3F0796-15, Forwards Response to RAI Re GL 95-03, Circumferential Cracking of Steam Generator Tubes
| ML20116A941 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 07/25/1996 |
| From: | Beard P FLORIDA POWER CORP. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| 3F0796-15, 3F796-15, GL-95-03, GL-95-3, NUDOCS 9607290038 | |
| Download: ML20116A941 (16) | |
Text
r Florida Power CORPORATION O ~$N July 25, 1996 3F0796-15 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555-0001
Subject:
Generic Letter 95-03, Request for Additional Information
References:
A.
NRC to FPC letter, 3N0696-12, dated June 21, 1996 B.
FPC to NRC letter, 3F0695-03, dated June 22, 1995
Dear Sir:
Attached please find Florida Power Corporation's (FPC) response to Reference A, Request for Additional Information (RAI) regarding Generic Letter (GL) 95-03, "Circumferential Cracking of Steam Generator Tubes". Reference A was received on June 25, 1996 and contains eight plant-specific questions relevant to the Crystal River Unit 3 (CR-3) Once Through Steam Generators (OTSGs).
The first four questions of the RAI were directed to the areas that have been identified as susceptible to circumferential cracking in OTSGs.
These areas were the focus of the GL 95-03 inspections during the CR-3 Refuel Outage 10 (10R) examinations of the OTSGs.
Although the area addressed by your Question 1 (denting / dings for OTSGs) was not part of the inspection plan identified in our original response to the GL (Reference B),
this area was subsequently incorporated into the inspection plan.
The decision to inspect this area was made due to our awareness of this being an area of interest for recirculating steam generators (RSGs) which was also identified as being of interest for OTSGs subsequent to the submittal of our original response to the GL. The inspections described in Reference B were implemented during 10R. Since the RAI was received after 10R, in addition to the information requested in it, FPC is also providing a summary of results of each of the GL 95-03 inspections performed during 10R including the results of additional inspections added to the 10R scope as a result of industry operating experience feedback.
Specifically, FPC is providing a summary of the inspection and the results of the denting (dings) inspection (Question 2), the tube-to-tubesheet expansion transition inspections (Question 3) and the tube-to-sleeve expansion inspections (Question 7).
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U. S. Nuclear Regulatory Commission 3F0796-15 Page 2 -
Based on the results of our inspection and potential for steam generator tube rupture at CR-3 remaining very low, FPC continues to believe that operation is safe and fully t
justified. To assure this confidence is maintained, future inspections will continue monitoring areas susceptible to circumferential cracking.
I Sincerely, l
P. M. Beard Jr, j
Senior Vice President j
Nuclear Plant Operations PMB/LVC Attachment xc:
Regional Administrator, Region II Project Manager, NRR Senior Resident Inspector l
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U. S. Nuclegr Regulatory Commission 3F0796-15 Page 3' STATE OF FLORIDA COUNTY 0F CITRUS P. M. Beard, Jr. states that he is the Senior Vice President, Nuclear Operations for Florida Power Corporation; that he is authorized on the part of said company to sign and file with the Nuclear Regulatory Commission the information attached hereto; and that all such statements made and matters set forth therein are true and correct to the best of his knowledge, information, and belief.
V P. M. Beard, Jr.
Senior Vice President Nuclear Operations Subscribed and sworn o before me, a Notary Public in and for the State and County above named, this day of JULY
, 1996.
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U. S. Nuclegr Regulatory Commission 3F0796-15 Page 4' NRC Question:
1.
Discuss the differences between the Crystal River steam generators and the generic information provided in the B&W Owners Group response, if any.
FPC Response:
The design characteristics of Crystal River Unit 3 (CR-3) are generally the same as those described in the generic design. information provided in FPC's response to GL 95-03.
However, there are some design and manufacturing differences between CR-3 and the generic B&W Owners Group (BWOG) response.
Only those differences determined to be potentially significant to the circumferential cracking issue that were not addressed in the BWOG letter are included here.
The outer tube locations in the 15th tube support plate (TSP) are drilled to a 0.637" minimum /0.646" maximum diameter (see Figure 1.1).
There are 1,608 drilled hole locations in "A" 0TSG and 1,601 drilled hole locations in "B" 0TSG remaining in service.
All remaining TSP openings in the 15th TSP, and all openings at the other support plates are broached as described in the GL 95-03 response.
OTSG tubesheet bore sizes differ among plants. OTSGs at CR-3 and three other B&W units have 0.635" +.006/.002 tube-sheet bores. The smaller tube-sheet bore size is significant to the discussion of potential for cracking since smaller hole sizes would have resulted in a lower strain required to mechanically. roll in the 0.625" outside diameter (OD) OTSG tube to form the 4
tube-to-tubesheet joint during manufacturing.
The generic response to GL 95-03 noted that a number of roll transitions in each OTSG were re-rolled after full bundle stress relief to eliminate leakage observed through seal welds during shop hydrostatic testing. According to shop manufacturing records, the number of tubes presently in service with preservice re-roll, non-stress relieved roll transitions are as follows:
A-0TSG B-0TSG Upper Tube Sheet (UTS) 2 4
Lower Tube Sheet ~(LTS) 2 2
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U. S. Nuclear Regulatory Comission j
3F0796-15 Page 5 FIGURE 1.1 DRILLED H0LES IN THE 15TH TSP I
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U. S. Nuclear Regulatory Commission 3F0796-15 Page 6 -
NRC Question:
2.
Dented regions including dented tube support plates.
In the Electric Power Research Institute (EPRI) report NP-6201, "PWR Steam Generator Examination Guidelines":
Revision 3, dated November 1992, it indicated that B&W plants have experienced denting of tube support plates and l
in the lower tubesheet.
Circumferential indications have been observed at I
dented areas in recirculating steam generators (RSGs).
If denting has been observed at Crystal River and it is a location potentially susceptible to circumferential cracking, please _ submit the information requested in Generic Letter (GL) 95-03 per the guidance contained in the GL.
If a voltage threshold is used to determine the threshold for examining dent s, provide the calibration procedure used (e.g., 2.75 volts on 4-20% through wall ASME holes at 550/130 mix).
EPRI report NP-6201 indicates that the fifteenth tube support plate contains both broached holes and drilled holes.
The drilled holes being prone to denting.
P. lease clarify whether all of the tube support plates are of the l
l broached hole designs or whether a number of them contain drilled holes.
Discuss whether denting has been limited to the drilled hole locations, if applicable, or if it has been observed at other support pate intersections (i.e., broached holes).
FPC Response:
0TSG OPERATING EXPERIENCE In general, tube diameter reductions (called " dings" in most OTSGs to distinguish them from the more severe denting observed in RSGs) are most prevalent at the secondary face of the upper and lower tubesheets. Most plants have detected some dings at tube support plate (TSP) locations as well, but in most cases, the number is minor when compared to the tubesheet (TS) secondary faces.
Previous inspection of dings at other OTSG plants have documented the presence of small eddy current indications within larger ding indications. At one OTSG pl ant, two circumferentially oriented indications were detected in upper l
tubesheet (UTS) secondary face dings during motorized pancake coil (MRPC) examinations.
Expanded MRPC examination of other UTS dings during the same l
inspection, as well as follow up examinations, did not identify the presence I
of any similar indications.
Because this plant also identified circumferentially oriented IGA indications in the same region at locations l
where no dings were present, it could not be determined whetner the presence i
of the crack-like indications were due to the dings associated with them or due l
to general IGA coincidental to the ding.
Another OTSG plant has also detected circumferential indications within larger ding indications. These dings were typically of very large voltages and were located at TSPs in the upper boiling region of the OTSGs where higher temperatures are present. Although no tube leaks have occurred in OTSGs due to circumferential cracking at ding 1r ations and no tube pull data is available to confirm the occurrence of crarking at dings, inspection experience at other OTSG plants supports the potential susceptibility of dings to circumferential cracking.
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I U. S. Nuclear Regulatory Commission 3F0796-15 i
Page 7 CR-3 INSPECTION OF DINGS Although not a commitment to GL 95-03, during 10R (Spring 1996), FPC inspected l
l a sample of dings using MRPC during 10R.
This inspection was added to the l
outage scope as a result of the B&W plants' operational experience findings described above. FPC inspected dings in 31 tubes including 18 dings at the UTS l
secondary face and 8 dings at TSPs in the "A" 0TSG and 5 dings at TSPs in the "B"
OTSG.
The UTS secondary face dina sample was biased to those considered most susceptible to cracking through selection of dings in inservice tubes l
which border tubes plugged via an explosive charge.
l No voltage threshold was used in the selection of individual dings for RPC l
examination.
However, the use of a voltage threshold for ding reporting requirements did limit the population of dings considered for RPC inspection.
The bobbin reporting criteria used at CR-3 is 5.0 volts with olibration performed at 6.0 volts on 4-100% thronh-wall ASME holes at both the straight 600 kHz frequency and the 600/200 mix frequency.
No crack-like indications were det m+ed during MRPC examination of the dings for circumferential cracking.
W non-quantifiable indication (NQI) was l
identified during tube bobbin inspections at a ding location which had n9t been selected for MRPC examinaon.
This NQI was examined using both MRPC and rotating Plus-Point probes.
Both inspections confirmed the indication to be i
small and volumetric as confirmed on all coils.
This tube was removed from service.
Lower tube sheet (LTS) secondary face dings were not inspected during 10R since these are believed to be attributable to tubesheet/ tube outer diameter deposits.
During CR-3's 1994 tube pull, three tubes removed contained ding indications at the LTS secondary face as detected by field bobbin examination.
l These indications were later again confirmed by MRPC during laboratory examination.
Radiography of all three revealed no obvious indications, although a deposit ridge was noted on two of the samples.
Additional examinations (stereovisual and post-swelling) did not confirm the presence of any corrosion or reduction in diameter at these locations.
As shown in Table 2.1, the overall number of dings identified on CR-3 tubes is extremely small in comparison to the total population of inservice tubes. This l
is particularly true considering the fact that the largest number of dings cecorded are at the LTS secondary face where pulled tubes have not confirmed tN presence of any corrosion or tube diameter reduction as the source of LTS l
di g indications.
10R MRPC examination of a sample of dings likewise failed i
to.dentify the presence of crack-like indications in CR-3 ding indications.
Cantinued operation of the CR-3 OTSGs is justified by good operational l
l performance with low Reactor Coolant System leakage.
Continued operation is further justified by the small population of dings present in the CR-3 OTSGs and the absence of crack-like indications.
I Future inspection plans at CR-3 will continue to assess the status of ding indications through performance of additional MPRC examinations.
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Table 2.1 below provides a listing by TSP of the current number of in service dings at CR-3. As mentioned in the response to Question 1, only the eeter tube locations in the 15th TSP are drilled holes. Therefore, there does not ap p ar to be a direct correlation between drilled holes and ding indf cations at CR-3.
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- U. S. Nuclear Regulatory Commission 3F0796-15 Page 8--.
l TABLE 2.1 i
Number of Dings at TSPs (-TSa i 1.0 inch from center line) l 1
i TS/ TSP "A"
0TSG "B" OTSG IS 20 6
t 2S 12 4
t 3S 5
5 4S 10 6
55 8
14 6S 8
12 I
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BS 13 13 9S 10 14 10S 7
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11S 7
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12S 11 7
l 135 18 9
14S 17 5
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ifs 14 11 UTS 36 36 LTS 636 308 a!'
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1 U. S. Nuclear Regulatory Commission 3F0796-15 Page 9 NRC Question:
3.
Expansion transition examinations.
Provide the number of tubes currently in service that were rrrolled after the furnace stress relief.
Clarify the inspections performed during the last outage at the expansion transition region. Address the probe used and the number of tubes inspected.
Provide the criteria to be used for determining whether expansion of the inspections for expansion transition indications is necessary.
FPC Response:
The number of tubes re-rolled after stress relief (currently in service) are four (4) in the A-0TSG and six (6) in the B-0TSG.
During 10R, FPC performed examinations at the tube-to-tubesheet expansion transitions (see below) and at tube-sleeve expansions at sleeve roll transitions (the information about tube-sleeve expansions is provided in the response to Question 7).
10R Tube-to-tubesheet Expansion Transition Inspections i
The non-stress relieved roll transitions had been included in the scope of previous bobbin inspections as part of the random samples inspected per CR-3 Technical Specifications. However, the 10R inspections represented the first time these transitions have been inspected with a rotating probe.
The probe of record for tnis examination was an MRPC with 0.115 inch diameter, unshielded pancake coil. The analyst guidelines used during the 10R inspection required a review of all three coils regardless of their orientation in the transition area. This probe is palified for detection of Primary Water Stress Corrosion Cracking (PWSCC) and Outside Diameter Stress Corrosion Cracking (0DSCC) per Appendix H of EPRI Report NP-6201, "PWR Steam Generator Examination Guidelines".
No indications of circumferential cracking were observed in any of the locations inspected.
Multiple axial crack-like indications were detected in the UTS roll of tube 39-116 in the "A" 0TSG.
Specifically, a shallow single axial indication (SAI) was noted in the roll itself and a multiple axial indication (MAI) was detected in the tube end, above the shop re-roll. It was clear this tube had been re-rolled as evidenced by the multiple rolls visible in the ECT data. Given the orientation and location of the crack on the inside diameter of the tube, the cause of the degradation is believed to be PWSCC.
This tube was plugged during 10R.
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l U. S. Nuclear Rcgulatory Commission 3F0796-15 Page 10 Considerations for Sample Expansion Although the population of tube expansion transition areas believed to te most susceptible to circumferential cracking is limited to those tubes which had received preservice re-roll following stress relief, the need for expanded inspections was considered following identification of the axial indication in tube 39-116.
1 As previously noted, the indications in tube 39-116 were found in an upper tubesheet (hot leg) expansion transition with clear indication of multiple I
rolls present on eddy current probe maps. Thus, it is reasonable to postulate elevated residual stresses were present at this location.
Since PWSCC would typically be expected to occur first in areas of higher residual stress combined with exposure to elevated operating temperatures, the presence of these conditions in combination was the key criteria used in selection of additional locations for inspection.
During Refuel Outages 8, 9, and 10, FPC performed tube end repair (TER) on a population of upper tube ends in the "B" 0TSG which had been damaged during the 1979 loose burnable poison rod assembly incident at CR-3.
The TER process consisted of drilling out flattened tube ends to an inside diameter which would permit the passage of an eddy current probe.
TER performed during 8R and 9R l
were followed by a field re-roll.
The field re-roll was performed over the original UTS shop roll in an effort to reduce leakage which had been observed since 1979 from damaged tube seal welds.
No stress relief was performed following the field re-roll.
Use of the field re-roll following TER was i
discontinued following 9R due to concerns with creation of new locations potentially susceptible to circumferential cracking. Only 9 tubes were field re-rolled during 10R.
These 9 field re-rolls were necessary due to over drilling of the tube end during the TER process.
Given the potential for l
additional residual stress due to the field re-roll process and the higher i
temperature present at UTS rolls (hot leg), the field re-rolled TER locations were identified as the next population of tubes which W 5e most susceptible to circumferential cracking in the expansion transitica Additionally, since the field re-rolled tube ends were originally stress ielieved inspection of a sample from the field re-rolled tubes would serve as a leading indicator by which to assess the susceptibility cf stress relieved expansion transitions to circumferential cracking.
Forty (40) UTS expansion transitions which were field re-rolled prior to 10R i
were examined using MRPC.
All 9 of the tubes field re-rolled during 10R were l
al so examined using MRPC.
No indications were identified during these inspections, thus no further expansion of the sample was performed.
i Industry Feedback i
At the closure o# the 10R inspection, FPC was notified by Centerior Energy of the identification of an axial crack-like in a potentially stress relieved roll at. Davis-Besse plant.
The affected expansion transition was originally believed to have been re-rolled following stress relief; however, subsequent review of shop records appeared to indicate that the expansion transition had not been re-rolled.
FPC participated in BWOG effort to remove the affected Davis Besse tube. A laboratory analysis plan was developed to identify the mechanism and its cause to assess the impact on future inspection plans.
Non-destructive and destructive examinations of the tube sample are currently being performed by Framatome Technologies, Inc. at Lynchburg Research Center.
U. S. Nuclear Regulatory Commission 3F0796-15 Page ll, NRC Question:
i 4.
Lane / Wedge Region.
Clarify the %spection scope in the lane / wedge region during the last steam generator 9W inspections (including the probe type and number (and/or percentagy of tubes inspected).
]
Provide the criteria to be used for determining whether the expanded inspection scope around any identified indications adjacent to the sleeve lane / wedge region is bounded.
FPC Response:
l Lane / wedge region tubes in OTSGs have long been considered susceptible to failure due to corrosion-assisted high-cycle fatigue. This susceptibility was confirmed by examination of circumferentially oriented flaws in failed tubes at other B&W plants.
Due to difficulty in early detection of this failure mechanism, as a function of the rapid propagation rate for high cycle fatigue failure (review of failed tube ECT records showed that no detectable degradation had been present in the inspection prior to the failure), CR-3 preventively installed 163 sleeves in the lane / wedge region tubes of each OTSG (326 total sleeves) during Refuel Outage 9 (1994).
A one-tube border of un-sleeved tubes in service around the lane / wedge region of sleeved tubes was examined in both OTSGs during 10R (185 tubes with 370 MRPC intersections of interest). The purpose of this examination was to confirm the continued acceptability of the existing CR-3 sleeve region and ensure the presence of the preventive sleeves did not result in expansion of the region susceptible to corrosion assisted high-cycle fatigue tube failure. The examination consisted of a motorized rotating pancake coil (MRPC) inspection of the 15th TSP and UTS face areas of each tube. The probe of record for this examination was a 0.080 inch diameter, shielded motorized rotating pancake coil which is qualified per Appendix H of EPRI Report NP-6201.
No indications of circumferential cracking were observed in any of the tubes inspected.
Since no indications of concern were identified during the 10R lane / wedge inspection of CR-3 OTSGs, nc expansion of the sample was performed.
1 U. S. Nuclear Regulatory Commission 3F0796-15 Page 12 NRC Question:
5.
Recently, several tubes have been pulled from B&W Once Through Steam Generators (OTSGs). Discuss any analysis performed on these pulled tubes for monitoring the development of circumferential cracking.
For examp7e, discuss the destructive and non-destructive examinations performed on the se pulled tubes in the laboratory at the expansion transition area.
FPC Response:
The diseassion below addresses tube pull findings from B&W OTSGs which are relevant u monitoring of those areas susceptible to circumferential cracking.
HIGH CYCLE FATIGUE (lane /wedae reoion at 15th TSP and UTS face)
During the late 1970's and early 1980,s tubes were pulled from the Oconee plants to investigate the cause of tube failures observed in a lane / wedge region near the untubed lane.
Laboratory results from these pulls confirmed failures due to circumferential cracks caused by corrosion assisted high-cycle fatigue.
This damage mechanism was attributed to the unique secondary flow characteristics existing in this part of the steam generator.
Review of historical eddy current examination results for the failed tubes determined in most cases that no detectable degradation had been present in the inspection prior to tube failure. The lack of early detection capability was attributed to the rapid propagation of the high-cycle fatigue mechanism as evidenced by the rapid step increases in leakage observed over short periods of time during actual tube failures.
These failures have been addressed in OTSG plants by sleeving the tubes in the susceptible area.
DINGS Discussion of evaluations performed on ding indications present at the LTS secondary face on CR-3 pulled tubes is provided in the response to Question 2.
Two pulled tube samples removed from Oconee Unit 1 in 1994 contained field eddy current indications identified as possible dings. These indications were both located at tube support plates.
Subsequeat laboratory analysis of tubes at these locations (including NDE with bobbin, MRPC, and Rotating Field Eddy Current (RFEC), ultrasonic testing, stereovisual and electron microscope (SEM) examination) identified a deposit covered erosion pit on one tube sample but failed to confirm the presence of any degradation on the other tube sample.
No crack-like indications or tube diameter reductions characteristic of dings were present.
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O. S. Nuclear Regulatory Commission 3F0796-15 l
Page 13 EXPANSION TRANSITIONS Recent tube pulls ? 'om CR-3 (1992 and 1994) and Oconee-3 (1994) have been performed to determi.e the cause of ECT indications that were observed in areas of the steam generator where the damage mechanisms are not well understood.
These included both freespan indications and TSP indications, primarily in the l
boiling region of the OTSG. The tubesheet expansion region was not an area of interest due to the lack of observed degradation in this area. Additionally, the tubesheet expansion area was drilled out during the removal process to ease the removal of the rest of the tube.
The tubesheet expansion area was therefore not available for laboratory examination.
The response to Question 3 provides an update regarding the tube pull that was performed at Davis-Besse to identify the mechanism causing a crack-like indication detected at a stress relieved roll transition.
The response explains that the final results of the tube pull are not available at the time of this submittal.
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O. S. Nuclear Regulatory Commission 3F0796-15 Page 14.
NRC Question:
l 6.
Clarify whether the inspection method at Crystal River is qualified for the detection of circumferential cracks per Appendix H of Electric Power research Institute (EPRI) report NP-6201 or whether a site specific qualification program will be used.
If using site specific qualification procedures, state the differences and provide the justification for these criteria including a discussion of pulled tube data to support the deductibility of circumferential cracks in the field.
FPC Response:
i The following summarizes the qualification of the probes used for the inspections performed during Refuel 10 for the Generic Letter 95-03 examinations:
Border tubes on the lane / wedge region were inspected at the UTS secondary face and 15th TSP intersections using a 0.080 inch shielded rotating pancake coil.
l This probe is qualified to Appendix H of EPRI Report NP-6201 for datection of IGA /0DSCC and wear at TSPs if no denting (dings) is present.
The probe is qualified for detection of ODSCC and PWSCC at support plates with dents.
l The inspection of the non-stress relieved roll transitions and field re-roll were performed with a 0.115 inch diameter unshielded pancake coil.
MRPC has been qualified per Appendix H of EPRI Report NP-6201.
t The tube-sleeve inspections were performed using a motorized Plus Point probe
/
(Type 3331-2-1). No inspection technique is currently qualified per Appendix i
H for the detection of circumferential cracks in OTSG sleeves.
However, the l
Plus Point probe is currently qualified per Appendix H of EPRI Report NP-6201 for detection of circumferential cracking in Westinghouse HEJ sleeves and is the best technique available for OTSG sleeve inspection.
A BWOG Non-l Destructive Examination Committee project to qualify the plus point probe for OTSG sleeves is currently being pursued.
Qualification to Appendix H of EPRI l
Report NP-6201 is expected by the end of 1996.
Although not included as a specific commitment in FPC's respon:;e to GL 95-03, l
FPC inspected a sample of ding indications using a 0.080 inch shielded rotating pancake coil. This coil is qualified per Appendix H of EPRI Report NP-6201 for detection of PWSCC at dented tube support plates. A rotating Plus Point probe was used as a second level inspection to further assess any RPC identified indications. The Plus Point probe is qualified for detection of both ODSCC and PWSCC at dented tube support plates.
Field comparison of MRPC inspection results and Plus Point probe inspection results for the small, volumetric indication identified in a tube support plate ding on tube 56-98 in the "A"
OTSG indicated comparable detection capabilities for indications located within j
dings.
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V. S. Nuclear Regulatory Commission 3F0796-15 Page 15.
NRC Question:
7.
Discuss the number and types of sleeves used at Crystal River.
Clarify the extent of the inspections performed on these sleeved tubes during the last outage (e.g.,100% of all the sleeve joints were examined with the
" optimized" rotating cross wound probe).
FPC Response:
The total population of sleeves in CR-3 OTSGs is 326 sleeves. 163 were installed in the upper 80 inches of the lane / wedge region of each OTSG during 9R. The sleeves are mechanically rolled, Inconel 690 material, 80 inches long.
A 20% random sample of tube-sleeve expansions at sleeve roll transition (66 sleeves) in the "A" 0TSG was examined during 10R with the Plus-Point probe.
This probe is qualified to Appendix H of the EPRI Guidelines for the detection of crack-like indications in Westinghouse HEJ sleeves. A qualification program for OTSG sleeves is currently in progress through the BWOG.
The unrolled portion of each sleeve was examined using a bobbin probe. There were no crack-like indications detected during sleeve examinations.
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Page 16.
NRC Question:
8.
During the Maine Yankee outage.in July / August 1994, several weaknesses were identified in their eddy current program as detailed in NRC Information Notice 94-88, " Inservice Inspection Deficiencies Result in Severely Degraded Steam Generator Tubes". In Information Notice 94-88, the Staff observed that several circumferential indications could be traced back to earlier inspections when the data was reanalyzed using terrain plots. These terrain plots had not been generated as part of the original field analysis for these tubes.
For the rotating pancake coil (RPC) e'xaminations performed at your plant at locations susceptible to circumferential cracking during the previous inspection (i.e.,
the previous inspection per your Generic Letter 95-03 response), discuss the extent to which terrain plots were used to analyze the eddy current data.
If terrain plots were not routinely used at locations susceptible to circumferential cracking, discuss whether or not the RPC eddy current data has j
been re-analyzed using terrain mapping of the data.
If terrain plots were not routinely used during the outage and your data has not been reanalyzed with terrain mapping of the data, discuss your basis for not reanalyzing your previous RPC data in light of the findings at Main Yankee.
l Discuss whether terrain plots will be used to analyze the eddy current data at locations susceptible to circumferential cracking during your next steam generator tube inspection (i.e., the next inspection per your Generic Letter 95-03 response).
FPC Response:
The CR-3 analysis guidelines required routine terrain mapping of MRPC data during 9R (outage prior to the GL 95-03 response).
The CR-3 eddy-current analysis guidelines used during 10R (the next. inspection after our original GL 95-03 response) also required, as a minimum, terrain plotting of all MRPC data r
using the base frequency (300 kHz) whether the data was being used for i
circumferential crack detection or confirmation of bobbin coil indications.
It is expected this practice will continue in future inspections. In addition to terrain plotting, the guidelines required the use of lissajous and strip chart displays to ensure that all tube wall degradation was detected and recorded. CR-3 completed the examination commitments in response to GL 95-03 during our 10R outage. Since our analysis guidelines required routine terrain mapping of RPC data during 9R, reanalysis of previous MRPC data is not necessary.
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i 4
.m,.
.--r--
,.,