L-15-053, Response to Request for Additional Information Regarding 2014 Steam Generator Inspection Reports
| ML15047A015 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 02/16/2015 |
| From: | Emily Larson FirstEnergy Nuclear Operating Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| L-15-053, TAC MF4620 | |
| Download: ML15047A015 (7) | |
Text
FENOC' FirstEnergy Nuclear Operating Company Eric A. Larson Site Vice President February 16, 2015 L-15-053 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001
SUBJECT:
Beaver Valley Power Station, Unit No. 2 Docket No. 50-412, License No. NPF-73 Beaver Valley Power Station P.O. Box4 Shippingport, PA 15077 724-682-5234 Fax: 724-643-8069 Response to Request for Additional Information Regarding 2014 Steam Generator Inspection Reports (TAC No. MF4620)
By letters dated August 11, 2014 (Agencywide Documents Access and Management System [ADAMS] Accession No. ML14224A573) and November 5, 2014 (ADAMS Accession No. ML14309A245), FirstEnergy Nuclear Operating Company (FENOC) submitted reports summarizing the results of the 2014 steam generator tube inspections for Beaver Valley Power Station, Unit No. 2. By letter received January 22, 2015, the Nuclear Regulatory Commission (NRC) requested additional information to complete its review of the reports (ADAMS Accession No. ML15007A558). The FENOC response to the NRC request is attached.
There are no regulatory commitments included in this submittal. If there are any questions or if additional information is required, please contact Mr. Thomas A. Lentz, Manager-Fleet Licensing, at (330) 315-6810.
Sincerely, c:-
~
- ~
z -- &r I e---
Eric A. Larson
Attachment:
Response to Request for Additional Information cc:
NRC Region I Administrator NRC Resident Inspector NRC Project Manager Director BRP/DEP Site BRP/DEP Representative
Attachment L-15-053 Response to Request for Additional Information Page 1 of 6 The Nuclear Regulatory Commission (NRC) staff has requested additional information (Agencywide Documents Access and Management System [ADAMS] Accession No. ML15007A558) to complete its review of the FirstEnergy Nuclear Operating Company (FENOC) Beaver Valley Power Station, Unit No. 2 (BVPS-2) 2014 steam generator (SG) tube inspection reports. The NRC staffs request for additional information (RAI) is provided below in bold text followed by the FENOC response.
Letter dated August 11,2014 RAI1:
It was indicated that the combined accident induced leakage from all sources remains well below the 2.2 gallons per minute per the steam generator limit.
Please provide the projected end-of-cycle accident induced leakage from the tubesheet indications.
Response
All indications reported within the 3.0 inch (5.0 inch for particular tube locations) inspection distance below the top-of-tubesheet are removed from service using the plug on detection philosophy. Thus, the projected end-of-cycle accident-induced leakage from the tubesheet indications is considered zero. This information is provided in the right column (entitled Projected Leakage) of the tables shown on pages 3 and 4 of Enclosure B to the August 11, 2014 letter for each tubesheet indication observed during the spring 2014 refueling outage.
In a follow-up phone call, the NRC verbally requested the maximum accident induced leakage. SG C is the limiting SG for maximum projected end-of-cycle leakage. For a main steam line break (MSLB), the combined leakage from all SG C sources is projected to be 0.373 gallons per minute (at room temperature). This information was provided on page 1-1 of Enclosure A to the August 11, 2014 letter.
Letter dated August 11, 2014 RAI2:
The report that summarizes the results of your tube pulls indicates it is an "interim report." Is there any additional information that will be provided to the NRC? If so, what information is still expected and when will it be provided?
Response
Paragraph 6.b.(a) of Generic Letter 95-05, "Voltage Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking," states, in part, if it is not practical to provide all the [metallurgical examination] results within 90 days, as a minimum, the burst test, leakage test and morphology conclusions should be provided within 90 days. The burst test, leakage test, and morphology conclusions were submitted in the interim report (Enclosure C to
Attachment L-15-053 Page 2 of6 the August 11, 2014 letter). The final report will include additional metallurgical results, and is currently scheduled to be submitted to the NRC by the middle of March 2015.
Letter dated August 11, 2014 RAI3:
A "leak screen" (rather than a leak test) was performed on the pulled tube test specimens. These specimens were held at a test pressure for 5 minutes. Given the low leak rate (if any) that would be expected from such low voltage indications, was the duration of the test sufficient to detect the onset of leakage?
Response
As stated in section 3.3 of Enclosure C to the August 11, 2014 letter, the work instructions are in compliance with the industry standard Electric Power Research Institute (EPRI) document "Steam Generator Tubing Burst Testing and Leak Rate Testing Guidelines," Revision 0 and therefore sufficient to detect the onset of leakage.
No leakage was observed throughout a 15 minute test comprised of 5 minute steps at test pressures of 1700 pounds per square inch gauge (psig), 2250 psig, and 2875 psig.
If leakage would have been reported, leak rate measurements would have been conducted. In addition, the bobbin and Plus Point signal voltages for these indications suggested shallow depths. The maximum depth of penetration from destructive examination was < 50 percent through-wall for both indications, thus the decision to perform a leak screen as opposed to a leak test was considered valid.
Letter dated August 11, 2014 RAI 4:
Please discuss whether the results of your burst and leakage test are consistent with the pulled tube database. Please discuss your plans (or the industry's plans) for updating the pulled tube database with the information you obtained from your pulled tubes.
Response
A direct comparison of the burst and leakage test results to the existing EPRI database has not been performed. However, based on the low voltage of the indications, it is not anticipated that the spring 2014 outage data (for example metallurgical results) would have any significant impact to the database. The measured burst pressures of the distorted signal with possible indication (OS I) are slightly larger than the calculated burst pressures when actual tube material properties are included in the calculated burst pressure.
Since BVPS-2 is the only plant that still utilizes the 7/8 inch diameter tubing data contained within the EPRI database, there is no industry benefit and updating the database is an unnecessary burden. FENOC does not intend to update the database.
Attachment L-15-053 Page 3 of6 Letter dated November 5, 2014 RA11:
It was highlighted that a 0.630-inch diameter bobbin probe was used in sleeved tubes in rows 3 and 4. For the other tubes with sleeves, were 0. 720-inch bobbin probes used to inspect the tube support plate elevations in those tubes? For all sleeved tubes, were the probe sizes that were used capable of detecting flaws of any type that may have been present in the tube and the sleeve at the time of the inspection?
Response
The only sleeves installed at BVPS-2 are located at the hot leg top-of-tubesheet. A 0.720 inch diameter bobbin probe cannot pass through a tube where a hot leg tubesheet sleeve is located; however, a 0.630 inch diameter bobbin probe can. The 0.630 inch bobbin probe was site qualified for use and capable of detecting flaws of any type that may have been present in the tube at the time of the inspection in accordance with Appendix H and I of the EPRI SG Examination Guidelines.
For tubes with hot leg tubesheet sleeves in row 5 and higher, all cold leg and hot leg tube support plate elevations were examined with a 0.720 inch diameter bobbin probe that entered the tube from the cold leg side. In SG A, 23 tubes in row 5 required entry of the 0.720 inch diameter probe to be from both the hot and cold legs due to the inability of the 0.720 inch diameter probe to traverse the U-bend region of these tubes.
No hot leg tubesheet sleeves are located in these 23 tubes.
For tubes with hot leg tubesheet sleeves in row 4 and lower (zero tubes in SG A, two tubes in SG B (row 3 column 48; row 4 column 66) and one tube in SG C (row 4 column 31)), all hot leg tube support plate elevations were examined with a 0.630 inch diameter wide groove bobbin probe due to the inability of a 0.720 inch diameter bobbin probe to traverse the U-bend region of the lower row tubes. The cold leg tube support plate elevations of tubes with hot leg tubesheet sleeves were examined with a 0.720 inch diameter bobbin probe. If an indication was reported at a support plate elevation examined with a 0.630 inch diameter wide groove probe, the tube was removed from service (SG B, row 3 column 48).
For hot leg tubesheet sleeves, the sleeves were examined with a 0.610 inch diameter Plus Point probe. This probe was site qualified for use and capable of detecting flaws of any type that may have been present in the sleeve at the time of the inspection in accordance with Appendix H and I of the EPRI SG Examination Guidelines. This qualification does not apply to a sleeve area behind the nickel band of the lower hard roll.
Letter dated November 5, 2014 RAI 2:
For your primary and secondary side inspections (inspections of plugs including plug-in-plug tack welds, channel head, and steam drum inspections), it was
Attachment L-15-053 Page 4 of 6 indicated that they were determined to be acceptable. Please discuss whether any degradation was observed as a result of those inspections. Similarly, for the ultrasonic thickness measurement of the feedwater header, please discuss whether the results suggest degradation was occurring at these locations. If degradation was observed, please discuss any corrective actions taken.
Response
Visual inspection of tube plugs and plug-in-plug (PIP) tack welds:
No degradation was observed in any of the tube plugs. All tube plugs were accounted for and all were verified to be in their proper location. No sign of cracking was reported in any of the eighteen PIP tack welds.
Visual inspection of channel head welds:
A remote visual inspection of the area around the drain line was performed in each hot and cold leg channel head to meet the requirements of Westinghouse Nuclear Safety Advisory Letter 12-1, "Steam Generator Channel Head Degradation."
Included in this examination was (a) the divider plate to stub runner weld, (b) the tubesheet to stub runner weld, and (c) the divider plate to channel head weld. This inspection looked for evidence of gross defects such as indications in welds, missing weld filler material, a breach in the weld metal, and unusual discoloration of the weld metal and cladding imperfections. No signs of degradation related to cladding breach, cracking, missing filler metal or discoloration were observed.
Visual inspection of steam drum:
SG 8: A general area inspection was performed of the feed ring area including the primary separator riser barrel outside diameter (OD) at the J-nozzle discharge. No anomalies or degradation were noted. No bare metal, which could indicate the potential for erosion/corrosion, was observed.
A visual inspection of the inside diameter (I D) of the feed ring at selected J-nozzles was performed. This inspection showed that there was little change in the visual condition of the feed ring at the J-nozzle entrance from the last inspection performed during refueling outage 12. J-nozzle 11 was found to have experienced additional erosion of the feed ring at the nozzle entrance. The affected area of the feed ring did not encompass the entire circumference. The erosion observed is considered normal for this vintage of SG's, and no corrective actions were taken. Visual comparison of the nozzle-to-feed ring weld shows that the size of the weld extends well beyond the area of the feedring ID erosion.
SG C: A general area inspection was performed of the feed ring area including the primary separator riser barrel OD at the J-nozzle discharge. No anomalies or degradation were noted. No bare metal, which could indicate the potential for erosion/corrosion, was observed.
Attachment L-15-053 Page 5 of 6 A visual inspection of the ID of the feed ring at selected J-nozzles was performed. This inspection showed that there was little change in the visual condition of the feed ring at the J-nozzle entrance from the last inspection during refueling outage 12. J-nozzle 13 was found to have experienced additional erosion of the feed ring at the nozzle entrance. The extent of the erosion is localized. Patterns of erosion stripes were observed on this reducing union. This condition was evident on this reducer only.
These stripes appear to have a small amount of penetration into the reducer wall. The orange colored deposit that was observed is believed to be rust. Similar observations on the exterior of the feed ring were wiped away. No corrective actions were taken.
Ultrasonic thickness (UT) measurements of feedwater header:
UT thickness measurements were performed at various locations along the axis and around the circumference of the feedwater header in both B & C generators. The minimum reported thickness was 0.401 inch. Although there is no specified minimum permissible material thickness for the feed ring complex, FENOC engineering considers this value to be sufficient to preclude corrective action, and none was taken. Minimum thicknesses as small as 0.12 inch have been developed by Westinghouse for other plants that have experienced significant erosion of the feed ring. The feed ring erosion at BVPS-2 is considered minor compared to these other plants.
Future inspections of the steam drum regions and feedwater header will continue to coincide with the secondary manway gasket replacement schedule.
Letter dated November 5, 2014 RAI 3:
Two volumetric indications associated with sleeves were observed. Please discuss whether these indications were present in the inspections (if any) performed at the time of installation. If not, please discuss the cause of these indications. For example, is there any evidence that water is accumulating between the tube and the sleeve (either through the joint or through a through-wall flaw in the tube)? Please discuss the size/severity of these volumetric indications.
Response
In SG A, two tubes (row 15 column 85 and row 42 column 43) repaired in fall of 2012 with hot leg tubesheet sleeves were removed from service in spring of 2014 for having volumetric indications reported above the hot leg top-of-tubesheet.
Prior to installing the hot leg tubesheet sleeves in fall of 2012, the Plus Point coil was utilized to examine the hot leg top-of-tubesheet region from +6.0 inch above the hot leg tubesheet to -3.0 inch below the hot leg tubesheet. No additional indications were reported in this area in the fall of 2012 other than the single circumferential indication, which was why the hot leg tubesheet sleeve was installed.
Attachment L-15-053 Page 6 of 6 The apparent cause of the spring of 2014 indications is not known. Scrutiny of the indications could not definitively determine if the indications were located on the tube ID or sleeve OD; however, it was the best judgment of several resolution analysts that the indications were located on the tube ID surface. The parent tube between the sleeve joints where these indications were located is not considered part of the pressure boundary. Indications that are detected in the parent tube between the sleeve to tube joints do not impact the pressure boundary of the sleeve/tube assembly and do not impact the structural integrity of the sleeve.
No investigation into whether there was water accumulating between the tube and sleeve wall was performed. No deformation of the sleeves was reported. As a precautionary measure, these two locations were removed from service by plugging.
The spnng of 2014 reported severity of the indications 1s:
Row Column Indication Location Inch Volts* Degree Length Width Extent 15 85 Volumetric TSH
+1.72" 0.73 72° 0.32" 0.54" Volumetric TSH
+2.04" 0.40 84° 0.26" 0.37" 42 43 Volumetric TSH
+2.01" 1.30 83° 0.34" 0.58" Volumetric TSH
+2.06" 0.66 91° 0.29" 0.54"
- Plus Point probe, channel 3 (70 kHz)
Letter dated November 5, 2014 RAI4:
An indication in the U-bend was in-situ pressure tested and successfully passed the test. Please discuss the size of this indication. Please discuss the results of the previous inspection of this location. Please discuss whether any corrective action was taken in response to this indication.
Response
During the spring of 2014 refueling outage, a single axial indication within a ding was reported in SG B (row 25 column 45). The morphology of this indication was believed to be outside diameter stress corrosion cracking. This indication was located in the U-bend region approximately 3. 7 inches from anti-vibration bar number 1. The Plus Point peak-to-peak voltage, which included both the ding and flaw components, was 1.40 volts, which exceeded the EPRI in-situ pressure guideline voltage screening limit for leakage testing of 1.25 volts. The total flaw length was estimated to be 0.38 inch. The estimated maximum depth was 67 percent through-wall. In both of the two previous inspections, Plus Point data suggested precursor signals (that is ding voltage of approximately 6.0 volts). No additional indications were reported in the spring of 2014 that exceeded the EPRI in-situ guideline thresholds. The tube in row 25 column 45 was removed from service by plugging after the in-situ test was completed.