View source for NOC-AE-02001355, Response to Request for Additional Information Re License Amendment Request - Revised Proposed Amendment to Technical Specification 4.4.5.3a, Dated 06/20/2002

{{Adams
| number = ML021910231
| issue date = 07/03/2002
| title = Response to Request for Additional Information Re License Amendment Request - Revised Proposed Amendment to Technical Specification 4.4.5.3a, Dated 06/20/2002
| author name = Jordan T
| author affiliation = South Texas Project Nuclear Operating Co
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000498
| license number = NPF-076
| contact person = 
| case reference number = NOC-AE-02001355
| document type = Letter type:NOC
| page count = 10
| project = 
| stage = Response to RAI
}}

=Text=
{{#Wiki_filter:Nuclear Operating Company South Texas Prqed ElectricGeneratingStation P.. Box 289 Wadsworth Texas 77483                                 ,
July 3, 2002 NOC-AE-02001355 10CFR50.90 U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852 South Texas Project Unit 1 Docket No. STN 50-498 Response to Request for Additional Information

==Reference:==
Letter, T. J. Jordan to NRC Document Control Desk, "License Amendment Request - Revised Proposed Amendment to Technical Specification 4.4.5.3a,"
dated June 20, 2002 (NOC-AE-02001351)
The referenced letter submitted a license amendment request for a change in the steam generator inservice inspection frequency requirements in Technical Specification (TS) 4.4.5.3a for South Texas Project Unit 1. The change would allow a one-time inspection interval of once per 40 months for the steam generator tube inspection performed immediately following IRE10.
The NRC staff has informally requested additional information regarding the license amendment request. The attachment to this letter provides our response. If there are any questions regarding this response, please contact Mr. Mark Kanavos, Manager, Modifications and Design Basis Engineering at (361) 972-7181 or me at (361) 972-7902.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on:                  July 3, 2002 AT .kJor-dan Vice President, Engineering & Technical Services jtc

==Attachment:==
Response to Request for Additional Information STI: 31463776

NOC-AE-02001355 Page 2 of 2 cc:
(paper copy)                        (electronic copy)
Ellis W. Merschoff                  A. H. Gutterman, Esquire Regional Administrator, Region IV   Morgan, Lewis & Bockius LLP U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400     M. T. Hardt/W. C. Gunst Arlington, Texas 76011-8064         City Public Service U. S. Nuclear Regulatory Commission Mohan C. Thadani Attention: Document Control Desk    U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike                R. L. Balcom Rockville, MD 20852                 Reliant Energy, Inc.
Richard A. Ratliff                  A. Ramirez Bureau of Radiation Control         City of Austin Texas Department of Health 1100 West 49th Street               C. A. Johnson Austin, TX 78756-3189               AEP - Central Power and Light Company Cornelius F. O'Keefe                Jon C. Wood U. S. Nuclear Regulatory Commission Matthews & Branscomb P. 0. Box 289, Mail Code: MN1 16 Wadsworth, TX 77483 C. M. Canady City of Austin Electric Utility Department 721 Barton Springs Road Austin, TX 78704

NOC-AE-02001355 Attachment Page 1 of 8 ATTACHMENT Response to Request for Additional Information
: 1.      During a conference call with the licensee on June 17, 2002, the staff expressed a concern with reviewing the amendmentfor STP Unit 2. The staff recognizes the STP Unit 2 steam generatorswill be replaced with the same model as the Unit 1 steam generators;however, the staff explained to the licensee that the preserviceandfirst inservice inspection results are criticalinformation requiredfor our evaluation of this type of technical specificationchange request. The licensee has not, yet, performed the first inservice inspection. To facilitate the staffs review of the Unit I request, the licensee indicatedthey would withdraw the amendment requestfor Unit 2. If the licensee were to revise this decision, additionalstaff review and questions would be necessary.

===Response===
STP Nuclear Operating Company submitted a revised license amendment request (Reference 1) to apply to Unit 1 only.
: 2.       In Attachment 1 of the submittal,the licensee briefly describes the steam generator (SG) inspection scope for STP Unit 1 duringthe 1REJO outage as a full-length inspection of 100% of the steam generatortubes. The staff assumes this inspection scope refers to a bobbin coil probe inspection. The staff requests the licensee to provide a more detaileddiscussion of the inspection scope, including thefollowing information:
: a.      Describe the scope of any rotatingpancake coil (RPC)probe inspections including RPC of the hot leg top-of-tubesheet region, the low-row U-bend tubes, dings and dents. If any of these regions were not inspected,please provide the technicaljustificationfor excluding these areasfrom the inspection scope duringthe 1REIO outage.

===Response===
Rotating pancake coil (+Point) testing of all bobbin possible indications (I-codes) was performed in all four steam generators (SGs) during 1RE10. Manufacturing buff marks (MBMs) and dents/dings (> 0.75 volt) were compared to the baseline signals, and if any changes were detected, they were assigned I-codes for further +Point examination.

NOC-AE-02001355 Attachment Page 2 of 8 Neither full nor sample +Point inspections were performed at the hot leg top-of-tubesheet (TTS) expansion area, at low-row U-bends, or at dings and dents, unless I-codes were located at these areas. The technical bases for not including these areas are described in the South Texas IRE10 Degradation Assessment, Appendix F (Reference 2), which was faxed to the NRC on June 17, 2002. To summarize Appendix F, stress corrosion cracking is not regarded as a potential damage mechanism at the TIS transition, low-row U-bends, or in dents and dings in the Delta 94 SGs. The bobbin probe inspection is regarded as qualified for detection of the volumetric indications. To date there has been no confirmed identification of stress corrosion cracking in the Delta Series, Model F, or F-Type replacement SGs currently in service.
: b.      Please include a discussion of the 75 +Pointcoil examinations that were mentioned in the submittal

===Response===
Included in the IRE10 +Point examination were five I-codes at dents, nine at dings, and 32 at MBMs. Twenty-eight non-quantifiable possible indications (NQIs) were found at locations other than at dents, dings, and MBMs. One possible loose part (PLP) was examined by +Point in SG "D" at support plate 6 and the six surrounding tubes at support plate 6 were examined by +Point to confirm no additional loose part signals. These I-codes were inspected by +Point at the following tube locations:
    "* Hot leg (HL) free span                 45 inspections
    "* Cold leg (CL) free span                23 inspections
    "* HL support plate                        8 inspections
    "* CL support plate                        4 inspections
    "* Row 2 U-bend                             1 inspection
    "* CL TTS                                  2 inspections No defects or degradation were confirmed by any of these +Point inspections. The details of the inspection results were provided to the NRC in Reference 3.
: 3.      In the submittal,the licensee states that "[n]o defective or degradedtubes were indicated"during the 1REJO outage of STP Unit 1. Utilizing the Technical Specification definition of degradedand defective would imply that no tubes contained defects greaterthan 20% throughwall.
: a.      Did the inspection results revealdefects (i.e., service-induceddegradation)less than 20% throughwall? If so, please list all indicationsthat were identified and sizing estimates, if appropriate.

NOC-AE-02001355 Attachment Page 3 of 8

===Response===
No wear or service-induced wall reduction was detected in any of the four SGs during IRE10.
: b.      Describe inspection results identified that were not attributedto service-induced degradationand were left in service (i.e., dents, manufacturingburnish marks, etc.). Briefly describe the actions taken that led to the decision to leave them in service (e.g., history review, supplemental eddy currentinspection, etc.).

===Response===
Manufacturing buff marks greater than or equal to one volt on the 150 kHz absolute that were found to be in the baseline bobbin data results and had not changed were re-identified as MBMs and left in service. If the signal was new or a change had occurred, the signal was called a manufacturing buff mark possible indication (MBI) and subjected to +Point examination.
MBMs less than one volt were also compared to the preservice inspection (PSI) database for change and were called MBIs if change had occurred. These were further examined by +Point.
No cracks or degradation were detected in any MBM and all MBMs were left in service.
Dings and dents greater than 0.75 volts on the 630/150 kHz mix were monitored for distortion or change from the baseline. Those that exhibited change were reported as dent/ding possible indications (DNIs) and subjected to +Point testing. All NQI signals were also compared to the baseline data. Those that either changed or did not exist in the baseline data were subjected to
+Point examination. There were no crack-like indications detected by +Point examination in any of the four SGs.
: 4.      In the submittal,the operatingconditions of V. C. Summer recirculatingsteam generators(RSGs) and Westinghouse Delta model RSGs are compared to the current STP Unit 2 model "E"steam generators. The staff assumes the licensee believes the operatingconditions are also similarto STP Unit 1. Pleaseprovide information that shows that the operatingconditions of STP Unit 1 are similarto those of V. C. Summer and other Westinghouse Delta model RSGs.

===Response===
The operating conditions that most affect stress corrosion cracking are temperature, primary and secondary chemistry, and to a much lesser degree, tube differential pressure. The average hot leg temperatures do not vary more than twelve degrees among these plants:
South Texas             620OF Shearon Harris          620&deg;F V. C. Summer            619&deg;F Arkansas - 2            608&deg;F

NOC-AE-02001355 Attachment Page 4 of 8 Although each plant has its own method of chemistry control, each operates within the strict bounds of the EPRI Primary and Secondary Chemistry Guidelines. If SG tube degradation or cracking were identified in one of these plants, a detailed comparison between the subject plant and STP would be performed in accordance with the requirement of the EPRI Guidelines to determine susceptibility for similar degradation. If extended operation based upon this evaluation could not be justified, then a SG inspection would be performed at the next scheduled refueling outage.
: 5.      In the submittal, the licensee states that Westinghouse Delta model RSGs have been stress corrosionfree after six calendaryears of operation.
: a.      The staff requeststhe licensee to list the other Delta models RSGs, other than STP Unit 1 and V. C. Summer, to which the submittalreferredand to discuss their operatingexperience.

===Response===
The six years of operation referred to V. C. Summer. However, subsequent to the initial STP amendment request, inspection after the first operating cycle at Arkansas-2 was completed in April 2002. The only reported tube degradation was wear on two tubes (4% and 18%) from a small loose part that was removed. Arkansas-2 does not have the same type of feedwater spray nozzles as described in the response to Question 7. Thus, the STP feedwater spray nozzle would have captured a loose part similar to the one removed at Arkansas-2.
: b.      What process is in place to gain relevant industry operatingexperience that may effect the operationalassessment of STP Unit 1 duringan extended inspection interval?

===Response===
The STP SG Engineering organization maintains close communications with other utility representatives through direct participation on EPRI SGMP member committees. If degradation is discovered at another station with thermally treated Alloy 690 SG tubing, it would be immediately communicated to our Engineers, and an Operational Assessment would be performed to determine susceptibility at STP and whether an inspection would be required.
: 6.      In the submittal,the licensee highlightsthe results of the October 2000 V. C. Summer inspection results. The V. C. Summer replacement steam generatorshave been in service since 1994. What are the resultsfrom 1994 through 2000 with respect to service-induceddegradation? Provide a list including outage identified,flaw type, location and sizing estimates.

NOC-AE-02001355 Attachment Page 5 of 8

===Response===
Refer to Table 1 at the end of this Attachment.
: 7.      In the submittal, the licensee states that the Delta 94 steam generatordesign incorporatesfeatures to minimize the development of loose parts duringoperation and maintenance. Briefly respond to the following related questions.
: a.       How do these designfeatures minimize the development of loose parts?

===Response===
Feedwater enters the Delta 94 SG through 34 spray nozzles on a ring header. The spray nozzles are vertical cylinders on the top of the feedring, each with an outside diameter of 2.875 inches and height of approximately 6 inches. There are 130 holes with a diameter of 0.29 inch in the outer surface of each cylindrical nozzle. The nozzles will trap loose parts that might be introduced into the SG from the feedwater system. As described in the submittal, small objects that would pass through the 0.29-inch holes would flow through the tube bundle (gap of 0.293 inch between tubes) and would be unlikely to produce tube wear.
Likewise, auxiliary feedwater is introduced into the SG through a single cylindrical nozzle with a diameter of 6.625 inches and height of approximately 13.5 inches. There are 560 holes with a diameter of 0.29 inch in the outer surface of the cylindrical nozzle. Like the feedwater spray nozzles, the auxiliary feedwater spray nozzle will trap foreign objects that are large enough to produce tube wear.
The use of threaded members inside the SG has been minimized. In all cases threaded members are secured by welding or mechanical means to minimize the potential for loose parts in service.
Threaded members used on STP have been used on many Westinghouse steam generators with no history of degradation in service.
: b.       From what materialsare these features constructed?

===Response===
Both the main feedwater and the auxiliary feedwater spray nozzles are fabricated from thermally treated Alloy 690 material. The tube support plates and baffle plates are manufactured from 405 stainless steel to minimize corrosion potential.
: c.       What inspectionplans, if any, are in place to verify the structuralintegrity of these new features duringthe extended SG ISI interval? If there are no plans to inspect these features,please discuss the technicalbasisfor this position.

NOC-AE-02001355 Attachment Page 6 of 8

===Response===
A secondary-side foreign object search and retrieval operation was performed in all four SGs after RSG installation during 1RE09. Several loose parts that were left during the fabrication of the SGs were found and removed. No signs of damage during shipment were seen.
An extensive internal visual inspection was performed during 1RE10 in one SG. The objectives were to verify that the upper steam generator internal welds and parts were not cracked or eroded during the first cycle of operation and to obtain data on deposits. No problems were identified during this inspection. In addition, inspections were performed at the TTS prior to sludge lancing in all four SGs as described in the submittal.
V. C. Summer Delta 75 SGs have not experienced internal structural degradation nor have other Westinghouse replacement SGs.
A loose part was detected and removed in the April 2002 Arkansas-2 inspection. The piece was identified as a curled machining chip believed to have been introduced into the SG from the feedwater system.
Based upon this good industry experience with replacement SGs, there are no STP plans to perform secondary internal structural integrity inspections during the interval between tube inservice inspections.
: 8.       In the submittal, the licensee describes a loose part indication below the sixth hot leg supportplate that could not be visually investigated. To justify leaving this loose part in the SG, the licensee performeda bounding analysis to provide assurancethat the loose part would not cause significant wear over the proposed operatingperiod. In the analysis, the licensee assumes that the loose partis a metal gasket bandingpiece located at the "worst SG tube location." The staff requests the licensee to discuss where the "worst SG tube location" is and the basisfor assumingthat the loose part is a metal gasket bandingpiece.

===Response===
The worst assumed location was at a tube that exhibits the limiting amplitudes of vibration and cross flow velocity. It was also assumed that the tube had an existing 20% throughwall degradation, which is a conservative limit of wear detection with bobbin exam. Additional conservative assumptions included that the object would remain in the same location (once tube wear begins) and that only the tube would experience wear.
The loose part was assumed to be a gasket banding piece because similar banding pieces were found on the TTS in SG "A" and it would be small enough to reach this location. The gap between the tubes is only 0.293 inch and a larger object could not have reached this area deep in

NOC-AE-02001355 Attachment Page 7 of 8 the tube bundle. The possible loose part signal was not detected on the six adjacent tubes that were examined, which provided further confirmation that the piece was very small.
References
: 1. Letter, T. J. Jordan to NRC Document Control Desk, "License Amendment Request Revised Proposed Amendment to Technical Specification 4.4.5.3a," dated June 20, 2002 (NOC-AE-02001351)
: 2. "South Texas 1RE10 Degradation Assessment," dated September 20, 2001
: 3. Letter, T. J. Jordan to NRC Document Control Desk, "Special Report - 1RE10 Refueling Outage Inservice Inspection Results for Steam Generator Tubing," dated January 22, 2002 (NOC-AE-02001254) (Accession Number ML020390361)
: 4. Letter, G. J. Taylor to NRC Document Control Desk, "V. C. Summer Special Report (SPR 960004)," dated May 13, 1996 (PDR 9605170213 960513)
: 5. Letter, G. J. Taylor to NRC Document Control Desk, "V. C. Summer Special Report (SPR 970001)," dated November 3, 1997 (PDR 9711070068 971103)
: 6. Letter, G. J. Taylor to NRC Document Control Desk, "V. C. Summer Special Report (SPR 1999-003)," dated April 29, 1999 (PDR 9905050083 990429)
: 7. Letter, S. A. Byrne to NRC Document Control Desk, "V. C. Summer Special Report (SPR 2000-005)," dated November 8, 2000 (Accession Number ML003769321)

NOC-AE-02001355 Attachment Page 8 of 8 Table 1 - Results of V. C. Summer Tube Inspections Since 1994 Steam Generator Replacement Outage                            Flaw Type                     Location                    Sizing                 Plugged April 1996 (Reference 4)
   - 22% of SG "A"                Imperfection indication
* A-R1 13C72 @ TSP6+10.09     Not quantifiable           0
   - 16% of SG "B"                Imperfection indication
* B-R52C11 @ TSP9+1.09        < 20% of NTW               0
* Present in baseline October 1997 (Reference 5)
   - 30% of SG "C"                None                                                                                 0 April 1999 (Reference 6)
   - 40% of SG "A"                None                                                                                 0
   - 40% of SG "B"                None                                                                                 0 October 2000 (Reference 7) 100% of SG "A"                 Small piece of wire removed   A-R89C62/R88C63 @ TTS 100% of SG "B"                 Wear-like indication          A-R19C140 @ AV7
* est. 9% of NTW 322 tubes TTS                Wear-like indication          A-R26C139 @ AV2
* est. 5% of NTW S5% HL                       Wear-like indication          A-R26C139 @ AV7
* est. 9% of NTW 100% of SG "C"                 No tube expansion (NTE)       A-R25C26                                               1 14 tubes Row 1 +P U-bend     NTE                           A-R25C31                                               1
     +P w/ HFC and MRC            NTE                           A-R94C51                                               1
     - 20% Row 1                  NTE                           C-R99C100                                              1 NTE                           C-R57C96                                               1
* Found to be apparent in reviewing 1994 PSI}}