NOC-AE-12002828, Response to Request for Additional Information for Relief Request RR-ENG-3-06 for Leak Testing of Class 1 Pressure-Retaining Components
| ML12135A178 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 04/10/2012 |
| From: | Ruvalcaba M South Texas |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| NOC-AE-12002828, TAC ME7053, TAC ME7054 | |
| Download: ML12135A178 (10) | |
Text
Nuclear Operating Company South Texas Pro/ectElectric GeneratingStation PO Box 289 Wadsworth, Texas 77483 A April 10, 2012 NOC-AE-12002828 File No.: G25 10 CFR 50.55a U. S. Nuclear Regulatory Commission Attention: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2746 South Texas Project Units 1 and 2 Docket Nos. STN 50-498, 50-499 Response to Request for Additional Information for Relief Request RR-ENG-3-06 for Leak Testinq of Class 1 Pressure-Retaining Components(TAC Nos. ME7053, ME7054)
Reference:
Marco Ruvalcaba, STP Nuclear Operating Company, to NRC Document Control Desk, "Request for Relief from ASME Section Xl Table IWB-2500-1 for Leak Testing Boundaries of Class I Pressure-Retaining Components" (RR-ENG-3-06)," dated August 31, 2011 (NOC-AE-12002679) (ML11250A169)
In accordance with the provisions of 10 CFR 50.55a(a)(3)(i) and 10 CFR 50.55a(a)(3)(ii), STP Nuclear Operating Company (STPNOC) submitted the referenced request for relief from the requirements of ASME Section XI Table IWB-2500-1 for examination of Class 1 pressure-retaining components. Alternatives are proposed because either: (1) they provide an acceptable level of quality and safety, or (2) compliance with the requirements as specified would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety. Attached are responses to NRC requests for additional information provided February 23, 2012.
Approval of this relief request will exempt the specified components from being tested at full Reactor Coolant System pressure for the third 10-year inspection interval, effective until September 24, 2020 (Unit 1) and October 18, 2020 (Unit 2).
There are no commitments included with this request.
If there are any questions, please contact either Mr. P. L. Walker at (361) 972-8392 or me at (361) 972-7904.
Marco Ruv~al aba Manager, Testing and Programs Engineering PLW
Attachment:
Response to Request for Additional Information for Relief Request RR-ENG-3-06 STI: 33431213
NOC-AE-12002828 Page 2 of 2 cc:
(paper copy) (electronic copy)
Regional Administrator, Region IV John Ragan U. S. Nuclear Regulatory Commission Catherine Callaway 1600 East Lamar Blvd Jim von Suskil Arlington, Texas 76011-4511 NRG South Texas LP Balwant K. Singal A. H. Gutterman, Esquire Senior Project Manager Morgan, Lewis & Bockius LLP U.S. Nuclear Regulatory Commission One White Flint North (MS 8B1) 11555 Rockville Pike Balwant K. Singal Rockville, MD 20852 U. S. Nuclear Regulatory Commission Senior Resident Inspector Richard Pena U. S. Nuclear Regulatory Commission Ed Alarcon P. 0. Box 289, Mail Code: MNl 16 Kevin Polio Wadsworth, TX 77483 City Public Service C. M. Canady C. Mele City of Austin City of Austin Electric Utility Department 721 Barton Springs Road Peter Nemeth Austin, TX 78704 Crain Caton & James, P.C.
Richard A. Ratliff Texas Department of State Health Services Alice Rogers Texas Department of State Health Services
Attachment NOC-AE-1 2002828 Page 1 of 8 SOUTH TEXAS PROJECT UNITS I AND 2 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION FOR RELIEF REQUEST RR-ENG-3-06 By letter dated August 31, 2011 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML11250A169), STP Nuclear Operating Company (STPNOC, the licensee) requested relief from American Society of Mechanical Engineers Boiler and Pressure Vessel Code,Section XI Table IWB-2500-1 for leak testing boundaries of Class 1 pressure retaining components. To complete its review, the U.S. Nuclear Regulatory Commission staff needs the following additional information.
- 1. Please provide a more detailed description of the system leakage test that will be performed for each component group (test pressure and temperature, hold-time, etc). In particular, for component groups 3, 4, and 5, your application states that the examination will be performed at a reduced test pressure. Please provide the pressure(s) that will be used for the test.
Response
" Component Group 1:
Pressure: The actual pressure between the first (inboard) and second isolation valves depends on the leakage rate past these isolation valves. In accordance with IWB-5221, pressure upstream of the inboard valves will be that corresponding to 100% rated reactor power (_>2220 psig). The pressure downstream from the second isolation valve is atmospheric or near atmospheric where discharge is to the Reactor Coolant Drain Tank (RCDT) or pressurizer relief tank. Therefore, the pressure between the first and second isolation valves will be between 0 and 2220 psig, dependant on the isolation valve leakage rates.
Temperature: In accordance with IWB-5240(a), the test temperature for the Reactor Coolant System (RCS) shall not be lower than the minimum temperature associated with normal operating pressure as specified in Technical Specification 3.4.9.1 (about 2900 F). The temperature of Group 1 components is not specified.
Hold Time: In accordance with IWB-5221, the system test pressure and temperature shall be attained at a rate in accordance with the heat-up limitations specified for the system. Therefore, no hold time is required after the system has achieved normal operating pressure.
" Component Group 2:
Pressure: The actual pressure between the first (inboard) and second isolation valves depends on the leakage rate past these isolation valves. In accordance with IWB-5221, pressure upstream of the inboard valves will be that corresponding to 100% rated reactor power L> 2220 psig). The pressure downstream from the second isolation valve will be approximately that of the associated safety injection (SI) accumulator (590-670 psig). Therefore, the pressure between the first and second isolation valves will be between 590 and 2220 psig, dependant on the isolation valve leakage rates.
Temperature: In accordance with IWB-5240(a), the test temperature for the RCS shall not be lower than the minimum temperature associated with normal operating pressure as specified in Technical Specification 3.4.9.1 (about 2900 F). The temperature of Group 2 components is not specified.
Attachment NOC-AE-1 2002828 Page 2 of 8 Hold Time: In accordance with IWB-5221, the system test pressure and temperature shall be attained at a rate in accordance with the heat-up limitations specified for the system. Therefore, no hold time is required after the system has achieved normal operating pressure.
Component Group 3:
Pressure: The actual pressure between the first (inboard) and second isolation valves depends on the leakage rate past these valves. In accordance with IWB-5221, pressure upstream of the inboard valves (SI-10 A,B,C and SI-38 A,B,C) will be that corresponding to 100% rated reactor power (_>2220 psig). The pressure downstream from the second isolation valve will be approximately that of the associated Residual Heat Removal (RHR) and High Head Safety Injection train, or as low as 0 psig. Therefore, the pressure between the first and second isolation valves will be between 0 and 2220 psig, dependant on the isolation valve leakage rates.
Temperature: In accordance with IWB-5240(a), the test temperature for the RCS shall not be lower than the minimum temperature associated with normal operating pressure as specified in Technical Specification 3.4.9.1 (about 2900 F). The temperature of Group 3 components is not specified.
Hold Time: In accordance with IWB-5221, the system test pressure and temperature shall be attained at a rate in accordance with the heat-up limitations specified for the system. Therefore, no hold time is required after the system has achieved normal operating pressure.
Component Group 4:
Pressure: The actual pressure between the first (inboard) and second isolation valves depends on the leakage rate past these isolation valves. In accordance with IWB-5221, pressure upstream of the inboard valves (RH-60 A,B,C) will be that corresponding to 100% rated reactor power (> 2220 psig). The pressure downstream from the second isolation valve will be approximately that of the associated RHR train or as low as 0 psig.
Therefore, the pressure between the first and second isolation valves will be between 0 and 2220 psig, dependant on the isolation valve leakage rates.
Temperature: In accordance with IWB-5240(a), the test temperature for the RCS shall not be lower than the minimum temperature associated with normal operating pressure as specified in the plant Technical Specification 3.4.9.1 (about 2900 F). The temperature of Group 4 components is not specified.
Hold Time: In accordance with IWB-5221, the system test pressure and temperature shall be attained at a rate in accordance with the heat-up limitations specified for the system. Therefore, no hold time is required after the system has achieved normal operating pressure.
Component Group 5:
Pressure: The actual pressure between the first (inboard) and second isolation valves depends on the leakage rate past these isolation valves. In accordance with IWB-5221, pressure upstream of the inboard valves (CV-1, CV-4, and CV-9) will be that corresponding to 100% rated reactor power (> 2220 psig). The pressure downstream from the second isolation valve will be approximately that of the charging header
(> 2220 psig) for the alternate charging line (CV-08 is locked open) and the auxiliary spray line (some valve leakage will occur). For the normal charging line, this pressure may be as low as 0 psig if the normal changing header is vented. Therefore, the
Attachment NOC-AE-12002828 Page 3 of 8 pressure between the first and second isolation valves will be > 2220 psig (but not directly measureable) for the alternate charging line and the auxiliary spray line and between 0 and 2220 psig for the normal changing line, dependant on the isolation valve leakage rates and vent valve positions.
Temperature: In accordance with IWB-5240(a), the test temperature for the RCS shall not be lower than the minimum temperature associated with normal operating pressure as specified in Technical Specification 3.4.9.1 (about 2900 F). The temperature of Group 5 components is not specified.
Hold Time: In accordance with IWB-5221, the system test pressure and temperature shall be attained at a rate in accordance with the heat-up limitations specified for the system. Therefore, no hold time is required after the system has achieved normal operating pressure.
- 2. Has there been plant or industry operating experience of degradation of the subject segments by mechanisms such as stress corrosion cracking or fatigue?
Response
STRESS CORROSION CRACKING STP has not experienced stress corrosion cracking (SCC) in the subject piping.
Industry Operating Experience NRC Information Notice 2011-04, "Contaminants and Stagnant Conditions Affecting Stress Corrosion Cracking in Stainless Steel Piping in Pressurized Water Reactors," details operational experiences in which chlorides, attributing to ODSCC in stainless steel, were introduced environmentally. Potential sources of chlorides included atmospheric chlorides from marine environments, tapes, marking fluid, threaded joint compounds, human sweat, and insulation.
" November 1, 2009: Wolf Creek discovered axial indications due to Outside Diameter Stress Corrosion Cracking (ODSCC) that may have developed from chlorides concentrated under piping support clamps.
- September 2008: A through-wall leak on 2" Schedule 160, Class 2, Type 304 stainless steel pressurizer auxiliary spray line was found at Callaway. The axially-oriented flaw found under a sway strut clamp was a result of ODSCC. Subsequently, the licensee detected a second pipe support clamp with corrosion on the same piping, although no leak was observed. The licensee replaced the degraded section of pipe. Based on a failure analysis of the pipe specimen, the licensee attributes the flaws to transgranular stress corrosion cracking (TGSCC) originating at the outside surface.
Table 1 summarizes operating experience given in EPRI MRP-236, "Materials Reliability Program: Stress Corrosion Cracking of Stainless Steel Components in Primary Water Circuit Environments of Pressurized Water Reactors":
FATIGUE STP has not experienced fatigue in the subject piping.
Industry Operating Experience Industry operating experience with fatigue is listed in Table 2. Following is a summary of the industry operating experience associated with cracks in small bore piping. The events
Attachment NOC-AE-1 2002828 Page 4 of 8 found are categorized into three categories: Vibration (with or without flaws/stress), Weld Flaws, and Corrosion. The distribution of events found are listed below (many events are excluded due to dissimilarities from STP).
" Vibration (high cycle fatigue):
- Five with weld flaw initiators
- Five with other stressors
- Six with no other certain contributors
" Weld Flaws (primary listed cause):
- Seven due to various flaws (technique failures such as cold lap, porosity, fusion, hot crack due to contaminant, etc.)
" Corrosion (SCC; excluding Alloy 600 issues)
- Three OD initiated due to surface chloride contamination A review of industry operating experience for these failures indicates that, in general, these conditions were resolved by repairing or replacing the flawed weld.
Attachment NOC-AE-12002828 Page 5 of 8 TABLE 1 - INDUSTRY OPERATING EXPERIENCE WITH SSC Service NominalLife/
Unit Component Nominal Temperature Contaminant Stress Source Year Source Size Ya Found Callaway (W) PZR Aux 2" 550°F in use Chlorides 2250 psi 24 years CAR Spray Line Sch. 160 80-110°F not (source pressurized /2008 200809886 in use unknown) pipe Wolf Creek (W) PZR Aux 2" 550°F in use Chlorides 2250 psi 24 years OE 30001 Spray Line Sch. 160 80-110°F not (source pressurized /2008 in use unknown) pipe San Onofre ECCS 24" Outside Chlorides Residual stress 25 years OE 30296 Units 2 &3 (CE) suction piping Sch. 10 ambient (marine in weld HAZ /2009 environment)
San Onofre Alternate 6" Outside Chlorides Residual stress 25 years OE 30296 Units 2 &3 (CE) boration Sch. 10 ambient (marine in weld HAZ /2009 gravity feed environment) to charging line San Onofre ECCS mini Not Outside Chlorides Residual stress 25 years OE 30296 Unit 3 (CE) flow return to available ambient (marine in weld HAZ /2009 RWST environment)
Seabrook (W) Inlet piping to Not Not available Chlorides Residual stress 7 years INPO event residual heat available (non-standard in weld HAZ /1997 443-971205-1 removal insulation) pump suction relief valve Ikata CVCS Not 120-212OF Chlorides (Vinyl Pressure not 23 years OE 12516 (Mitsubishi) standby available Maintained chloride tape) available /2000 charging pipe during start up Sequoyah CVCS BA 1" 175-185°F Chlorides Not available 3 years OE 1845 Units 1 &2 (W) transfer line Sch. 40 Normal (source /1986 operation unknown)
Turkey Point CVCS BA %"-3" 180°F (1s 19 Chlorides Residual stress 23 years OE 7201 Unit 3 (W) transfer line Sch. 40 years) and (source in weld HAZ /1995 130OF (4 unknown) years)
St. Lucie ECCS 24" Outside Chlorides Residual stress 16 years OE 10050 Unit 2 (CE) suction piping Sch. 10 ambient (marine in field weld /1993 environment) HAZ Salem RCS 3/8" Not available Chlorides Residual stress 29 years OE 22672 Unit 1 (W) instrument tubing (historic spills inweld HAZ /2006 tubing or service water leaks)
River Bend CRD Not 125 0F Chlorides 1200-1300 psi 8 years LER 94-027-00 (GE BWR) hydraulic available (historical spill) pressurized /1994 system piping pipe Fukushima CRD Not 125°F Chlorides 1200-1300 psi 26 years OE 15325 Daiichi Unit 3 hydraulic available (leaking pressurized /2002 (Toshiba BWR) system piping seawater pipe) pipe
Attachment NOC-AE-12002828 Page 6 of 8 Service NmnlLife/ Suc Unit Component Nominal Temperature Contaminant Stress Source Year Source UntSize Ya Found North Anna Lower head 10" Not available Chlorides Residual stress 27 years Root Cause Unit 1 (W) safety Sch. 40S (leaking ground in weld HAZ /2005 N-2005-5034 injection water) piping in the valve pit Turkey Point CVCS BA %"-3" 180°F ( 1st 19 Chlorides Residual stress 23 years OE 7201 Unit 3 (W) transfer line Sch. 40 years) and (source in weld HAZ /1995 130°F (4 unknown) years)
St. Lucie ECCS 24" Outside Chlorides Residual stress 16 years OE 10050 Unit 2 (CE) suction piping Sch. 10 ambient (marine in field weld /1993 environment) HAZ ,
Salem RCS 3/8" Not available Chlorides Residual stress 29 years OE 22672 Unit 1 (W) instrument tubing (historic spills in weld HAZ /2006 tubing or service water leaks)
River Bend CRD Not 125 0 F Chlorides 1200-1300 psi 8 years LER 94-027-00 (GE BWR) hydraulic available (historical spill) pressurized /1994 system piping pipe Fukushima CRD Not 125 0 F Chlorides 1200-1300 psi 26 years OE 15325 Daiichi Unit 3 hydraulic available (leaking pressurized /2002 (Toshiba BWR) system piping seawater pipe) pipe North Anna Lower head 10" Not available Chlorides Residual stress 27 years Root Cause Unit 1 (W) safety Sch. 40S (leaking ground in weld HAZ /2005 N-2005-5034 injection water) piping in the valve pit I _ II _III
Attachment NOC-AE-1 2002828 Page 7 of 8 TABLE 2 - INDUSTRY OPERATING EXPERIENCE WITH FATIGUE Industry OE Event Cause LER 97-001 Pressure boundary leak on socket High cycle fatigue with likely weld Hatch, 02/19/1997 weld on % inch line connected to anomaly/discontinuity RHR suction line from loop.
OE 9126 1 Y2" seal injection line to RCP Hypothesis: stresses Surry, 05/09/1998 thermal barrier at socket weld. (due to flaws or supports and high cycles)
OE 8564 Leak at vent valve weld. Weld defect (fusion) with high River Bend, 05/06/1997 cycle fatigue.
LER 02-004 /" drain line off HHSI cold leg High cycle fatigue with weld flaws ANO, 10/05/2002 injection line. (fusion and shrinkage)
LER 95-019 Two leaks on 3/4" socket welds. On Vibration fatigue from stress riser Millstone, 12/01/1995 RCP seal injection drain line and in the socket weld, probably at the RCS loop flow instrument line. root of the weld.
OE 14693 3/4" drain line sockolet connection High cycle fatigue. Likely:
Indian Point, 06/25/2002 to charging pump suction header. Inaccurate pipe fitup or fluid pressure vibration.
OE 11475 RCP seal water piping socket Vibration due to improper Palisades, 07/01/2000 weld at RCP. supports changed the natural frequency.
SER 27-85 2" aux letdown line socket weld Fatigue crack by vibration, failed McGuire, 08/06/1984 due to water hammer OE 18110 1" cracked socket weld on drain High cycle fatigue due to support Palo Verde, 02/03/2004 valve on HHSI injection line induced additional stress LER 94-003 3/4" Safety Injection tank test High cycle fatigue with harmonic Calvert Cliffs, 07/11/1994 connection socket weld failure oscillation based on excitation frequency of RCS loop.
OE 8334 Six socket weld failures on low High vibration caused by flow Surry, 01/06/1997 pressure letdown line (various line downstream of an orifice.
types, including cantilever drains) Unknown if flaws existed.
OE 9454, 2" letdown line, sockets on Vibratory loading Wolf Creek, 08/01/1998 coupling downstream of throttle valve OE 9964 3/4" line sockolet connection to Modification to line changed valve Byron, 05/14/1999 RCS bypass line sizes and changed the resonance frequency.
LER 93-009 2" sockolet connection from High cycle fatigue due to Comanche Peak, 08/05/1993 eductor line to Containment Spray inadequately restricted vibration pump suction levels.
LER 89-012 3/4" vent line fillet weld at sockolet High cycle fatigue (no flaws or Yankee, 03/24/1989 material problems noted)
Attachment NOC-AE-1 2002828 Page 8 of 8 Industry OE Event Cause LER 89-010 1 11/2" socket weld at drain line Pinhole, suggesting weld flaw.
ANO, 05/17/1989 valve Location was in area not easily accessible LER 94-001 3/4" vent line off accumulator line, Weld flaws, inadequate Diablo Canyon, 03/28/1994 socket weld penetration and lack of fusion. No fatigue driver noted.
OE 17621 3/4" vent line on SI injection line. Construction groove in toe of Wolf Creek, 11/17/2003 Valve socket weld. weld.
OE 16784 2" reactor head vent line, socket Poor quality weld (porosity, Quad Cities, 05/20/2003 weld. fusion, overlap) was not detected.
LER 93-002 Spray valve bypass line, SCC on fillet weld. Inadequate Turkey Point, 01/15/1993 abandoned. Pipe cap to nipple pullback between the cap and socket weld. pipe in socket.
LER 93-18 Rx vessel drain line socket weld. Lack of full penetration or fusion.
Pilgrim, 07/22/1993 Water in area and physical constraints.
LER 97-005 1" vent line from SI line. Socket Hot cracking of weld due to boric St Lucie, 04/19/1997 weld. acid contamination.
OE 6213 Steam Generator bowl drain line SCC due to chlorides from ID.
Surry, 08/21/1993 socket weld at isolation valve. Normally stagnant location SS316 material, collected contaminants OE 13954 3/4" balance line at RHR pump at TGSCC from OD. Chloride Surry, 04/13/2002 sockolet on suction line (stuffing surface contaminant.
box back to suction line)
LER 94-002 BMI thimble tube connection at TGSCC from OD. 304SS.
Turkey Point, 03/10/1994 seal table. %"guide tube. Chloride from improper cleaning I_ techniques.