CP-201301238, Sixteenth Refueling Outage (1RF16) Steam Generator 180 Day Report

Sixteenth Refueling Outage (1RF16) Steam Generator 180 Day Report

ML13304A711
Person / Time
Site:	Comanche Peak
Issue date:	10/15/2013
From:	Flores R, Thomas McCool Luminant Generation Co, Luminant Power
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CP-201301238, TXX-13152
Download: ML13304A711 (11)

Text

Rafael Flores Luminant Power Senior Vice President P 0 Box 1002

& Chief Nuclear Officer 6322 North FM 56 rafael.flores@Luminant.com Glen Rose, TX 76043 Luminant T 254 897 5550 C 817 559 0403 F 254 897 6652 CP-201301238 Ref. # 10 CFR 50.55a TXX-13152 October 15, 2013 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT DOCKET NO. 50-445 UNIT 1 SIXTEENTH REFUELING OUTAGE (1RF16) STEAM GENERATOR 180 DAY REPORT

Dear Sir or Madam:

By means of the enclosure with this letter, Luminant Generation Company LLC (Luminant Power) submits the Comanche Peak Nuclear Power Plant (CPNPP) Unit 1 steam generator tube inspection report for 1RF16 as required by Technical Specification 5.6.9.

This communication contains no new licensing basis commitments regarding Comanche Peak Unit 1.

Should you have any questions, please contact Mr. Jim Barnette at (254) 897-5866 or james.barnette@luminant.com.

Sincerely, Luminant Generation Company LLC Rafael Flores By:

Thomas P. Mctool Vice President, Station Support Enclosure - Comanche Peak Nuclear Power Plant 1RF16 Steam Generator 180 Day Report A member of the STARS Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• San Onofre

• South Texas Project - Wolf Creek

($O41

U. S. Nuclear Regulatory Commission TXX-13152 Page 2 10/15/2013 c - Steve Reynolds, Region IV Balwant K. Singal, NRR Resident Inspectors, Comanche Peak

Enclosure with TXX-13152 Comanche Peak Nuclear Power Plant 1RF16 Steam Generator 180 Day Report CPNPP This report is being submitted pursuant to TS 5.6.9, "Steam Generator Tube Inspection Report," to provide the results of the most recent CPNPP Unit 1 Replacement Steam Generator (RSG) inservice inspection.

Enclosure with TXX-13152 Steam Generator Configuration Comanche Peak Unit 1 is a four-loop Westinghouse pressurized water reactor plant equipped with Delta 76 replacement steam generators (RSGs) that were installed during the 12th refueling outage (1 RF1 2). The Attachment to this Enclosure provides drawings depicting major components and inspection openings of the Delta 76 RSGs.

The RSGs each have 5532 U-tubes made of thermally treated Alloy 690 (A690TT).

Each U-tube has a nominal outside diameter of 0.750 inch, a nominal wall thickness of 0.043 inch (except tubes in Rows 1 and 2, which have a nominal thickness of 0.044 inch), and a straight length ranging from 398.944 inches (Row 1) to 409.344 inches (Row 108). The tubes are arranged in a triangular pitch of 1.030 inches in 108 rows (parallel to the tube lane) and 131 columns. The distance between adjacent rows is 0.515 inch and between adjacent columns is 0.892 inch. The U-bend radii range from 3.09 inches (Row 1) to 58.195 inches (Row 108). The tubesheet is 24.315 inches thick, including the 0.25 inch cladding at the bottom (primary coolant side). The tubes have full depth hydraulic expansion within the tubesheet. Above the tubesheet, the tubes are supported by ten (10) tube support plates (TSP) which are 1.125 inches thick. The TSPs have trefoil broached holes and are made of stainless steel (Type 405). The elevation of the lowest TSP at its midpoint is 20.56 inches above the top of the tubesheet. The distance between adjacent TSPs (center to center) is 39.00 inches. In the U-bend, the tubes are supported by four (4) sets of stainless steel (Type 405) anti-vibration bars (AVB). The AVBs have a rectangular cross section of 0.48 inch x 0.14 inch thickness with chrome plating.

Each SG has 18 primary separators and a single-tier secondary separator consisting of six banks of demister vanes in a parallel orientation. The feedwater is discharged into the SG through 38 spray nozzles attached to the elevated (in relation to the feedwater nozzle) feedring. Each spray nozzle has 156 holes of 0.27 inch diameter. The feedring has an inside diameter (ID) of 9.75 inches and the spray nozzles have an ID of 2.323 inches. Above the lower deck plate and at its rim, a six inch high wall exists. This structure functions very much like a loose parts weir in preventing most of the loose parts and foreign objects in the upper drum from entering the downcomer annulus. This structure has a very positive impact on preventing loose parts from reaching the tube bundle and thus protecting the tubes from loose parts wear.

Inspection Summary The second inservice inspection of the RSGs was completed by Westinghouse Electric Company (WEC) during the Unit 1 Refueling Outage 16 (1RF16). Initial entry into MODE 4 after the inspection was achieved on April 19, 2013.

The CPNPP Unit 1 Cycle 16 operating period was 512.8 effective full power days (EFPD), or 1.402 effective full power years (EFPY). The cumulative operating history of the RSGs since their installation at 1RF12 is 5.646 EFPY. No eddy current inspection was performed during 1RF14 or 1RF15, and no inspection is planned during 1RF17 or 1RF18. The next scheduled eddy current inspection is during the 1RF19 outage with an estimated 9.9 EFPY (cumulative). Hence, the operating Page 1 of 6

Enclosure with TXX-13152 duration until the next inspection is expected to be 4.25 EFPY (in Cycles 17 through 19). The operational assessment is based on a conservative duration of 4.3 EFPY.

During the last three fuel cycles, the nuclear steam supply system (NSSS) power level was 3628 MWt. No power uprate is planned during the next three cycles and this power level is expected to remain constant through the operational period to the next scheduled eddy current inspection. Only one tube (R32C90 in SG 3) was plugged in the factory during SG fabrication. All other tubes have been in service since 1RF12, when the RSGs were placed in operation.

Prior to 1RF16, tube wear at AVBs, tube wear at TSPs, and tube wear due to foreign objects were identified as potential degradation mechanisms and there were no existing degradation mechanisms. During the 1RF16 inspection, no indications of tube degradation were reported at AVBs or due to foreign object. Only one indication of tube wear was found at a TSP.

A tube wear indication at TSP 9C was reported in SG 3 in Tube R55C121. TSP 9C is the second highest TSP and the ninth TSP counting from the bottom, and the letter C stands for cold leg. A +Point inspection was carried out to characterize the indication. The estimated wear depth by the resolution analysis was 5% through-wall (TW). A detailed evaluation was performed subsequently by the lead analyst in support of the engineering evaluation. The estimated wear depth from this evaluation was 6% TW. Being more conservative (than the 5% depth reported by resolution analysis), the 6% TW depth was used for the condition monitoring assessment.

Since the tube R55C121 is a peripheral tube in the bundle, a +Point inspection of this tube was performed over the tubesheet in both the Hot Leg (HL) and the Cold Leg (CL) as a part of the base scope inspection to detect possible loose parts (PLP) or tube degradation from loose parts.

No primary-to-secondary leakage was reported during normal operation during the last three cycles.

Video inspections were performed in the RSG channel heads. In SG 3, plugs installed in the factory in one tube were inspected on both the HL and CL sides. No anomaly was detected and the plugs were in good condition. The bottom of the channel head bowl was inspected in all SGs on both the HL and the CL in response to the Westinghouse Nuclear Safety Advisory Letter 12-1 (NSAL-12-1). The channel head cladding was found to be intact with no anomalies observed.

Secondary side maintenance and inspections were also performed:

A total of 14 possible loose parts (PLPs) were identified, most of them being in SG 2. The treatment of PLP indications during the outage was discussed in detail in the degradation assessment. Accordingly, all of these PLP indications were referred for foreign object search and retrieval (FOSAR). FOSAR was conducted at these locations. All foreign objects remaining in the SGs were referred for engineering Page 2 of 6

Enclosure with TXX-1 3152 disposition. The engineering evaluation concluded that SG performance criteria will be satisfied with these objects remaining in the SGs during the next three fuel cycles until the next planned inspection of the SGs during 1RF1 9.

Even though the objects were determined to be acceptable for safe and reliable operation of the SGs without affecting the SG performance criteria, Luminant decided to preventively plug one tube so as to assure safe operation of the plant.

Accordingly, Tube R1 3C17 in SG 4 was preventively plugged and a cable stabilizer was installed in the HL where a PLP was reported. The FOSAR observed the loose part resting between this tube and a stay rod. Attempts to retrieve the object were unsuccessful.

An upper bundle inspection of support plates "J" and "G" was performed on SG 2 only (refer to Attachment). The tubelane and flow slots were clean and the support structures were in good condition. The trefoils were open and free of deposit. Columns 59/60, 62/63, 73/74, 83/84 and 87/88 were inspected in the hot leg of support plate J.

Columns 70/71 and 80/81 were inspected in both the hot and cold legs of support plate G. Details of the tube columns are given as follows:

• Support Plate J - no anomalies noted during the inspection.

Columns 59/60, 62/63, 73/74, 83/84 and 87/88 HL: The trefoils were clean and a very light coating of magnetite can be seen on the tubes in the HL. A coating of magnetite is considered normal and has been shown to improve boiling heat transfer depending on the thickness and density of the layer.

• Support Plate G - no anomalies noted during the inspection.

Columns 70/71 HL: The findings at TSP G are consistent with the findings over TSP J, in which the hot leg columns contained a light coating of magnetite and the trefoils were clean. Scale profiling of other steam generators has shown that magnetite coatings generally form first in the hot leg regions of the upper support plates.

Columns 70/71 and 80/81 CL: CL columns were examined by video inspection of TSP G. The trefoils were clean. The tubes in the cold leg region were shiny, indicating little to no magnetite coating.

The condition of the SGs has met all industry and regulatory structural and leakage integrity requirements.

Section 1 of this report describes the scope of inspections performed, including the nondestructive examination techniques utilized for each degradation mechanism.

Section 2 contains the inspection results, which include:

• Degradation mechanisms found;

• Number of tubes plugged during the inspection outage for each degradation mechanism;

• Number and percentage of tubes plugged to date; Page 3 of 6

Enclosure with TXX-13152

• The results of condition monitoring, including the results of tube pulls and in-situ testing; Section 3 contains the location, orientation (if linear), and measured sizes (if available) of service induced indications.

Section 1: Scope and Examination Techniques of Inspections Performed The actual inspections performed during 1RF1 6 met or exceeded both the Technical Specification minimum requirements and the requirements of the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR) Steam Generator Examination Guidelines, Revision 7. The following primary side inspections were performed in all four SGs (unless specified):

• 50% full length bobbin inspection (straight legs only in Rows 1 through 3)

• Full length bobbin inspection of 96 tubes surrounding the stayrods

• 20% +Point inspection of hot leg (HL) Top of Tubesheet (TTS) from 3 inches above to 3 inches below TTS

• 50% +Point inspection of the U-bends in Rows 1 through 3 (same tubes as in the bobbin program)

• 50% +Point inspection of all dents/dings > 5 volts

• 50% +Point inspection of the traceable anomaly signals (TRA) from the PSI (50% of 23 tubes)

• 100% +Point inspection of peripheral tubes in the HL and CL from 3 inches above to 3 inches below TTS

• Special interest Rotating Pancake Coil (RPC) (freespan signals without historical resolution, bobbin I-code indications)

• 100% tube plug video inspection in HL and CL (1 tube)

• Video scan of channel head bowl in HL and CL as recommended by NSAL-12-1 In addition, the following secondary side maintenance and inspections were performed:

• Sludge Lancing in all four SGs

" TTS secondary side video inspection including FOSAR in all four SGs

• Upper bundle video inspection (SG 2)

• Lower shell gasket replacement Page 4 of 6

Enclosure with TXX-13152 Section 2: Inspection Results Degradation mechanisms found:

One degradation mechanism was found during 1 RF1 6, namely, tube wear at tube support plate. One indication of tube wear at a TSP was found.

Identification of Tubes Plugged:

One tube was stabilized and plugged during 1RF1 6 by administrative decision since it was located adjacent to a loose part that could not be retrieved. The plugged tube is R13C17 in SG4.

Total Number and percentage of tubes plugged to date:

A total of two tubes have been plugged in U1 RSGs. The two plugged tubes account for 0.01% of the total tubes in U1 RSGs. Tube R32C90 in SG3 was plugged in the factory.

Table 2A: List of All Plugged Tubes through CPNPP 1RF16 NoPlug Ind Per Chn Locn Repair Inchl Attribute No Date SG Row Col Volts Deg 1 Pre- 3 32 90 Factory service plug 2 1RF1 4 13 17 4.8 83 PLP 11 TSH 0.16 Preventive Results of Condition Monitoring (CM), including the results of tube pulls and in-situ testing:

CM is a "backward looking" evaluation to determine if SG performance criteria were satisfied during the operating period prior to the shut down and inspection. The SG inspection results are used as the input for this assessment.

Existing degradation mechanisms are those tube degradation mechanisms that were present in these SGs as determined by SG inspections. Prior to 1RF16, no degradation mechanisms existed in the CPNPP Unit 1 RSGs; hence, CM was successful for the "existing" mechanisms.

Potential degradation mechanisms are those mechanical and corrosive processes that have not been reported in prior inspections in the SGs but are judged to have a potential to occur in the current inspection period based on industry experience and/or laboratory data. Based on the assessment of industry experience and laboratory data, the following three potential degradation mechanisms were identified for CPNPP Unit 1 RSGs for 1RF16:

• Tube wear at AVBs

• Tube wear at TSPs

• Tube wear due to foreign objects Page 5 of 6

Enclosure with TXX-13152 During the 1RF16 inspection, no indications of tube degradation were reported at AVBs or due to foreign objects. Hence, SG performance criteria were satisfied for these two potential degradation mechanisms. One eddy current indication suggestive of tube wear at a TSP was reported during 1RF16. This indication was located in SG 3 in Tube R55C121 at TSP 9C. This indication was detected by bobbin inspection. The location was tested using a +Point probe. The +Point results confirmed the indication as a volumetric degradation (wear) at the bottom edge of the TSP. A detailed evaluation was performed subsequently by the lead analyst in support of the engineering evaluation. This detailed evaluation showed a wear depth of 6% TW and an estimated axial length of 0.37 inch.

The CM limit for tube wear at TSP was reported in the 1RF1 6 Degradation Assessment (DA). The CM limit reported in the DA was 52% TW for depth estimation using bobbin coil ETSS 96004.1. This CM limit is based on a conservative flaw length of 1.2 inches (slightly longer than the 1.12 inch thickness of the TSP). The DA also reported the CM limit for +Point estimation of the flaw size using ETSS 96910.1. The CM limit based on the +Point inspection for a 1.2 inch long wear flaw is 46% TW. Since the flaw length is much smaller than the value used for the CM limit calculation, the calculated CM limits are very conservative. The estimated depth of the flaw is 6% by +Point inspection. Since the flaw depth is much smaller than the CM limit, CM was satisfied.

No tube pulls or in-situ testing was performed during 1 RF1 6.

Section 3: Indication Listing No service induced indications were found except for the one indication suggestive of tube wear at a TSP. This indication was located in SG 3 in Tube R55C121 at TSP 9C. The production analysis yielded a depth of 5% TW for this indication. A detailed evaluation showed a wear depth of 6% TW and an estimated axial length of 0.37 inch.

The eddy current inspection results for this tube, including the +Point inspection at the top of the tubesheet, is shown in the following table.

SG Row Col Volts Deg Ind Per Chn Locn Inchi BegT EndT PDia PType 3 55 121 NDD TSC TSC 0.61 ZPSMR 3 55 121 NDD TSH TSH 0.61 ZPSMR 3 55 121 0.2 138 DSS P1 09C -0.56 TEC TEH 0.61 ZBAZC 3 55 121 0.24 41 VOL 6 09C -0.52 09C 09C 0.61 ZPSMR 3 55 121 0.14 0 PCTI" 5 P4 09C -0.54 09C 09C 0.61 ZPSMR Page 6 of 6

Attachment to Enclosure with TXX-13152 Page 1 of 2

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Attachment to Enclosure with TXX-13152 Page 2 of 2 FIOURE 9A 84MADHOLL M~E IhPECIMN POR; 0t40 4.GP Amp 2,s' I)4rCh Pa~r cou LomAiG.s crm wuEmkit 04LY)

°X-TS NEAR SIDE Z-TS 2 -TPS FAR SIDE ARSID NOTE Closure openings are identified per the following designations:

0 Secondary Manways M-1 & M-2 a Handholes: W-TS, X-TS, Y-TS and Z-TS 0 2_5" Inspection Ports: W-A, W-8, W-C, W-D, W-E, W-F, W-G and W-H; Y-A, Y-B, Y-C, Y-D, Y-E, Y-F, Y-G and Y-H

• 4" Inspection Ports: W-J and Y-J

• Cone Inspection Ports: W-K and Y-K Figure 1-3. Location of secondary side inspection and access ports