NRC 2009-0012, Response to Request for Additional Information Spring 2008 Unit 2 (U2R29) Steam Generator Tube Inspection Report
| ML090641097 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 03/03/2009 |
| From: | Jim Costedio Florida Power & Light Energy Point Beach |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NRC 2009-0012, U2R29 | |
| Download: ML090641097 (7) | |
Text
FPL Energy Point Beach Nuclear Plant March 3.2009 FPL Energy Point Beach, LLC, 6610 Nuclear Road, Two Rivers, WI 54241 NRC 2009-001 2 TS 5.6.8 U.S Nuclear Regulatory Commission AlTN: Document Control Desk Washington, DC 20555-0001 Point Beach Nuclear Plant, Unit 2 Docket 50-301 Renewed License No. DPR-27 Response to Request for Additional lnformation Spring 2008 Unit 2 (U2R29) Steam Generator Tube lnspection Report
Reference:
(1) FPL Energy Point Beach, LLC to NRC Letter dated September 16,2008, Spring 2008 Unit 2 (U2R29) Steam Generator Tube lnspection Report, (ML082590073)
(2) NRC to FPL Energy Point Beach, LLC Letter dated February 3, 2009, Point Beach Nuclear Plant. Units 1 and 2 - Request For Additional lnformation Related to Unit 2 Steam Generator Tube lnspection Report (TAC NO. MD9689),
FPL Energy Point Beach, LLC submitted the Spring 2008 Unit 2 Steam Generator Tube lnspection Report via Reference (A), documenting the scope and results of the inspection per prescribed Technical Specification reporting requirements.
On January 7,2009, a teleconference was held between NRC staff and FPL Energy Point Beach personnel discussing this report and additional information requested by the Commission in order to complete its review. Reference (2) is the Request for Additional lnformation (RAI) that transmitted the staft's questions. provides the FPL Energy Point Beach response to Reference (2).
An FPL Group Company
Document Control Desk Page 2 This letter contains no new commitments and no revisions to existing commitments.
Very truly yours, FPL Energy Point Beach, LLC Licensing Manager Point Beach Nuclear Plant Enclosure cc:
Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW
ENCLOSURE 1 FPL ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNlT 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION SPRING 2008 UNlT 2 (U2R29) STEAM GENERATOR TUBE INSPECTION REPORT The following information is provided by FPL Energy Point Beach, LLC in response to the NRC staffs request for additional information dated February 3, 2009, regarding the Spring 2008 Unit 2 (U2R29)
Steam Generator Tube Inspection report.
Questions 1:
For each refueling outage or steam generator (SG) tube inspection since installation of the SGs, please provide the cumulative effective full power months that the SGs have operated.
Response
Question 2:
On page 1 of Enclosure 1 for the September 16, 2008 letter, it is stated that the tubes are on a 1,0687-inch triangular pitch. On page 1 of Enclosure 1 fw the October 13, 2004, letter (ADAMS Accession No. ML042990532), it is stated that the tube pitch and pattern is 1.234" Triangular. Please cIam.
Response
U2R28 Oct-06 456.65 15.00 81.00 7.67 The Unit 2 SGs have a staggered or triangular pitch. This configuration results in different longitudinal (columns) and transverse (rows) pitches as measured between tube centers. The tube arrangement in the Unit 2 SGs have a longitudinal pitch of 1.0687 inches (distance between tube centers between columns) and a transverse pitch of 0.61 7 inches (tube centers between rows). The calculated diagonal pitch is 1.234 inches (tube centers between tubes of adjacent row and column).
U2R29 Apr-08 507.00 16.66 97.65 9.05 U2R26 Oct-03 487.17 16.01 50.08 5.09 Outage Date Cycle EFPDays Cycle EFPMonths Cumulative EFPMonths (for first period)
Cumulative EFPYears (since replacement)
Page 1 of 5 U2R27 Mar-05 484.37 15.91 65.99 6.41 U2R23 (first ISI) an-99 334.39 10.99 0.00 0.92 U2R22 (install) 0ct Aug-97 NA NA O.OO 0.00 U2R24 (begin144 EFPM)
Oct-00 573.34 18.84 18.84 2.49 U2R25 Apr-02 463.76 15.24 34.07 3.75
Question 3:
Please confirm that the only service induced indications detected were those listed.
Response
There were no service induced indications identified during the Spring 2008 Unit 2 SG inspection other than those identified in Reference 1.
Question 4:
Other than foreign object search and retrieval, please discuss the scope and results of any other secondary side inspections. In addition, please discuss the results of your 2006 inspection of the SG B steam drum, upper internals, feedrings, and integrated J-nozzles, as discussed in your February 19, 2007, letter (ADAMS Accession No. ML070590203).
In addition to Foreign Object Search and Retrieval (FOSAR) for SG A, visual inspections included:
Flow Distribution Baffle (FDB) general inspection Top (7'h) support plate including observation of tri-foils Upper lntemals O
Steam Drum General Area O
J-nozzles o
Primary Moisture Separator Swirl Vanes In addition to FOSAR for SG B, visual inspections included:
FDB general inspection Top (7'h) support plate including observation of tri-foils An upper intemals inspection was not required for SG B during this outage.
Results for SG A:
The FDB was clear - there was no observed sludge, scale or anomalies.
The top ( 7 ~ )
support plate was clear - no visible sludge, scale or anomalies were noted. The tri-foils were clear (no observed blockage).
Upper intemals were evaluated, no anomalies were reported. Flow impingement patterns were noted on the outside diameter (OD) of the feedwater distribution pipe ring and on the OD of the primary separator riser barrels at the discharge area of the associated J-nozzles with no discemable depth. All supports and structural welds had no signs of degradation.
All 112 primary moisture separator swirl vanes were visually inspected. No degradation evident of erosion or corrosion was noted.
Page 2 of 5
Portions of the inside diameter of the feedwater distribution pipe ring and integrated J-nozzles were inspected. The only observed indications were bum-through or melt-through at the J-nozzle to feedwater distribution pipe ring interface on eight J-nozzles. This is the same observed manufacturing induced anomaly as reported in inspection reports for Unit 1 SGs where welding at the interface causes some observed protrusion of material in the ID.
Results for SG B:
The FDB was clear - there was no observed sludge, scale or anomalies.
The top (p) support plate was clear - no visible sludge, scale or anomalies were noted. The tri-foils were clear (no observed blockage).
As stated in the February 19,2007 letter (ML070590203), during the Fall 2006 Unit 2 outage (U2R28) inspections of the upper internals were completed on SG B only. SG A upper intemals inspection was not required in the Fall 2006 Unit 2 SG Inspection.
General visual observed no anomalies in the upper intemals. All surfaces were coated with a light layer of magnetite. All supports and structural welds had no signs of degradation.
A sampling of the 11 2 primary moisture separator swirl vanes was completed with no observed anomalies.
Flow impingement patterns were noted on the outside diameter (OD) of the feedwater distribution pipe ring and on the OD of the primary separator riser barrels at the discharge area of the associated J-nozzles with no discemable depth.
Portions of the inside diameter of the feedwater distribution pipe ring and integrated J-nozzles were inspected including approximately 13 J-nozzle to feedwater distribution pipe ring interfaces. No erosion was noted, no anomalies were observed.
Question 5:
In the area around Row 81, Column 42, a possible loose part was reported but this area could not be visually inspected. Please discuss how you assessed that tube integrity would be maintained at this location until the next inspection. In addition, please clarijl whether any loose parts (other than those specifically mentioned in your report) were found in either SG.
The area around Row 81, Column 42 was bounded by both bobbin and +pointTM inspections. No degradation was detected with respect to either the tube or the surrounding tubes. The possible loose part (PLP) signal was present only on this tube, which suggests the signal is most likely due to local sludge or scale deposits. In addition, because the PLP signal was present only on one tube at an elevation above the support plate it was judged that the size and location of the PLP was such that tube integrity would not be challenged during the period to the next scheduled inspection. There are no historical indications at this location associated with PLP or wear.
There were no other loose parts found in either SG other than those specifically mentioned in Reference 1.
Page 3 of 5
Question 6:
In Section "c" you imply that 100 percent of the dings in the freespan that are greater than or equal to 5 volts were inspected with a +pointTM probe. In addition, this section also implies that all dingddents in the U-bend and at tube supports were inspected with a +pointTM probe. Please confirm these inspections were performed since they were not reported in Section "a" of your report.
Response
Section "c" of Reference 1 identifies the proposed inspection plan for dings in the freespan area at or greater than 5 volts and all dingsldents in the U-bends and tube support areas. The results of the Bobbin probe inspection in the freespan area did not reveal indications of at least 5 volts, thereby negating the need for a +pointTM probe inspection in this area. All of the dingsldents in the U-bend and tube support areas were inspected using a +pointTM probe. No degradation was reported at any of the dentlding locations.
Question 7:
Wear indications at the anti-vibration bars and at the tube supports were reported for the first time during your 2008 inspections. Please discuss any insights on why these indications appeared to have initiated after - 10 years of operation (e.g., any power uprates or changes in secondary flow conditions).
Response
The most likely reason is that the indications are at very shallow depths and have a correspondingly low probability of detection. As a result of the anti-vibration bar (AVB) and tube support wear reported, a look back analysis was completed to determine if indications were present as part of the condition monitoring and operational assessment for the spring outage (U2R29). The look back analysis tabulated below for the AVBs shows that wear was observable in some cases:
Page 4 of 5 Growth
%TWIEFPY 0.46 0.76 0.31 0.15 0.51 0
1.07 SG 2A 2A 2A 2A 2A 2A 2A Row 84 84 78 78 84 79 82 Bobbin Probe Depth, %TW Col 45 45 59 59 63 66 69 2008 9.03 EFPY 11 5
8 7
7 6
7 AVB AV5 AV6 AV4 AV5 AV5 AV5 AV1 2003 5.09 EFPY No Insp.
No Insp.
No Insp.
No Insp.
5 6
No Insp.
2000 2.49 EFPY 8
NDD 6
6 NDD NDD NDD 1998 0.92 EFPY NDD NDD NDD NDD NDD NDD NDD
The look back analysis tabulated below for the tube support indication shows indications were present but not sized:
For these indications the growth rate is calculated by taking the difference between the depths at two successive inspections and dividing by the EFPY between those inspections. It is seen that the apparent growth rate is on the order of 1 % through walVeffective full power years (TWIEFPY). All of these depths are below the condition monitoring limit defined in the Degradation Assessment.
Therefore, condition monitoring is satisfied for AVB and tube support wear in SG A. No AVB or tube support wear was detected in SG 9.
Page 5 of 5 Growth
%oTWIEFPY 1.07 0.61 Support 06H 06H Col 53 53 SG 2.4 2A Row 12 12 Bobbin Probe Depth, %TW t998 0.92 EFPY NDD NDD 2000 2008 2003 9.03 EFPY 7
4 5.09 EFPY No Insp.
No Insp.
2.49 EFPY No Size No Size