IR 05000331/2004006

IR 05000331-04-006(DRS), 01/26/2004 - 02/13/2004; Duane Arnold Energy Center; Safety System Design and Performance Capability

ML040690133
Person / Time
Site:	Duane Arnold
Issue date:	03/09/2004
From:	Dave Hills NRC/RGN-III/DRS/MEB
To:	Peifer M Nuclear Management Co
References
IR-04-006
Download: ML040690133 (40)

Text

rch 9, 2004

SUBJECT:

DUANE ARNOLD ENERGY CENTER NRC SAFETY SYSTEM DESIGN AND PERFORMANCE CAPABILITY INSPECTION 050000331/2004006(DRS)

Dear Mr. Peifer:

On February 13, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed a baseline inspection at your Duane Arnold Energy Center. The enclosed report documents the inspection findings which were discussed on February 13, 2004, with Mr. J. Bjorseth and other members of your staff.

The 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 procedures and records, observed activities, and interviewed personnel. Specifically, this inspection focused on the design and performance capability of the high pressure coolant injection and reactor core isolation cooling systems.

Based on the results of this inspection, there were two NRC-identified findings of very low safety significance, both of which were determined to involve violations of NRC requirements.

However, because of their very low safety significance and because these issues were entered into your corrective action program, the NRC is treating these issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a Non-Cited Violation, you should provide a response within 30 days of the date of this inspection report, with a basis for your denial, to the U.S.

Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 801 Warrenville Road, Lisle, Il 60532-4351; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Duane Arnold Energy Center. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

David E. Hills, Chief Mechanical Engineering Branch Division of Reactor Safety Docket No. 50-331 License No. DPR-49 Enclosure: Inspection Report 05000331/2004006(DRS)

cc w/encl: E. Protsch, Executive Vice President -

Energy Delivery, Alliant; President, IES Utilities, Inc.

J. Cowan, Executive Vice President and Chief Nuclear Officer J. Bjorseth, Plant Manager S. Catron, Manager, Regulatory Affairs J. Rogoff, Esquire, Vice President, Counsel, & Secretary B. Lacy, Nuclear Asset Manager Chairman, Linn County Board of Supervisors Chairperson, Iowa Utilities Board The Honorable Charles W. Larson, Jr.

Iowa State Senator D. McGhee - Department of Public Health

SUMMARY OF FINDINGS

IR 05000331/2004006(DRS), 01/26/2004 - 02/13/2004; Duane Arnold Energy Center; Safety

System Design and Performance Capability.

The inspection was a three week baseline inspection of the design and performance capability of the high pressure coolant injection and reactor core isolation cooling systems. The inspection was conducted by regional engineering inspectors. The inspection identified two issues of very low significance. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter 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 a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, having very low safety significance. Specifically, when relocating a high pressure coolant injection turbine exhaust line valve the licensee failed to correctly use the original design anchor bolt safety factor in the supporting calculation.

Following discovery, the licensee entered the violation into their corrective action system as condition report CAP 030373.

The finding was determined to be greater than minor because the calculation error would be expected to necessitate extensive calculation rework and possibly a modification in order to demonstrate that the support meets design acceptance limits commensurate with those applied to the original design. The issue was of very low safety significance because the support remained operable but degraded. (Section 1R21.2.b.1)

Green.

The team identified a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion XVI, "Corrective Action," having very low safety significance. Specifically, the licensee failed to promptly identify and evaluate a calculation error that resulted in a potentially non-conservative technical specification value for the condensate storage tank low level setpoint. The licensee agreed that the issue was not adequately entered into the corrective action program, initiated CAP 030703 to address the issue, and performed an immediate operability review.

This issue was more than minor because it required an analysis to be reperformed and could require a change to the licensees technical specifications. The issue was of very low safety significance because HPCI remained operable throughout the period.

(Section 4OA2.1b1)

Licensee-Identified Violations

None.

REPORT DETAILS

1R21 Safety System Design and Performance Capability

Introduction:

Inspection of safety system design and performance verifies the initial design and subsequent modifications and provides monitoring of the capability of the selected systems to perform design bases functions. As plants age, the design bases may be lost and important design features may be altered or disabled. The plant risk assessment model is based on the capability of the as-built safety system to perform the intended safety functions successfully. This inspectable area verifies aspects of the mitigating systems cornerstone for which there are no indicators to measure performance.

The objective of the safety system design and performance capability inspection is to assess the adequacy of calculations, analyses, other engineering documents, and operational and testing practices that were used to support the performance of the selected systems during normal, abnormal, and accident conditions.

The systems and components selected were the high pressure coolant injection (HPCI)and reactor core isolation cooling (RCIC) systems (two samples). These systems were selected for review based upon:

• having a high probabilistic risk analysis ranking;

• having had recent significant issues;

• not having received recent NRC review; and

• being interacting systems.

The criteria used to determine the acceptability of the systems performance was found in documents such as:

• licensee technical specifications;

• applicable final safety analysis report sections; and

• the systems' design documents.

The following system and component attributes were reviewed in detail:

System Requirements Process Medium - water, fuel oil, electricity; Energy Source - electrical power, fuel oil, air; Control Systems - initiation, control, and shutdown actions; Operator Actions - initiation, monitoring, control, and shutdown; and Heat Removal - ventilation.

System Condition and Capability Installed Configuration - elevation and flow path operation; Operation - system alignments and operator actions; Design - calculations and procedures; and Testing - flow rate, pressure, temperature, voltage, and levels.

Component Level Equipment Qualification - temperature and radiation; and Equipment Protection - tornado and electrical.

.1 System Requirements

a. Inspection Scope

The inspectors reviewed the updated safety analysis report, technical specifications, system descriptions, drawings and other available design basis information, as listed in the attached List of Documents, to determine the performance requirements of HPCI, RCIC, and their associated support systems. The reviewed system attributes included process medium, energy sources, control systems, and operator actions. The rationale for reviewing each of the attributes was:

Process Medium: This attribute required review to ensure that the HPCI and RCIC systems would supply the required amount of water to the reactor following design basis events.

Energy Sources: This attribute needed to be reviewed to ensure that the HPCI and RCIC systems would start when called upon, and that appropriate valves would have sufficient power to change state when so required.

Controls: This attribute required review to ensure that the automatic controls for the HPCI and RCIC systems were properly established. Additionally, review of alarms and indicators was necessary to ensure that operator actions would be accomplished in accordance with the design.

Operations: This attribute was reviewed because the operators took a number of actions during the monthly and quarterly surveillance tests that had the potential for affecting HPCI and RCIC automatic operation. In addition, the emergency operating procedures permitted the operators to manually control HPCI and RCIC operation to maintain desired reactor water levels. Therefore, operator actions played an important role in the ability of the HPCI and RCIC systems to achieve their safety related functions.

Heat Removal: This attribute was reviewed to ensure that there was sufficient heat removal capability for the HPCI and RCIC systems from the associated room coolers.

.1 Station Blackout Coping Analysis

Introduction:

An unresolved item was identified concerning the licensees station blackout (SBO) coping analysis performed to support the extended power uprate.

Description:

The revised SBO analysis showed that, as a result of increased decay heat load, the suppression pool water temperature would reach the heat capacity temperature limit (HCTL) as defined in the emergency operating procedures (EOPs)approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> into the postulated event. The licensee determined that the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping period continued to be met, despite reaching the HCTL limit, because operators would begin another reactor vessel cooldown as suppression pool temperature approached or exceeded the HCTL. The rate of cooldown was judged to be slow enough that the end of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping period would be reached before the RCIC system, which was used to maintain reactor vessel water level, isolated on low reactor pressure. At the end of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period, offsite power was assumed to be restored and operators would bring the plant to cold shutdown.

The inspectors determined that the EOPs would direct operators to perform an emergency depressurization if suppression pool temperature and reactor pressure vessel pressure could not be maintained below the HCTL limit. The inspectors were concerned that an emergency depressurization during a SBO event would result in losing all sources of core cooling systems for injection to the reactor vessel. Since this limit was shown to be exceeded prior to the end of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping period, the inspectors could not conclude that the coping period was met.

The SBO analysis also showed that the drywell shell temperature limit would be reached approximately 3.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> into a postulated SBO event. The analysis concluded that adequate drywell integrity was maintained because the duration above the temperature limit was short and the drywell pressure was low. The inspectors determined that the EOPs would again direct operators to perform an emergency depressurization if this limit could not be restored and maintained. Since this limit also was shown to be reached prior to the end of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> coping period, and could result in emergency depressurization and loss of all core cooling systems for injection, the inspectors could not conclude that the coping period was met.

Because this information impacted a document which was previously reviewed by the NRC as part of the extended power uprate, the inspectors discussed this issue with the Office of Nuclear Reactor Regulation staff, who planned additional review of the issue.

This issue will remain an unresolved item pending further review by NRC staff to determine if the licensees analysis and justification adequately support the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> SBO coping period. (URI 05000331/2004006-01)

.2 System Condition and Capability

a. Inspection Scope

The inspectors reviewed design basis documents and plant drawings, abnormal and emergency operating procedures, requirements, and commitments identified in the updated safety analysis report and technical specifications. The inspectors compared the information in these documents to applicable electrical, instrumentation and control, and mechanical calculations, setpoint changes and plant modifications. The inspectors also reviewed operational procedures to verify that instructions to operators were consistent with design assumptions.

The inspectors reviewed information to verify that the actual system condition and tested capability was consistent with the identified design bases. Specifically, the inspectors reviewed the installed configuration, the system operation, the detailed design, and the system testing, as described below.

Installed Configuration: The inspectors confirmed that the installed configuration of the HPCI and RCIC systems met the design basis by performing detailed system walkdowns. The walkdowns focused on the installation and configuration of piping, components, and instruments; the placement of protective barriers and systems; the susceptibility to flooding, fire, or other environmental concerns; physical separation; provisions for seismic and other pressure transient concerns; and the conformance of the currently installed configuration of the systems with the design and licensing bases.

Operation: The inspectors performed procedure walk-throughs of selected manual operator actions to confirm that the operators had the knowledge and tools necessary to accomplish actions credited in the design basis.

Design: The inspectors reviewed the mechanical, electrical and instrumentation design of the HPCI and RCIC systems to verify that the systems and subsystems would function as required under accident conditions. The review included a review of the design basis, design changes, design assumptions, calculations, boundary conditions, and models as well as a review of selected modification packages. Instrumentation was reviewed to verify appropriateness of applications and set-points based on the required equipment function. Additionally, the inspectors performed limited analyses in several areas to verify the appropriateness of the design values.

Testing: The inspectors reviewed records of selected periodic testing and calibration procedures and results to verify that the design requirements of calculations, drawings, and procedures were incorporated in the system and were adequately demonstrated by test results. Test results were also reviewed to ensure automatic initiations occurred within required times and that testing was consistent with design basis information.

.1 Incorrect Factor of Safety Specified in Design Evaluation of HPCI Pipe Support

Introduction:

The inspectors identified a finding of very low significance involving a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control.

Specifically, the inspectors identified that the design bases for a HPCI turbine exhaust line pipe support were not correctly translated into calculations or drawings.

Description:

The inspectors reviewed calculation CAL-M96-010, Relocation of Valve V22-0016 Next to V22-0017, which was performed to evaluate the effects of relocating a HPCI turbine exhaust line valve 50 feet closer to the torus. The inspectors noted that, for support 200S, the calculation listed the allowable anchor bolt load for Level D pipe reactions as twice that for Levels A, B or C. The inspectors determined that the anchor bolt load design capacity should not have increased for Level D pipe reactions if the original anchor bolt design requirement had been met. The original design requirement was that wedge type anchor bolts had a safety factor greater than or equal to four based on the ultimate bolt capacity.

The licensee determined that calculation CAL-M96-010 specified the operability limit for the anchor bolt allowable load instead of the design limit. The operability limit only required that wedge type anchor bolts had a safety factor greater than or equal to two, based on the ultimate bolt capacity. The use of the operability limit did not meet design requirements.

Further review by the inspectors verified that the original support design bases calculation, 25.2638.1170.03, Support

Analysis:

HBB-6-SS-22 (200S), used the correct design safety factor based on the ultimate bolt capacity and had evaluated the installed asymmetric anchor bolt configuration. While the increased pipe reactions due to relocating valve V22-0016 were revised on the pipe support design drawing, the calculation had not been revised. The licensee determined that support HBB-6-SS-22 was operable but degraded.

Analysis:

Evaluation of this issue concluded that it was a design control deficiency resulting in a finding of very low significance (Green). The deficiency was due to the licensee not using the correct minimum safety factor as required by the original design to determine the wedge type anchor bolt acceptance limit as in the original design bases calculation for support HBB-6-SS-22. The mitigating systems cornerstone was affected as the failure of a HPCI turbine exhaust pipe support could result in the failure of the HPCI system to fulfill its design function. No other cornerstones were determined to be degraded as a result of this issue.

The finding was determined to be greater than minor because the calculation error would be expected to necessitate extensive calculational rework and possibly a modification to ensure that the support met design acceptance limits.

The finding was assessed through Phase I of the significance determination process.

The inspectors agreed with the licensees position that the pipe support was operable but degraded. Therefore, the inspectors concluded that the finding did not represent an actual loss of a safety function, and the issue screened out as having a very low safety significance or Green.

Enforcement:

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

Contrary to the above, as of February 13, 2004, the design bases for the HPCI turbine exhaust line piping and supports were not correctly translated into specifications, drawings, procedures, and instructions, in that design calculation CAL-M96-010, Relocation of Valve V22-0016 Next to V22-0017, did not use a factor of safety equal to or greater than four based on the ultimate anchor bolt capacity for pipe support HBB-6-SS-22 commensurate with the original design requirements. Because the licensee entered the violation into their corrective action system as condition report CAP 030373, this violation is being treated as a Non-Cited Violation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000331/2004006-02)

.2 HPCI Injection Piping Hydraulic Transient Susceptibility

Introduction:

The inspectors identified an unresolved item concerning the potential for conditions to exist in the HPCI injection piping which could result in a hydraulic transient event whenever the system was called upon to function.

Description:

The inspectors reviewed the licensees evaluation of a Dresden hydraulic transient which occurred in July 2001. The Dresden licensee determined the event occurred due to a combination of air pockets and steam voids in the Unit 3 HPCI injection piping. The inspectors noted several similarities between the Dresden and Duane Arnold HPCI piping configurations which signified that a similar hydraulic transient event could be possible at Duane Arnold upon an automatic HPCI injection.

The inspectors determined that three conditions combined to cause the Dresden hydraulic transient:

(1) a length of stagnant heated water between two closed valves in the HPCI injection line;

(2) an air pocket at the high point of the system; and

(3) an injection valve which opened prior to HPCI system pressure being high enough to overcome the feedwater system pressure. When the injection valve began to open during system initiation, heated water between the injection valve and downstream check valve flashed to steam into the low pressure air pocket immediately upstream of the injection valve. The HPCI steam void subsequently collapsed as pump discharge pressure increased, resulting in a system hydraulic transient.

The inspectors were concerned that the Duane Arnold HPCI system could also be susceptible to a hydraulic transient due to system similarities between the two plants:

the proximity of the piping downstream of the injection valve to the interfacing feedwater system, the physical layout of the injection line with the system high point immediately upstream of the injection valve and a valve initiation logic which did not have a pressure interlock.

At Duane Arnold, similar to Dresden, the HPCI system injected into the feedwater system. However, Duane Arnold had a longer segment of piping between the normally closed injection and check valves which was filled with stagnant water. No information was available during the inspection as to the temperatures in this segment of piping during normal operation. Therefore, the inspectors could neither prove nor disprove whether the water volume between the HPCI injection valve and downstream check valve would flash to steam when the injection valve opened.

On both the Duane Arnold and Dresden HPCI systems, the high point in the piping occurred just prior to the injection valve. However, Dresden had intermediate high points which did not exist at Duane Arnold. The inspectors verified that, at Duane Arnold, the HPCI pump discharge piping was filled and vented prior to plant operation.

The inspectors also confirmed that the system was not routinely vented during plant operation, unless the suction piping was not aligned to its normal source, the condensate storage tank. Therefore, the inspectors were unable to confirm that an air void either did or did not exist at the HPCI injection valve high point due to air coming out of solution over time.

The inspectors confirmed that the Duane Arnold initiation logic allowed the HPCI injection valve to begin opening independently of the pump start. Therefore, the inspectors determined that low pressure conditions could be present when the valve first opened.

Based on the above, the inspectors concluded that the licensee had insufficient information to demonstrate that the Duane Arnold HPCI system would not be subject to transient hydraulic loads. The licensee also did not have any evaluation which demonstrated that the system could function if it did experience a hydraulic transient.

This item is being held as an unresolved item pending sufficient additional information from the licensee to demonstrate that the system is either susceptible or not susceptible to a hydraulic transient. Furthermore, the unresolved item encompasses the need for a licensee evaluation of the severity and impact of a hydraulic transient, if the additional information concludes that susceptibilities do exist. The licensee entered this issue into their corrective action system as condition report CAP 030715.

(URI 05000331/2004006-03)

.3 Unverified Methodology for Analysis of Torus Attached Piping

Introduction:

The inspectors identified a an unresolved item concerning design changes to the HPCI turbine exhaust subsystem which were not subject to design control measures commensurate with those applied to the original design.

Description:

The inspectors reviewed a HPCI modification which relocated a valve to decrease the potential to siphon suppression pool water into the HPCI turbine exhaust line due to steam condensation. The valve, V22-0016, was relocated close to valve V22-0017 in order to minimize the trapped water volume between the two valves. The HPCI turbine exhaust line penetrated primary containment at torus penetration N214, and terminated inside the torus below the suppression pool water level.

The inspectors determined that the design loads for the redesigned HPCI turbine exhaust line had to include the torus response to a loss of coolant accident (LOCA) and a safety-relief valve (SRV) discharge, because of the location of the valves in relation to the torus penetration. The inspectors ascertained that the effect of LOCA and SRV discharge loads was expected to attenuate as the piping distance from the torus increased. However, valve V22-0016 was relocated more than 50 linear piping feet closer to the torus and was finally positioned within a few feet of the torus. As described in Updated Final Safety Analysis Report (UFSAR) Section 6.2.1.6.2.2, Mark I Containment Long Term Program, the NRC reviewed and accepted the Duane Arnold plant unique analysis report for the Mark I containment. In the NRC safety evaluation related to the structural review of the Mark I containment long term program, the NRC concluded, in part, that the original design used properly determined loadings and load combinations, and that the licensees analyses were verified by independent audit and approved by the staff under LOCA and SRV discharge loads. The inspectors determined that response spectra for LOCA and SRV discharge loads typically had sharp peaks at narrow critical frequency ranges. Therefore, the inspectors concluded that small changes in piping system resonant frequency near LOCA or SRV discharge load critical frequencies could produce large changes in the piping system analysis results.

The inspectors reviewed the licensees piping evaluation in calculation CAL-M96-010, Relocation of Valve V22-0016 Next to V22-0017. The inspectors determined that the calculation did not evaluate the effect of torus LOCA and SRV discharge loads using the original design methodology. Instead, the calculation estimated the change in pipe moments and reaction forces for the LOCA and SRV discharge loads by comparing piping system frequency responses for the unmodified and modified piping systems.

The calculation assumed that, if the resultant changes in frequency response were less than ten percent, the overall change in system acceleration response for the modified piping would be insignificant from the original analysis. Pipe moment and support reactions due to LOCA and SRV discharge loads for the modified system were then increased based on static analyses of the piping system mass redistribution due to the valve relocation.

The inspectors could not determine that the licensees simplified methodology was at least as conservative as the original design methodology. The licensee did not benchmark the simplified methodology against the original design methodology nor did the licensee provide any information to verify the reliability or accuracy of the assumptions used in the simplified methodology. The licensee's calculation did not provide justification that the original design methodology included sensitivity analyses or other methods to support the ten percent assumption.

The inspectors noted that the piping stress level documented in CAL-M96-010 was at 90 percent of design acceptance limits, and that pipe support allowable reactions were at 94 percent of design acceptance limits, or very close to the maximum allowables.

Due to the complexity of the original design analysis methodology, the inspectors determined that the licensee's calculation did not provide sufficient information to demonstrate whether or not the effect of piping system resonant frequency changes was bounded by the results of the originally analyzed LOCA and SRV discharge loads.

This item is being held as an unresolved item pending sufficient additional information from the licensee to demonstrate that the simplified methodology used was bounded by the original design methodology. Furthermore, the unresolved item encompasses the need for licensee re-evaluation of piping and piping support loads, if the additional information concludes that the simplified methodology was not bounded. The licensee had not entered this issue into their corrective action system as of the end of the inspection. (URI 05000331/2004006-04)

.3 Components

a. Inspection Scope

The inspectors examined the HPCI and RCIC systems to ensure that component level attributes were satisfied. Specifically, the following attributes of the HPCI and RCIC systems were reviewed:

Equipment/Environmental Qualification: This attribute verifies that the equipment is qualified to operate under the environment in which it expected to be subjected to under normal and accident conditions. The inspectors reviewed design information, specifications, and documentation to ensure that the HPCI and RCIC components were qualified to operate in within the temperatures and radiation fields specified in the environmental qualification documentation.

Equipment Protection: This attribute verifies that the HPCI and RCIC systems are adequately protected from natural phenomenon and other hazards, such as high energy line breaks, floods or missiles. The inspectors reviewed design information, specifications, and documentation to ensure that the HPCI and RCIC systems were adequately protected from those hazards identified in the updated safety analysis report which could impact their ability to perform their safety function.

b. Findings

No findings of significance were identified.

4OA2 Problem Identification and Resolution

.1 Review of Condition Reports

a. Inspection Scope

The team reviewed a sample of HPCI and RCIC system problems that were identified by the licensee and entered into the corrective action program. The inspectors reviewed these issues to verify an appropriate threshold for identifying issues and to evaluate the effectiveness of corrective actions related to design issues. In addition, condition reports 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.

.1 Condensate Storage Tank Low Level Setpoint

Introduction:

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," having very low safety significance (Green) for failing to promptly identify and evaluate a calculation error that resulted in a potentially non-conservative technical specification value. Specifically, the inspectors identified that the licensee recognized an error in the condensate storage tank (CST)low level setpoint calculation, but failed to adequately enter the issue into the corrective action program.

Description:

The inspectors reviewed calculation CAL-E93-027, Condensate Storage Tank Low Level LS5218 and LS5219. This calculation provided the basis for the CST low level setpoint described in Table 3.3.5.1-1, item 3d, and Table 3.3.5.2-1, item 3, in the Duane Arnold technical specifications. The safety function of the setpoint was to initiate transfer of HPCI and RCIC suction from the CST to the torus once the water volume of the CST was depleted. The inspectors determined that the calculation did not take into account the time that necessary to complete the transfer nor did it include process measurement error. With the setpoint at the allowed value, the inspectors determined that vortexing could occur in the HPCI suction prior to the completion of the suction transfer. This would allow air to be drawn into the pump.

The licensee determined that the above deficiencies were previously identified during a self-assessment performed in December 2003. The deficiencies had been noted, but had not been entered into the licensee's corrective action program until a low level tracking item, OTH037080, was generated in February 2004. This low level tracking item did not get a review for operability. The inspectors noted that operability of the system would be affected if the CST were at the technical specification allowable value.

The licensee agreed that the issue had not been adequately entered into the corrective action program, initiated CAP 030703, CAPs not Written for CAQs Discovered During Self Assessment, on February 12, 2004, and performed the required operability review.

The licensee concluded that during the period from December 2003, until February 12, 2004, the HPCI system was operable as the actual setpoint was sufficiently higher than the technical specification allowable value and provided reasonable assurance that the system would perform its design basis function.

Analysis:

Evaluation of this issue concluded that it was a performance deficiency resulting in a finding of very low safety significance (Green). The performance deficiency was the failure to promptly identify and correct a potentially non-conservative technical specification value. The inspectors concluded that the finding was greater than minor because it required an analysis to be reperformed and could require a change to the licensees technical specifications. This finding affected the mitigating system cornerstone, as the underlying calculational error affected the reliability of HPCI, a system designed to mitigate the consequences of an accident.

The finding was assessed through Phase I of the significance determination process.

The inspectors agreed with the licensees position that the actual setpoint was sufficiently higher than the technical specification allowable value and provided reasonable assurance that the system would perform its design basis function.

Therefore, the inspectors concluded that the finding did not represent an actual loss of a safety function, and the issue screened out as having a very low safety significance or Green.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action,"

requires, in part, that measures be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected.

Licensee procedures ACP114.5, Action Request System, and ACP 117.4, Snapshot Self-Assessment Process, required that a corrective action plan CAP be initiated for conditions adverse to quality.

Contrary to the above, as of February 11, 2004, the licensee failed to assure that a condition adverse to quality was promptly identified and corrected. Specifically, a potentially nonconservative technical specification allowed value was first identified during the week of December 2, 2003. On February 2, 2004, the licensee initiated a low level tracking document, OTH037080, rather than a CAP. This OTH document bypassed the process for operability review. The licensee finally entered this issue into its corrective action program as part of CAP 030703, CAPs not Written for CAQs Discovered During Self Assessment, on February 12, 2004, and performed the required operability review. Because this violation was of very low safety significance and because it was entered into the licensees corrective action program, this violation is being treated as a non-cited violation consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000331/2004006-05)

4OA6 Meetings, Including Exits

.1 Exit Meeting

The inspectors presented the inspection results to Mr. J. Bjorseth and other members of licensee management at the conclusion of the inspection on February 13, 2004. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. Proprietary information was reviewed during the inspection. The inspectors confirmed that the proprietary material had been returned and discussed the likely content of the inspection report. The licensee did not indicate any potential conflicts with information presented.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Anderson, Business Support Manager

J. Bjorseth, Plant Manager

S. Catron, Manager Regulatory Affairs

D. Curtland, Engineering Director

T. Evans, Operations Manager

S. Haller, Systems Engineering Manager

P. Hansen, Outage and Scheduling Manager

G. Hawkins, Plant Engineering Supervisor

M. Peifer, Site Vice President

R. Morrell, Performance Improvement Manager

K. Schneider, Nuclear Oversight Manager

Nuclear Regulatory Commission

R. Caniano, Deputy Director, Division of Reactor Safety

S. Caudill, Resident Inspector

G. Wilson, Senior Resident Inspector

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000331/2004006-01 URI Station Blackout Coping Analysis (Section 1R21.1.b.1)

05000331/2004006-02 NCV Incorrect Factor of Safety Specified in Design Evaluation of HPCI Pipe Support (Section 1R21.2.b.1)

05000331/2004006-03 URI HPCI Pump Discharge Piping Hydraulic Transient Susceptibility (Section 1R21.2.b.2)

05000331/2004006-04 URI Unverified Methodology for Analysis of Torus Attached Piping (Section 1R21.2.b.3)

05000331/2004006-05 NCV Failure to Promptly Enter a Condition Adverse to Quality into the Corrective Action Program (Section 4OA2.1.b.1)

Closed

05000331/2004006-02 NCV Incorrect Factor of Safety Specified in Design Evaluation of HPCI Pipe Support (Section 1R21.2.b.1)

05000331/2004006-05 NCV Failure to Promptly Enter a Condition Adverse to Quality into the Corrective Action Program (Section 4OA2.1.b.1)

A1 Attachment