC), (1E22 S002 and S003):

The team reviewed the one-line diagrams and the purchase specification for the switchgear and the MCC to verify acceptable equipment ratings.

The team verified bus loading limits, voltage adequacy, short circuit capability, breaker coordination, and satisfactory operation of connected loads. The review included verifying ac voltage calculations to assure satisfactory voltage to the bus under worst case conditions, verifying that bus loading did not exceed bus rating, and reviewing short circuit calculations to verify that a condition did not exist that could result in exceeding the switchgear and breaker ratings. The team also reviewed the 4160/600 V transformers for adequate sizing, ventilation, and correct tap position. The team reviewed the breaker test program, the maintenance program and maintenance history. The team reviewed modification packages to replace the entire MCC buckets with equivalent buckets, and to replace specific internal relays with equivalent relays. Molded case breaker sizing was verified to ensure adequacy to meet the requirements of Regulatory Guide 1.106.

6. 125 VDC Division 1 Bus, MCC 1A (1DC13E): The team reviewed short circuit

calculation, electrical coordination calculation, voltage drop calculation, fuse sizing criteria and basis, fuse control program, maintenance procedure. The team also performed a walkdown of a few selected panels to verify the fuse types and ratings against the fuse specification and the drawings.

7. 125 VDC Division 1 Battery 1A (1DC01E): The team reviewed electrical

calculations including battery sizing, dutycycle, voltage drop calculations, short-circuit fault current calculation, breaker interrupting ratings and electrical coordination, battery float and equalizing voltages. In addition, the voltage drop calculations for safety-related dc loads and dc control power to 4160V and 480V switchgear were evaluated to verify that adequate voltage was available at these loads during a design bases event with loss of offsite power and for a station blackout event. The team verified minimum and maximum battery room temperatures and hydrogen buildup calculations for consistency with design basis requirements. The team reviewed the 125Vdc ground detection system including the ground sensitivity and basis for alarms and action levels. The operating procedures for normal, abnormal, and emergency conditions were reviewed. The team also reviewed the overall battery capacity, latest modified performance discharge test and service test, and quarterly battery surveillance tests required by technical specifications. The team performed a visual non-intrusive inspection of observable portions of the batteries to assess the installation configuration, material condition, and potential vulnerability to hazards.

8. 125 VDC Division 1 Battery Charger 1A (1DC06E): The team reviewed electrical

calculations for the 125Vdc battery charger 1DC06E, including sizing calculation, contribution to short-circuit fault current, and breaker sizing. The operating procedures for normal, abnormal, and emergency conditions were reviewed. In addition, the test procedures were reviewed to determine if maintenance and testing activities for the battery chargers were in accordance with UFSAR requirements and vendor recommendations. The team performed a visual non-intrusive inspection of the battery chargers to assess the installation configuration, material condition, and potential vulnerability to hazards.

9. 4160 VAC Switchgear 1A1 (1AP07E); 480V Unit Sub Station A (0AP05E); 480V

MCC 1C (1AP31E) and 1C1 (1AP78E): The team reviewed the one-line diagrams and the switchgear purchase specification to verify acceptable equipment ratings.

The bus loading calculations were reviewed to assure that worst case loads had been applied and that the switchgear rating had not been exceeded, and that the bus duct ratings were equal to the switchgear continuous rating as required. The short circuit and voltage calculations were reviewed to verify that they were representative of the worst case line-up of power sources and bus configurations, and that sufficient margin existed. The 5 kV cables used for distribution of power to and from the switchgear were reviewed to assure they were designed for the worst case service conditions. Breaker coordination plots were reviewed to assure selective breaker tripping. System grounding calculations were reviewed to assure optimum functionality of the grounding system. The switchgear maintenance program was also reviewed to ensure conformance with industry and vendor recommendations.

The team also reviewed the 4160/600 V transformer for adequate sizing, ventilation, and correct tap position. The team reviewed the breaker test program, and the maintenance program and history. A walkdown was also performed to determine the material condition of the switchgear. Modification packages to replace the entire MCC buckets with equivalent buckets, and to replace specific internal relays with equivalent relays were reviewed. MCC molded case breaker sizing was verified to ensure adequacy to satisfy the requirements of Regulatory Guide 1.106.

10. Emergency Diesel Generator (EDG) 1A (1DG01KA): The team evaluated the EDG to determine if it can meet its design basis functions. Included in this inspection was the evaluation of the lube oil, inlet air, air starting, and exhaust air sub-systems.

The fuel oil pump and fuel supply subsystem were reviewed. The team performed a walkdown of the EDG, observed a portion of a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> surveillance run of the diesel generator and performed a walkdown of the exhaust silencer and ducting. Included in the review were structural calculations of the lube oil tubing, air supply receiver volume, pressure drop for the air exhaust system for normal and abnormal conditions, and jacket water/heat exchanger heat transfer calculations. An interview was conducted with the systems engineer regarding EDG performance and the a corrective action related to EDG governor speed control. Maintenance records and records of EDG In-service Testing (IST) for the past 3 years were reviewed.

The team also reviewed the EDG purchase specification. The EDG loading calculation was reviewed to assure that worst case loading had been considered, and that process controlled loads, load increase due to over frequency conditions had been considered. The EDGs response to a degraded grid voltage signal on the bus was reviewed. Periodic surveillance tests were reviewed to assure that test results were in compliance with TS requirements. The alarm response procedure used for EDG ground fault annunciation was reviewed to ensure adequate operator response in the event of a ground fault. Diesel fuel oil consumption and storage calculations were reviewed to verify that they accounted for the use of ultra low sulfur fuel. A walkdown of the diesel generator was performed to assess the material condition.

11. EDG 1A, Fuel Oil Transfer Pump (1DO01PA): The team reviewed the fuel oil transfer pump to verify that it would provide oil to the emergency diesel generators during EDG operation. The team reviewed the oil supply tank and piping to assure that an adequate supply of oil was available and that the Pump NPSH requirements were satisfied. The discharge piping to the day tank and the day tank were also reviewed. Associated hydraulic calculations and test results were reviewed and a walkdown of the equipment was performed during pump and EDG operation.

Maintenance records were reviewed for the EDG oil supply and Corrective actions were reviewed. The oil volume calculation was compared to the oil consumption in two 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> diesel runs to assure that the calculated oil supply would meet design requirements. The systems engineer was interviewed to discuss recent system performance and discuss results from past EDG tests.

12. Reserve Auxiliary Transformer (RAT) and Switcher 4538. The team reviewed the three-winding RAT transformer nameplate, sizing, current carrying capability, and output voltage under worst-case conditions. The transformer tap position was also verified to ensure consistency with the tap position assumed in the voltage drop and short circuit calculations. The bus ducts emanating form the transformer were reviewed to ensure that the bus duct ratings were equal to the switchgear continuous rating as required. A walkdown of the RAT transformer was performed.

13. 345KV Circuit Switcher 4522: The team reviewed the history of newly installed switchyard breaker 4522, which connects the 345 kV North, bus to line 4522. The team noted that earlier failures of this new breaker had raised questions concerning its reliability, but the team determined that subsequent modifications assured present day reliability commensurate with the other four 345 kV circuit breakers.

A walkdown of the switchyard and relay house was performed.

14. Nuclear System Protection System (NSPS) Invertors 1A thru 1D (1C71S001A-D):

The team reviewed surveillance testing; short circuit calculations for sizing inverter bus; maintenance records and vendor requirements.

15. Shutdown Service Water (SX) Pump 1A (1SX01PA): The team reviewed analyses, operating procedures, test procedures, and test results associated with operation of the SX pump 1A. The evaluation considered both test and accident conditions.

The analyses included hydraulic performance, NPSH, and minimum flow to the pumps. The team reviewed completed tests to ensure that design basis requirements were correctly translated into test acceptance criteria and that the tests demonstrated the pump=s capacity to perform its design basis required functions. Design change history and IST results were reviewed to assess potential component degradation and impact on performance margins. The team also reviewed periodic inspection program to ensure strainers were maintained in a clean condition. The team reviewed operating and maintenance procedures associated with the service water strainers. In addition, the team reviewed the IRs issued to document SX pump problems.

The team reviewed the bus and diesel generator loading calculations, the breaker coordination plots, and the voltage and short circuit calculations to assure that the SX pump would perform its function as required. The team reviewed anchorage calculations for the pump for the plant design basis seismic loads. The team assessed water hammer analysis for Generic Letter 89-10 commitments and action taken to satisfy these commitments. The team reviewed flow balance data with resized piping for affects on pipe analysis and pipe support loads.

16. SX Strainer 1A (1SX01FA): The team reviewed anchorage calculations for the strainer for the plant design basis seismic loads. The team reviewed the preventive maintenance tasks, corrective maintenance history, problem history, and operating history of SX strainers to ensure that they were capable of performing their required functions under required condition. The team also reviewed procedures, surveillances, corrective actions, surveillance results, trending data and differential pressure and debris loading calculations to ensure the strainers were capable of performing their required functions under required conditions. The team reviewed strainer design requirements to ensure debris loading assumptions were consistent with industry guidance.

17. RHR Hx Inlet Valve (1E12 F014A): The team reviewed the one-line and schematic diagrams and the associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The team reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components.

18. Reactor Core Isolation Cooling (RCIC) Pump (1E51 C001): The RCIC pump and turbine were reviewed to assure that it could meet its safety function of supply of water to the reactor. Hydraulic calculations were reviewed to assure that the flow requirements were met and that sufficient NPSH was available from both the RCIC tank and the suppression pool. The water supply was further examined to assure that a reliable water supply was available and that transfer from the RCIC tank to the suppression pool could be accomplished without pump damage and within acceptable transfer times. An interview was conducted with the systems engineer to discuss recent testing, parts replacement and maintenance history. The requirements from both the UFSAR and TSs were reviewed to assure that the design conformed to the licensing commitments.

19. RCIC Steam Supply Turbine Governing Valve (1E51 F610): The team reviewed the MCC molded case breaker utilized for the valve motor to verify adequate sizing to satisfy the requirements of Regulatory Guide 1.106.

1. Continuously Submerged Cables Design Deficiency

Introduction:

The team identified a Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green),involving inadequate cable design. Specifically, the team identified that the licensee failed to incorporate appropriate licensing and design basis requirements reflecting worst case environmental conditions for power and control safety related cables. Incorporation of these requirements would ensure that the cables were designed for the continuous submerged conditions that are experienced.

Description:

Safety related and non-safety related power and control cables are submerged in water on a continuous basis, often with no physical means of evacuating the water. The affected cables included cables from the Emergency Reserve Auxiliary Transformer (ERAT) transformer carrying offsite power to the plant Class 1E buses, cables to the SX pumps, and cables to the water system pumps. The team reviewed the specifications used to purchase these cables and noted that both safety-related and non-safety related cables were specified and purchased to the same specification. The normal environmental conditions in the specification were listed as 90 percent maximum, 50 percent average, and 5 percent minimum relative humidity. A review of the licensees underground cable duct drawings showed that some of the cables would be continuously submerged in water because there were no procedures in place to routinely evacuate the water from manholes, and some cable duct banks sloped downwards and away from the manholes thus ensuring that cables would be continuously submerged. The licensee failed to ensure that the cables were designed for the anticipated environmental conditions by not thoroughly evaluating the submerged cables conditions that were identified in IR 00114481 and IR 00633239, issued July 5, 2002 and May 24, 2007, respectively.

USAR Sections 8.1.6.1.24, 8.1.6.2.4, and 8.3.1.4.4.2 stated that the cables would be qualified for the worst case design basis event. The physical configuration of the cable duct banks and manholes determined that the worst case service conditions for the cables would be submergence on a continuous basis; however, these USAR design requirements were not applied when specifying and procuring cable. Additionally, IEEE Standard 323-1971 IEEE Standard for Qualifying Class 1E Equipment, requires that the service conditions for Class 1E equipment include environmental loading expected as a result of normal and abnormal operating environments throughout the installed life of equipment. These IEEE requirements were also not met for the above cables even though USAR Section 8.1.6.2.4 indicated that the design of the Clinton Power Station was in accordance with the requirements of IEEE 323.

Analysis:

The team determined that failure to ensure that the installed cables were designed for the worst case anticipated environmental conditions was a performance deficiency warranting a significance evaluation. The team determined the finding was more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, because the finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety-related power systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of cables could adversely impact availability of power to redundant equipment as well as affect the availability of offsite power to safety related equipment in all three safety divisions.

The team evaluated this finding using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, SDP Phase 1 screening. The inspectors answered NO to all screening questions in the Mitigating Systems Cornerstone column because the licensees evaluation in IR 00692997, dated November 1, 2007, stated that although the cables were not designed for continuous submergence duty, based on lack of evidence of cable degradation or of past failures, including that of similar energized cables, the condition was acceptable. Therefore, the finding screened as having very low safety significance (Green).

This finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because the licensee did not thoroughly evaluate problems such as the resolutions, address causes, and extent of condition (P.1 (c)).

Specifically, the licensee failed to ensure that the cables were designed for the anticipated environmental conditions by not thoroughly evaluating the submerged cables conditions that were identified in IR 00114481 and IR 00633239, issued July 5, 2002 and May 24, 2007, respectively. In the former IR, the Plant Health Committee was presented with a recommendation to not implement corrective actions regarding the submerged cable issue. In addition, in the response to GL 2007-1, Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients, dated February 7, 2007 the licensee made a commitment to monitor inaccessible underground power cables using Exelon procedure ER-AA-3003; Cable Condition Monitoring Program, Revision 0; however, the licensee informed the team that there were no cables at Clinton Power Station that would be subjected to the monitoring program requirements of ER-AA-3003, and furthermore, there were no maintenance or surveillance requirements in place to specifically inspect the cables, or to evacuate water from accessible submerged areas. In addition, the licensee did not effectively incorporate pertinent industry experience from NRC IN 2002-12, Submerged Safety Related Electric Cables into their evaluations and decisions, and erroneously concluded that the 4 kV cables were environmentally qualified to meet IEEE 323, when in fact the cables were neither specified nor qualified for their abnormal worst case operating environments, that is, submergence duty.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, required, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by performance of design reviews, by the use of alternate simplified calculational methods, or by performance of a suitable testing program.

Contrary to the above, as of November 16, 2007, the licensees design control measures failed to ensure the adequacy of the power and control cables that are submerged on a continuous basis. Specifically, the as-built design failed to meet USAR Sections 8.1.6.1.24, 8.1.6.2.4, 8.3.1.4.4.2, and those of IEEE Standard 323. The licensee entered the finding into their corrective action program as IR 00692997 to initiate a review of the current cable monitoring programs given their recognized service conditions, and to initiate actions over the long term. Because this finding was of very low safety significance, and it was entered into the licensees corrective action program, this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000461/2007008-01).

2. Division 3 - Emergency Diesel Generator (EDG) Neutral Ground Resistor Design

Inadequacy

Introduction:

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green), involving inadequate equipment design. Specifically, the Division 3 EDG neutral ground resistor was found to be in a non-ventilated enclosure contrary to the USAR, which called for a ventilated housing.

Description:

The Division 3 EDG incorporates a high resistance grounding system in accordance with USAR Section 8.3.1.1.2. The high resistance grounding permits continuous operation of the diesel generator in the presence of a ground fault on the system. On experiencing a ground fault, a current of approximately 30 Amperes flows through the resistor producing approximately 4 Kilowatts of heat. In accordance with GE NEDO-10905 (reference USAR 8.3.1.1.2.1) the grounding apparatus was specified to be separately mounted and enclosed in a ventilated steel housing. However, the team identified that the grounding transformer and resistor were neither separate nor in a ventilated housing, but in a totally enclosed panel within the non-ventilated Division 3 EDG control panel. The lack of ventilation or other means of heat dissipation from the transformer and resistor could result in an unacceptable increase of temperature within the transformer and resistor panel as well as the EDG 3 Control Panel. Any consequential equipment failures, or smoke from the overheated painted panel, could result in the failure of the Division 3 EDG.

To address this non-conforming condition and design deficiency, the licensee issued IR 00697048, IR 00702527, and Operability Evaluation 00697048-02, and also proposed a long term corrective action to develop a design change to enhance ventilation for the resistor.

Analysis:

The team determined that failure to ensure that the installed grounding transformer and resistor enclosures were in accordance with the design basis was a performance deficiency warranting a significance evaluation. The team determined the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, because the finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety-related power systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of the grounding resistor could adversely impact availability of the Division 3 EDG.

The team evaluated this finding using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, SDP Phase 1 screening. The inspectors answered NO to all screening questions in the Mitigating Systems Cornerstone column because the failure to ensure that the Division 3 EDG neutral ground resistor was in a ventilated enclosure did not impact current operability of the EDG. Therefore, the finding screened as having very low safety significance (Green).

The team determined that there was no cross-cutting aspect to this finding.

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 performance of design reviews, by the use of alternate simplified calculational methods, or by performance of a suitable testing program.

Contrary to the above, prior to November 16, 2007, the licensees design control measures failed to ensure the adequacy of the EDG 3 neutral grounding resistor housing. Specifically, the as-built design failed to meet USAR Section 8.3.1.1.2.1.

However, because this violation was of very low safety significance, and it was entered into the licensees corrective action program (IR 00697048), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000461/2007008-02).

3. Inadequate Design of Emergency Diesel Generator Exhaust Sub-systems

Introduction:

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green) involving the EDG exhaust sub-systems. Specifically, the design of the system did not account for severe weather conditions that could result in blockage of the EDG exhaust ducts by icing the screen that are located at the outlet of the duct. The blockage could result in a backpressure that exceeds the design allowable value potentially impacting operability of the EDGs.

Description:

The team reviewed the EDG exhaust system calculation and identified that the maximum back pressure of five inches of water would be exceeded when complete blockage of the primary exhaust outlet of all three EDGs occurs during severe weather conditions due to icing or glazing, and when partial blockage of the exhaust screens occurs during external events conditions (tornados). The EDG ducting has two outlets; a smaller outlet located upstream of an exhaust silencer and a larger outlet located downstream of the silencer. The function of the smaller opening is to limit the backpressure to five inches of water in the event that partial blockage occurs from external events. The analysis calculated the backpressure to be 45 inches of water if complete blockage of the silencer or larger outlet occurs.

During a walkdown of the EDGs, on November 1, 2007, the team noted that the end of the exhaust ducts were oriented upward and were potentially subject to icing and snow blockage. The ducting had been modified during original plant construction to include a screen to prevent debris from entering the duct. The screen was specified to be non-safety grade although its obstruction could impact the operation of a safety grade system. Also, there was no documented evidence that icing of the screen had been evaluated by the licensee.

The team noted that the exhaust ducts of the three EDGs had similar designs and were therefore subject to a potential common mode failure. During the inspection, documented evidence was not available for review to confirm that the EDGs could start or operate at rated power with the elevated back pressure.

In response to this finding, the licensee performed an operability evaluation and determined that the EDGs were operable due to the fair weather conditions at the time of this inspection. The licensee also implemented compensatory actions to remove the screen in the event of severe weather that could result in icing or glazing. In addition, a design change was initiated to modify the exhaust ducts design to prevent future blockage. The team determined that severe weather conditions that can lead to icing or blockage of the screens can occur every 2-3 years as discussed in Chapter 2 of the UFSAR. The team reviewed weather conditions for the past 20 years and noted that the weather conditions in the area of the Clinton plant were consistent with the conditions documented in the UFSAR.

Clinton also identified an EDG of similar design, located at another nuclear facility that was started with a back pressure higher than 45 inches of water. A test report for this test was provided to the team for review. The test was performed to demonstrate the function of a relief disc, as such was only at the higher pressure for a brief period.

Clinton also provided the team with results of another test, performed by a vendor which demonstrated that the EDG was capable of running for 5-6 minutes at pressures greater than 45 inches of water. The diesel generator operation time at the higher back pressure was not identified and the report was therefore not conclusive regarding the ability for the EDG to operate for a sufficient time to melt the ice on the exhaust screen.

Nonetheless, the team did not have further questions regarding the EDG operability.

To address this non-conforming condition and design deficiency, the licensee issued IR 00695303 to document and correct this design deficiency.

Analysis:

The team determined that the failure to properly account for external factors including severe weather conditions was a performance deficiency warranting a significance evaluation. The team determined the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, because the finding was associated with the design control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of safety-related power systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to account for severe weather conditions described in Chapter 2 of the UFSAR in the design of the EDG exhaust system. This condition, if left uncorrected, could affect the EDG operability.

The team evaluated this finding using IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, SDP Phase 1 screening. The inspectors answered NO to all screening questions in the Mitigating Systems Cornerstone column because re-evaluation of this issue confirmed the operability of the system. Therefore, the finding screened as having very low safety significance (Green). The team determined that there was no cross-cutting aspect to this finding.

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 performance of design reviews, by the use of alternate simplified calculational methods, or by performance of a suitable testing program.

Contrary to the above, prior to November 2007, the licensee failed to establish effective measures to ensure that the design basis for the EDG exhaust system considered severe weather conditions in the design of the exhaust ducting. The failure to ensure that the design basis considered severe weather conditions could have affected operability of all three EDGs when needed for an event. However, because this violation was of very low safety significance, and the issue was entered into the licensees corrective action program (IR 00695303), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000461/2007008-03).

4. Residual Heat Removal (RHR) Pipe Support Calculation Deficiencies

Introduction:

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green) involving the pipe support analysis performed for the RHR piping system. Specifically, the team identified numerous design basis calculational omissions and non-conservative technical errors associated with calculation IP-M-0704, Revision 0, which analyzed the RHR subsystem 1RH09 piping for design basis loading conditions with the installation of lead shielding.

Description:

The team reviewed calculations IP-M-0704, Evaluation subsystem 1RH-09 due to installation of temporary shielding per TSP 2001-110, 2001-120 and 2001-121 Revision 0, and associated RHR pipe support calculations. Calculation IP-M-0704 analyzed the RHR subsystem 1RH09 piping for the addition of temporary lead shielding to ensure that piping and supports would be able to withstand a design basis earthquake. This calculation provided the basis for the installation of the temporary lead shielding. The acceptance criteria of this temporary installation stated All penetration, anchors and support load shall remain within their design load or shall be qualified for their acceptance. The team identified that the temporary installation, as implemented, failed to demonstrate Code compliance for the RHR pipe supports analyzed for design basis seismic loads and all other design basis loads.

During the review of the calculations associated with this temporary installation, the team identified numerous errors and omissions in the design calculations. These errors included two codes of record for a single base plate evaluation, non-conservative load increase factor used for anchor bolt design, non-conservative computation error of design forces and moments, calculational omission of proper reduction in stress cone for anchor bolt evaluation and unsubstantiated support acceptability for an overstress condition. The team also found an instance where a pipe hanger embedment plate was not analyzed for the induced bending moment due to pipe hanger angularity in combination with the applied straight pull out force. The pipe hanger embedment plate was qualified using a standard embedment plate design criteria which is based only on a straight pull out force. As a result of the pipe hanger embedment plate stresses exceeding their design basis and operability allowables, the RHR B LPCI, Containment Spray, feedwater leakage control, suppression pool cooling and shutdown cooling subsystems were declared inoperable during the inspection. Subsequently, Temporary Shielding Package 2001-121 was removed and the operability was restored. In response to these issues, the licensee initiated IRs 695282, 695925, 695250, 698813, and 696851.

Subsequent engineering justification and calculation performed in these IRs provided reasonable assurance that these errors did not result in an operability concern.

However, even though the licensee was able to provide this reasonable assurance for operability, the issues provided multiple examples of inadequate design basis calculations supporting this temporary installation.

Analysis:

The team determined that the numerous design basis calculational omissions and non-conservative technical errors associated with calculation IP-M-0704 were a performance deficiency warranting a significance evaluation. The team determined that the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, because it was associated with the Mitigating systems attribute of design control, which affected the Mitigating System Cornerstone objective of ensuring the availability, reliability, and capability of the RHR system during a Seismic Class I design basis event. Specifically, numerous non-conservative technical errors and calculation omissions resulted in the need to re-perform seismic design basis analysis calculations and removal of the temporary lead shielding to assure that the piping supports for the aforementioned RHR piping would function as required during a design basis seismic event.

The finding screened as having very low significance (Green) using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for the At-Power Situations, because the team answered no to all five questions under the Mitigating Systems Cornerstone column of the Phase 1 worksheet. Specifically, after re-performing the calculations and removing temporary lead shielding for the supports that were called into question by the inspection team, the licensee was able to show that enough design margin was still available to support the loads that would be seen during a design basis seismic event.

The cause of the finding is related to the cross-cutting element of Human Performance, Resources, because the licensee did not maintain complete, accurate and up-to-date design documentation to assure nuclear safety (H.2(c)). Specifically, the licensee had the temporary installation of lead shielding in place since 2002 and did not formally update the associated pipe support calculations in a timely manner. Further, a preliminary calculation was performed for the pipe support calculations in 2002. The preliminary calculation failed to identify numerous non-conservative technical errors and calculational omissions.

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, prior to November 13, 2007, the licensee design control measures failed to verify adequacy of design of RHR pipe supports, in that the methodology and design input did not account for as-built conditions (pipe hanger angularity and stress cone reduction for anchor bolt evaluation) and did not apply an appropriate load increase factor to an anchor bolt evaluation, which affected RHR pipe support design basis calculations. Specifically, calculation IP-M-0704 which analyzed RHR subsystem 1RH09 piping for design basis loading conditions with the addition of lead shielding contained numerous non-conservative calculational assumptions and omissions affecting the design basis for seismic analysis. However, because this violation was of very low safety significance and because the issue was entered into the licensees corrective action program (IR 695250 and IR 698813), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000461/2007008-04).

5. Inappropriate Shutdown Service Water (SX) Pump Test Acceptance Criteria

Introduction:

The team identified an NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, having very low safety significance (Green), in that, the A and B SX pumps tests did not have appropriate acceptance criteria. Specifically, the tests failed to have appropriate minimum pump hydraulic operability limits to ensure the pumps minimum design basis requirements were met.

Description:

On November 13, 2007, the team requested the design calculation that determined the acceptance criteria for the A SX pump operability test. No calculation could be found for determining that the test acceptance criteria for all three SX pumps would ensure that the pumps allowed test performance would be greater than the minimum design basis accident analysis requirements assumed in design calculation IP-M-0486, Shutdown Service Water (SX) System Hydraulic Network Analysis Model and Flow Balance Acceptance Criteria, Revision 6, dated January 1, 2003.

Based on the teams questions, the licensee identified that:

(1) the A and B SX pumps tests acceptance criteria had been changed in 2003 without verifying that the new minimum required pump performance allowed by the test acceptance criteria was more than the minimum pump performance required by the design limits;

(2) the result of the October 3, 2007, performance (WO 01044766) of the A SX pump test was more than the test acceptance criteria but less than the minimum pump performance assumed by the design calculation;

(3) the test acceptance criteria had only been based on the section XI IST limits for the pumps and did not consider the minimum required performance assumed in the design calculation;

(4) the A and B pump re-baselining was performed in accordance with Procedure ER-AA-321, Administrative Requirements for In-service Testing and this procedure and process did not direct personnel to search for impacted calculations. The personnel re-baselining the pump were not aware that IP-M-0486 was impacted and therefore did not request an update to the calculation prior to revising the test procedure. The licensee initiated IR 700713 to document and address these deficiencies. The licensee performed a prompt operability assessment (OE 700713-02, Revision 0) which determined that the SX pumps were able to perform their safety function because the lake was at 51 degrees F vice the design basis maximum of 95 F. The OE used an equation which had been derived in design calculation IP-M-0486, Revision 6.

On November 28, 2007, the team determined that the methodology used in design calculation IP-M-0486, Revision 6, to derive the equation used in the OE was incorrect.

The equation derived in design calculation IP-M-0486, Revision 6, was then used to incorrectly model potential pump degradation and calculate the resulting IST limits for the A and B SX pumps. The preparer of design calculation IP-M-0486, Revision 6 had incorrectly inserted (without a correct technical basis) a term (denoted L to represent internal leakage in a pump) into a curve-fitting equation. The preparer then incorrectly used the curve-fitting equation as a theoretical hydraulic performance equation and solved the equation for L. The leakage values predicted by the incorrect equation were not realistic pump degradation estimates, e.g.,

(1) at shutoff head the equation incorrectly predicted that the leakage in the pump would be zero and

(2) the equation incorrectly predicted that the higher the pump differential pressure, the lower the internal leakage would be. The licensee issued IR 706104 to initiate actions to correct the methodology used in the OE and the design calculation, and retested the A SX pump using corrected acceptance criteria. The licensee revised the OE to use corrected methodology and test acceptance criteria and determined that the SX pumps were operable under all design conditions. The team reviewed the evaluation and did not identify any deficiencies with the licensee=s conclusion.

Analysis:

The team determined that failure to establish appropriate test acceptance criteria was a performance deficiency warranting a significance evaluation. The team determined the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, because the finding was associated with the procedure quality attribute of the Mitigating System cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of the SX system to respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not appropriately ensure that test acceptance criteria for the SX pump demonstrated that the SX pumps would be capable of providing the required design basis flow during accident conditions.

The team evaluated the finding using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening. The team answered No to all the screening questions because the SX pumps remained operable based on re-evaluation and re-testing. Therefore, the finding screened as having very low safety significance (Green). The team concluded this finding did not have a cross-cutting aspect.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XI, ATest Control,@ requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service and be performed in accordance with written test procedures that incorporate the requirements and acceptance limits contained in applicable design documents. The results shall be documented and evaluated to assure that test requirements have been satisfied.

Contrary to the above, from October 2003 to November 16, 2007, the licensee failed to incorporate appropriate SX system flow and pump differential pressure design requirements into the A and B SX pumps test acceptance criteria. Specifically, on October 3, 2007, the A SX pump passed the acceptance criteria but did not meet the performance assumed in the design calculation. Also, the A and B SX pumps test acceptance criteria from October 2003 to November 16, 2007, allowed the pumps to pass the test but not meet the performance assumed in the design calculation.

However, because this issue was of very low safety significance, and it was entered into the licensee=s corrective action program (IR 700713 and IR 706104), this violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy (NCV 05000461/2007008-05).

.4 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues (6 samples) to ensure that NRC generic concerns had been adequately evaluated and addressed by the licensee. The operating experience issues listed below were reviewed as part of this inspection:

• IN 2005 -04, Bus Single Failure - Crystal River;

• IN 2006-18, Significant Loss of Safety Related Electric Power at Forsmark Unit 1 in Sweden;

• AR 00456192 (IN 06-02), Galvanized Supports/Trays with Jacketed Cable;

• AR 00296788, Bus Single Failure - Crystal River - IN-2005-04;

• ATI 521373, OE 23020 -- Potential for RCIC Water Hammer; and

• ATI 179683, OPEX SME review of Airbound Containment Spray Pumps.

b. Findings

No findings of significance were identified.

.5 Modifications

a. Inspection Scope

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

• ECN 31580, Installation of Interposing Relay into Voltage Regulator Circuit;

• EC-330624, Class 1E MCC Molded Case Circuit Breaker Control Unit (Bucket)

Replacement;

• ECN 32363, Install a Synchrocheck Rly 225-DG1KA to Provide DG Div 1 Breaker Closing Permissive When Paralleling;

• EC-350432, Replacement of Obsolete ITE/Gould J10 Control Relays Used in Safety and Non-Safety 5600 Series 480 V MCC Applications;

• EC 0000349235, Replace Division 1 Diesel Generator Governor Actuators;

• EC 359252, HPCS and RCIC Pump Suction Line Submersion; and

• ECN 30873, Modify Valve 1E12F064A to Eliminate Pressure Lock.

b. Findings

No findings of significance were identified.

.6 Risk Significant Operator Actions

a. Inspection Scope

The team performed a margin assessment and detailed review of five risk significant, time critical operator actions (five samples). 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 team 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 Initiate Automatic Depressurization System for Depressurization;

• Operator Fails to Shed 125V DC Non-Essential Loads;

• Operator Fails to Manually Initiate Suppression Pool Cooling and Manipulate Valves;

• Operator Fails to Vent the Containment; and

• Operator Fails to Line up Main Condenser Vacuum Pumps.

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

The inspectors routinely reviewed issues during inspection activities to verify that they were being entered into the licensees corrective action system at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed.

Issues During the review of the RCIC pump and turbine design (component sample 18), the team reviewed the RCIC tank vortex calculation and the empirical method that was used to calculate the required water level to assure that a vortex will not draw air into the RCIC System (suppression height). The method that was used to calculate the submergence height (Lubin and Springer) was not consistent with the redesigned outlet piping. The Lubin and Springer method was developed based on downward flow through a gravity fed drain whereas the Clinton design withdraws water by pumping it upward through an elbow leading to a horizontal pipe. The team questioned whether the use of the Lubin and Springer method was appropriate and could not validate the submergence height calculation for either the RCIC or the HPCS systems. This was of potential concern because recent changes were made to reduce the margin of the submergence height when accounting for the flow of both the RCIC system and the HPCS system. The team reviewed pertinent documents, including licensee corrective action documents and extent of condition reviews, since the RCIC tank also is a suction source for the HPCS system. The NRC previously performed a 95001 Supplemental Inspection relating to vortexing concerns (IR 05000461/2007009).

The Clinton calculation for the HPCS system, using the Lubin and Springer formula determined that required submergence height 12 inches results in a margin of 5.4 inches prior to vortex formation. The Denny method for a downward facing pipe determines that 2 to 2.5 times the exit diameter is needed when the exit flow is in the range of 10 feet per second. This results in a required submergence height of 30 - 45 inches. This would result in a negative margin in the range of 17.6 to 23.6 inches. In the case of the RCIC system Clinton calculated a required submergence height of 6 inches for a margin of 3.9 inches. The Denny method determined that the submergence height should be approximately 11 to 13.5 inches resulting in a negative margin of approximately 7 to 10 inches. The team noted that, the geometry of the Clinton outlet pipe is different than the Denny experiments and the Denny method may over-predict the required submergence height.

The team did not identify a concern regarding immediate operability relating to the RCIC tank and associated pumps. Nonetheless, the NRC continues to review pump vortexing concerns, and lack of confirmatory testing to evaluate whether this is a potential generic issue.

4OA6 Meeting(s)

Exit Meeting The inspectors presented the inspection results to Mr. F. Kearney and other members of licensee management at the conclusion of the inspection on November 16, 2007. A second telephone exit was conducted on December 19, 2007, to inform the licensee of changes to the findings discussed during the exit meeting on November 16, 2007. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

F. Kearney, Plant Manager

R. Peak, Site Engineering Director

R. Schenck, Work Management Director

J. Domitrovich, Maintenance Director

D. Schavey, Operations Director

C. VanDenburgh, Nuclear Oversight Manager

R. Vickers, Radiation Protection Manager

R. Weber, Sr. Manager Design Engineering

J. Miller, Design Engineering Supervisor

Nuclear Regulatory Commission

J. F. Lara, Chief, Engineering Branch 3

B. Dixon, Senior Resident Inspector

LIST OF ITEMS

OPENED AND CLOSED

Opened and Closed

05000461/2007008-01 NCV Continuously Submerged Cables Design Deficiency

05000461/2007008-01

05000461/2007008-02 NCV Division 3 Emergency Diesel Generator Neutral Ground

05000461/2007008-02 Resistor Design Inadequacy

05000461/2007008-03 NCV Inadequate Design of Emergency Diesel Generator Exhaust

05000461/2007008-03

05000461/2007008-04 NCV Residual Heat Removal Pipe Support Calculation

05000461/2007008-04 Deficiencies

05000461/2007008-05 NCV Inappropriate SX Pump Test Acceptance Criteria

Discussed

None Attachment