IR 05000382/2006012

IR 05000382-06-012; Entergy Operations, Inc; 12/4/2006 - 02/12/2007; Waterford Steam Electric Station, Unit 3; Inservice Inspection Activities, Inspection Procedure 71111.08

ML070660153
Person / Time
Site:	Waterford
Issue date:	03/05/2007
From:	William Jones Division of Reactor Safety IV
To:	Walsh K Entergy Operations
References
IR-06-012
Download: ML070660153 (23)

Text

March 5, 2007

SUBJECT:

WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC BASELINE INSPECTION REPORT 05000382/2006012

Dear Mr. Walsh:

On February 12, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Waterford Steam Electric Station, Unit 3. The enclosed report documents the inspection findings, which were discussed on February 12, 2007, with you and other members of your staff.

This 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 plant and contract personnel who were involved in the performance of inservice inspection activities.

Based on the results of this inspection, the NRC has identified an issue that was evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that a violation is associated with this issue. This violation is being treated as a noncited violation, consistent with Section VI.A of the Enforcement Policy. The noncited violation is described in the subject inspection report. If you contest the violation or significance of the noncited 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 copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Waterford Steam Electric Station, Unit 3 facility.

Entergy Operations, Inc.

-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/ by GDR William B. Jones, Chief Engineering Branch 1 Division of Reactor Safety Docket: 50-382 License: NPF-38

Enclosures:

Inspection Report 05000382/2006012 Attachments: A. Supplemental Information B. Timeline of Events

REGION IV==

Docket:

50-382 License:

NPF-38 Report No.:

05000382/2006012 Licensee:

Entergy Operations, Inc.

Facility:

Waterford Steam Electric Station, Unit 3 Location:

Hwy. 18 Killona, Louisiana Dates:

December 4, 2006, through February 12, 2007 Team Leader:

C. Paulk, Senior Reactor Inspector, Engineering Branch 1 Inspectors:

G. George, Reactor Inspector, Engineering Branch 1 M. Holmberg, Reactor Inspector, Engineering Branch 1, Region III W. Sifre, Senior Reactor Inspector, Engineering Branch 1 Approved By:

William B. Jones, Chief, Engineering Branch 1

Enclosure-2-

SUMMARY OF FINDINGS

IR 05000382/2006012; 12/4/2006 - 02/12/2007; Waterford Steam Electric Station, Unit 3; inservice inspection activities, Inspection Procedure 71111.08.

The report covered an announced inspection by regional inspectors. One Green noncited violation was identified. The significance of most findings is indicated by its color (Green,

White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.

Cornerstone: Barrier Integrity

Green.

A noncited violation of Criterion XVI of Appendix B to 10 CFR Part 50 was identified for the failure to promptly identify and correct an adverse condition (i.e., steam generator batwing-to-wrapper bar welds not in accordance with design). Specifically, in May 2005, during Refueling Cycle 13, licensee personnel found that the batwing-to-wrapper bar welds were not in accordance with design drawings, but did not enter the adverse condition into the corrective action program until December 2006. This condition was entered into the corrective action program as Condition Report WF3-2006-04395.

This finding was more than minor because by not promptly entering the non-conforming welds into the corrective action program and taking actions to correct the adverse condition, it became a more significant condition when two welds failed during Operating Cycle 14. Using the guidance of Appendix J to NRC Inspection Manual Chapter 0609, Significance Determination Process, the finding is determined to have very low safety significance (Green) because there was no tube degradation that exceeded 40 percent through-wall which did not increase in the large early release frequency. This finding had a crosscutting aspect in the area of problem identification and resolution (corrective action)program component. (Section 1R08.5).

B.

Licensee-Identified Findings None.

REPORT DETAILS

1R08 Inservice Inspection Activities

Inspection Procedure 71111.08P requires four samples, as identified in Sections 02.01, 02.02, 02.03, and 02.04.

.1 Examination Activities Other Than Steam Generator Tube Inspections, Pressurized

Water Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control (Section 02.01)

a. Inspection Scope

The procedure requires the review of two to three types of nondestructive examination activities (NDE) (i.e. volumetric, surface, or visual). The inspectors reviewed the records of one visual examination, one magnetic particle (surface) examination, and two ultrasonic (volumetric) examinations. The ultrasonic examinations are listed below.

ISI REPORT NUMBER SYSTEM/WELD AREA EXAM METHOD ISI-VT-06-064 Rigid Pressurizer System Restraint (RCCRR-0321)

Visual, VT-3 ISI-MT-06-001 Welded Support (43-WS-1) to 40-Inch Main Steam Pipe Magnetic Particle ISI-UT-05-029 Steam Generator 2 Main Steam Nozzle-to-Top Head-To-Dome Weld (04-030)

Ultrasonic 2002-238 Steam Generator 1 Hot leg Nozzle-to-Vessel Weld (03-010)

Ultrasonic BOP-PT-06-011 SW-22 Final Weld Inspection Penetrant For each of the activities reviewed, the inspectors reviewed the examination records, NDE procedures, NDE staff certification records and interviewed the licensee inservice inspection program owner to determine if these activities performed were in accordance with site procedures and the applicable ASME Code requirements.

For the NDE examinations identified above, no recordable indications were identified or accepted for continued service and no Code recordable indications had been identified within the past two refueling outages. Therefore, the inspectors could not evaluate the licensees resolution of Code recordable indications and this portion of the inservice inspection sample was considered unavailable for review.

In addition to NDE examinations, the procedure requires the inspectors review one to three welds performed on the pressure boundary of Class 1 systems. The inspectors reviewed welding to replace Safety Injection Valve SI-1421B and a drip pot upstream of Main Steam Isolation Valve 2.

The inspectors completed an additional review of welding activities to repair batwings (antivibration bars)-to-wrapper bar weld connections in Steam Generator 2. The inspectors reviewed the welder qualification mockup, welder qualification records, procedure qualification records, weld procedure specifications, acceptance criteria, and weld records. The inspectors performed these activities to verify that the weld connections met the design of Steam Generator 2.

The inspectors completed the one sample required by Section 02.01.

b. Findings

No findings of significance were identified.

.2 Pressurized-Water Reactor Vessel Upper Head Penetration Inspection Activities

(Section 02.02)

a. Inspection Scope

The inspection requirements for this section parallel the inspection requirement steps in Section 02.01. The inspectors observed the nondestructive examinations on nine reactor vessel upper head penetrations. There were eight control element drive mechanism penetrations and one incore instrumentation penetration examinations observed.

The inspectors verified that the nondestructive activities were performed in accordance with the requirements of NRC Order EA-03-009. The nondestructive examinations performed during the NRC inspection did not reveal any defects or indications.

The inspectors completed the one sample required by Section 02.02.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control Inspection Activities (PWR) (Section 02.03)

a. Inspection Scope

The inspectors performed a review of boric acid corrosion control procedures, interviewed licensee inspectors who were qualified to perform the boric acid inspections, performed a visual inspection of safety injection system valves located at the 35-foot elevation in containment, and observed a licensees inspector perform a VT-2 visual examination of Valve SI-304B (2B safety injection tank drain valve) bolted connection.

The inspectors performed these activities to verify that the licensees visual examinations to detect leakage emphasized locations where boric acid leaks would cause degradation and to evaluate if boric acid leaks and/or component degradation were properly documented.

The inspectors reviewed four boric acid evaluations associated with minor boric acid deposits identified at the 2B reactor coolant pump seals, Steam Generator 2 cold leg piping, high pressure safety injection system flow element, and at assorted safety injection system valve packing and body-to-bonnet joints during the previous operating cycle. For these components, the inspectors evaluated the licensees boric acid evaluations and associated corrective actions to determine if the ASME Code requirements associated with leakage or structural integrity were maintained (e.g.,

minimum wall thickness or bolt integrity).

The inspectors completed the one sample required by Section 02.03.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities (Section 02.04)

a. Inspection Scope

Section 02.04 requires an assessment of insitu pressure testing screening criteria to assure consistency between assumed nondestructive examination flaw sizing accuracy and data from the Electric Power Research Institute (EPRI) examination technique specification sheets; a comparison of the predicted versus actual size and number of flaws detected; a confirmation that the scope of examinations and expansion criteria met the technical specification requirements, the EPRI Guidelines, and commitments made to the NRC; a verification that the licensee enveloped any new degradation mechanisms; a confirmation that all areas of potential degradation were inspected; a confirmation that any repairs were approved for use at the site; a confirmation that the plugging criteria were adhered to; an assessment of evaluation of any leakage

>3 gallons per day; a confirmation that the probes and equipment were qualified; and, a review of corrective actions for any loose parts identified during the inspections.

The inspectors reviewed the in-situ pressure testing screening criteria to confirm that the criteria were in accordance with EPRI Guidelines, technical specifications, and commitments made to the NRC.

The inspectors reviewed licensees Report ER-W3-2006-0180-000, RF14 - Steam Generator Degradation Assessment, Revision 0. The purpose of the assessment is to identify degradation mechanisms and, for each mechanism, to determine proper detection technique, determine number of tubes, establish structural limits, and establish flaw growth rates.

The inspection procedure specified confirmation be made that the steam generator tube eddy-current testing scope and expansion criteria met technical specification requirements, EPRI guidelines, and commitments made to the NRC. The inspectors review determined that the steam generator tube eddy-current testing scope and expansion criteria were being met.

The inspection procedure also specified that, if the licensee identified new degradation mechanisms, then verify that the licensee had fully enveloped the problem in an analysis and had taken appropriate corrective actions before plant startup. At the time of this inspection, licensee engineers were evaluating degradation mechanisms that were the result of batwing failures. Additional information is provided in Section 1R08.5 below.

The inspection procedure also required confirmation that all areas of potential degradation were being inspected, especially areas which were known to represent potential eddy-current testing challenges (e.g., top-of-tubesheet, tube support plates, and U-bends). The inspectors confirmed that all known areas of potential degradation, including eddy-current testing-challenged areas, were included in the scope of inspection and were being inspected.

The inspection procedure further required that repair processes being used were approved in the technical specifications for use at the site. The inspectors verified that the repair criteria were in accordance with EPRI Guidelines, technical specifications, and commitments made to the NRC.

The inspection procedure required confirmation that the technical specification plugging limit was being adhered to, and determination whether depth sizing repair criteria were being applied for indications other than wear or axial primary water stress corrosion cracking in dented tube support plate intersections. The inspectors confirmed that the licensee was adhering to these specifications.

The inspection procedure stated that if steam generator leakage >3 gallons per day was identified during operations or during post-shutdown visual inspections of the tubesheet face, then assess whether the licensee had identified a reasonable cause and corrective actions for the leakage based on inspection results. The inspectors did not conduct any assessment because this condition did not exist.

The inspection procedure required confirmation that the eddy-current testing probes and equipment were qualified for the expected types of tube degradation and assessment of the site-specific qualification of one or more techniques. The inspectors observed portions of the eddy-current testing performed. During these examinations, the inspectors verified that:

(1) the probes appropriate for identifying the expected types of indications were being used;

(2) probe position location verification was performed;

(3) calibration requirements were adhered to; and

(4) probe travel speed was in accordance with procedural requirements.

Finally, the inspection procedure specified the review of one to five samples of eddy-current testing data if questions arose regarding the adequacy of eddy-current testing data analyses. The inspectors did not identify any results where eddy-current testing data analyses adequacy was questionable.

The inspection performed met the requirements for the sample size of Section 02.04.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems (Section 02.05)

a. Inspection Scope

This portion of the inspection report details the inspectors review of licensee personnels followup activities to batwing failures in Steam Generator 2. As part of their review, the inspectors were to complete the following:

• Develop a detailed background and timeline for licenseesbatwing failures (Attachment 2)

• Review the design requirements of the steam generators, particularly concerning batwing supports and structural integrity

• Evaluate the potential effects from the June 2005 power uprate

• Assess the licensees problem identification and resolution efforts associated with the batwing failures

• Evaluate whether there were prior opportunities to have addressed and prevented the batwing failures

• Evaluate the potential for the issue to represent a generic concern with other facilities with similar batwing designs and/or configurations

• Monitor and assess selected repair activities and non-destructive examinations that the licensee or their contractors performed in conjunction with the batwing failures (Documented in 1R08.4 of this report)

• Determine and review the licenseesprimary leak detection and loose parts monitoring capabilities

• Assess the licensees contingencies and any planned limitations or action levels for plant startup and continued operation b.

Description of Event and Observations Waterford 3 is a pressurized water reactor designed by Combustion Engineering Inc..

The Combustion Engineering, Inc. design incorporates two vertical shell, U-tube steam generators. The high temperature reactor coolant flows through the U-tube shaped steam generator tubes, which form the boundary between the primary and secondary sides of the steam generator. Cooling water flows upward through the vertical shell portion, cooling the steam generator tubes to generate steam. To prevent tube damage due to flow-induced vibration, each steam generator is equipped with 350 anti-vibration bars, or batwings. Each batwing is placed diagonally between the upper portions of adjacent steam generator tubes. Each batwing is connected to the tube bundle structure on the upper end by a double sided fillet weld to a wrapper bar surrounding the tube bundle and on the lower end by a batwing support structure in the center of the tube bundle.

On May 3, 2005, while performing an eddy-current inspection of the steam generator tubes during Refueling Outage 13, an analyst determined that two adjacent batwings had moved in Steam Generator 2. On May 10, 2005, a video inspection confirmed that the lower ends of two batwings had detached from the batwing support structure. This condition was documented in Condition Report WF3-2005-01977.

In addition, licensee personnel identified, from the video inspection, that a number of upper end batwing-to-wrapper bar welds were single sided fillet welds. These welds did not conform to manufacturing specifications, which called for double sided fillet welds.

The upper end batwing-to-wrapper bar welds were determined to be intact and placed into service. Although the nonconforming welds were reviewed by a contractor, the nonconforming welds were not entered into the corrective action program and corrected by the licensee until prompted by the inspectors in December 2006.

As a corrective action for the detached lower ends of the batwings, licensee personnel implemented a protective strategy of plugging and stabilizing steam generator tubes in areas that could be affected by the broken batwings. Additionally, Operational Decision Making Instruction was revised to include conservative action levels for operators to mitigate a primary-to-secondary leakage event. This included a plan to visually inspect the batwings for more damage during Refueling Outage 14 (December 2006).

After the identification of initial batwing failures, licensee personnel generated an operational experience report, disseminating potential generic concerns. Similar plants of concern were St. Lucie 2, Palisades, and San Onofre Units 2 and 3. Batwing failures were not identified at any of the plants above. A search of operational experience databases indicated the batwing failures are unique to Steam Generator 2 at Waterford 3.

Starting with Operating Cycle 14, June 2005 to December 2006, the licensee operated in an approved uprated power condition. The Facility Operating License was amended to increase reactor core power level from 3441 MWt to 3716 MWt. Licensee personnel evaluated the potential effects of the power uprate causing additional batwing failures.

The evaluation determined that there would be a low probability of additional failures specifically caused by the power uprate. The evaluation was based on engineering analysis and the knowledge that initial batwing failures occurred in pre-uprate power conditions.

On December 4, 2006, during Refueling Outage 14, licensee personnel identified additional lower end batwing failures in Steam Generator 2. On December 8, 2006, a video inspection identified two upper end batwings that had broken free from the single sided fillet weld attachments on the upper end. The video inspection also identified additional upper end batwing-to-wrapper bar welds, which did not conform with original design. These conditions were documented in Condition Reports WF3-2006-03966, WF3-2006-04122, WF3-2006-04138, WF3-2006-04144, WF3-2006-04395 and WF3-2006-04203.

As a corrective action for the additional batwing failures and nonconforming/broken batwing failures, licensee personnel continued the implementation of the protective strategy by plugging and stabilizing additional steam generator tubes in areas that could be affected by the broken batwings. Licensee personnel restored upper end batwing-to-wrapper bar welds in affected regions of the tube bundle to original design specifications. Additionally, licensee personnel revised the Operational Decision Making Instruction to include even more conservative action levels for operators to mitigate a primary to secondary leakage event. Furthermore, licensee personnel installed additional loose parts monitors to indicate impending batwing damage. As a prerequisite for continued operation past Refueling Outage 14, licensee personnel documented their commitments to implement the aforementioned actions in Letter W3F1-2006-0070.

c. Findings

Introduction.

The inspectors identified a noncited violation of very low safety significance (Green) of 10 CFR Part 50, Appendix B, Criterion XVI for the licensees failure to promptly identify and correct an adverse condition involving nonconforming welds at the upper and batwing-to-wrapper bar.

Description.

The licensee identified, in May 2005, that a number of upper end batwing-to-wrapper bar welds did not conform to manufacturing specifications.

However, licensee personnel did not enter the nonconforming condition into the corrective action program until being prompted by the inspectors in December 2006.

Corrective actions were not taken and two of the welds failed during Operating Cycle 14.

Analysis.

The inspectors identified the failure to promptly identify and correct the nonconforming welds in May 2005 to be a performance deficiency. As a result of not taking corrective action to repair the batwing-to-wrapper bar connections, two welds failed during Operating Cycle 14. The inspectors found this to be more than minor because the lack of corrective actions resulted in a more significant condition (i.e., failed welds).

The significance of this finding was assessed using the guidance of Appendix J, to NRC Inspection Manual Chapter 0609, Significance Determination Process, as having very low safety significance (Green). This was based on no tube degradation that exceeded 40 percent through-wall, and therefore, there was not an increase in the large early release frequency.

The inspectors determined that the finding had a crosscutting aspect in the area of problem identification and resolution (corrective action program component). The failure to promptly identify the condition in their corrective action program caused the licensee to miss an opportunity to thoroughly evaluate and resolve the condition before the two batwing-to-wrapper bar single sided fillet weld failures occurred during Operating Cycle 14.

Enforcement.

In accordance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, the licensee are required to promptly identify and evaluate conditions adverse to quality. Contrary to this, in May 2005, licensee personnel failed to enter the adverse condition into their corrective action program and correct nonconforming welds.

This item has been determined to be of very low safety significance and has been entered into the licensees corrective action program as Condition Report WF3-2006-04395. This is being treated as a noncited violation, consistent with Section VI.A if the Enforcement Policy: NCV 05000382/2006012-001, Failure to Promptly Identify and Correct an Adverse Condition (Welds Not In Accordance With Design).

4OA6 Meetings, Including Exit

On February 12, 2007, the inspectors presented the inspection results to Mr. K. Walsh, Vice President, Operations, and other members of his staff who acknowledged the findings. The inspectors confirmed that proprietary information was provided and examined during this inspection. However, no proprietary information is included in this report.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

K. Cook, Acting General Plant Manager, Operations

T. Gaudet, Manager, Quality Assurance

J. Holman, Manager, Nuclear Engineering

B. Lanka, Manager, Design Engineering

R. OQuinn, Senior Engineer, Steam Generator Inservice Inspection

B. Proctor, Manager, System Engineering

R. Putnam, Manager, Engineering

J. Ridgel, Director Nuclear Safety Assurance

B. Williams, Director, Engineering

R. Williams, Engineer, Licensing

NRC personnel

K. Karwoski, Senior Level Advisor for Steam Generators and Material Inspections, Office of

Nuclear Reactor Regulation

G. Larkin, Senior Resident Inspector

E. Murphy, Senior Materials Engineer, Office of Nuclear Reactor Regulation

D. Overland, Resident Inspector

LIST OF ITEMS

OPENED AND CLOSED

Opened and Closed

05000382/2006012-001 NCV Failure to Promptly Identify and Correct an Adverse Condition (Welds Not In Accordance With Design)

(Section 1R08.5)