IR 05000331/2007002

IR 05000331-07-002 on 01/01/2007 - 03/31/2007, Duane Arnold Energy Center, Inservice Inspection Activities, Operability Evaluations, Problem Identification and Resolution, Access Control to Radiologically Significant Areas, and Event Follow

ML071200370
Person / Time
Site:	Duane Arnold
Issue date:	04/27/2007
From:	Burgess B NRC/RGN-III/DRP/RPB2
To:	Vanmiddlesworth G Duane Arnold
References
IR-07-002
Download: ML071200370 (57)

Text

ril 27, 2007

SUBJECT:

DUANE ARNOLD ENERGY CENTER NRC INTEGRATED INSPECTION REPORT 05000331/2007002

Dear Mr. Van Middlesworth:

On March 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Duane Arnold Energy Center. The enclosed integrated inspection report documents the inspection findings which were discussed on April 5, 2007, with you and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, there were four NRC-identified and two self-revealed findings of very low safety significance, of which six involved a violation of NRC requirements.

However, because these violations were of very low safety significance and because the issues were entered into the licensees corrective action program, the NRC is treating these findings and 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 the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Duane Arnold Energy Center.

G. Van Middlesworth -2-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/

Bruce L. Burgess, Chief Branch 2 Division of Reactor Projects Docket No. 50-331 License No. DPR-49

Enclosure:

Inspection Report 05000331/2007002 w/Attachment: Supplemental Information)

REGION III==

Docket No: 50-331 License No: DPR-49 Report No: 05000331/2007002 Licensee: FPL Energy Duane Arnold, LLC Facility: Duane Arnold Energy Center Location: Palo, Iowa Dates: January 1 through March 31, 2007 Inspectors: R. Orlikowski, Senior Resident Inspector R. Baker, Resident Inspector S. Sheldon, Reactor Inspector M. Holmberg, Reactor Inspector T. Go, Health Physicist M. Mitchell, Health Physicist M. Kurth, Resident Inspector G. Wright, Project Engineer J. Tapp, Reactor Engineer Observers: None Approved by: B. Burgess, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000331/2007002; 01/01/2007 - 03/31/2007; Duane Arnold Energy Center. Inservice

Inspection Activities, Operability Evaluations, Problem Identification and Resolution, Access Control to Radiologically Significant Areas, and Event Follow-up.

This report covers a 3-month period of baseline resident inspection and announced baseline inspections of radiation protection and inservice inspection. The inspections were conducted by Region III reactor inspectors, health physicists, and the resident inspectors. 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 Nuclear Regulatory Commission (NRC) management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a Non-Cited Violation (NCV) of 10 CFR 50.55a(g)4 for failure to complete a Code qualified volumetric examination of the reactor vessel shell welds during the previous refueling outage No.19. Specifically, the licensee used a longer cable length than that used in the ultrasonic examination procedure demonstration, which may have affected the flaw detection capability. On February 19, 2007, the licensee submitted a relief request to allow deferral of the affected reactor vessel weld examinations until the next refueling outage. The cause of this finding was related to the work practices component of the human performance cross-cutting area because the licensee failed to ensure adequate oversight of vendor activities with respect to review of the vendors procedure for examination of reactor vessel welds.

Specifically, the licensee approved procedure ISwT-PDI-AUT1, "Automated Inside Surface Ultrasonic Examination of Ferritic Vessel Wall Greater Than 4.0 Inches in Thickness," without adequately understanding and challenging the vendors basis for changing essential procedure variables.

This finding was of more than minor significance because the finding could be reasonably viewed as a precursor to a significant event involving the ability to detect weld flaws prior to weld failure. In addition, the finding was associated with the Initiating Events cornerstone attribute of "Equipment Performance," and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Absent NRC intervention, the licensee would have relied on an unqualified ultrasonic examination of reactor vessel shell welds for an indefinite period of service, which may have placed reactor coolant pressure boundary welds at increased risk for undetected cracking, leakage, or component failure. Based on review of industry operational experience, the inspectors did not identify any active degradation mechanisms which affect reactor vessel shell welds. Absent active degradation mechanisms, the inspectors concluded that a structurally significant flaw had not likely developed since completion of the last Code qualified vessel weld ultrasonic examination during the second Code interval (i.e., about 11 years earlier). Therefore, based upon NRC management review using qualitative measures of risk in accordance with Appendix M of Inspection Manual Chapter 609, the NRC determined that this finding was of very low safety significance.

(Section 1R08.b.1)

Green.

The inspectors identified a NCV of 10 CFR 50.55a(g)4 for failure to complete Code qualified weld repairs for the main steam safety relief valve PSV-4401.

Specifically, the weld procedures for this repair were not qualified by performing tensile and guided bend tests intended to demonstrate that the weld procedure produced welds with satisfactory strength and ductility for the intended service. Without these tests, the inspectors were concerned that these non-Code conforming weld repairs affecting the pressure boundary (valve body) could lead to cracking and failure of PSV-4401 valve body or bellows when this valve was placed in service. The licensee determined that this issue affected the structural integrity of the safety relief valve (SRV) pilot bellows and could cause the SRVs to not operate in an overpressure condition and declared all of the relief valves inoperable and entered this issue into the corrective action program.

The cause of this finding was related to the work practices component of the human performance cross-cutting area because the licensee failed to ensure adequate oversight of vendor activities with respect to review of the vendors weld procedures for repair of reactor coolant pressure boundary retaining components (PSV-4401).

Specifically, during review of vendor procedures 889C W-6d and 889C W-1, the licensee did not demonstrate adequate understanding of Code requirements and/or did not sufficiently challenge the vendors basis for not performing weld procedure qualification tests.

This finding was of more than minor significance because the finding could be reasonably viewed as a precursor to a significant event involving the failure of repair welds from weld flaws introduced by use of an unqualified welding process. In addition, the finding was associated with the Initiating Events cornerstone attribute of "Equipment Performance," and affected the cornerstone objective to limit the likelihood of those events that upset plant stability, and challenge critical safety functions during shutdown as well as power operations. Absent NRC intervention, the licensee would have relied on unqualified weld repairs on PSV-4401 for an indefinite period of service, which may have placed the reactor coolant pressure boundary at increased risk for weld failure resulting in leakage, or an inoperable relief valve. The NRC evaluated this finding in accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for the At-Power Situation," and because this issue was identified prior to repressurizing the plant, determined that this finding was of very low safety significance. (Section 1R08.b.2)

Green.

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

Appendix B, Criterion 5, was self-revealed when an unplanned RPS reactor scram occurred during surveillance testing due to a scram discharge volume (SDV) high level.

On March 2, 2007, with the reactor shutdown for a planned refuel outage, operators were performing surveillance testing to verify the backup scram valves port air when a scram occurs. After inserting a manual scram and verifying that the backup scram valves ported air, the operators reset the scram. A short time later an unanticipated automatic scram was inserted due to a SDV high level. The operators bypassed the SDV high level scram and reset the scram. Corrective Action Process document (CAP) 048038 was entered into the licensees corrective action program to document the automatic scram.

This issue was more than minor because it directly affects the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the Human Performance attribute as well as the configuration control attribute for controlling the shutdown equipment lineup. The NRC evaluated this finding in accordance with IMC 0609, Appendix G, Shutdown Operation Significance Determination Process, and the finding was determined to be of very low safety significance because it did not impact any of the 5 shutdown safety functions identified. The inspectors also determined that the cause of this finding was related to the work practices component of the human performance cross-cutting area because operations personnel failed to communicate human error prevention techniques, such as holding pre-job briefings, self and peer checking, and proper documentation of activities during performance of the surveillance testing. (Section 4OA3.6)

Cornerstone: Mitigating Systems

Green.

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

Appendix B, Criterion 16, was identified by the inspectors for failure to take prompt corrective action to repair an operable but nonconforming condition on the A and B Emergency Diesel Generators (EDGs). On December 7, 2005, engineering personnel identified that during testing to simulate a Loss of Offsite Power concurrent with a Loss of Coolant Accident (LOOP/LOCA), the output voltage of the EDGs momentarily dropped below 75 percent of nominal voltage during the loading sequence of the EDG.

The Updated Final Safety Analysis Report (UFSAR) states that the output voltage of the EDG shall not drop below 75 percent of nominal with the exception of the initial loading.

The licensee failed to correct the nonconforming condition on the EDGs during the first available opportunity, which was the refueling outage that occurred in the first quarter of 2007. The failure to correct the nonconforming condition was entered into the licensees corrective action program as CAP 047955.

This issue is more than minor because it directly impacts the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The NRC evaluated this finding using IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations. The finding was determined to be of very low safety significance since the finding is a design deficiency confirmed not to result in a loss of operability per part 9900 technical guidance for the operability determination process for operability and functional assessment. (Section 4OA2.3)

Cornerstone: Barrier Integrity

Green.

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

Appendix B, Criterion 5, was identified by the inspectors when engineering and operations personnel failed to include acceptance criteria in a Troubleshooting Instruction Form (TIF). On February 12, 2007, engineering and operations personnel completed a TIF to determine the effects upon the control building envelope of open penetrations between the cable spreading room and the turbine building. The TIF failed to include acceptance criteria to identify whether the Standby Filter Units (SFUs) were being left in an operable condition at the completion of the troubleshooting activity. At the completion of the TIF, operations personnel failed to immediately identify that the as-left control building static pressure was less that the Technical Specification (TS)required limit of > 0.1 inches water gauge relative to the outside atmosphere. When the Shift Manager later identified that the TS requirement was not met, core alterations and fuel moves were secured and the issue was entered into the licensees corrective action program as CAP 047315.

This issue was more than minor because it directly impacts the barrier integrity cornerstone objective to provide reasonable assurance that physical barriers (containment) protect the public from radio nuclide release caused by accident and events. The NRC evaluated this finding in accordance with IMC 0609, Appendix G,

Shutdown Operation Significance Determination Process, and the finding was determined to be of very low safety significance because it did not require a phase 2 quantitative assessment. The inspectors also determined that the cause of this finding was related to the work control component of the human performance cross-cutting area because engineering and operations personnel failed to appropriately coordinate work activities by communicating, coordinating, and cooperating with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance. (Section 1R15.b.1)

Cornerstone: Occupational Radiation Safety

Green.

A self-revealed finding of very low safety significance and an associated NCV of TS 5.7.1 were identified for the failure to satisfy TS requirements for worker access into a high radiation area with dose rates in accessible areas between 100 and 1000 mrem/hour at 30 centimeters. Workers entered the reactor building 716'

Northwest Corner Room (NWCR) which was posted as a high radiation area (HRA),

without adequate recognition of the area radiological conditions and without positive radiological control over the activities within the area. The electronic dosimetry (ED)worn by one of the workers alarmed when significantly higher than expected dose rates were encountered.

The issue was more than minor because it was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation. The issue represents a finding of very low safety significance because it did not involve As-Low-As-Is-Reasonably-Achievable (ALARA) planning or work controls, there was no overexposure, nor did a substantial potential for an overexposure exist given the radiological conditions in the area and the workers response to the ED alarm.

Also, the licensees ability to assess worker dose was not compromised. Corrective actions taken by the licensee included reminding radiation protection staff to better coordinate entries into these areas with operations staff, and plans to reevaluate the radiation protection department practices for entry into high radiation areas, and in general for entry into high radiation areas with the potential for significant dose rate gradients. A cross-cutting aspect in the area of human performance was associated with this finding in the work practices component. (Section 2OS1.4)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Duane Arnold Energy Center (DAEC) operated at full power for the entire assessment period except for brief down-power maneuvers to accomplish rod pattern adjustments and to conduct planned surveillance testing activities with the following exceptions:

• On January 18, 2007, fuel cycle coastdown began followed by a shutdown for a planned refueling outage on February 3. The refueling outage continued through March 15, with the generator connected to the grid on March 18. During power ascension on March 18, the plant incurred a substantial chemistry excursion.

• On March 18, 2007, the reactor was shutdown for a forced outage due to substantial chemistry excursion caused by an apparent resin intrusion from the condensate demineralizers. The reactor was restarted on March 20, following restoration of the chemistry parameters, and the generator connected to the grid on March 22. Full power was achieved the afternoon of March

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial walkdowns of accessible portions of trains of risk-significant mitigating systems equipment. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure.

Equipment alignment was reviewed to identify any discrepancies that could impact the function of the system and potentially increase risk. Redundant or backup systems were selected by the inspectors during times when the trains were of increased importance due to the redundant trains of other related equipment being unavailable.

Inspection activities included, but were not limited to, a review of the licensees procedures, review of equipment alignment, and an observation of material condition, including operating parameters of in-service equipment. Identified equipment alignment problems were verified by the inspectors to be properly resolved.

The inspectors selected the following equipment trains to review operability and proper equipment line-up for a total of three samples:

• A Emergency Service Water with the B Standby Diesel Generator (SBDG) out-of-service (OOS) for maintenance;

• A SBDG with B SBDG OOS for maintenance; and

• B SBDG following overhaul.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Fire Zone Walkdowns

a. Inspection Scope

The inspectors walked down risk-significant fire areas to assess fire protection requirements. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. Various fire areas were reviewed to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for OOS, degraded or inoperable fire protection equipment, systems or features. Fire areas were selected based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events, their potential to adversely impact equipment which is used to mitigate a plant transient, or their impact on the plants ability to respond to a security event. Inspection activities included, but were not limited to, the control of transient combustibles and ignition sources, fire detection equipment, manual suppression capabilities, passive suppression capabilities, automatic suppression capabilities, compensatory measures, and barriers to fire propagation.

The inspectors selected the following areas for review for a total of eight samples:

• Area Fire Plan (AFP) 5, Reactor Building South Control Rod Drive Module Area, Offgas Recombiner Rooms and Railroad Airlock;

• AFP 6, Reactor Building Residual Heat Removal Valve Room Elevation;

• AFP 8, Reactor Building Standby Gas Treatment System and Motor Generator Set Rooms;

• AFP 17, Turbine Building Condenser Bay, Heater Bay, and Steam Tunnel;

• AFP 21, Turbine Building North Turbine Operating Floor, and Middle Operating Floor;

• AFP 25, Control Building Cable Spreading Room;

• AFP 26, Control Building Control Room Complex; and

• AFP 27, Control Building Control Room Heating, Ventilation, Air-Conditioning Room.

b. Findings

No findings of significance were identified.

.2 Annual Fire Drill Review

a. Inspection Scope

The inspectors conducted an annual observation of the licensees fire brigade response activities during drills which simulated a hydrogen fire in the turbine building as well as a simulated fire inside a mechanical fabrication building located in the protected area for a total of one sample. The inspectors evaluated the readiness of personnel to fight fires by verifying that protective clothing/turnout gear was properly donned; self-contained breathing apparatus equipment was properly worn and used; fire hose lines were capable of reaching all necessary fire hazard locations, the lines were laid out without flow constrictions, the hoses were simulated being charged with water, and the nozzles were pattern (flow stream) tested prior to entering the fire area; the fire area was entered in a controlled manner; sufficient fire fighting equipment was brought to the scene by the fire brigade; the fire brigade leader's directions were thorough, clear, and effective; communications with plant operators and between fire brigade members were efficient and effective; the fire brigade checked for fire victims and for fire propagation into other plant areas; effective smoke removal operations were simulated; fire fighting pre-plan strategies were used; and the drill scenario was followed and the drill objectives met. The inspectors used the documents listed in the Attachment to accomplish the objectives of the inspection procedure.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors performed a semi-annual review of flood protection barriers and procedures for coping with internal flooding in the southeast corner room (SECR)for a total of one sample. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. Inspection activities focused on reviewing flood mitigation plans and equipment were consistent with design requirements and risk analysis assumptions. Inspection activities included, but were not limited to, a review and/or walkdown to assess design measures, seals, drain systems, contingency equipment condition and availability of temporary equipment and barriers, performance and surveillance tests, procedural adequacy, and compensatory measures.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities

Piping Systems ISI

a. Inspection Scope

From February 12-15, 2007, the inspectors conducted a review of the implementation of the licensees ISI program for monitoring degradation of the reactor coolant system boundary, and the risk significant piping system boundaries. The inspectors selected the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI required examinations and Code components in order of risk priority as identified in Section 71111.08-03 of the inspection procedure, based upon the ISI activities available for review during the onsite inspection period.

The inspectors observed ultrasonic examination (UT) of the following welds to evaluate compliance with the ASME Code Section XI requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section XI:

• 12 inch diameter feedwater pipe weld (FWA-J002); and

• 20 inch diameter residual heat removal pipe weld (RHC-F002).

The inspectors observed dye penetrant examination of pipe weld (RHC-F002) to evaluate compliance with the ASME Code Section III and Section V requirements and to verify that indications and defects (if present) were dispositioned in accordance with the ASME Code Section III requirements.

The inspectors reviewed relevant indications identified during a VT-1 examination of a control rod drive cap screw (bolt) during the previous refueling outage (RFO) to determine if the licensees corrective actions and extent of condition reviews were in accordance with the ASME Code Section XI requirements.

The inspectors reviewed pressure boundary weld records for replacement of a section of 18 inch diameter residual heat removal pipe and welded repairs on safety relief valve PSV-4401, to determine if the welding acceptance and preservice examinations (e.g.,

pressure testing, visual, dye penetrant, and weld procedure qualification tensile tests and bend tests) were performed in accordance with ASME Code Sections III, V, IX, and XI requirements.

The inspectors performed a review of ISI related problems that were identified by the licensee and entered into the corrective action program, conducted interviews with licensee staff, and reviewed licensee corrective action records to determine if:

• the licensee had described the scope of the ISI related problems;

• the licensee had established an appropriate threshold for identifying issues;

• the licensee had evaluated industry generic issues related to ISI and pressure boundary integrity; and

• the licensee implemented appropriate corrective actions.

The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

The reviews as discussed above counted as one inspection sample.

1. Unqualified Reactor Vessel Weld Examinations

Introduction:

The inspectors identified a Green NCV of 10 CFR 50.55a(g)4 for failure to complete a Code qualified volumetric examination of the reactor vessel shell welds during the previous RFO 19. Specifically, the licensee used a longer cable length than that used in the UT procedure demonstration, which may have affected the flaw detection capability.

Description:

On February 9, 2007, the inspectors determined that the licensee failed to complete a Code qualified volumetric examination of the reactor vessel shell welds during RFO 19.

The licensee scheduled UT of two reactor vessel vertical shell welds VLA-A001 and VLA-A002 during RFO 20 using procedure ISwT-PDI-AUT1, "Automated Inside Surface Ultrasonic Examination of Ferritic Vessel Wall Greater Than 4.0 Inches in Thickness," Revision 0, Change 0. This procedure was demonstrated by the licensees vendor as capable of detecting rejectable weld flaws in accordance with the ASME Code Section XI, Appendix VIII Supplement 4 and 6 in March of 1996. During this demonstration, the licensees vendor used a maximum of 1018 feet of RG-58 cable with two 40-foot sections of RG-174 cable and a maximum of 13 connectors for examinations of vessel welds less than 7.5 inches thick. The procedure identified the maximum cable lengths and maximum number of connectors as essential procedure variables consistent with requirements of Section XI, Appendix VIII, Article VIII-3130 "Essential Variable Ranges."

On October 5, 2001, the licensees vendor issued interim change notice 1 to ISwT-PDI-AUT1, which allowed 1350 feet maximum of RG-58 cable and 230 feet maximum of RG-174 cable and 20 connectors maximum. The vendor changed these procedure essential variables without performing a procedure demonstration to show that the revised configuration did not adversely affect the capability to detect weld flaws.

The vendor performed a technical justification to support the procedure change which measured and applied bandwidth and center frequency shift criteria from Section XI Appendix VIII Article 4110 "Pulsers, Receivers and Search Units." The inspectors determined that the vendor had inappropriately applied criteria from the ASME Code Section XI Appendix VIII Article 4110 which applied to pulsers, receivers and search units to justify the change in cable configuration. The acceptance criteria of this Code Section considered only the affects of bandwidth and center frequency shift and did not measure changes in the signal-to-noise ratio for the UT system. The inspectors were concerned that the cable changes could degrade the signal-to-noise ratio and adversely effect the flaw detection capability of the UT system.

On March, 12, 2005, the licensee approved ISwT-PDI-AUT1, with interim change notice 1 and failed to identify that the vendor had not met applicable ASME Code requirements and had applied an inappropriate technical justification to accept the increased cable lengths and number of connectors. Consequently, this unqualified procedure was used to examine six vertical reactor vessel shell welds and the vessel shell-to-flange weld on May 12, 2005, during RFO 19. During these weld examinations, the licensees vendor used a cable configuration which included no RG-58 cable and 235 feet of RG-174 cable with 6 cable connectors. With this configuration, the licensee had exceeded the maximum length of RG-174 cable demonstrated for this UT system.

Specifically, the licensees vendor used 235 feet of RG 174 cable during these weld examinations instead of 80 feet of RG-174 cable used during the procedure demonstration.

The licensee entered this issue into the corrective action program (CAP 047205) and concluded that this issue did not call into question the structural integrity or operability of the vessel. The inspectors agreed that this issue did not affect operability with the plant shutdown for a refueling outage and the vessel depressurized. The licensee initially believed that the weld examinations completed were technically satisfactory and on February 15, 2007, the licensee submitted a request to the NRC to approve the non-Code examinations completed for these vessel welds. After further discussions with staff in the Office of Nuclear Reactor Regulation, the licensee withdrew this relief request. On February 19, 2007, the licensee submitted a second relief request to allow deferral of the affected reactor vessel weld examinations until the next RFO.

Analysis:

The inspectors determined that the failure of the licensee to complete a qualified volumetric examination of reactor vessel shell welds was a performance deficiency that warranted a significance evaluation. This finding was of more than minor significance because the finding could be reasonably viewed as a precursor to a significant event involving the ability to detect weld flaws prior to weld failure. In addition, the finding was associated with the Initiating Events cornerstone attribute of "Equipment Performance," and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Absent NRC intervention, the licensee would have relied on an unqualified UT of reactor vessel shell welds for an indefinite period of service, which may have placed reactor coolant pressure boundary welds at increased risk for undetected cracking, leakage, or component failure.

The inspectors applied the IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for the At-Power Situation" to this finding. The inspectors answered "yes" to question 1 of the Initiating Events Cornerstone column of the phase 1 worksheet, which asked "Assuming worst case degradation, would the finding result in exceeding the TS limit for identified reactor coolant system leakage." Specifically, the worst case degradation would be a very large weld crack (e.g., close to the critical crack size as defined by fracture mechanics) connected to the inside diameter, which could propagate under operating pressure induced hoop stress causing a catastrophic failure of the reactor vessel. The SDP worksheet required a phase 2 analysis for this type of finding. However, the phase 2 worksheets did not contain guidance for estimating the risk significance of leakage from the reactor vessel welds that could potentially exceed the leakage rates for a large break design basis loss-of-coolant accident. After consultation with a Region 3 Senior Reactor Analyst, it became apparent that no SDP methods or tools exist to determine the significance of this finding. Because the finding was not suitable for evaluation using the SDP process, the risk significance of this finding was established in accordance with the qualitative criteria of Appendix M of IMC 609. Specifically, the qualitative decision-making attribute from Table 4.1 of Appendix M "Degree of degradation of failed or unavailable components" was applied.

Based on review of industry operational experience, the inspectors did not identify any active degradation mechanisms which affect reactor vessel shell welds. Absent active degradation mechanisms, the inspectors concluded that a structurally significant flaw had not likely developed since completion of the last Code qualified vessel weld UT during the second Code interval (i.e., about 11 years earlier). Therefore, based upon NRC management review using qualitative measures of risk in accordance with Appendix M of IMC 609, the NRC determined that this finding was of very low safety significance (Green).

The inspectors also determined that the cause of this finding was related to the work practices component of the human performance cross-cutting area because the licensee failed to ensure adequate oversight of vendor activities with respect to review of the vendors procedure for examination of reactor vessel welds. Specifically, the licensee approved procedure ISwT-PDI-AUT1 "Automated Inside Surface Ultrasonic Examination of Ferritic Vessel Wall Greater Than 4.0 Inches in Thickness" without adequately understanding and challenging the vendors basis for changing essential procedure variables.

Enforcement:

10 CFR 50.55a(g)4 required in part, that throughout the service life of a boiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2, and 3 must meet requirements of Section XI.

The 1989 Edition, of ASME Code Section XI, Article IWB-2500(a) required that components shall be examined and tested as specified in Table IWB-2500-1.

Table IWB-2500-1 Examination Category B-A items B.1.12 and B.1.30 required, in part, volumetric (e.g., radiographic or ultrasonic examination) of welds.

10 CFR 50.55a(g)(6)(ii)(C)(1) required, in part, that UT be performed in accordance with Appendix VIII and the supplements to Appendix VIII to Section XI, Division 1, 1995 Edition, with the 1996 Addenda.

The 1995 Edition, 1996 Addenda of the ASME Code Section XI, Appendix VIII, Article VIII-3140 "Requalification" states "When a change in an examination procedure causes an essential variable to exceed a qualified range, the examination procedure shall be requalified for the revised range."

ISwT-PDI-AUT1 "Automated Inside Surface Ultrasonic Examination of Ferritic Vessel Wall Greater Than 4.0 Inches in Thickness" Revision 0, Change 0 "List of Essential Variables" identified that the maximum length for RG-174 cable was

(2) 40 foot lengths.

Contrary to the above, on May 12, 2005, the licensee completed a volumetric examination of six reactor vessel vertical shell welds and vessel shell-to-flange weld (Code examination category B-A items B.1.12 and B.1.30) with procedure ISwT-PDI-AUT1 using 235 feet of RG-174 cable which exceeded the

(2) 40 foot lengths of RG-174 without requalification of this procedure for the revised range.

Failure to perform a qualified UT of these vessel welds is a violation of 10 CFR 50.55a(g)4. Because of the very low safety significance of this finding and because the issue was entered into the licensee s corrective action program (CAP 047205), it is being treated as a NCV, consistent with Section VI.A.1 of the Enforcement Policy (NCV 05000331/2007002-01).

2. Unqualified Main Steam Safety Relief Valve Weld Repair

Introduction:

The inspectors identified a Green NCV of 10 CFR 50.55a(g)4 for failure to complete Code qualified weld repairs for the main steam safety relief valve PSV-4401.

Specifically, the weld procedures for this repair were not qualified by performing tensile and guided bend tests intended to demonstrate that the weld procedure produced welds with satisfactory strength and ductility for the intended service.

Description:

On February 15, 2007, the inspectors identified that weld repairs completed on the bellows and pilot valve seat of main steam safety relief valve PSV-4401 did not meet the ASME Section IX Code.

In November of 2004, the licensees vendor completed welded repairs on the PSV-4401 bellows flange-to-base in accordance with Target Rock Corporation weld procedure 889C W-6d and welded repairs on the seat-to-pilot body weld in accordance with Target Rock Corporation weld procedure 889C W-1b. The licensee stated that these procedures were qualified in accordance with the 1968 Edition of the ASME Code Section IX, and that the supporting qualification document was a Target Rock Corporation Metallurgical Test Report dated April 30, 1968. However, this report did not contain "reduced section tensile specimens" and "guided bend test specimens" as required by Article Q-10(b) of Section IX of the ASME Code. These tests were intended to demonstrate that the weld procedure produced welds with satisfactory strength and ductility for the intended service. Without these tests, the inspectors were concerned that the weld repairs affecting the pressure boundary (valve body) could lead to cracking and failure of PSV-4401 or could lead to cracking of the pilot bellows resulting in a nonfunctional relief valve.

The licensees vendor concluded that the 1968 Edition of ASME,Section IX, did not address the types of welds needed in the construction of the safety relief valve design because it only provided requirements for groove and fillet welds. Also, the vendor concluded that the 1968 edition of ASME Section IX did not include base material groupings or filler metal groups for base materials and filler metals used in fabrication of this relief valve. Therefore, the vendor applied the term "Special Welds" for all weld designs that were not groove or fillet with non-Code recognized base/filler materials.

The inspectors noted that the design of the welds for the repairs to the bellows and seat of PSV-4401 in fact, would be consistent with groove or fillet welds as described in Section IX of the ASME Code and the weld filler materials were also identified in Section IX. In any case, the licensees vendor failed to apply the Code requirements as invoked by Article N-522 "Welding Qualifications and Weld Records" of Section III of the ASME Code 1968 Edition. This article required "Each manufacturer or contractor is responsible for the welding done by his organization and shall establish the procedure and conduct the tests required in N-540 and/or in Section IX of the Code to qualify the welding procedures..."

The licensee determined that this issue affected the structural integrity of the SRV pilot bellows and could cause the SRVs to not operate in an overpressure condition and entered this issue into the corrective action program (CAP 047714). The licensee subsequently declared all of the relief valves inoperable, and entered TS 3.4.3 "Safety Relief Valves and Safety Valves" which required the plant to be shutdown in Mode 4.

The licensee extent of condition review determined that this welding procedure applied to the original valve construction and therefore, affected each of the main steam relief valves for Duane Arnold. The licensee stated the corrective action program would include an evaluation step to determine if reporting requirements of 10 CFR Part 21 "Reporting of Defects and Noncompliance," applied to this issue. The inspectors also forwarded this issue to the NRC Vendor Inspection Branch for review.

Analysis:

The inspectors determined that the failure of the licensee staff to identify the non-Code weld repairs completed on main steam relief valve PSV-4401 was a performance deficiency that warranted a significance evaluation. This finding was of more than minor significance because the finding could be reasonably viewed as a precursor to a significant event involving the failure of repair welds from weld flaws introduced by use of an unqualified welding process. In addition, the finding was associated with the Initiating Events cornerstone attribute of "Equipment Performance,"

and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Absent NRC intervention, the licensee would have relied on unqualified weld repairs on PSV-4401 for an indefinite period of service, which may have placed reactor coolant pressure boundary at increased risk for weld failure resulting in leakage, or an inoperable relief valve.

The inspectors applied the IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for the At-Power Situation" to this finding. The inspectors answered "no" to question 1 of the Initiating Events Cornerstone column of the phase 1 worksheet, which asked "Assuming worst case degradation, would the finding result in exceeding the TS limit for identified reactor coolant system leakage." Specifically, the worst case degradation would be a weld repair induced failure of the pilot valve bellows or body, which could propagate under operating pressure induced hoop stress causing a catastrophic failure of the valve. Because the weld repair issue for PSV-4401 was identified prior to repressurizing the plant, this scenario did not occur. Therefore, the inspectors answered "no" to this question and the finding was determined to be of very low safety significance (Green).

The inspectors also determined that the cause of this finding was related to the work practices component of the human performance cross-cutting area because the licensee failed to ensure adequate oversight of vendor activities with respect to review of the vendors weld procedures for repair of reactor coolant pressure boundary retaining components (PSV-4401). Specifically, during review of vendor procedures 889C W-6d and 889C W-1, the licensee did not demonstrate adequate understanding of Code requirements and/or did not sufficiently challenge the vendors basis for not performing weld procedure qualification tests.

Enforcement:

10 CFR 50.55a(g)4 requires in part, that throughout the service life of a boiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2, and 3 must meet requirements of Section XI.

The 1992 Edition, of ASME Code Section XI, Article IWA-4170 required that "Repairs and installation of replacement items shall be performed in accordance with the Owners Design Specification and the original Construction Code of the component or system."

The Owners Design Specification General Electric Specification No. 21A9206 Revision 7 paragraph 4.5.2.1 "Qualification" required "All welding including fillet, seal, repair and attachment welds shall be performed in accordance with written welding procedures. Procedure qualification and welder performance qualification shall be in accordance with ASME Boiler and Pressure Vessel Code,Section IX."

The original Construction Code for PSV-4401, 1968 Edition of Section III, Article N-522 "Welding Qualifications and Weld Records" required "Each manufacturer or contractor is responsible for the welding done by his organization and shall establish the procedure and conduct the tests required in N-540 [required supplemental weld qualification requirements for vessels in addition to those required by Section IX] and/or in Section IX of the Code to qualify the welding procedures..."

The 1968 Edition of Section IX, Article Q-10(b) "Types of Tests Required" states "procedure qualification tests for groove and fillet welds shall be made on groove welds using reduced section tensile specimens and guided bend specimens."

Contrary to the above, on November 11, 2004, repair welds were performed on the pilot seat and bellows of PSV-4401 (reference purchase order P101779) using weld procedures 889C W-1b revision A and 889C W-6d original revision, which had not been qualified by tensile and guided bend specimens. Failure to perform Code qualified weld repairs to main steam relief valve PSV-4401 is a violation of 10 CFR 50.55a(g)4. Because of the very low safety significance of this finding and because the issue was entered into the licensees corrective action program (CAP 047714), it is being treated as a NCV, consistent with Section VI.A.1 of the Enforcement Policy (NCV 05000331/2007002-02).

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed a training crew performance on Simulator Exercise Guide (SEG) 2007A-01 for a total of one sample. The scenario included a trip of the B EDG on overspeed followed by a loss of electrical busses due to a lightening strike. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. The inspection activities assessed the licensees effectiveness in evaluating the requalification program, ensuring that licensed individuals operated the facility safely and within the conditions of their license, and evaluated licensed operators mastery of high-risk operator actions. Inspection activities included, but were not limited to, a review of high risk activities, emergency plan performance, incorporation of lessons learned, clarity and formality of communications, task prioritization, timeliness of actions, alarm response actions, control board operations, procedural adequacy and implementation, supervisory oversight, group dynamics, interpretations of technical specifications, simulator fidelity, and the licensee critique of performance.

The crew performance was compared to licensee management expectations and guidelines as presented in the following documents:

• Administrative Control Procedure (ACP) 110.1, Conduct of Operations, Revision 5;

• ACP 101.01, Procedure Use and Adherence, Revision 40; and

• ACP 101.2, Verification Process and SELF/PEER Checking Practices, Revision 5.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed systems to assess maintenance effectiveness. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. Maintenance activities were reviewed to assess maintenance effectiveness, including maintenance rule activities, work practices, and common cause issues. Inspection activities included, but were not limited to, the licensee's categorization of specific issues including evaluation of maintenance performance criteria, appropriate work practices, identification of common cause errors, extent of condition, and trending of key parameters. Additionally, the inspectors reviewed implementation of the Maintenance Rule (10 CFR 50.65) requirements, including a review of scoping, goal-setting, performance monitoring, short-term and long-term corrective actions, functional failure determinations associated with reviewed condition reports, and current equipment performance status.

The inspectors performed the following maintenance effectiveness reviews for a total of two samples:

C A and B EDGs; and C Primary Containment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees evaluation of plant risk, scheduling, and configuration control. An evaluation of the performance of maintenance associated with planned and emergent work activities was completed by the inspectors to determine if they were adequately managed. In particular, the inspectors reviewed the program for conducting maintenance risk safety assessments and to ensure that the planning, assessment and management of on-line risk was adequate. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. Licensee actions taken in response to increased on-line risk were reviewed including the establishment of compensatory actions, minimizing activity duration, obtaining appropriate management approval, and informing appropriate plant staff. These activities were accomplished when on-line or shutdown risk was increased due to maintenance on risk-significant structures, systems, and components (SSCs).

The following activities were reviewed for a total of four samples:

• The inspectors reviewed the maintenance risk assessment for work planned during the weeks ending January 13 and 27, February 24, and March 17, 2007.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed of the licensees operability evaluations of degraded or non-conforming systems. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. Operability evaluations were reviewed that affected mitigating systems or barrier integrity cornerstones to ensure adequate justification for declaration of operability and that the component or system remained available. Inspection activities included, but were not limited to, a review of the technical adequacy of the evaluation against the TSs, UFSAR, and other design information; validation that appropriate compensatory measures, if needed, were taken; and comparison of each operability evaluation for consistency with the requirements of ACP-114.5, Action Request System and ACP-110.3, Operability Determination.

The inspectors reviewed the following operability evaluations for a total of four samples:

• Jacket Coolant Leak Identified on the A EDG;

• Spurious Average Power Range Monitor (APRM) and Local Power Range Monitor Downscale Alarms;

• SBDG LOOP/LOCA test voltage below USAR value; and

• Both SFUs Declared Inoperable.

1. Failure to Include Acceptance Criteria in Troubleshoot Instruction Form (TIF)

Introduction:

A finding of very low safety significance and an associated NCV of 10 CFR 50 Appendix B, Criterion 5, was identified by the inspectors when engineering and operations personnel failed to include acceptance criteria in a TIF. The failure to include acceptance criteria resulted in operations personnel failing to immediately identify that the SFUs did not meet TS requirements for maintaining positive pressure of

> 0.1 inches water gauge relative to the outside atmosphere during the isolation mode of operation.

Description:

On February 10, 2007, maintenance personnel identified that work order steps were not followed resulting in two penetrations between the cable spreading room and turbine building being opened and not worked in the order planned. This resulted in the integrity of the control building envelope being in question from a period of February 6, when the penetrations were originally opened, to February 10, when the openings were identified and subsequently sealed up.

On February 12 engineering personnel wrote a TIF to determine the effect upon the control building envelope of open penetrations between the cable spreading room and the turbine building. This TIF simulated the previously identified open penetrations by cracking open a door between the cable spreading room and the administrative building and then measuring the control building differential pressure relative to the outside atmosphere. The TIF was completed at approximately 5:46 AM on February 12.

Shortly after the TIF was completed operations personnel recommenced core alterations and fuel moves. At approximately 10:52 AM the Shift Manager reviewed the results of the TIF and identified that the as-left differential pressure between the control building and outside atmosphere was 0.095 inches water gauge. Recognizing that this was less than the TS limit, the Shift Manager declared both SFUs inoperable and stopped all core alterations and fuel moves.

Analysis:

The inspectors determined that the failure to include acceptance criteria within the TIF was a performance deficiency warranting further evaluation. The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Disposition Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the issue was more than minor because the finding affects the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical barriers (containment) protect the public from radio nuclide release caused by accidents and events. Specifically, the design control attribute for maintaining functionality of the control room.

The inspectors reviewed this finding in accordance with IMC 0609 Appendix G, Shutdown Operations Significance Determination Process. Using checklist 7, BWR Refueling Operation with Reactor Coolant System Level > 23' above the Flange, the finding was determined to affect the containment shutdown safety function identified in NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management.

The finding did not require a phase 2 quantitative assessment and was therefore considered to be of very low safety significance (Green).

The inspectors also determined that the cause of this finding was related to the work control component of the human performance cross-cutting area because engineering and operations personnel failed to appropriately coordinate work activities by communicating, coordinating, and cooperating with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance.

Enforcement:

10 CFR 50 Appendix B, Criterion 5, Instructions, Procedures, and Drawings, requires that procedures shall include appropriate qualitative acceptance criteria. Contrary to this requirement, the TIF used to test the Control Building Envelope did not include appropriate acceptance criteria to identify that the TS requirement for maintaining positive pressure relative to the outside atmosphere was not met. This resulted in operators recommencing fuel moves and core alterations with both standby filter units inoperable. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000331/2007002-03). The licensee entered this issue into their corrective action program as CAP 047315 and returned both SFUs to operable status.

2. CAP 047315, Control Building Envelope Inoperable

On February 10 maintenance personnel identified that work order steps were not followed resulting in two penetrations between the cable spreading room and turbine building being opened and not worked in the order planned. This resulted in the integrity of the control building envelope being in question from a period of February 6, when the penetrations were originally opened, to February 10, when the openings were identified and subsequently sealed up.

On February 12 engineering personnel wrote a TIF to determine the effect upon the control building envelope of open penetrations between the cable spreading room and the turbine building. This TIF simulated the previously identified open penetrations by cracking open a door between the cable spreading room and the administrative building and then measuring the control building differential pressure relative to the outside atmosphere. This TIF revealed that the SFUs did not meet TS requirements for maintaining positive pressure of > 0.1 inches water gauge relative to the outside atmosphere during the isolation mode of operation.

The licensee entered an action item in their corrective action program, CAP 047315, to determine if the TIF performed accurately recreated the conditions of the original configuration identified when penetrations were inadvertently opened between the control building and turbine building. This evaluation will also determine the effect upon the control building envelope of three 6 inch holes that were temporarily created between the control room and cable spreading room (both of which are inside the control building envelope) while installing new cabling. Pending a review of the apparent cause evaluation and condition evaluation for the control building envelope inoperability, this issue is considered unresolved. (URI 05000331/2007002-04).

1R17 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed one permanent plant modification. The documents listed in the Attachment were reviewed to accomplish the objectives of the inspection procedure.

The inspectors focused on verification that the design bases, licensing basis, and performance capability of related SSCs were not degraded by the installation of the modification. The inspectors also verified that the modifications did not place the plant in an unsafe configuration. The inspection activities included, but were not limited to, a review of the design adequacy of the modification by performing a review, or partial review, of the modifications impact on plant electrical requirements, material requirements and replacement components, response time, control signals, equipment protection, operation, failure modes, and other related process requirements.

The inspectors reviewed the following permanent plant modification for a total of one sample:

• High Pressure Coolant Injection (HPCI) High Pressure Keep Fill System, Engineering Change Package 1797

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed post-maintenance testing (PMT) activities. The documents listed in the Attachment were used to accomplish the objectives of the inspection procedure. PMT procedures and activities were verified to be adequate to ensure system operability and functional capability. Inspection activities were selected based upon the SSCs ability to impact risk. Inspection activities included, but were not limited to, witnessing or reviewing the integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use and compliance, control of temporary modifications or jumpers required for test performance, documentation of test data, system restoration, and evaluation of test data. Also, the inspectors verified that maintenance and PMT activities adequately ensured that the equipment met the licensing basis, TS, and UFSAR design requirements.

The inspectors selected the following PMT activities for review for a total of five samples:

• Preventive Work Order 1137741, Test Molded Case Circuit Breakers in 1B42;

• Corrective Work Order (CWO) A79462/A79463, Inspect Current Transformers and Voltage Regulator Components in 1C93 (A SBDG)/1C94 (B SBDG);

• CWO A64524, Relay C71A-K008D [RPS Trip Channel B2 Turbine CV-4 Fast Closure Relay] Replacement Due to Excessive Vibrating and Buzzing Noise;

• Surveillance Test Procedure (STP) 3.6.1.1-02, Primary Containment Integrated Leak Rate Test; and

• STP NS520004, HPCI Overspeed Trip Test.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage

a. Inspection Scope

The inspectors observed outage activities for Scheduled Refueling Outage Number 20 during this inspection period. The entire Refueling Outage, which began on February 3 and ended on March 18, will count as a total of one sample. Outage configuration management was also monitored on a daily basis by verifying that the licensee maintained appropriate defense in depth to address all shutdown safety functions and satisfy TS requirements, thereby ensuring that the licensee considered risk in developing, planning, and implementing the outage schedule. In addition, proper operation of the decay heat removal system was reviewed during multiple reactor building and control room tours and observations.

The inspectors observed or reviewed electrical lineups, selected clearances, control of containment activities, identification and resolution of problems associated with the outage, and the reactor startup and heatup. The licensee restarted the reactor on March 15, 2007. The documents listed in the Attachment were used to accomplish the objectives of the inspection procedure.

b. Findings

No findings of significance were identified.

.2 Forced Outage Due to RCS Chemistry Excursion During Power Ascension

a. Inspection Scope

During the post refueling outage power ascension activities on March 18, the licensee inserted a manual reactor scram to shutdown the reactor for a forced outage, due to a substantial chemistry excursion caused by an apparent resin intrusion from the condensate demineralizers. A plant cooldown to less than 200 degrees F was performed following the shutdown. Activities monitored by the inspectors included the licensees cooldown process and that TSs were followed during the transition into Modes three and four. Proper operation of the decay heat removal system was reviewed during multiple reactor building and control room tours and observations.

Outage configuration management was also monitored on a daily basis by verifying that the licensee maintained appropriate defense in depth to address all shutdown safety functions and satisfy TS requirements. This counts as one inspection sample.

The reactor was restarted on March 20, following restoration of the chemistry parameters, and the generator connected to the grid on March 22. The documents listed in the Attachment were used to accomplish the objectives of the inspection procedure.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed surveillance test activities. Inspection procedure objectives were accomplished as indicated by the documents listed in the Attachment to this inspection report. Surveillance testing activities were reviewed to assess operational readiness and ensure that risk-significant SSCs were capable of performing their intended safety function. Surveillance activities were selected based upon risk significance and the potential risk impact from an unidentified deficiency or performance degradation that a SSC could impose on the unit if the condition were left unresolved.

Inspection activities included, but were not limited to, a review for preconditioning, integration of testing activities, applicability of acceptance criteria, test equipment calibration and control, procedural use, control of temporary modifications or jumpers required for test performance, documentation of test data, TS applicability, impact of testing relative to Performance Indicator (PI) reporting, and evaluation of test data.

The inspectors selected the following surveillance testing activities for review for a total of seven samples:

• STP 3.3.8.2-01, Reactor Protection System (RPS) Motor Generator Set and alternate Power Source Electrical Protection Assembly Channel Calibration (routine);

• STP NS510001, Core Spray Check Valve Operability Test - Refueling (inservice testing);

• STP 3.8.1-07, Loss Of Offsite Power/Loss Of Coolant Accident Test for B SBDG (routine);

• STP 3.3.5.1-30, HPCI System Logic System Functional Test (routine);

• STP 3.3.6.1-49, HPCI System Isolation Logic System Functional Test (routine);

• STP 3.6.2.4-01, Drywell and Torus Spray Headers and Nozzles Functional Test (routine);

• STP 3.1.4-01, Scram Insertion Time Test (routine).

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Review of Licensee Performance Indicators for the Occupational Exposure Cornerstone

a. Inspection Scope

The inspectors reviewed the licensees occupational exposure control cornerstone PIs to determine whether or not the conditions surrounding the PIs had been evaluated and identified problems had been entered into the corrective action program for resolution.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

.2 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following three radiologically significant work areas within radiation areas, high radiation areas (HRAs),and airborne radioactivity areas in the plant and reviewed work packages which included associated licensee controls and surveys of these areas to determine if radiological controls including surveys, postings, and barricades were acceptable:

• Refuel Floor ISI activities;

• Drywell Nozzle ISI; and

• Diving Refuel Floor/Reactor Vessel Sparger Repair.

The inspectors reviewed the radiation work permits (RWPs) and work packages used to access these three areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed.

The inspectors walked down and surveyed using a survey meter these three areas to verify that the RWP, procedure, and engineering controls were in place, that licensee surveys and postings were complete and accurate, and that air samplers were properly located.

The inspectors reviewed RWPs for any airborne radioactivity areas that existed during the inspection to verify barrier integrity and engineering controls performance (e.g., high efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent. There were no airborne radioactivity areas in the plant during this outage. Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and provided appropriate worker protection.

This review represented four inspection samples

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, Licensee Event Reports, and Special Reports related to the access control program to verify that identified problems were entered into the corrective action program for resolution.

The inspectors reviewed nine CAP reports related to access controls and two high radiation area radiological incidents (non-performance indicators identified by the licensee in high radiation areas less than 1R/hr). Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

• Resolution of NCVs tracked in the corrective action system; and

• Implementation/consideration of risk significant operational experience feedback.

The inspectors evaluated the licensees process for problem identification, characterization, prioritization, and verified that problems were entered into the corrective action program and resolved. For repetitive deficiencies and/or significant individual deficiencies in problem identification and resolution, the inspectors verified that the licensees self-assessment activities were capable of identifying and addressing these deficiencies The inspectors reviewed licensee documentation packages for all PI events occurring since the last inspection to determine if any of these PI events involved dose rates greater than 25 R/hr at 30 centimeters or greater than 500 R/hr at 1 meter. Barriers were evaluated for failure and to determine if there were any barriers left to prevent personnel access. There were no PI events occurring since the last inspection.

These reviews represented four inspection samples

b. Findings

No findings of significance were identified.

.4 Job-In-Progress Reviews and Review of Work Practices in Radiologically Significant

Areas

a. Inspection Scope

The inspectors accompanied radiation protection and outage contractor maintenance staff in areas of the:

(1) dry well (posted and locked HRAs), and

(2) reactor building torus room and condenser areas (posted HRAs) to assess the adequacy of the radiological controls implemented in these areas. In addition, the inspectors evaluated the licensees radiological controls, job coverage and radiation worker practices during outage work activities in other areas of the plant. Radiation survey information to support these work activities was reviewed by inspectors, and the radiological job requirements and the access control provisions for these areas was assessed for conformity with TIs and with the licensees procedures. The inspectors also attended the pre-job briefings for these activities to assess the adequacy of the information exchanged.

Job performance was observed to determine if radiological conditions in the work areas were adequately communicated to workers through the pre-job briefings and area postings. The inspectors also evaluated the adequacy of the oversight provided by the radiation protection staff including the performance of radiological surveys and air sampling, the work oversight provided by the radiation protection technicians (RPTs),and the administrative and physical controls used over ingress/egress into these areas.

The inspectors reviewed the licensees procedures and discussed with radiation protection (RP) staff its practices for access into locked high and very high radiation areas and for areas with the potential for changing radiological conditions such as the dry well. This included review of the circumstances and consequences associated with workers staging welding machines in a torus room, a high radiation area entry incident that occurred on February 8, 2007. These reviews were conducted to determine the adequacy of the radiological controls and the radiological hazards assessment associated with such entries. Work instructions provided in RWPs and in pre-entry briefing documents were discussed with RP staff to determine their adequacy relative to industry practices and NRC Information Notices.

The inspectors also reviewed the licensees procedure and generic practices associated with dosimetry placement and the use of multiple whole body dosimetry for work in high radiation areas having significant dose gradients for compliance with the requirements of 10 CFR 20.1201(c) and applicable industry guidelines. Additionally, previously completed work in areas where dose rate gradients were subject to significant variation such as work under-vessel were reviewed to evaluate the licensees practices for dosimetry placement.

These reviews represented three inspection samples.

b. Findings

Introduction:

A self-revealed finding of very low safety significance and an associated NCV of NRC requirements were identified for the failure to satisfy TS requirements for worker access into a HRA with dose rates between 100 and 1000 mrem/hour at 30 centimeters. Workers entered a HRA without adequate recognition of the radiological conditions and without adequate radiological job coverage. The licensee was alerted to the problem when the ED worn by one of the workers alarmed.

Description:

On February 8, 2007, five contract pipe fitters (workers) were in the process of staging welding machines in the torus room. The workers were informed by radiation protection (RP) staff that they should use the SECR to enter the torus room, since that would be the closest approach to the torus area destination. The RP personnel advised the workers that they needed approval from operations to enter the SECR because it was a protected area. The workers proceeded to get approval for entry into the torus room; however, the operations personnel in the Work Control Center did not approve the workers to go through the SECR until it was cleared by the operations supervisor. Meanwhile, the workers staged the welding machines and equipment near the NWCR (designated as Room No. 226, as listed on the door), a room that was posted and controlled as a high radiation area. After about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> elapsed, the workers returned to the Work Control Center and obtained approval to enter Room No. 226. The workers then proceeded to the RP desk and were authorized by RP staff to transit through door No. 226 because the RP staff erroneously presumed that door led to the SECR and was a route previously approved. The workers then entered the NWCR, which was posted HRA. These workers were logged onto a general RWP with dose/dose rate alarm setpoints lower than those for a HRA. As a result, one of the workers received a dose rate alarm prompting the crew to vacate the area. The worker reported the ED alarm to the RP personnel. The recorded workers ED dose was one mrem.

Technical Specification 5.7.1, requires that an entry into HRAs with dose rates between 100 and 1000 mrem/hr at 30 centimeters be made only after dose rates in the area have been determined and the personnel entering the area are knowledgeable of the dose rates. In addition, these personnel will receive a pre-job briefing prior to entering into such areas. Specifically, on February 8, 2007, workers entered the NWCR, a posted HRA without the knowledge of the dose rates in the area and these workers did not receive a pre-job briefing. This resulted in the ED worn by one of the workers to alarm when significantly higher than expected dose rates were encountered.

Analysis:

This failure to satisfy TS HRA entry requirements represents a performance deficiency as defined in NRC IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening. The inspectors determined that the issue was associated with the Program/Process attribute of the Occupational Radiation Safety Cornerstone and affected the cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation. Therefore, the issue was more than minor and represented a finding which was evaluated using the SDP.

Since the finding involved a high radiation area radiological control issue, the inspectors utilized IMC 0609, Appendix C, Occupational Radiation Safety SDP, to assess its significance. Based on the radiological conditions in the area coupled with the workers response to the ED alarm, the inspectors determined that no overexposure occurred nor did a substantial potential for an overexposure exist. The licensees ability to assess dose was also not compromised for this incident. Consequently, the inspectors concluded that the SDP assessment for this finding was of very low safety significance (Green).

The inspectors identified a cross-cutting aspect in the area of human performance associated with this finding in the work practices component. Specifically, the licensee failed to hold an effective pre-job briefing and implement effective self and peer checking commensurate with the risk of the assigned task, such that work activities are performed safely.

In addition, the inspectors evaluated the event at the time it occurred to determine if the licensee correctly determined those factors that contributed to it. The corrective actions taken by the licensee were adequate; however, following the inspection, the licensee planned to re-evaluate its practices for HRA entries.

Enforcement:

TS 5.7.1, High Radiation Area Entry, requires that radiological conditions of HRAs be established and personnel made aware of these conditions prior to entry and/or an RP qualified individual equipped with a radiation survey instrument provide positive control over the activities in the area and perform periodic radiation surveillance.

Contrary to these requirements, on February 8, 2007, as described in the above paragraphs, workers entered into an area with dose rates between 100 and 1000 mrem/hour and none of the entry options required by the TS were met.

Corrective actions taken by the licensee included reminding the staff during outage briefings to better coordinate entries into these areas with the operations department, and plans to reevaluate the radiation protection department practices for entry into HRAs. Since the licensee documented this issue in its corrective action program (CAP 047125) and planned to complete an Apparent Cause Evaluation (ACE No. 001678) by March 10, 2007, and because the violation is of very low safety significance, it is being treated as a NCV (NCV 05000331/2007002-05).

.5 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, of the RWP controls and limits in place, and that their performance had accounted for the level of radiological hazards present.

The inspectors reviewed radiological problem reports which found that the cause of the event was due to radiation worker errors to determine if there was an observable pattern traceable to a similar cause and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. These problems, along with planned and taken corrective actions, were discussed with the Radiation Protection Manager.

These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.

.6 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated RPT performance with respect to radiation protection work requirements and evaluated whether they were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports which found that the cause of the event was radiation protection technician error to determine if there was an observable pattern traceable to a similar cause and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.

2OS2 As Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls (71121.02)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed plant collective exposure history and current exposure trends, along with ongoing and planned outage activities, in order to assess current performance and exposure challenges. This included reviewing the plants current 3-year rolling average collective exposure and comparing the sites radiological exposure on a yearly basis for the previous 3 years.

The inspectors reviewed the outage work activities scheduled during the inspection period along with associated work activity exposure estimates, including the five-work activities which were likely to result in the highest personnel collective exposures.

Procedures associated with maintaining occupational exposures ALARA and processes used to estimate and track work activity specific exposures were reviewed.

These reviews represented three inspection samples.

b. Findings

No findings of significance were identified.

.2 Radiological Work Planning.

a. Inspection Scope

The inspectors evaluated the licensees list of work activities, ranked by estimated exposure, that were in progress and selected the five work activities of highest exposure potential.

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements, in order to determine if the licensee had established procedures, along with engineering and work controls, that were based on sound radiation protection principles, in order to achieve occupational exposures that were ALARA. This also involved determining if the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, or special circumstances.

These reviews represented two inspection samples.

b. Findings

No findings of significance were identified.

.3 Job Site Inspections and ALARA Controls

a. Inspection Scope

The inspectors observed the following four jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

• drywell cooler maintenance and support work;

• main steam safety valve and safety/relief valve maintenance and associated support;

• control rod drive under vessel preparations in drywell; and

• ISI exam and associated support work.

The licensees use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensees ALARA reviews, that sufficient shielding of radiation sources was provided for, and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

.4 Radiation Worker Performance

a. Inspection Scope

Radiation worker and RPT performance was observed during work activities being performed in radiation areas, airborne radioactivity areas, and HRAs that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dose waiting areas, and by complying with work activity controls.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

.5 Problem Identification and Resolution

a. Inspection Scope

The inspectors assessed the adequacy of the licensees problem identification processes and verified that identified problems were entered into the corrective action program for resolution.

Corrective action reports generated during the licensees outage (RFO-20) that related to the ALARA program were selectively reviewed, and staff members were interviewed to verify that follow-up activities were being conducted in a timely manner commensurate with their importance to safety and risk using the following criteria:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes; and

• Identification and implementation of effective corrective actions.

The licensees corrective action program was also reviewed to determine if repetitive deficiencies in problem identification and resolution were being addressed.

This review represented one inspection sample.

b. Findings

During the inspection the week of February 12, 2007, the inspectors reviewed a corrective action program (CAP 047066) document that described a contractor/supervisor moving reactor cavity lights from the spent fuel pool (SFP) to the reactor cavity without notifying the health physics technician. Based on the information provided by the licensee and additional information obtained during the inspection, this issue remains under review by the NRC and is categorized as an Unresolved Item (URI), (URI 05000331/2007002-06).

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

For inspections performed and documented in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Minor issues entered into the corrective action program as a result of the inspectors observations are included in the attached list of documents reviewed.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

b. Findings

No findings of significance were identified.

3. Corrective Actions Associated with an Operable but Nonconforming Condition of the

Emergency Diesel Generators (EDGs)

a. Scope

The inspectors reviewed the licensees corrective actions associated with corrective action program document operable but degraded (OBD) 000258, Calculations CAL-E02-003 shows EDG Voltage Dips Less that UFSAR/Regulatory Guide 1.9 Required, and associated corrective action program documents to assess the licensees corrective actions associated with an operable but nonconforming condition on the EDGs. This review constituted one problem identification and resolution annual inspection sample.

The inspectors reviewed the corrective action documentation listed in Attachment 1 and interviewed engineering personnel to assess the effectiveness and adequacy of the licensees efforts to correct the identified problem. The inspectors focused their review on the effectiveness of the licensees corrective actions taken to address the conditions identified including the operability evaluation, the extent of condition analysis, and the prioritization of the corrective actions. Additionally, the inspectors compared these elements to the requirements of the licensees corrective action program.

b. Findings

Introduction:

A finding of very low safety significance and an associated NCV of 10 CFR 50 Appendix B, Criterion 16, was identified by the inspectors when the licensee failed to take prompt corrective action to repair an operable but nonconforming condition on the A and B EDGs. The UFSAR states that the output voltage of the EDG shall not drop below 75 percent of nominal with the exception of the initial loading. The licensee failed to correct the nonconforming condition on the EDGs during the first available opportunity, which was the refueling outage that occurred in the first quarter of 2007.

Description:

On December 7, 2005, engineering personnel identified that during testing to simulate a LOOP/LOCA, the output voltage of the EDGs momentarily dropped below 75 percent of nominal voltage during the loading sequence of the EDG. The UFSAR states that the output voltage of the EDG shall not drop below 75 percent of nominal with the exception of the initial loading. At the time of discovery, the licensee entered this operable but nonconforming condition into their corrective action program as CAP 039229. An operability evaluation was performed (OPR 303) to document that the EDGs were operable but non-conforming since they did not meet the requirements of the UFSAR.

OPR 303 identified seven previous instances where, during LOOP/LOCA testing, the voltage dips were below the 75 percent limit of the UFSAR during the second, third, or fourth loads being put on the EDG. On March 1, 2006, CAP 040658 was added to the licensees corrective action program to document that there were no CAPs written for the previously instances identified in OPR 303. A revision to the LOOP/LOCA STP was made to document any further instances of voltage dips less that 75 percent in a CAP.

During the refueling outage performed during the first quarter of 2007, the engineering and maintenance groups performed retuning of the EDGs voltage regulators to correct the operable but nonconforming condition. During subsequent LOOP/LOCA testing, both the A and B EDGs again exhibited voltage dips less that 75 percent of nominal during loading of the EDGs. The engineering group revised OPR 303 to document that both EDGs were operable but were still not conforming to the requirements of the UFSAR. This operable but nonconforming condition is being tracked in the licensees corrective action program as ODB 258. No further maintenance was performed on the A or B EDGs to remedy the operable but nonconforming condition prior to plant restart from the refueling outage.

Analysis:

The inspectors determined that the failure to take prompt corrective action was a performance deficiency warranting further evaluation. The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Disposition Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the issue was more than minor because the finding affects the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors reviewed this finding in accordance with IMC 0609 Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations.

This issue screened as having a very low safety significance (Green) since the finding is a design deficiency confirmed not to result in a loss of operability per the part 9900 technical guidance for operability determination process for operability and functional assessment.

Enforcement:

10 CFR 50 Appendix B, Criterion 16, Corrective Action, states that measures shall be established to assure that conditions adverse to quality, such as deficiencies and nonconformances are promptly corrected. Contrary to this requirement, a non-conformance that was identified in December of 2005 was not corrected at the first available opportunity during refueling outage 20 in the first quarter of 2007. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000331/2007002-07). The licensee entered this issue into their corrective action program as CA 45351 and continue to track the operable but nonconforming condition until it is fixed at the next available opportunity.

4OA3 Event Follow-up

.1 Review of Personnel Performance for HPCI and Primary Containment Being Declared

Inoperable due to Missing Pipe Clamp Bolt

a. Inspection Scope

The inspectors reviewed the site response and personnel performance during an unplanned event when HPCI and Primary Containment were declared inoperable on January 24, 2007. During a pre-outage inspection of the HPCI system injection line pipe support, it was identified that one of the two pipe clamp bolts was missing. This rendered the HPCI system and Primary Containment inoperable. The missing bolt was replaced and the HPCI system and Primary Containment were subsequently declared operable. The inspectors observed the operator response, repair activities, and the documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. This review represented one sample.

b. Findings

No findings of significance were identified.

.2 Observation of Personnel Performance During Planned Non-Routine Evolution: Plant

Shutdown for Refueling Outage

a. Inspection Scope

The inspectors observed personnel performance during a planned non-routine evolution when the plant was shut down for the commencement of refueling outage 20. The inspectors observed the operators manipulation of the plant, including shutting down the reactor and taking the main generator offline. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure.

This review represented one sample.

b. Findings

No findings of significance were identified.

.3 Observation of Personnel Performance During Planned Non-Routine Evolution: Diving

Operations in the Reactor Vessel to Repair Feedwater Sparger Pin Keeper and End Bracket Support

a. Inspection Scope

The inspectors observed personnel performance during a planned non-routine evolution when the licensee identified a damaged feedwater sparger pin keeper and worn end bracket support. The inspectors observed the work planning, ALARA planning, pre-job briefing activities, and the diving work performed. The documents listed in the were used by the inspectors to accomplish the objectives of the inspection procedure. This review represented one sample.

b. Findings

No findings of significance were identified.

.4 Observation of Personnel Performance During Planned Non-Routine Evolution: Weld

Repairs for Degraded Primary Coolant System Components Structural Integrity Due to Material Defects Which Cannot be Found Acceptable Under ASME Section XI

a. Inspection Scope

The inspectors reviewed the site response and personnel performance during planned non-routine evolutions to perform weld overlay repairs to two recirculation system riser nozzle to safe-end welds. On February 19 and 21, 2007, the results from the phased-array UT examinations of the recirculation system F and C riser nozzles revealed that the welds contained linear indications and through wall extents which could not be found acceptable under ASME Code Section XI, for structural integrity. The licensees evaluation of these conditions required horizontal weld overlays repairs to be performed to restore the primary coolant system structural integrity. The inspectors observed the work planning and ALARA planning, the equipment staging and pre-job briefing activities, the actual weld repairs performed, and the post maintenance non-destructive testing of the weld overlays. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. This review represented one sample.

b. Findings

No findings of significance were identified.

.5 Ice Storm and Loss of Five of Six Offsite Power Sources

a. Inspection Scope

The inspectors reviewed personnel performance during an unplanned non-routine evolution when, on February 24, 2007, severe weather caused a loss of five of six offsite power sources at the DAEC. The inspectors communicated with operators during the severe weather to assess plant conditions and remain apprized of plant conditions. The inspectors also inspected shift logs and records to review personnel performance during the severe weather conditions. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. This review represented one sample.

b. Findings

No findings of significance were identified.

.6 Automatic Scram during Surveillance Testing for Backup Scram Valves

a. Scope

The inspectors reviewed the circumstances surrounding an unplanned reactor scram received during surveillance testing for backup scram valves (SV)-1840A and SV-1840B. A review of the STP, shift logs, and NRC event notification were performed by the inspectors. The documents listed in the Attachment were used by the inspectors to accomplish the objectives of the inspection procedure. This review represented one sample.

b. Findings

Introduction:

A finding of very low safety significance and an associated NCV of 10 CFR 50 Appendix B, Criterion 5, was self-revealed when an unplanned RPS reactor scram occurred during surveillance testing due to a scram discharge volume high level.

The failure to include steps in the surveillance test procedure to bypass the SDV high level scram resulted in an unanticipated automatic RPS scram being inserted due to a SDV high level.

Description:

On March 2, 2007, operations personnel were performing STP NS550002 to verify that the backup scram valves port air when a scram occurs. With the reactor already shutdown for a refueling outage, an operator in the control room inserted a manual reactor scram to support the test. An operator in the reactor building verified that the backup scram valves ported air. After the verification was complete, the operator in the control room was preparing to reset the scram per the STP when the SDV not drained alarm was received. Knowing that resetting the scram would open the vent and drain valves for the SDV, the operator in the control room reset the scram.

Shortly thereafter an automatic RPS scram occurred due to a high SDV level. Because the reactor was already shutdown, no rods were inserted. The operators bypassed the SDV high level scram, and reset the scram.

Subsequent investigation identified that the time it took for the SDV vent and drain valves to open and commence draining following the scram reset exceeded the time it took for the water continuing to discharge to the SDV through the control rod drive mechanisms to reach the SDV high level. As a result, an automatic reactor scram occurred. It was also identified that the procedure did not include any precautions related to the potential SDV high level scram or include any guidance to bypass the SDV high level scram prior to resetting the manually inserted scram. Contributing causes to this event include a failure of the operators to recognize the potential for a SDV high level scram during the pre-job brief and the performance of the STP.

Analysis:

The inspectors determined that the unplanned automatic RPS scram was a performance deficiency warranting further evaluation. The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Disposition Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the issue was more than minor because the finding affects the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown operations. Specifically, the human performance attribute as well as the configuration control attribute for controlling the shutdown equipment lineup were affected.

The inspectors reviewed this finding in accordance with IMC 0609 Appendix G, Shutdown Operations Significance Determination Process. Using checklist 7, BWR Refueling Operation with Reactor Coolant System Level > 23' above the Flange, the finding was determined to be of very low safety significance because it did not impact any of the 5 shutdown safety functions identified in NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management. The finding was therefore considered to be of very low safety significance (Green).

The inspectors also determined that the cause of this finding was related to the work practices component of the human performance cross-cutting area because operations personnel failed to communicate human error prevention techniques, such as holding pre-job briefings, self and peer checking, and proper documentation of activities during performance of the surveillance testing.

Enforcement:

10 CFR 50 Appendix B, Criterion 5, Instructions, Procedures, and Drawings, requires that activities affecting quality shall be prescribed by documented instructions and procedures of a type appropriate to the circumstances. Contrary to this requirement, the STP did not include direction to bypass the SDV high level scram prior to resetting the scram that was manually inserted during the surveillance test. This resulted in an unplanned RPS scram due to a SDV high level. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000331/2007002-08). The licensee entered this issue into their corrective action program as CAP 048038 and has a corrective action in place revise the STP to include guidance on bypassing the SDV high level scram prior to resetting the manually inserted scram.

.7 (Closed) LER 50-331/2006-005-00: Reactor Scram During Main Turbine Testing

On November 6, 2006, with the plant operating at approximately 99 percent reactor power in Mode 1, during the performance of the Main Turbine Operational Tests, STP NS93001, Section 7.3, Overspeed Trip Device and Mechanical Trip Valve Test (Test A), a reactor scram occurred. The scram was initiated by a Reactor Protection System actuation due to the Turbine Stop Valves being less than 90 percent open.

The licensees analysis of the key plant responses evaluated this condition to be of very low safety significance since the plants actual response (all safety-related equipment functioned as expected and no safety/relief valves opened) was milder and bounded by the analyzed turbine trip with bypass event, and there were no actual safety consequences or effect on public health and safety. The licensee attributed the cause of the Turbine Stop Valve closure to be an electronic noise spike, which was permitted to reach the normally defeated control circuit through the closed contacts of a normally open mercury-wetted relay. The spike generated a speed error signal in excess of 5 percent that started closing the Turbine Stop Valves. Corrective actions taken by the licensee during troubleshooting included replacement of the mercury-wetted relay boards in the main turbine overspeed control circuit, replacement of the mechanical trip valve switch cable, and burnishing the contacts in the main turbine mechanical trip interlock switch. Additionally, all front standard wiring between the junction box and the field devices, as well as the cabling between the junction box and the back panel in the control room, were replaced during the refueling outage.

The LER was reviewed by the inspectors and no finding of significance were identified.

The licensee entered this issue into their corrective action program as CAP 045248.

4OA5 Other Activities

.1 Correction of Typographical Error

NRC Inspection Report 05000331/2006005 incorrectly stated in section 4OA5.3 that URI 05000331/2004006-03, Station Blackout Coping Analysis, was closed. The correct number for the URI closed is URI 05000331/2004006-01, Station Blackout Coping

Analysis.

URI 05000331/2004006-03, HPCI Pump Discharge Piping Hydraulic Transient Susceptibility, was previously closed in Inspection Report 05000331/2005010.

4OA6 Meetings

.1 Exit Meeting

The inspectors presented the inspection results to Mr. G. Van Middlesworth and other members of DAEC management on April 5, 2007. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meetings

Interim exit meetings were conducted for:

• Procedure 7111108 with Mr. Van Middlesworth and other members of licensee management at the conclusion of the inspection on February 15, 2007, and by phone exit meeting on February 22, 2007. The inspectors returned proprietary information reviewed during the inspection and the licensee confirmed that none of the potential report input discussed was considered proprietary.

• Access control to radiologically significant areas and the ALARA planning and controls program with Mr. D. Curtland, Plant Manager, on February 16, 2007.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

G. Van Middlesworth, Site Vice President

J. Bjorseth, Site Director

D. Curtland, Plant Manager

S. Catron, Licensing Manager

S. Haller, Site Engineering Director

B. Kindred, Security Manager

J. Morris, Training Manager

D. Blair, Operations Manager

G. Pry, Maintenance Manager

J. Windschill, Chemistry & Radiation Protection Manager

P. Sullivan, Emergency Preparedness Manager

Nuclear Regulatory Commission

Rick Ennis, Project Manager, NRR

Karl Feintuck, Project Manager, NRR

Bruce Burgess, Chief, Reactor Projects Branch 2

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000331/2007002-01 NCV Failure to perform Qualified UT of Reactor Vessel Shell Welds (Section 1R08.b.1)

05000331/2007002-02 NCV Unqualified Main Steam Safety Relief Valve Weld Repair (Section 1R08.b.2)

05000331/2007002-03 NCV Failure to Include Acceptance Criteria in Troubleshooting Instruction Form for Control Building Standby Filter Unit Testing (Section 1R15.b.1)

05000331/2007002-04 URI Control Building Envelope Inoperable (Section 1R15.2)

05000331/2007002-05 NCV Workers inappropriately entered a High Radiation Area (Section 20S1.4)

05000331/2007002-06 URI Contractor/Supervisor Moving Reactor Cavity Lights from the Spent Fuel Pool to the Reactor Cavity Without Notifying the Health Physics Technician (Section 20S2.5)

05000331/2007002-07 NCV Failure to Take Prompt Corrective Action to Correct an Operable but Nonconforming Condition on the Emergency Diesel Generators (Section 40A2.3)

Attachment

05000331/2007002-08 NCV Unplanned Reactor Protection System Automatic Scram Due to Inadequate Procedure (Section 40A3.6)

Closed

05000331/2007002-01 NCV Failure to perform Qualified UT of Reactor Vessel Shell Welds (Section 1R08.b.1)

05000331/2007002-02 NCV Unqualified Main Steam Safety Relief Valve Weld Repair (Section 1R08.b.2)

05000331/2007002-03 NCV Failure to Include Acceptance Criteria in Troubleshooting Instruction Form for Control Building Standby Filter Unit Testing (Section 1R15.b.1)

05000331/2007002-05 NCV Workers inappropriately Entered a High Radiation Area (Section 20S1.4)

05000331/2007002-07 NCV Failure to Take Prompt Corrective Action to Correct an Operable but Nonconforming Condition on the Emergency Diesel Generators (Section 40A2.3)

05000331/2007002-08 NCV Unplanned Reactor Protection System Automatic Scram Due to Inadequate Procedure (Section 40A3.6)

05000331/2006005-00 LER Reactor Scram During Main Turbine Testing (Section 40A3.7)

Discussed

05000331/2004006-01 URI Station Blackout Coping Analysis (Section 40A5.1)

Attachment