NRC 2007-0083, Spring 2007 Unit 1 (U1R30) Steam Generator Tube Inspection Report

Spring 2007 Unit 1 (U1R30) Steam Generator Tube Inspection Report

ML072990108
Person / Time
Site:	Point Beach
Issue date:	10/25/2007
From:	Mccarthy J Florida Power & Light Energy Point Beach
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC 2007-0083
Download: ML072990108 (9)

Text

FPL Energy Point Beach, LLC, 6610 Nuclear Road, Two Rivers, WI 54241 FPL Energy Point Beach Nuclear Pliirrt October 25, 2007 NRC 2007-0083 TS 5.6.8 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington DC 20555 Point Beach Nuclear Plant Unit 1 Docket No. 50-266 Renewed License No. DPR-24 Spring 2007 Unit 1 (U1R30)

Steam Generator Tube lnspection Report

References:

(1) Nuclear Management Company, LLC letter to NRC dated January 19,2007, Supplement 1 to License Amendment Request 248; Technical Specification 5.5.8, Steam Generator Program (ML070220084)

Pursuant to the requirements of Point Beach Nuclear Plant (PBNP)

Technical Specification (TS) 5.6.8, "Steam Generator Tube lnspection Report," FPL Energy Point Beach, LLC is submitting the 180-day Steam Generator Tube lnspection Report for Unit 1.

The report contains the results of the spring 2007 Unit 1 (U1R30) steam generator (SG) tube in-service inspections.

This report fulfills the following Regulatory Commitments contained in Reference 1:

"NMC will provide, in the 180-day Steam Generator Tube lnspection Report for PBNP Unit 1 Refueling Outage 30 (U1R30), a listing of indications detected in the upper 17 inches of the hot-leg tubesheet thickness with respect to their location, orientation, and size. NMC will also provide in this report the operational primary to secondary leakage rate observed in each steam generator during the cycle preceding the inspection, and the calculated accident induced leakage (AIL) rate for each steam generator from the lowermost 4 inches of tubing for the most limiting accident. If the calculated AIL rate for any steam generator is less than two times the total observed operational primary-to-secondary leakage rate, a description of how the AIL rate was determined will be included. This information will be provided if the alternate repair criteria for the hot leg tubesheet region are implemented."

An FPL Group company

Document Control Desk Page 2 This letter contains no new commitments.

Very truly yours, FPL Energy Point Beach, LLC m

13 7 James H. McCarthy Site Vice President 1 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 PBNP UNlT 1 UNlT 1 (U1R30) STEAM GENERATOR TUBE INSPECTION REPORT

1. Background

The Point Beach Nuclear Plant (PBNP) steam generator (SG) tube inspection program for the spring 2007 Unit 1 Refueling Outage 30 (U1 R30) was conducted in accordance with the requirements of PBNP Technical Specification (TS) 5.5.8. PBNP Unit 1 entered MODE 4 on April 30, 2007, following this in-service inspection. past inspections of these SGs have resulted in an inspection classification of Category C-1. The U1R30 SG tube inspections were limited to SG B (no primary side inspections were performed on SG A).

An analysis was conducted to determine which sequential period was appropriate for the current inspection. It was determined that the U1R30 was within the third sequential inservice inspection period following the first inservice inspection, which is the first 60 effective full power month (EFPM) period. U1R30 marks the initial inspection of this 60 EFPM period.

The PBNP Unit 1 SGs are Westinghouse Model 44F with 718-inch outer diameter, 0.050-inch wall, lnconel Alloy 600 thermally-treated tubing. The tubes are on a 1.234" square pitch and were hydraulically expanded the full depth of the tubesheet, with the exception of the tube at Row 38IColumn 69 in SG A which is not expanded the full length of the tubesheet. The Row 1 U-bends have a 2.19-inch radius and the first eight rows were stress relieved after bending.

The tubes are supported by a stainless steel flow distribution baffle with round holes, six stainless steel tube support plates with quatrefoil holes and two sets of chrome-plated lnconel anti-vibration bar (AVB) assemblies. The PBNP Unit 1 SGs were replaced during Refueling Outage 11 in 1983. The replacement SGs have accumulated approximately 19.05 effective full power years of operation.

2. TS 5.6.8 Inspections

a. S c o ~ eof Inspections for SG B A tube end-to-tube end bobbin coil inspection was performed on approximately 54% of the active tubes in PBNP Unit 1 SG B during U1R30. Rotating probe techniques (i.e., +pointTM) were used in locations where the bobbin probe is not qualified. Additional +pointTMspecial interest examinations were completed to further investigate suspect bobbin indications. The purpose of the inspection was to identify existing or potential forms of SG degradation as detailed in Item c.

The following summarizes the SG eddy current examinations performed at PBNP Unit 1 during U1R30.

Page 1 of 7

Bobbin coil inspections included:

Full length tube end to tube end - 1743 tubes (approx 54%)

Hot leg (H/L) straight sections only - 181 tubes Cold leg (C/L) straight sections only - 51 tubes Cold tube end to the top support on the H/L only - 81 tubes.

+pointTMrotating coil inspections included:

50% of the hot leg tubesheets

+W-17" (1398 tubes)

+6"/-17" (205 tubes)

+8"/-17" (7 tubes) 50% Tight Radius U-bends in Row 1 (49 tubes) 50% Tight Radius U-bends in Row 2 (49 tubes)

All dents and dings 25 volts in freespans All dents and dings at tube supports and in U-bends Additional special interest (SI) examinations were based on the results of the 54%

bobbin inspections.

b. Active Deqradation Mechanisms Found During the U1R30 SG eddy current inspection, no crack-like indications were reported and no tubes required plugging. No active degradation mechanisms were found. The only existing degradation mechanism observed during the inspection was wear at the anti-vibration bars (AVB) and wear due to a transient foreign object above the tubesheet. Existing degradation mechanisms are further discussed under Item d.

Page 2 of 7

c. Nondestructive Examination Techniques Utilized for Each Dearadation Mechanism Denradation Mechanism Examination Technique  % Sample Existinq Mechanisms AVB Wear Bobbin Tube Support Plate Bobbin Wear Mechanical Wear Bobbin; +pointTM;visual 50% bobbin; 50% tube sheet complemented with visual inspection Potential Mechanisms PWSCC at BLG and +pointTM OXPs in tubesheet Loose Parts, Wear Bobbin; +pointTM;visual 50% bobbin; 50% tube sheet complemented with visual inspection ODSCC Transition +pointTM Zone ODSCC in Sludge Bobbin; +pointTM 50% bobbin Pile and Freespan 50% +pointTMHTS ODSCC at Tube Bobbin 50%

support plates ODSCC U-bend +pointTM 50% Row 1; 50% Row 2 ODSCC DingIDent Bobbin; +pointTM 50% Bobbin; 100% +pointTM( 25V freespan, all at TSP & U-bends)

PWSCC DingIDent Bobbin; +pointTM 50% Bobbin;100% +pointTM( 25V freespan, all at TSP & U-bends)

PWSCC U-bends +pointTM 50% Row 1; 50% Row 2 PWSCC Transition +pointTM Zone Leaend:

ODSCC outside diameter stress corrosion cracking PWSCC primary water stress corrosion cracking BLG bulges OXP overexpansions HTS hot-leg tubesheet TSP tube support plate Transition Zone refers to the area near the top of tubesheet (TTS) inspected over a range of at least + 3 to - 2 .

Page 3 of 7

d. Location, Orientation (if Linear) and Measured Sizes (if Available) of Service Induced Indications AVB Wear There were 23 indications, in 13 tubes, in SG B with indications of wear at the AVBs. None of these indications were required to be repaired and all remain in service. Table 1 shows AVB wear indications along with a historical comparison. There were two new indications measured at 7% depth; Row 32, Col 32, AVB 4 and Row 36, Col 74, AVB. For these two indications, historical data has been obtained from previous inspection results. The change in depth was very small at all pre-existing locations. Based on the growth rate of the wear indications, no significant degradation is anticipated to occur during the next two operating cycles.

Table 1 - Anti-Vibration Bar Wear History, % Through-Wall, SG B 2007 2004 2001 1998 1995 Row Column Location U1R30 U1R28 U1R26 U1R24 U1R22 32 32 AVB3 13% 13% 12% 8% 7%

32 32 AVB4 7% 6% 6%

23 33 AVB1 12% 11% 6% 8% 8%

23 33 AVB2 16% 15% 13% 16% 11%

23 33 AVB3 26% 25% 17% 19% 18%

Mechanical Wear Indication above the Top of Tubesheet (TTS) Hot Leq There was one tube in SG B, on the extreme outer periphery of the generator, with an indication attributed to mechanical wear above the TTS HIL. Both bobbin and +pointTMprobes reported an indication at this location. This indication was reported in the spring 2004 Unit 1 (U1R28)

Page 4 of 7

inspection and measured nearly the same depth. Table 2 lists the percent through-wall of the indication sized by +pointTM.

In Reference (2), Summary of Spring 2004 Unit 1 (U1R28) Steam Generator Examinations, it was stated that this wear appears to be the result of transient loose parts that are no longer present or damage inflicted by contact with sludge lancing equipment. No loose parts were reported in the area during U1R30.

Table 2 - Mechanical Wear History, SG 6

% Through wall  % Through wall Elevation

'OW Column Location U1R30 (2007) U1R28 (2004) (U1 R30lU1R28) 1 92 7 9 Tubesheet +6.21/+6.16 Eddv Current Test Indications from Possible Loose Parts (PLP)

A PLP location was identified by the eddy current inspection in the H/L at Columns 31, 32 and 33 of Row 42 and at Column 33 of Row 41 (see Table 3 below). Such indications may indicate the presence of a metallic object and are routinely investigated with +pointTMand/or visual inspections. These indications were not present in the U1R28 inspection. This area was visually inspected from the secondary side prior to sludge lancing. Several pieces of material were observed in the area and three pieces were retrieved. The pieces were thin, brittle and magnetic. All broke or crumbled easily and were determined to be scale pieces which had fallen off the tubes. No pieces were found after sludge lancing. No degradation was observed in conjunction with these indications.

Table 3 - PLP Indication Summary Row Column Location Elevation 41 33 Tubesheet +3.45" 42 31 Tubesheet +0.7OV 42 32 Tu besheet +1.37" 42 33 Tubesheet +1.48" A very small fine wire was observed in the bundle of SG B following sludge lancing. The wire is of the same dimensions or smaller than those identified during U1R28 (Reference 3).

Comparable analysis determined that other wires with dimensions bounded by the dimensions of the wire described in the previously performed analysis referenced for U1R29 would not adversely affect the SG for at least two operating cycles. No degradation was present in the area where the wire was located and no secondary side wear was visible. Planned chemical cleaning of the Unit 1 SGs in 2008 is expected to eliminate the presence of remaining fine wires.

e. Number of Tubes Pluqqed Durinq the Inspection Outaae for Each Active Dearadation Mechanism No SG tubes required plugging as a result of this inspection.

Page 5 of 7

f. Total Number and Percentaae of Tubes Pluqaed To Date The total number and percentage of tube plugged to date for SG A is 413214 (0.1 2%) and 613214 (0.19%) for SG B.

g. Results of Condition Monitorina, lncludinq the Results of Tube Pulls and In Situ Testing Condition monitoring was completed. SG B did not exceed any performance criteria during the last inspection cycle (since U1R28). Tube pulls and in situ testing were not required and were not conducted.

h. The Effective Tube Pluqqinq Percentaqe for All Pluqqinq in Each SG No tube repair methods are approved for PBNP Unit 1. Therefore, the effective plugging levels are as stated per Section f above.

3. Requlatorv Commitments Contained in Reference 1

a. A Listinq of Indications Detected in the Upper 17 Inches Of the Hot-Leu Tubesheet Thickness with Respect to Their Location, Orientation, and Size Half of the hot-leg tubesheet for SG B was inspected with +pointTM,including the upper 17 inches of the tubesheet. There were no indications.

b. The O~erationalPrimarv-to-SecondarvLeakaae Rate Observed in Each SG During the Cvcle Precedinq the Inspection A primary-to-secondary leak rate of approximately 0.3 gpd was detected for the cycle preceding U1R30 (Reference 1). The low leakage rate precludes accurately differentiating leakage between individual SGs. Therefore, it is assumed that the total leakage is from a single SG.

c. The Calculated Accident Induced Leakaqe (AIL) Rate for Each SG from the Lowermost 4 lnches of Tubinq for the Most Limitinq Accident The calculated AIL rate from the SG is assumed to be from the area below the 17 inch inspection height and all from one SG (Reference 1). Doubling the leak rate of 0.3 gpd equates to 0.6 gpd. This is below the TS AIL of 500 gpd per SG for the most limiting accident.

Page 6 of 7

References

1. Letter from Nuclear Management Company, LLC letter to NRC, "Supplement 1 to License Amendment Request 248; Technical Specification 5.5.8, Steam Generator Program," dated January 19,2007 (ML070220084)

2. Letter from Nuclear Management Company, LLC letter to NRC, "Summary of Spring 2004 Unit 1 (U1R28) Steam Generator Examinations," dated June 10, 2004 (ML041740744)

3. Letter from Nuclear Management Company, LLC letter to NRC, "Response to Request for Additional Information Fall 2005 Unit 1 (U1 R29) Steam Generator Tube Inspection Report," dated July 14, 2006 (ML061980407)

Page 7 of 7