RS-08-019, Response to Request for Additional Information - Steam Generator Inspection Summary Report
| ML080510729 | |
| Person / Time | |
|---|---|
| Site: | Byron  (NPF-066) |
| Issue date: | 02/20/2008 |
| From: | Simpson P Exelon Generation Co, Exelon Nuclear |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| RS-08-019 | |
| Download: ML080510729 (12) | |
Text
Exelon Generation www.exeloncorp.com 4300 Winfield Road Warrenville, IL 60555 RS-08-019 February 20, 2008 U. S. Nuclear Regulatory Commission ATTN : Document Control Desk Washington, DC 20555-0001 Byron Station, Unit 2 Facility Operating License No. NPF-66 NRC Docket No. STN 50-455
Subject:
Response to Request for Additional Information - Steam Generator Inspection Summary Report
References:
- 1) Letter from D. M. Hoots (Exelon Generation Company, LLC) to U. S. Nuclear Regulatory Commission, "Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling Outage 13," dated July 31, 2007
- 2) Letter from M. Thorpe-Kavanaugh (U. S. Nuclear Regulatory Commission) to C. G. Pardee (Exelon Generation Company, LLC),
"Byron Station, Unit 2 - Request for Additional Information Regarding the 2007 Steam Generator Tube Inspection," dated January 17, 2008 In the Reference 1 submittal, Exelon Generation Company, LLC (EGC) provided the Byron Station Unit 2 Spring 2007 (B2R13) Steam Generator Inservice Inspection Summary Report. During the course of their review of the Reference 1 submittal, the NRC determined that additional information was required. This NRC request for additional information was provided in Reference 2.
The attachments to this letter provide the EGC response to the Reference 2 request.
There are no regulatory commitments contained in this response.
If you have any questions about this letter, please contact Mr. David Chrzanowski at (630) 657-2816.
Respectfully, Patrick R. Simpson Manager - Licensing Exelon : Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection : Byron Station Steam Generator 2C Pre-Heater Baffle Plate Inspection Tubesheet Map Nuclear Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection
NRC Question 1 :
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection For each refueling outage or SG tube inspection since installation of the SGs, please provide the cumulative effective full power months that the SGs have operated.
Exelon Generation Comoanv. LLC (EGC) Response:
The following is a listing of effective full power months (EFPM) by refueling outage for Byron Station Unit 2.
NRC Question 2:
EGC Response:
Byron Station Unit 2 Cumulative Operating Duration The +Pointm coil was used to inspect the U-bend region of 25 percent of the SG tubes in rows 1 and 2. Please discuss when the last time the U-bend region of the remaining 75 percent of the row 1 and 2 tubes was inspected. In addition, please confirm that you have inspected 50 percent of the portions of the tubes (with the objective of detecting flaws that may satisfy
, the tube repair criteria) susceptible to cracking (e.g.,bulgesloverexpansions, dents, etc.) by the refueling outage nearest the midpoint of your current sequential period and the remaining 50 percent by the refueling outage nearest the end of your current sequential period, whichever is applicable given your response to Question 1.
The following table provides the eddy current bobbin coil and +PointTM inspection summaries from refueling outage (RFO) 8 through RFO 13.
Refueling Outage Cumulative Effective Full Power Years Cumulative Effective Full Power Months 1
1.192 14.304 2
2.354 28.248 3
3.484 41.808 4
4.674 56.088 5
5.902 70.824 6
7.217 86.604 7
8.629 103.548 8
10.038 120.456 9
11.426 137.112 10 12.823 153.876 11 14.285 171.420 12 15.738 188.856 13 17.191 206.292
- Inspection of SG 2B only
- Inspection extended to 3" above to 17 inches below the top of the hot leg tubesheet
- Degradation mechanism not considered being a potential damage mechanism as determined by degradation assessment in referenced outage.
NRC Question 3:
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection Byron Station Unit 2 90 EFPM Period Inspection Summary Twenty five percent of the dents and dings whose voltages were greater than 5 volts were inspected with a rotating probe, and 50-percent of the dents and dings whose voltages were between 3 and 5 volts were inspected with a rotating probe. Given the limited ability of the bobbin probe to detect any forms of degradation in dents whose voltages are greater than 5 volts, please discuss why more inspections were performed in the lower voltage dents than in the higher voltage dents.
EGC Response:
During the second half of the current inspection period, the threshold for inspecting dents and dings was conservatively lowered from 5 volts to 3 volts. This was due to experience at a plant with mill annealed Alloy 600 tubing where cracking was found in dents and dings that were less than 5.0 volts. Although, Byron Station Unit 2 steam generators contain thermally treated Alloy 600 tubing, which is more resistant to corrosion degradation than mill annealed Alloy 600 tubing, the threshold for inspecting dents and dings was conservatively lowered during the second half of the inspection period. To meet the Technical Specification 5.5.9.d inspection requirements of inspecting 50% of the tubes by the end point outage, a 50% inspection of dents and dings that were 3-5 volts was performed. Byron Station had already been inspecting dents and dings that were > 5.0 volts, as indicated by the Table in the response to Question 2. Therefore, a 25% sample in the current outage was performed to meet the 50% inspection requirement by the end-point outage.
RFO 8 RFO 9 RFO 10 RFO 11 RFO 12 RFO 13 90 Mo. Inspection Interval Start Mid End Point Point Point Point Outage Outage Outage Period EFPM 0.456 16.656 33.42 50.964 68.4 85.836 Bobbin Coil Full Length 100%
100%*
100%
100%
100%
100%
Row 1 and 2 U-Bend +Point 25%
0%
75%
25%
0%
25%
Hot
+Point" Le Top of Tubesheet 25%
0%
75%
25%
20%**
30%**
+3"/-3" Hot Leg Tubesheet Bulges
- .~*
20 ° /° 30 ° /° and Overex ansions +Point"'
Hot
+Point" Le Dents/Dings >5 volts 25 °
/° 0 ° /° 75 ° /° 25
° /° 0 °
/° 25 °
/° Hot Leg Dents/Dings 3-5 volts 50%
+Point
NRC Question 4:
In evaluating the SG tube examination techniques in Table 4.1 [of the Referenced submittal], it does not appear that the SG tubes were inspected for axially oriented outside diameter stress corrosion cracking in dents and dings. In addition, it does not appear that the SG tubes were inspected for axially and circumferentially oriented outside diameter stress corrosion cracking in the U-bend region. Please confirm that the techniques used were capable of finding these degradation mechanisms.
EGC Response :
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection Electric Power Research Institute (EPRI) inspection technique 22401.1, revision 4, was used to inspect dents and dings. This technique was originally qualified by EPRI to detect indications of outer diameter stress corrosion cracking (ODSCC). Table 4.1 of the referenced submittal should have stated "ODSCC" instead of "PWSCC" (primary water stress corrosion cracking, which originates from the inner tube surface) for the description of inspection technique 22401.1.
Per the degradation assessment that was performed prior to the current outage, it was determined that the only potential damage mechanism in Row 1 and Row 2 U-bend region was PWSCC. This determination was based upon industry experience in low row U-bends, including the experience of the original Byron Station Unit 1 steam generator mill annealed Alloy 600 tubing. ODSCC in U-bend tubing had been found in the non-stress relieved U-bend tube region in plants with mill annealed Alloy 600 tubing.
Additionally, the stress corrosion cracking was first detected in other regions of the steam generator prior to detecting ODSCC in the non-stress relieved U-bend region (i.e.,
hot leg tubesheet expansion region and tube support plate region).
The Byron Station Unit 2 SG tubing is thermally treated Alloy 600 tubing and no stress corrosion cracking has been detected in any region of the steam generators.
Discussions with the steam generator original equipment manufacturer indicated that the non-stress relieved U-bend tubing contains less residual stress than the top of the tubesheet expansion transition. The U-bend region operates at a significantly lower temperature than the hot leg top of tubesheet region and consequently the U-bend region is less susceptible to stress corrosion cracking given equal or lower residual stress. The degradation assessment determined that ODSCC in the non-stress relieved U-bend region is not a potential damage mechanism until stress corrosion cracking occurs at other regions of the SG and therefore inspection of this area is not required.
Additionally, no other plant in the industry with thermally treated Alloy 600 tubing has found stress corrosion cracking in the U-bend region.
NRC Question 5:
Please clarify the last sentence in section 4.2.3, [of the Referenced submittal] "Tubes containing bulges and overexpansions within the initial sample were inspected from the top of the hot leg tubesheet +3 inches to -17 inches below the top of the tubesheet. " For example, is the sentence indicating that the 30 percent sample of bulges and overexpansions was a subset of the 30 percent sample of tubes inspected from 3 inches above the top of the tubesheet to 17 inches below the top of the tubesheet?
EGC Response :
During the inspection of the hot leg tubesheet, two areas of interest were inspected with 30% samples. Thirty percent of the tubes within the tube bundle were inspected with the
+PointTM probe from 3 inches above the tubesheet to 17 inches below the tubesheet.
Additionally, 30% of the tubes with bulges and overexpansions within the top 17 inches of the tubesheet were inspected were also inspected with the +PointTM probe from 3 inches above the tubesheet to 17 inches below the tubesheet. The total tubesheet inspection plan was developed to overlap the two populations to extent possible in order to limit the number of tubes inspected while satisfying the two separate inspection populations.
NRC Question 6:
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection Additional pre-heater baffle plate expansion transitions were inspected in three of the SGs. Please discuss the reason for expanding the sample, the final scope of examination (e.g., 35 percent of the expansions), and the results of the inspection. Please discuss the purpose and nature of the flow block.' Please discuss the results of the visual inspection of the preheater expansion transitions in SG 2D and discuss why a visual inspection was only necessary. In Attachment B.5 [of the Referenced submittal],
tubesheet maps for only SGs 2A and 2B were provided. Please clarify whether the preheater baffle expansion transitions were inspected in SG 2C.
EGC Response :
The Byron Station Unit 2 SGs are Westinghouse Model D-5 SGs that contain a feedwater preheater section. During fabrication of the SGs, Westinghouse hydraulically expanded 144 tubes into the 2"d and 3rd cold leg baffle plates in the high flow regions of the pre-heater in order to eliminate unacceptable tube vibration. The high flow region where the tubes were expanded is located in the last tube row (Row 49), specific tubes along the T-slot, and specific tubes on tube periphery from Row 49 to the flow block.
The flow block is located between the 2"d and 3rd cold leg baffle plates in the tube annulus between the wrapper and the tube bundle. The purpose of the flow block is to block the flow along the tube annulus and to distribute the flow into the tube bundle.
Consequently, as demonstrated by industry experience, this configuration along the periphery can trap foreign objects between the wrapper, flow block and the tubes above the 2"d baffle plate. Also demonstrated by industry experience, the expanded tubes in this region, in some cases, can interfere with foreign object detection. Therefore, Byron Station developed a program to inspect the 2"d baffle plate for foreign objects using visual and eddy current techniques.
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection The visual inspection of the 2nd baffle plate consists of a visual inspection of the tube annulus from Row 49 to the flow block and each tube row from the end of the T-slot to Row 49. Therefore, tubes in the area adjacent to the flow block where foreign objects could collect are inspected from three directions ; from the tube row below the tube, the tube row above the tube and from the tube annulus. This provides a comprehensive inspection of the tubes near the flow block and obviates the need for eddy current inspection for foreign objects as allowed by the EPRI Steam Generator Integrity Assessment Guidelines Section 10.5. This visual inspection was performed on all four SGs during B2R11 and one during each subsequent inspection on a rotating SG basis.
For SGs not visually inspected at the 2nd baffle plate, an eddy current +PointTM probe inspection of the tubes that are hydraulically expanded from the flow block to row 49, is performed (in addition to the 100% bobbin coil inspection) to identify if foreign objects or tube damage is present. Therefore, in any given inspection, a visual inspection of the 2nd baffle plate is performed, along with a +PointTm probe inspection of the expanded 2nd baffle plates near the flow block, as well as, a full length bobbin coil inspection of 100%
of the tubes, assuring a complete inspection of the area that can be susceptible to collecting foreign objects.
Apart from the inspections for detection of foreign objects and foreign object damage and consistent with NRC Generic Letter (GL) 95-03, "Circumferential Cracking of Steam Generator Tubes" recommendations, rotating probe inspections of the 2nd and 3rd baffle plate expansion transitions are performed on at least 20% of the expanded 2nd and 3rd pre-heater baffle plates in one SG, each inspection opportunity.
During the Spring 2007 (1321313) inspection, eddy current and visual inspections were performed to meet the pre-heater baffle plate foreign object and NRC GL 95-03 inspections programs described above. A 25% +PointTM sample of the 2nd and 3rd pre-heater baffle plate expansions were performed in the 213 and 2C SGs in order to meet the NRC GL 95-03 inspection reccomendations. A sample of the 2"d pre-heater baffle plate expansions near the flow block were performed in the 2A, 213 and 2C SGs to detect foreign objects and foreign object damage. No degradation or foreign objects were detected in these inspections. The tubesheet map for the 2C SG inspection scope was intended to be included in the final summary report (Referenced submittal), but it was inadvertently omitted from the version submitted to the NRC. Attachment 2 provides the tubesheet map showing the inspection scope for the 2C pre-heater baffle plate expansions.
The visual inspection of the 2D SG did not reveal any foreign objects or tube damage in the 2nd pre-heater baffle plate expansion transitions.
NRC Question 7:
EGC Response:
NRC Question 8_:
EGC Response :
NRC Question 9:
EGC Response :
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection Please clarify the number of tubes that have expansion transition and bulges that are significantly outside the tubesheet.
There were 23 indications of expansion transition and bulges that were significantly outside the hot leg and cold leg tubesheet. All indications were inspected with the
+PointTM probe and no degradation was found in any of the indications.
In Section 5.1.2, [of the Referenced submittal] it is stated that, "... two adjacent tubes that contained possible loose part (PLP) signals with no detectable degradation (R33-54 and R34-C64) located at the 8"' TSP' and in Section 5.2.4 it states, 'Tubes R33-C64 and R34-C65 in SG 2C were preventively plugged and stabilized because they contained a possible loose part signal....
Please clarify which tubes contained a possible loose part signal and which were plugged.
The tubes that contained a possible loose part signal were tubes R33-C64 and R34-C65 in SG 2C and these two tubes were plugged. There was no indication of possible loose parts in tube R33-C54 in SG 2C.
In Section 5.1.2 [of the Referenced submittal], it is stated, 'Additionally, the foreign object is adjacent to two tubes that were plugged during Refueling Outages 2 and 7 that were not stabilized due to what was believed at the time to be pitting degradation at TSP 08H. " Is it now believed that the degradation is now due to foreign object wear instead of pitting? If so, please discuss whether the eddy current data of these previously plugged tubes is consistent with eddy current data from wear indications attributed to loose parts.
The two tubes previously plugged (R33-C66 and R34-C66) in refueling outages 2 and 7 were plugged due to single volumetric indications as determined by rotating probe technology. The eddy current inspections at that time did not indicate the presence of a foreign object. In retrospect, after years of experience with foreign object wear since these tubes were plugged, the indications could be characterized as volumetric indications due to foreign object wear. Since a foreign object signal, adjacent to these tubes, was found during refueling outage 13, it was concluded that the prior indications in the previously plugged tubes were associated with the foreign object.
NRC Question 10 :
EGC Response :
NRC Question 11 :
EGC Response :
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection In Section 5.2.4 [of the Referenced submittal], it is stated, "... a large 139.4 volt bulge located at
.... " Please discuss whether this bulge has been present since the steam generators were installed or whether it has changed with time. If it has not been present since manufacture or has changed with time, please discuss the nature of this bulge and/or the reason for any change with time.
This bulge indication was present during the pre-service and subsequent inservice inspections. The indication had not changed over time. The tube that contained the bulge was preventatively plugged due to increased sensitivity to stress corrosion cracking in bulges.
Please clarify the following statement in Section 6.0 [of the Referenced submittal].
.Satisfying the structural limit ensures that the SG tube integrity performance criteria for structural integrity, accident induced leakage and operational leakage will be maintained." Is this statement implying that a tube that has structural integrity would not leak at a rate that is in excess of the accident induced or normal operational leakage limit? If so, please provide the technical basis.
All tube flaws found during the inspection were associated with wear/fretting damage mechanisms. The structural limit for these damage mechanisms was derived using the uniform wall thinning method consistent with the guidance and margins of safety described in Regulatory Guide 1.121, "Bases for Plugging Degraded PWR Steam Generator Tubes" using American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code minimum material properties. The margins of safety used were the most limiting value of 1.4 times accident differential pressure or 3 times normal operating differential pressure. For Byron Station Unit 2, the limiting case is 3 times normal operating differential pressure, which is significantly higher than the most limiting accident condition (i.e., steam line break). The ASME Section III, "Rules for Construction of Nuclear Power Plant Components," minimum wall equation was also used as the basis for the structural limits. In the case of uniform wall thinning, the remaining tube wall can still meet the applicable stress limits during normal and accident loading conditions. Therefore, with only wear/fretting damage mechanisms and application of the uniform wall thinning structural limit that meets ASME Code minimum tube wall requirements and Regulatory Guide 1.121 margins of safety, a tube will not leak at normal operating or accident conditions.
NRC Question 12 :
EGC Response.
Additional Information Regarding the Byron Station Unit 2 Spring 2007 Steam Generator Inspection Please discuss the scope and results of any foreign object search and retrieval. If any loose parts/foreign objects were left in the steam generators (other than those discussed in your July 31, 2007, letter [Referenced submittal]), please discuss the basis for leaving these parts in service (e.g., engineering analysis supports leaving part in service from a tube integrity perspective).
A foreign object search and retrieval (FOSAR) was performed in each SG following the completion of sludge lancing. The top of the secondary tubesheet was visually inspected in the following areas: tubesheet annulus, peripheral tubes (3-5 tubes deep),
tube lane, and T-slots. Additionally, the tube lane and tube lane peripheral tubes were inspected at the first baffle support plate in each SG. A total of four foreign objects were identified at the tubesheet location. The objects were characterized as two pieces of weld slag, a wire brush bristle and a small metallic object. A piece of weld slag and the metallic object were successfully removed. The other piece of weld slag was a historical object that was firmly wedged between two tubes remained in the SG and its condition was unchanged from previous outages. The wire brush bristle could not be retrieved because it was firmly contained within a hard scale pile adhered to the tubesheet. None of the foreign objects resulted in tube damage as determined by eddy current examination and visual inspection. No foreign objects were found on the first baffle support plate in any SG.
A FOSAR was also performed in the 2D SG in the pre-heater region at baffle plate 02C, which is the baffle plate at the feedwater entrance. Each tube row was inspected from Row 21 through Row 49 (last row closest to the feedwater inlet). Tube columns 52-63 were inspected from the end of the T-slot to the divider plate. Additionally, the tube-wrapper annulus was inspected from Row 49 to the Flow Block. A total of eight foreign objects were identified. These objects were characterized as small bristle brush wires (5), a small spring (0.102" x 0.09" diameter), weld slag and a small machine turning.
Five (5) of the objects were successfully removed. Three (3) of the small wires could not be retrieved because they were firmly wedged between the baffle plate crevice and the tube. One of the stuck wires was a historical object and had not changed since the previous inspection. None of the objects caused any tube damage as determined by eddy current and visual inspections.
An engineering evaluation was performed for all foreign objects that remain in the SGs.
The evaluation considered the object characteristics, flow conditions, tube vibration amplitudes and the assumption of any pre-existing tube flaws. The evaluation concluded that the objects remaining in the SGs would not cause significant tube wear over the next operating cycle. All structural and leakage performance criteria are expected to be satisfied over the next operating cycle when the next scheduled SG inspection is planned during refuel outage 14 in Fall 2008.
Reference:
Letter from D. M. Hoots (Exelon Generation Company, LLC) to U. S.
Nuclear Regulatory Commission, "Byron Station Unit 2 Steam Generator Inservice Inspection Summary Report for Refueling Outage 13," dated July 31, 2007 8
Byron Station Steam Generator 2C Pre-Heater Baffle Plate Inspection Tubesheet Map
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