CNRO-2006-00043, Request for Alternative GG-ISI-002, Request to Use ASME Code Case N-716
| ML062720254 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 09/22/2006 |
| From: | Burford F Entergy Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CNRO-2006-00043 | |
| Download: ML062720254 (42) | |
Text
Entergy Operations, Inc.
1340 Echelon Parkway EntergyJackson, Mississippi 39213-8298 F. G. Burford Acting Director Nuclear Safety & Licensing CNRO-2006-00043 September 22, 2006 U. S. Nuclear Regulatory Commission Attn.: Document Control Desk Washington, DC 20555-0001
SUBJECT:
Request for Alternative GG-ISI-002 Request to Use ASME Code Case N-716 Grand Gulf Nuclear Station Docket No. 50-416 License No. NPF-29
Dear Sir or Madam:
At a recent meeting of the ASME Code Committee, the NRC staff suggested that, as a pilot application for the industry, a licensee submit a request to implement a risk-informed Inservice Inspection (ISI) program based on ASME Code Case N-716, Alternative Piping Classification and Examination Requirements, Section X1 Division 1. Entergy Operations, Inc.
(Entergy) agreed to submit such a request for the Grand Gulf Nuclear Station (GGNS).
Therefore, pursuant to 10 CFR 50.55a(a)(3)(i), Entergy requests authorization to implement a risk-informed Inservice Inspection (ISI) program based on ASME Code Case N-716, as documented in Request for Alternative GG-ISI-002 contained in Enclosure I to this letter.
GG-ISI-002 is being submitted in a template format similar to submittals the NRC staff has approved for ASME Code Case N-578. A copy of ASME Code Case N-716 is also provided in Enclosure 2.
As recommended in NRC Information Notice 98-44, Entergy plans to submit in a separate letter a request to extend the current (second) ISI interval in order to allow the staff sufficient review time.
Entergy requests staff approval of Request for Alternative GG-ISI-002 on or before September 22, 2007.
This letter contains one commitment identified in Enclosure 3.
CNRO-2006-00043 Page 2 of 2 Should you have any questions regarding this submittal, please contact Guy Davant at (601) 368-5756.
Very truly yours, FGB/GHD/ghd
Enclosures:
- 1.
Request for Alternative GG-ISI-002
- 2.
- 3.
Licensee-identified Commitments cc:
Mr. W. R. Brian (G-ADM-1)
Mr. W. A. Eaton (E-MCH-38)
Dr. Bruce S. Mallett U. S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 U. S. Nuclear Regulatory Commission Attn: Mr. B. K. Vaidya MS O-7DIA Washington, DC 20555-0001 NRC Senior Resident Inspector Grand Gulf Nuclear Station Route 2, Box 399 Port Gibson, MS 39150
ENCLOSURE I CNRO-2006-00043 REQUEST FOR ALTERNATIVE GG-ISI-002
ENTERGY OPERATIONS, INC.
GRAND GULF NUCLEAR STATION REQUEST FOR ALTERNATIVE GG-ISI-002 APPLICATION OF ASMVE CODE CASE N-716 RISK-INFORMED / SAFETY-BASED INSER VICE INSPECTION PROGRAM PLAN Table of Contents
- 1. Introduction 1.1 Relation to NRC Regulatory Guides 1.174 and 1.178 1.2 PRA Quality
- 2.
Proposed Alternative to Current Inservice Inspection Programs 2.1 ASME Section XI 2.2 Augmented Programs
- 3.
Risk-informed / Safety-Based ISI Process 3.1 Safety Significance Determination 3.2 Failure Potential Assessment 3.3 Element and NDE Selection 3.3.1 Additional Examinations 3.3.2 Program Relief Requests 3.4 Risk Impact Assessment 3.4.1 Quantitative Analysis 3.4.2 Defense-in-Depth
- 4.
Implementation and Monitoring Program
- 5.
Proposed ISI Program Plan Change
- 6.
References/Documentation Page 1 of 28
ENTERGY OPERATIONS, INC.
GRAND GULF NUCLEAR STATION REQUEST FOR ALTERNATIVE GG-ISI -002
- 1.
INTRODUCTION Grand Gulf Nuclear Station (GGNS) is currently in the second inservice inspection (151) interval as defined by the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Section Xl Code for Inspection Program B. GGNS plans to complete the current (second) 151 interval by implementing a risk-informed I safety-based inservice inspection (RIS...B) program during the third inspection period of the interval. Entergy will also implement 100% of the RISB program in the third interval.
The ASME Section XI code of record for the second ISI interval at GGNS is the 1992 Edition for Examination Category B-F, B-J, C-F7-I, and C-F-2 Class 1 and 2 piping components. The ASME Section Xl code of record for the third ISI interval at GGNS is the 2001 Edition with 2003 Addenda for these welds.
The objective of this submittal is to request the use of the R1S.B3 process for the inservice inspection of Class 1 and 2 piping. The R1SB process used in this submittal is based upon ASME Code Case N-71 6, Alternative Piping Classification and Examination Requirements, Section X1 Division 1, which is founded in large part on the RI-ISI process as described in Electric Power Research Institute (EPRI) Topical Report (TR) 112657 Rev. B-A, Revised Risk-Informed Inservice Inspection Evaluation Procedure.
1.1 Relation to NRC Regulatory Guides 1.174 and 1.178 As a risk-informed application, this submittal meets the intent and principles of Regulatory Guide 1. 174, An Approach for Using Probabilistic Risk Assessment in Risk-In formed Decisions On Plant-Specific Changes to the Licensing Basis," and Regulatory Guide 1. 178, An Approach for Plant-Specific Risk-Informed Decisionmaking Insen'ice Inspection of Piping. Additional information is provided in Section 3.6.2 relative to defense-in-depth.
1.2 Probabilistic Safety Assessment (PSA) Quality The GGNS Individual Plant Evaluation (IPE) was submitted to the NRC in December 1992. The GGNS IPE consisted of the Level I PSA and back-end analysis (Level 2) consistent with the requirements of NRC Generic Letter (GL) 88-20, Individual Plant Examination for Severe Accident Vulnerabilities - 10 CFR 50.54(0. The NRC responded in a letter dated March 7, 1996 and approved the GGNS IPE results. The letter concluded that the GGNS IPE met the intent of GL 88-20; that is, the GGNS process was capable of identifying the most likely severe accidents and severe accident vulnerabilities for. GGNS.
Several model updates have been completed since the IPE was submitted. The scope of the updates was based on review of results and plant input to the model. The scope of the first update included revisions to system models, refinement of assumptions, incorporation of updated plant specific data, and re-quantification of the Level I model.
Page 2 of 28
These revisions and the final model and results, constituted what is now referred to as the GGNS Revision 1 PSA model. This was completed in July 1997.
An industry peer review of the GGNS PSA was conducted in August 1997 on the Revision 1 PSA and the report was subsequently published in October 1997. The Results Summary of the 1997 BWROG GGNS PSA Certification published in October 1997 contains the following statements:
"The Grand Gulf maintenance and update process is found to be consistent with maintaining a high quality PSA program that is useful for applications."
"Based on the Certification Team Review, the PSA can be effectively used to support applications involving relative risk significance; in addition, absolute risk determination applications can be performed with supporting deterministic analyses."
" "The average Grade level of each of the PSA elements is quite consistent indicating that all the PSA elements have been addressed in a manner that would allow supporting applications up to Grade 3 with only a few enhancements or additional deterministic analysis. In terms of the average element scores, areas that stand out as particularly strong are the following:
> Systems Analyses
> Structural Analysis of Containment
> Maintenance and Update Process"
" "The areas that provide the greatest opportunities for improvement on a relative basis are the following:
> Data Analysis
> HRA in selected areas
>~ Quantification Process and documentation" In October 2002, Revision 2 of the GGNS Level 1 PSA was issued. The scope of this revision included the incorporation of new methodologies in addition to revisions to various elements of the model. The modeling changes were made as a result of changes to the plant, revised plant procedures, revisions to system success criteria, addition of additional detail to system models and the addition of systems to the model.
New methodologies for various tasks necessary for the PSA update were also utilized.
These include the following:
- Utilized a more accepted methodology (alpha factor method) for the common cause analysis. In addition, the common cause analysis was much more extensive (applied to more components) than the analysis in the previous revision.
Page 3 of 28
Updated the human reliability analysis (HRA) with a more comprehensive and thorough methodology. This analysis was also much more extensive and took into account dependencies between multiple human error events when they occurred within a single cut set.
- Incorporated a new method for accounting for recovery of losses of offsite power.
This method uses a convolution approach to account for time dependencies in individual cut sets. A plant-specific offsite power recovery curve was also developed utilizing only those loss-of-offsite-power events that are applicable to GGNS.
Utilized more detailed fault trees to determine the frequency for certain support system initiating events.
Utilized updated data to determine basic event probabilities and initiating event frequencies. There was more extensive use of plant-specific data (primarily major components of risk significant maintenance rule systems).
As part of the Revision 2 update of the PSA, most of the important observations resulting from the peer review were also addressed. Following Revision 2 of the Level 1 update, a decision was made to develop a Large Early Release Frequency (LERF) model rather than update the IPE Level 2 model. The LERF model was developed using the methods described in NUREGICR-6595, Rev. 1, An Approach for Estimating
- the Frequencies of Various Containment Failure Modes and Bypass Events, and is directly linked to the Revision 2 internal events model. Because of the different method, most of the Level 2 peer review observations are not applicable and have not been addressed. The LERF model was completed and issued in December 2003.
Request for Alternative GG-ISI-002 is based on the GGNS PSA Revision 2 model and the GGNS LERF model. The base case Core Damage Frequency (CDF) is 4.27E-06/year, and the base case LERF is 2.04E-O7lyear.
Based on the above, Entergy believes that the current PSA model, used in the RISB evaluation, has an acceptable quality to support this application.
- 2.
PROPOSED ALTERNATIVE TO CURRENT ISI PROGRAMS 2.1 ASME Section Xl ASME Section XI Examination Categories B-F, B-J, C-F7-i, and C-F-2 currently contain requirements for the nondestructive examination (NDE) of Class I and 2 piping components, except as amended by application of ASME Code Case N-663 (Request for Alternative CEP-ISI-007) that was approved for use at GGNS by the NRC on August 26, 2003.
- The alternative RIS B Program for piping is described in Code Case N-716. The RISB Program will be sub~stituted for the current program for Class I and 2 piping (Examination Categories B-F, B-J, C-F-I and C-F7-2) in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. Other non-related portions of the ASME Section XI Code will be unaffected.
Page 4 of 28
2.2 Augmented Programs The impact of the RIS_B application on the various plant augmented inspection programs listed below were considered. This section documents only those plant augmented inspection programs that address common piping with the RISB application scope (e.g., Class 1 and 2 piping).
"The original plant augmented inspection program for high-energy line breaks outside containment, implemented in accordance with GGNS Final Safety Analysis Report (FSAR) Section 6.6.8, "Augmented Inservice Inspection to Protect against Postulated Piping Failures," is being revised in accordance with the risk-informed break exclusion region methodology (RI-BER) described in EPRI TR-1 006937, Extension of EPRI Risk Informed IS! Methodology to Break Exclusion Region Programs. TR-1 006937 was approved by the NRC in 2002. The results of the RI-BER application demonstrated that the inspection population for this scope of piping could be reduced to 7%. However, because of the limitations imposed by Code Case N-716, implementing this RIS_B application will ensure an inspection population of at least 10%.
" The plant augmented inspection program for flow accelerated corrosion (FAC) per GL 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, is relied upon to manage this damage mechanism but is not otherwise affected or changed by the RISB Program.
- The plant augmented inspection program for intergranular stress corrosion cracking (IGSCC) per GL 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping, is relied upon to manage this damage mechanism. GIL 88-01 specifies examination extent and frequency requirements for austenitic stainless steel welds that are classified as Categories A through G, dependent upon their susceptibility to IGSCC. In accordance with EPRI TR-1 12657, piping welds identified as "Category A" are considered resistant to IGSCC and are assigned a low failure potential provided no other damage mechanisms are present. As such, the examination of welds identified as Category A inspection locations is subsumed by the RIS_-B Program. The existing plant augmented inspection program for the other piping welds susceptible to IGSCC at GGNS (Categories "B" and "C") remains unaffected by the RIS_B Program submittal.
- 3.
RISK-INFORMED / SAFETY-BASED ISI PROCESS The process used to develop the RISB Program conformed to the methodology described in Code Case N-716 and consisted of th~e following steps:
" Safety Significance Determination
" Failure Potential Assessment
" Element and NDE Selection
" Risk Impact Assessment Implementation Program Page 5 of 28
0Feedback Loop 3.1 Safety Significance Determination The systems assessed in the RISB Program are provided in Table 3.1. The piping and instrumentation diagrams and addTitional plant information including the existing plant 151 Program were used to define the piping system boundaries.
Per Code Case N-716 requirements, piping welds are assigned safety-significance categories, which are used to determine the treatment requirements. High safety-significant (HSS) welds are determined in accordance with the requirements below.
Low safety-significant (LSS) welds include all other Class 2, 3, or Non-Class welds.
(1) Class 1 portions of the reactor coolant pressure boundary (RCPB), except as provided in 10 CFR 50.55a(c)(2)(i) and (c)(2)(ii);
(2) Applicable portions of the shutdown cooling pressure boundary function. That is, Class 1 and 2 welds of systems of portions of systems needed to utilize the normal shutdown cooling flow path either:
(a) As part of the RCPB from the reactor pressure vessel (RPV) to the second isolation valve (i.e., farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds; or (b) Other systems or portions of systems from the RPV to the second isolation valve (i.e., farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds; (3) That portion of the Class 2 feedwater system [> 4 inch nominal pipe size (NPS)] of pressurized water reactors (PWRs) from the steam generator to the outer containment isolation valve; (4) Piping within the break exclusion region (> NPS 4) for high-energy piping systems as defined by the Owner. This may include Class 3 or Non-Class piping; and (5) Any piping segment whose contribution to CDF is greater than 1 E-06 based upon a plant-specific PSA of pressure boundary failures (e.g., pipe whip, jet impingement, spray, inventory losses). This may include Class 3 or Non-Class piping.
3.2 Failure Potential Assessment Failure potential estimates were generated utilizing industry failure history, plant-specific failure history, and other relevant information. These failure estimates were determined using the guidance provided in EPRI TR-1 12657 (i.e., the EPRI RI-ISI methodology),
with the exception of the deviation discussed below.
Table 3.2 summarizes the failure potential assessment by system for each degradation mechanism that was identified as potentially operative.
Page 6 of 28
A deviation to the EPRI RI-ISI methodology has been implemented in the failure potential assessment for GGNS. Table 3-16 of EPRI TR-l 12657 contains criteria for assessing the potential for thermal stratification, cycling, and striping (TASCS). Key attributes for horizontal or slightly sloped piping greater than NPS 1 include:
1.
The potential exists for low flow in a pipe section connected to a component allowing mixing of hot and cold fluids; or
- 2. The potential exists for leakage flow past a valve, including in-leakage, out-leakage and cross-leakage allowing mixing of hot and cold fluids; or
- 3. The potential exists for convective heating in dead-ended pipe sections connected to a source of hot fluid; or
- 4. The potential exists for two phase (steam/water) flow; or
- 5. The potential exists for turbulent penetration into a relatively colder branch pipe connected to header piping containing hot fluid with turbulent flow; AND AT> 501F, AND Richardson Number > 4 (this value predicts the potential buoyancy of a stratified flow)
These criteria, based on meeting a high cycle fatigue endurance limit with the actual AT assumed equal to the greatest potential AT for the transient, will identify locations where stratification is likely to occur, but allows for no assessment of severity. As such, many locations will be identified as subject to TASCS where no significant potential for thermal fatigue exists. The critical attribute missing from the existing methodology that would allow consideration of fatigue severity is a criterion that addresses the potential for fluid cycling. The impact of this additional consideration on the existing TASCS susceptibility criteria is presented below.
Turbulent Penetration TASCS Turbulent penetration typically occurs in lines connected to piping containing hot flowing fluid. In the case of downward sloping lines that then turn horizontal, significant top-to-bottom cyclic ATs can develop in the horizontal sections if the horizontal section is less than about 25 pipe diameters from the reactor coolant piping. Therefore, TASCS is considered for this configuration.
For upward sloping branch lines connected to the hot fluid source that turn horizontal or in horizontal branch lines, natural convective effects combined with effects of turbulence penetration will keep the line filled with hot water. If there is no potential for in-leakage towards the hot fluid source from the outboard end of the line, this will result in a well-mixed fluid condition where significant top-to-bottom ATs will not occur. Therefore TASCS is not considered for these configurations.
Even in fairly long lines, where some heat loss from the outside of the piping will Page 7 of 28
tend to occur and some fluid stratification may be present, there is no significant potential for cycling as has been observed for the in-leakage case. The effect of TASCS will not be significant under these conditions and can be neglected.
Low Flow TASCS In some situations, the transient startup of a system (e.g., RHR suction piping) creates the potential for fluid stratification as flow is established. In cases where no cold fluid source exists, the hot flowing fluid will fairly rapidly displace the cold fluid in stagnant lines, while fluid mixing will occur in the piping further removed from the hot source and stratified conditions will exist only briefly as the line fills with hot fluid. As such, since the situation is transient in nature, it can be assumed that the criteria for thermal transients (TT) will govern.
Valve Leakage TASCS Sometimes a very small leakage flow of hot water can occur outward past a valve into a line that is relatively colder, creating a significant temperature difference.
However, since this is generally a "steady-state" phenomenon with no potential for cyclic temperature changes, the effect of TASCS is not significant and can be neglected.
Convection Heating TASCS Similarly, there sometimes exists the potential for heat transfer across a valve to an isolated section beyond the valve, resulting in fluid stratification due to natural convection. However, since there is no potential for cyclic temperature changes in this case, the effect of TASCS is not significant and can be neglected.
In summary, these additional considerations for determining the potential for thermal fatigue as a result of the effects of TASCS provide an allowance for considering cycle severity. The above criteria have previously been submitted by EPRI to the NRC for generic approval [letters dated February 28, 2001 and March 28, 2001, from P.J.
O'Regan (EPRI) to Dr. B. Sheron (USNRC), Extension of Risk-Informed Insevice Inspection Methodology]. The methodology used in the GGNS RIS_1B application for assessing TASCS potential conforms to these updated criteria. Final materials reliability program (MRP) guidance on the subject of TASCS will be incorporated into the GGNS RIS_B application, if warranted. It should be noted that the NRC has granted approval for RI-ISI relief requests incorporating these TASCS criteria at several facilities, including Comanche Peak (NRC letter dated September 28, 2001) and South Texas Project (NRC letter dated March 5, 2002).
3.3 Element and NDE Selection Code Case N-716 provides criteria for identifying the number and location of required examinations. Ten percent of the HSS welds shall be selected for examination as follows:
Page 8 of 28
(1) Examinations shall be prorated equally among systems to the extent practical, and each system shall individually meet the following requirements:
(a)
A minimum of 25% of the population identified as susceptible to each degradation mechanism and degradation mechanism combination shall be selected.
(b)
If the examinations selected above exceed 10% of the total number of HSS welds, the examinations may be reduced by prorating among each degradation mechanism and degradation mechanism combination, to the extent practical, such that at least 10% of the HSS population is inspected.
(c)
If the examinations selected above are not at least 10% of the HSS weld population, additional welds shall be selected so that the total number selected for examination is at least 10%.
(2)
For the RCPB, at least two-thirds of the examinations shall be located between the first isolation valve (i.e., isolation valve closest to the RPV) and the RPV.
(3)
A minimum of 10% of the welds in that portion of the RCPB that lies outside containment (e.g., portions of the main feedwater system in BWRs) shall be selected.
(4)
A minimum of 10% of the welds within the break exclusion region (BER) shall be selected.
In contrast to a number of RI-ISI Program applications where the percentage of Class 1 piping locations selected for examination has fallen substantially below 10%, Code Case N-716 mandates that 10% be chosen. A brief summary is provided below, and the results of the selections are presented in Table 3.3. Section 4 of EPRI TR-1 12657 was used as guidance in determining the examination requirements for these locations.
Clas Wld~
1 Cas 2We(s
- 2)
Class 3INSS(4 Uit Clss elected [CToals 2eece Welds (3)
All Piping Welds ')
oalSlce Total jSelec ted oa e td Total Selected]
1 880
[9 942 8
12 2
1834 109 Notes
- 2. Includes all Category C-F-I and C-F-2 locations. Of the 942 Class 2 piping weld locations, 116 are HSS and the remaining 826 are LSS.
- 3. Includes eleven Class 3 and one non-safety system (NSS) locations. All twelve of these piping weld locations are HSS.
- 4. Regardless of safety significance, Class 1, 2 and 3 in-scope piping components will continue to be pressure tested as required by the ASME Section Xl Program. VT-2 visual examinations are scheduled in accordance with the station's pressure test program that remains unaffected by the RISB Program.
Page 9 of 28
3.3.1 Additional Examinations The RISB Program in all cases will determine through an engineering evaluation the root cause of any unacceptable flaw or relevant condition found during examination. The evaluation will include the applicable service conditions and degradation mechanisms to establish that the element(s) will still perform their intended safety function during subsequent operation. Elements not meeting this requirement will be repaired or replaced.
The evaluation will include whether other elements in the segment or additional segments are subject to the same root cause conditions. Additional examinations will be performed on those elements with the same root cause conditions or degradation mechanisms. The additional examinations will include HSS elements up to a number equivalent to the number of elements required to be inspected during the current outage. If unacceptable flaws or relevant conditions are again found similar to the initial problem, the remaining elements identified as susceptible will be examined during the current outage. No additional examinations need be performed if there are no additional elements identified as being susceptible to the same root cause conditions.
3.3.2 Program Relief Requests An attempt has been made to select RISB locations for examination such that a minimum of >90% coverage (i.e., Code Case N-460 criteria) is attainable.
However, some limitations will not be known until the examination is performed since some locations may be examined for the first time by the specified techniques.
In instances where locations at the time of the examination fail to meet the >90%
coverage requirement, the process outlined 10 CFR 50.55a will be followed.
Request for Alternative CEP-ISI-007 pertaining to the application of Code Case N-663 will be withdrawn for use at GGNS upon NRC approval of the RISB Program submittal.
3.4 Risk Impact Assessment The RIS -B Program has been conducted in accordance with Regulatory Guide 1.174 and the requirements of Code Case N-716, and the risk of implementing this program is expected to remain neutral or decrease when compared to that estimated from current requirements.
This evaluation categorized segments as high safety significant or low safety significant in accordance with Code Case N-716, and then determined what inspection changes are proposed for each system. The changes include changing the number and location of inspections and in many cases improving the effectiveness of the inspection to account for the findings of the RISB degradation mechanism assessment. For example, examinations of locations subject to thermal fatigue will be conducted on an expanded volume and will be focused to enhance the probability of detection (POD) during the inspection process.
Page 10 of 28
3.4.1 Quantitative Analysis Code Case N-716 has adopted the EPRI TR-1 12657 process for risk impact analyses whereby limits are imposed to ensure that the change in risk of implementing the RIS_B Program meets the requirements of Regulatory Guides 1.174 and 1.178. The EPRI criterion requires that the cumulative change in CDF and LERF be less than 1 E-07 and 1 E-08 per year per system, respectively.
GGINS has conducted a risk impact analysis per the requirements of Section 5 of Code Case N-716 that is consistent with the "Simplified Risk Quantification Method" described in Section 3.7 of EPRI TR-1 12657. The analysis estimates the net change in risk due to the positive and negative influences of adding and removing locations from the inspection program. The conditional core damage probability (CCDP) and conditional large early release probability (CLERP) values used to assess risk impact were determined based on pipe break location as follows:
For RCPB pipe breaks that result in a loss-of-coolant accident (LOCA),
bounding CCDP (5.4E-04) and CLERP (5.4E-5) values were used to determine risk impact.
- For RCPB pipe breaks that result in an isolable LOCA, CCDP (1.84E-6) and CLERP (1.84E-7) values were calculated based on the above LOCA values and a bounding MOV failure to close on demand rate of 3.4E-3. Since these values fall within the medium consequence rank range per EPRI TR-1 12657, upper bound threshold values for CCDP (1 E-4) and CLERP (1 E-5) were used to determine risk impact.
For RCPB pipe breaks that result in a potential LOCA, CCDP (5.4E-7) and CLERP (5.4E-8) values were calculated based on the above LOCA values and a bounding check valve disc rupture failure rate of 1 E-3. Since these values fall within the low consequence rank range per EPRI TR-1 12657, upper bound threshold values for CCDP (1 E-6) and CLERP (1 E-7) were used to determine risk impact.
For non-RCPB pipe breaks that occur in operating system piping within the scope of the plant break exclusion region boundaries, CCDP and CLERP values were determined based on the RI-BER evaluation performed for GGNS. Because the values fell within the medium consequence rank range per EPRI TR-1 12657, upper bound threshold values for CCDP (1 E-4) and CLERP (1IE-5) were used to determine risk impact.
- For non-RCPB pipe breaks that occur in standby system piping, CCDP and CLERP values were determined based on the GGINS plant-specific PSA for internal flooding. Because the values fell within the low or medium consequence rank ranges per EPRI TR-I 12657, upper bound threshold values for CCDP (1 E-4) and CLERP (1 E-5) were used to determine risk impact.
Page 11 of 28
The likelihood of pressure boundary failure (PBF) is determined by the presence*
of different degradation mechanisms and the rank is based on the relative failure probability. The basic likelihood of PBF for a piping location with no degradation mechanism present is given as x0 and is expected to have a value less than 1 E-08. Piping locations identified as medium failure potential have a likelihood of 20x0. These PBF likelihoods are consistent with References 9 and 14 of EPRI TR-1 12657. In addition, the analysis was performed both with and without taking credit for enhanced inspection effectiveness due to an increased POD from application of the RIS-B approach.
Table 3.4-1 presents a summary of the RISB3 Program versus 1992 ASME Section Xl Code Edition program requirements on a "per system" basis. The presence of IGSCC was adjusted for in the quantitative analysis by excluding its impact on the failure potential rank. The exclusion of the impact of IGSCC on the failure potential rank and therefore in the determination of the change in risk is performed, because IGSCC is a damage mechanism managed by a separate, independent plant augmented inspection program. The RIS -B Program credits and relies upon this plant augmented inspection program to manage this damage mechanism. The plant IGSCC Program will continue to determine where and when examinations shall be performed. Hence, since the number of IGSCC examination locations remains the same "before" and "after" and no delta exist, there is no need to include the impact of IGSCC in the performance of the risk impact analysis.
As indicated in the following table, this evaluation has demonstrated that unacceptable risk impacts will not occur from implementing the RIS_B3 Program, and satisfies the acceptance criteria of Regulatory Guide 1. 174 and Code Case N-716.
GGNS Risk Impact Results System~l ARiskCDF ARiskLERF w/IPOD w/o POD w/IPOD w/o POD RPV
-4.32E-1 1 3.02E-10
-4.32E-12 3.02E-1 I FVV2 1
-7.16E-10 3.83E-1O0
-7.16E-1 1 3.83E-1 1 M()1.85E-1 1
1.85E-1 1 1.85E-12 1.8511-12 SD()-1.08E-1 1
-1.08E-1 1
-1.08E-12
-1.08E-12 S()-2.70E-12
-2.70E-12
-2.70E-1 3
-2.70E-13 RCR 7.02E-1I1 7.02E-1 1 7.02E-1 2 7.02E-12 CRD 5.OOE-1 I 5.OQE-1 1 5.OOE-12 5.OOE-12 SLC
-1.08E-11
-1.08E-1 1
-1.08E-12
-1.08E-1 2 RHR 2.66E-1O0 3.14E-10 2.66E-1 1 3.14E-1 1 LPCS 5.27E-1 1 5.27E-11I 5.27E-12 5.27E-12 HPCS
-3.45E-1 1 1.17E-10
-3.45E-12 1.17E-11 MSLC
-2.OOE-12
-2.OOE-12
-2.OOE-13
-2.OOE-13 FWLC
-1.OOE-14
-1.OOE-14
-1.OOE-15
-1.OOE-15 Page 12 of 28
System~')
ARiskCDF ARiskLERF wI POD w/o POD w/IPOD w/o POD RCIC 3.71 E-1 1 3.71 E-1 1 3.71 E-1 2 3.71 E-1 2.
OGO 3.OOE-1 1 3.OOE-1 1 3.OOE-12 3.OOE-12 RWCU 5.70E-12 5.70E-12 5.70E-1 3 5.70E-1 3 Total
-2.89E-10 1.35E-09
-2.89E-11 I.35E-1O Notes I1. Systems are described in Table 3.1.
- 2. FW, MVS, SD and SP comprise the B21 system at GGNS. As indicated above, each subsystem was analyzed individually to demonstrate compliance with the EPRI system level acceptance criteria. In addition, the acceptance criteria have also been met for the B21 system as a whole.
3.4.2 Defense-in -Depth The intent of the inspections mandated by ASME Section Xl for piping welds is to identify conditions such as flaws or indications that may be precursors to leaks or ruptures in a system's pressure boundary. Currently, the process for picking inspection locations is based upon structural discontinuity and stress analysis results. As depicted in ASME White Paper 92-01 -01 Rev. 1, Evaluation of lnservice Inspection Requirements for Class 1, Category B-J Pressure Retaining Welds, this method has been ineffective in identifying leaks or failures. EPRI TR-112657 and Code Case N-716 provide a more robust selection process founded on actual service experience with nuclear plant piping failure data.
This process has two key independent ingredients; that is, a determination of each location's susceptibility to degradation and secondly, an independent assessment of the consequence of the piping failure. These two ingredients assure defense-in-depth is maintained. First, by evaluating a location's susceptibility to degradation, the likelihood of finding flaws or indications that may be precursors to leak or ruptures is increased. Secondly, a generic assessment of high-consequence sites has been determined by Code Case N-716 supplemented by plant-specific evaluations thereby requiring a minimum threshold of inspection for important piping whose failure would result in a LOCA or BER break. Finally, Code Case N-716 requires that any piping on a plant-specific basis that has a contribution to CDF of greater than 1 E-06 be included in the scope of the application. GGNS did not identify any such piping.
All locations within the Class 1, 2, and 3 pressure boundaries will continue to be pressure tested in accordance with the Code, regardless of its safety significance.
Page 13 of 28
- 4.
IMPLEMENTATION AND MONITORING PROGRAM Upon approval of the RISB Program, procedures that comply with the guidelines described in EPRI TR-1 12657 will be prepared to implement and monitor the program. The new program will be integrated into the second ISI interval. No changes to the Technical Specifications or Updated Final Safety Analysis Report are necessary for program implementation.
The applicable aspects of the ASME Code not affected by this change will be retained, such as inspection methods, acceptance guidelines, pressure testing, corrective measures, documentation requirements, and quality control requirements. Existing ASME Section Xl program implementing procedures will be retained and modified to address the RISB process, as appropriate.
The monitoring and corrective action program will contain the following elements:
A. Identify B. Characterize C. (1) Evaluate, determine the cause and extent of the condition identified (2) Evaluate, develop a corrective action plan or plans D. Decide E. Implement F. Monitor G. Trend The RISB Program is a living program requiring feedback of new relevant information to ensure th appropriate identification of HSS piping locations. As a minimum, this review will be conducted on an ASME period basis. In addition, significant changes may require more frequent adjustment as directed by NRC Bulletin or Generic Letter requirements, or by industry and plant-specific feedback.
- 5.
PROPOSED 151 PROGRAM PLAN CHANGE A comparison between the RISB Program and ASME Section XI 1992 Code Edition program requirements for in-scope piping is provided in Table 5.
GGNS intends to start implementing the RIS_B Program during the plant's third period of the current (second) inspection interval. By the end of last refueling outage (RF-1 4), 71 % of the piping weld examinations required by ASME Section XI have been completed thus far in the second ISI interval for Examination Categories B-F, B-J, C-F-I and *C-F-2. To ensure the performance of 100% of the required examinations during the current (second) ten-year ISI interval, 29% of the inspection locations selected for examination per the RIS -B process will be examined in the third period of the interval. The third ISI interval will implement 100% of the inspection locations selected for examination per the RIS_B Program. Examinations shall be performed such that the period percentage requirements of ASME Section XI are met.
Page 14 of 28
- 6.
REFERENCESIDOCUMENTATION USNRC Safety Evaluation on the use of ASMVE Code Case N-663, dated August 26, 2003 (letter CNRI-2003-0001 0)
EPRI TR-1 006937, Extension of EPRI Risk In formed ISI Methodology to Break Exclusion Region Programs EPRI TR-1 12657, Revised Risk-Informed Inservice Inspection Evaluation Procedure, Rev. B-A ASMVE Code Case N-71 6, Alternative Piping Classification and Examination Requirements, Section X1 Division 1 Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis Regulatory Guide 1.178, An Approach for Plant-Specific Risk-Informed Decisionmaking Inservice Inspection of Piping Supporting Onsite Documentation GGNS-01 Q-302, RI-BER Evaluation for Grand G ulf Nuclear Station GGNS-01 Q-301, Degradation Mechanism Evaluation for the Class 1 and Class 2 Piping Welds at GGNS Nuclear Plant CE02006-001 27, Service History Review for GGNS Nuclear Plant GGNS-01 Q-303, Review of GGNS Flooding Study GGNS-01 Q-304, Safety Significance Determination, Element Selection and Risk Impact Analysis for GGNS Code Case N-716 Application Page 15 of 28
Table 3.1 N-716 Safety Significance Determination SytmDsrpinWeld N-716 Safety Significance Determination Safety Significance SytmDsrpinCount RCPB__
_PWR: FW BER ICDF >I E-.I High Low RPV - Reactor Pressure Vessel (1313) 40 10 NA ve FW-Feedwater(B21) 16 VVNA V
57 V
NAV 8
VNAVV 27 NAVV MS -Main Steam(1321) 79 VNAVV 94 VNAV 20 NAVV SD -Steam Drains (1321) 5 VNAVV 36 V,
NAV SP - Sodium Pentaborate (1321) 5 V,
NAV RCR - Reactor Recirculation (1333) 4 V1/
NAV 190 VNAV CRD - Control Rod Drive (Cli1) 63 NAV SLC - Standby Liquid Control (C41) 42 VNAV RHR - Residual Heat Removal (E12) 9 VVNAV 70 VNAV 35 NAVV 500 NAV LPCS - Low Pressure Core Spray (E21) 32 VNAV 64 NAV HPCS - High Pressure Core Spray (E22) 42 VNAV 82 NA V0 MSLC - Main Steam Leakage Control (E32) 31 VNAVV FXNLC - Feedwater Leakage Control (E38)
I1 I NA
%0 Page 16 of 28
Table 3.1 N-716 Safety Significance Determination Weld I N-716 Safety Significance Determination ____[SaeySgnificance Sytm ecipinCount jRCPB JSDC JPWR: FW JBER ICDF >IE-61 High JLow RCIC - Reactor Core Isolation Cooling (E51) 6 VNA V
6 VNA 12 NA V
107 NA CGC - Combustible Gas Control (E61) 8 NA RWCU - Reactor Water Cleanup (G33) 55 VNAVV 42 VNA 34 NA VV 2
NAV
SUMMARY
RESULTS FOR ALL SYSTEMS 16 VVNAVV 70 VVNAV 184 VNAVV 610 VNAV 128 NAVV 826 NAV TOTALS 1834 1008 826 Page 17 of 28
Table 3.2 Failure Potential Assessment Summary SystemW I Thermal Fatigue Stress Corrosion Cracking Localized Corrosion Flow Sensitive TSCS TT IGSCC jTGSCC jECSCCj PWSCC MIC j
[
%/%
FW V
HPCS(2)
RWCU( 2)
Notes
- 1. Systems are described in Table 3.1.
- 2.
A degradation mechanism assessment was not performed on low safety significant piping segments. This includes the CRD and CGC systems in their entirety, as well as portions of the RHR, LPCS, HPCS, RCIC and RWCU systems.
Page 18 of 28
Table 3.3 N-716 Element Selections Sytr~)
Weld Count N-716 Selection Considerations Slcin HSS LSS DMs RCPB IFIV RCPB o BER RPV 6
TASOS, TT, (IGSCC)
V4 RPV 2
TT, (IGSCC)
V0 RPV 6
None V0 FW 6
TASCS,TT v
V 6
TASCS,TT VV6 FW 4
TASCS,TT 1
FW 10 TASCS,TT NA NA Ve 3
FW 4
TASCS VV4 FW 3
U V
3 FW 4
None VV0 FW 17 None NA NA V0 MS 15 None VV0 MS 92 None V4 MVS 56 None VV0 MS 8
None V0 MS 2
None 0
MS 20 None NA NA V0 SD 1
None V
V 0
SD 2
None V0 SP 5
None 1
None 0
None Vr 4
SLC 37 None 1
RHR 4
TT, CC NA NA VI RHR 13 Ur NA NA V4 RHR 24 None V7 RHR 4
None VI RHR 51 None 0
RHR 18 None NA NA V0 RHR 500 LPCS 7
None V3 Page 19 of 28
Table 3.3 N-716 Element Selections Ssel)
Weld Count N-716 Selection Considerations Slcin HSS LSS DMs RCPBIFII RCPB o BER LPCS 2
None I
LPCS 23 None 0
iT 2
HPCS 8
None Ve 2
HPCS 7
None V1 HPCS 23 None 0
None ve v
1 RCIC 6
None ve 1
RCIC 2
None Vve I
RCIC 3
None V0 RCIC 12 None NA NA V0 RCIC 107 CGC 8__
RWCU 26 None VV10 RWCU 39 None V0 RWCU 7
None VV2 RWCU 2
None Ve 0
None 0
RWCU 34 None NA NA 2
RWCU 2
SUMMARY
6 TASCS, iTT (IGSCC)
V4 RESULTS 6
TASCS,TT V
V 6
FOR ALL SYSTEMS 54 TASCS,iT V
3 6
TASCS,TT VV6 4
TASCS,TT 1
10 TASCS,TT NA NA V3 2
TT, (IGSCC)
Ve 0
4 TT, CC NA NA 1
4 TASCS V
ol 4
7 TT V
13 T
NA NA__
V 4
Page 20 of 28
Table 3.3 N-716 Element Selections Sytr~)
Weld Count N-716 Selection Considerations Slcin HSS LSS DMs RCPBIRv RCPBc~
SUMMARY
51 None (IGSCC)
V8 RESULTS 43 None 11 I
FOR ALL SYSTEMS 389 None V38 (CONT'D) 102 None V
7 26 None V5 35 None Q
145 None 101 None NA NA V2 826
=TO=TALS 1008 826 109 Note
- 1. Systems are described in Table 3.1.
Page 21 of 28
Table 3.4-1 Risk Impact Analysis Results System~'l)
Safety IBreak Failure Potential J_____Inspections CDF Impact J
LERF Impact Significancej Location J DMs Rank Sxi( 2)
RISB13 (3 Delta wI POD w/o POD JwI POD jw/o POD RPV High LOCA TASCS, TT, (IGSCC)
Medium (Medium) 6 4
-2
-1.94E-10 1.08E-10
-1.942-1 1 1.08E-1 1 RPV High LOCA TT, (IGSCC)
Medium (Medium) 2 0
-2 6.48E-1 1 1.08E-10 6.48E-12 1.08E-11 RPV High LOCA None (IGSCC)
Low (Medium) 26 0
-26 7.02E-1 1 7.022-11I 7.02E-12 7.02E-12 RPV High LOCA None Low 6
0
-6 1.62E-1 1 1.62E-11I 1.62E-12 1.62E-12 RPV TOTAL
-4.32E-1 1 3.02E-10
-4.32E-12 3.02E-11I FW High LOCA TASCS,TT Medium 18 9
-9
-2.92E-10 4.86E-10
-2.92E-11I 4.86E-1 1 FW High ILOCA TASCS, TI Medium 8
7
-1
-7.802-11I 1.002-11I
-7.802-12 1.002-12 FW High BER TASCS, TT Medium 1
3 2
-4.80E-11I
-2.002-1 1
-4.80E-12
-2.002-12 FW High ILOCA TASCS Medium 0
4 4
-7.20E-11I
-4.002-1 1
-7.20E-12
-4.002-12 EW High LOCA TI Medium 2
3 1
-2.272-10
-5.40E-1 1
-2.27E-1 1
-5.40E-12 FW High ILOCA None Low 0
0 0
0.OOE+00 0.002+00 0.OOE+00 0.0011+00 FW High BER None Low 1
0
-1 5.002-1 3 5.002-13 5.OOE-14 5.002-14 FW TOTAL
-7.16E-10 3.8312-10
-7.16E-1 1 3.83E-11I MVS High LOCA None Low 9
4
-5 1.352-1 1 1.352-11I 1.35E-12 1.35E-12 MS High ILOCA None Low 8
0
-8 4.002-1 2 4.002-12 4.002-13 4.002-13 MS High PLOCA None Low 0
0 0
0.002+00 0.002+00 0.002+00 0.002+00 M S High BER None Low 2
0
-2 1.002-1 2 1.002-12 1.002-13 1.002-13 MVS TOTAL 1.85E-1 1 1.8512-11 1.85E-1 2 1.85E-12 SD High LOCA None Low 0
4 4
-1.082-1 1
-1.082-1 1
-1.082-12
-1.082-12 SD High ILOCA None Low 0
0 0
0.002+00 0.002+00 0.0012+00 0.002+00 SD TOTAL
____________________-1
.08E-1 1
-1.08E-1 I
-1.OBE-1 2
-1.08E-1 2 SID High LOCA None Low 0
1 1
-2.702-12
-2.702-12
-2.70E-13
-2.702-1 3 SP TOTAL
-2.70E-12
-2.70E-12
-2.70E-13
-2.70E-13 RCR High LOCA None (IGSCC)
Low (Medium) 6 6
0 0.002+00 0.002+00 0.002+00 0.002+00 RCR High LOCA None Low 38 12
-26 7.022-11 7.022-11I 7.022-1 2 7.022-12 Page 22 of 28
Table 3.4-1 Risk Impact Analysis Results System~" j Safety Break Failure Potential Inspections
-CDF Impact LERF Impac 't Significancel Location DMs J
Rank SXl12)
RIS B (3)
Delta w/ POD Iw/o POD wI POD Iw/o POD RCR High PLOCA None Low 0
0 0
0.002+00 0.002+00 0.002+00 0.002+00 RCR TOTAL
__________7.02E-11 7.02E-11I 7.02E-12 7.02E.12 CRD Low Class 2 N/A Assume Medium 5
0
-5 5.002-1 1 5.002-11I 5.002-12 5.002-12 CRD TOTAL,_____
5.OOE-1 I 5.00E-11I 5.OOE-12 5.OOE-12 SLC High LOCA None Low 0
4 4
-1.08E-11I
-1.08E-1 1
-1.08E-12
-1.08E-12 SLC High PLOCA None Low 0
1 1
-5.002.1 5
-5.002-15
-5.002-16
-5.002-16 SLC TOTAL
_____-1
.08E-11I
-1.08E-11I
-1.08E-1 2
-1.08E-1 2 RHR High BER TT, CC Medium 0
1 1
-1.OOE-1 1
-1.00E-1 1
-1.002-12
-1.00E-12 RHR High BER TT Medium 4
4 0
-4.80E-1 1 0.002+00
-4.80E-12 0.002+00 RHR High LOCA None Low 8
7
-1 2.70E-12 2.70E-12 2.702-13 2.70E-1 3 RHR High PLOCA None Low 10 1
-9 4.50E-14 4.502-14 4.50E-15 4.50E-15 RHR High BER None Low 3
0
-3 1.50E-12 1.50E-12 1.50E-13 1.502-13 RHR Low Class 2 N/A Assume Medium 32 0
-32 3.20E-10 3.20E-10 3.20E-11I 3.202-1 1 RHR TOTAL 2.66E-10 3.14E-10 2.66E-11I 3.14E-11I LPCS High LOCA None Low 4
3
-1 2.70E-12 2.702-1 2 2.702-13 2.702-1 3 LPCS High PLOCA None Low 4
1
-3 j1.50E-14 1.502-14 1.50E-15 1.50E-1 5 LPCS Low Class 2 N/A Assume Medium 5
0
-5 5.002-1 1 5.002-1 1 5.002-12 5.002-12 LPCS TOTAL 5.27E-1 I 5.27E-11I 5.27E-1 2 5.27E.1 2 HPCS High LOCA TT Medium 3
2
-1
-9.72E-1 1 5.40E-1 1
-9.72E-12 5.40E-12 HPCS High LOCA None Low 3
2
-1 2.702-12 2.702-12 2.70E-13 2.70E-1 3 HPCS High PLOCA None Low 2
1
-1 5.002-15 5.002-1 5 5.002-16 5.OOE-16 HPCS Low Class 2 N/A Assume Medium 6
0
-6 6.002-1 1 6.002-1 1 6.002-12 6.OOE-12 HPCS TOTAL
-3.45E-1 1 1.17E-10
-3.45E-12 1.17E-11 MSLC:
High ILOCA None Low 0
4 4
-2.002-12
-2.002-12
-2.002-13
-2.0011-13 MSLC TOTAL
-2.OOE-i 2
-2.OOE-1 2
-2.OOE-1 3
.2.OOE-1 3 FWLC High PLOCA None Low 0
2 2
-1.002-14
-1.002-14
-1.002-15
-1.002-15 Page 23 of 28
Table 3.4-1 Risk Impact Analysis Results System~" I Safety Break Failure Potential Inspections CDF Impact LERF Impact 1 ignificance Location DIVs JF Rank SXI(2)
RIS B(')
Delta wI POD jw/o POD w/ POD w/o POD FWLC TOTAL
-1.OOE-14
-1.OOE-14
-1.OOE2-1 5
-1.OOE-15 RCIC High LOCA None Low 0
2 2
-5.40E-1 2
-5.40E-12
-5.40E-13
-5.40E-13 RCIC High PLOCA None Low 0
1 1
-5.002-15
-5.002-15
-5.002-16
-5.002-16 RCIC High BER None Low 5
0
-5 2.50E-12 2.502-12 2.50E-1 3 2.50E-13 RCIC Low Class 2 N/A Assume Medium 4
0
-4 4.002-11I 4.002-1 1 4.002-1 2 4.002-12 RCIC TOTAL
__________3.71 E-11 3.71 E-1 1 3.71 E-1 2 3.71 E-1 2 CGC.
Low Class 2 N/A Assu~me Medium 3
0
-3 3.002-1 1 3.OOE-11I 3.002-12 3.002-12 CGC TOTAL__________
3.OOE-11I 3.OOE.11 3.0012-12 3.OOE-12 RWCU High LOCA None Low 11 10
-1 2.70E-12.
2.70E-12 2.70E-1 3 2.70E-13 RWCU High ILOCA None Low 8
2
-6 3.002-12 3.OOE-12 3.00E-13 3.002-13 RWCU High BER None Low 2
2 0
0.00E+00 0.002+00 0.002+00 0.00E+00 RWCU High Class 2 None Low 0
0 0
0.002+00 0.002+00 0.002+00 0.002+00 RWCU Low Class 2 N/A Assume Medium 0
0 0
0.002+00 0.002+00 0.002+00 0.002+00 RWCU TOTAL 5.70E-12 5.70E-12 5.70E-1 3 5.70E-13 GRAND
-2.89E-10 1.35E-09
-2.89E-11I 1.35E-10 TOTAL Notes
- 1. Systems are described in Table 3.1.
- 2.
Only those ASME Section XI Code inspection locations that received a volumetric examination in addition to a surface examination are included in the count. Inspection locations previously subjected to a surface examination only were not considered in accordance with Section 3.7.1 of EPRI TR-1 12657.
Page 24 of 28
Notes for Table 3.4.1 (Cont'd)
- 3. Inspection locations selected for RIS-B purposes that are in the plant's augmented inspection program for IGSCC are subject to the requirements provided below dependent upon other damage mechanisms identified. These requirements dictate how these inspection locations are accounted for in the risk impact analysis.
- i.
TACSC, TT, (IGSCC) and TT, (IGSCC) Damage Mechanism Combinations - these inspection locations are susceptible to thermal fatigue damage mechanisms in addition to IGSCC. In these cases, inspection locations selected for examination by both the IGSCC and RISB Programs should be included in both counts, but only those locations that were previously being credited in the Section XI Program and are now being credited in the RISB Program. The examination performed for IGSCC is judged adequate to have detected the other damage mechanisms subsequently identified by the RIS_B Program. For the GGNS RIS-B application, four of these inspections locations were selected for examination per the plant's augmented inspection program for IGSCC and for RISB1 purposes due to the presence of other damage mechanisms. These four inspection locations were previously credited in the Section XI Program.
ii.
None (IGSCC) Damage Mechanism - these inspection locations are susceptible to IGSCC only. In these cases, inspection locations selected for examination by both the IGSCC and RIS B Programs should be included in both counts, but only those locations that were previously credited in the Section XI Program and are now being credited in the R15.SB Program. For the GGNS RIS B application, eight of these inspection locations were selected for examination per the plant's augmented inspection program for IGSCC and are being credited for RISB ~purposes. Of these eight inspection locations, six were previously credited in the Section XI Program.
Page 25 of 28
Table 5 Inspection Location Selection Comparison Between ASMVE Section X1 Code and Code Case N-716 System~1l)
Safety Significance Break Location Failure Potential ICode IWeld Section XI Code Case N-716 yJ High J
Low DMs Rank Category Count Vol/Sur Sur Only~ RIS-B LOtheP2 RPV VLOCA TASCS, TT, (IGSCC)
Medium (Medium)
B-F 6
6 0
4 (3)
B-F 1
1 0
Medium (Medium)
B.-J 1
1 0
Low (Medium)
B-J 60 60 0
0 B-F 6
6 0
0 RPV VLOCA None Low
-1 11 0
0 B-J 5
5 0
0 FW VLOCA TASCS, TT Medium B-J 60 18 0
9 FW VILOCA TASCS, iT Medium B-J 10 8
2 7
FW VBER TASCS, iT Medium C-F-2 10 1
0 3
FW VILOCA TASCS Medium B-J 4
0 4
4 FW VLOCA TT Medium B-J 3
2 0
3 FW VILOCA None Low B-J 4
0 1
0 FW VBER None Low C-F-2 17 1
0 0
MIS Ve LOCA None Low B-J 107 9
4 4
MIS VILOCA None Low B-J 64 8
34 0
MS VPLOCA None Low B-J 2
0 2
0 MS VBER None Low C-F-2 20 2
0 0
SD VLOCA None Low B-J 37 0
4 4
SD VILOCA None Low B-J 4
0 0
0 0
Low (Medium)
B-J 25 6
0 8~
(4 RCR VLOCA None Low B-J 161 38 4
12 RCR VPLOCA None Low B-J 8
0 4
0 Page 26 of 28
Table 5 Inspection Location Selection Comparison Between ASMVE Section XI Code and Code Case N-716 Ssel)Safety Significance Bra oainFailure Potential 1Code Weld Section XIlCode Case N-716 High Low
~
oain DMs J
Rank JCategory Count tVol/Sur Sur Onlyl RIS-B LOtheP2 CRD VClass 2
N/A Assume Medium C-F-2 63 5
0 0
SLC VLOCA None Low B-J 5
0 0
4 SLC VPLOCA None Low 13-J 37 0
4 1
RHR VBER TT, CC Medium C-F-2 4
0 0
1 RHR VBER UT Medium C-F-2 13 4
0 4
RHR VLOCA None Low B-J 24 8
0 7
RHR VPLOCA None Low B-J 55 10 0
1 RHR VBER None Low C-F-2 18 3
0 0
RHR V/
Class 2 N/A Assume Medium C-F-2 500 32 2
0 LPCS VLOCA None Low B3-J 7
4 0
3 LPCS VPLOCA None Low B-J 25 4
0 1
LPCS VClass 2
N/A Assume Medium C-F-2 64 5
0 0
3 0
2 HPCS VLOCA None Low B-J 8
3 1
2 HPCS VPLOCA None Low B-J 30 2
0 1
HPCS VClass 2
N/A Assume Medium C-F-2 82 6
0 0
MSLC VILOCA None Low B-J 31 0
1 4
FWLC VPLOCA None Low B-J 11 0
0 2
RCIC VLOCA None Low B-J 7
0 0
12 RCIC VPLOCA None Low B-J 5
0 0
1 RCIC VBER None Low C-F-2 12 5
0 0
RCIC VClass 2
N/A Assume Medium C-F-2 107 4
0 0
CGC V
Class 2 N/A Assume Medium
-1 3
3 0
0 II C-F-2 5
0 0
0-RWCU j
V J
LOCA None I
Low
[
B-J 165 11 11 101 Page 27 of 28
.Table 5 Inspection Location Selection Comparison Between ASME Section Xl Code and Code Case N-716 SystemUl Safety Significance
-Break Location Failure Potential Code Weld ISection XI Code Case N-716 High Low DMs Rank Category Count Vol/SurSur Only RIS-B Othe r(2 )
RWCU ILOCA None Low B-J 25 8
0 2
B-J 4
0 0
0 RWCU IBER None Low CF2 2
Class 3 11 0
0 2
Other 1
0 0
0-RWCU Class 2 None Low B-_J (5) 3 0
0 0
RWCU e
Class 2 NIA Assume Medium IC-F-2 2
0 0
0 Notes
- 1. Systems are described in Table 3.1.
- 2. The column labeled "Other" is generally used to identify plant augmented inspection program locations credited per Section 4 of Code Case N-716. Code Case N-716 allows the existing plant augmented inspection program for IGSCC (Categories B through G) to be credited toward the 10% requirement. GGNS selected a 10% sampling without relying on IGSCC Program locations beyond those selected for RIS...B purposes either due to the presence of other damage mechanisms, or where no other damage mechanism is present. The "Other" column has been retained in this table solely for uniformity purposes with other RIS-B application template submittals.
- 3. These four piping welds have been selected for examination per the plant augmented inspection program for IGSCC (Category C) and for RIS-.B purposes due to the presence of other damage mechanisms.
- 4. These eight piping welds have been selected for~examination per the plant augmented inspection program for IGSCC (Category B) and are being credited for RIS..B purposes.
- 5. Although this piping classifies as Class 2 piping, GGNS conservatively treats it (i.e. NDE) as examination cat egory B-J for inspection purposes.
Page 28 of 28
ENCLOSURE 2 CNRO-2006-00043 ASME CODE CASE N-716
CASE N-716 CASES OF ASNIE BOILER AND PRESSURE VESSEL CODE Approval Date: April 19, 2006 The ASME Boiler and Pressure Vessel Standards Committee took action to eliminate Code Case expiration dates effective March 11, 2005. This means that all Code Cases listed in this Supplement and beyond will remain available for use until annulled by the ASME Boiler and Pressure Vessel Standards Committee.
Case N-716 Alternative Piping Classification and Examination Re-quirementsSection XI, Division 1 Inquiry: What alternative to the requirements of IWB-2420, IWB3-2430, and IWB-2500 (Examination Cat-egories B-F and B-i) and IWC-2420, IWC-2430, and IWC-2500 (Examination Categories C-F-I and C-17-2),
or as additional requirements for Subsection IWD, may be used for inservice inspection and preservice inspection of Class 1, 2, 3, or Non-Class piping?
Reply: It is the opinion of the Committee that the following requirements may be used in lieu of the require-mnents of IWB-2420, IWB-2430, Table IWB-2500-1 (Examination Categories B-F and 1-4), IWC-2420, IWC-2430, and Table IWC-2500-1 (Examination Cate-gories C-F-I and C-F-2) for inservice inspection of Class I or 2 piping and IWB-2200 and IWC-2200 for preservice inspection of Class I or 2 piping, or as additional require-ments for Class 3 piping or Non-Class piping, for plants issued an initial operating license prior to December 31, 20MX.
I SCOPE The scope shall include Class I and 2 piping as identi-fled in IWB-1200 and IWC-1200, Components Subject to Examination. The provisions of this Case may define additional requirements for Class 3 or Non-Class piping.
2 GENERAL REQUIREMIENTS (a) Welds shall be assigned a category that shall be used to determine thle treatment requirements of this Case.
High safety significant welds consist of welds that are (1) Class I portions of the reactor coolant pressure boundary (RCPB), except as provided in (c)(2)(i) and (c)(2)(ii) of Title 10 of the U.S. Code of Federal Regula-tions (10 CFR), Part 50.55a (2) applicable portions of the shutdown cooling pressure boundary function shall be included. That is, Class I and 2 wvelds of systems or portions of systems needed to utilize the normal shutdown cooling flow-path either (a) as part of the RCPB from the reactor pressure vessel (RPV) to the second isolation valve (i.e., farthest from the RPV) capable of remote closure, or to the con-tainment penetration, whichever encompasses the larger number of welds, or (b) other systems or portions of systems from the reactor pressure vessel (RPV) to the second isolation valve (i.e., farthest from the RPV) capable of remote closure or to the containment penetration, whichevcr encompasses the larger number of welds.
(3) that portion of the Class 2 feedwater system 1> NPS 4 (DN 100)] of pressurized water reactors (PWRs) from the steam generator to the outer containment isola-tion valve, (4) piping within the break exclusion region INPS 4 (DN 100)] for high energy piping systems I as defined by the Owner, and (5) any piping segment whose contributions to core damage frequency is greater than IE-06 based upon a plant-specific probabilistic risk assessment (PRA) of pres-sure boundary failures (e.g., pipe whip, jet impingement, spray, and inventory losses). This may include Class 3 or Non-Class piping. The PRA quality basis shall be NURE-G-0800, 3.6.2 provides a method for defining this scope of piping.
The Committee's function is to establish rules of safety, relating only to pressure integrity, governing the construction of boilers, pressure vessels, transport tanks and nuctear oM ponents, and inservice inspection for pressure integrity of nuclear components and transport tanks, and to interpret these rules when questions a rise regarding theoir intent. This Code does not address other safety issues relating to the construction of boilers, pressure vessels, transport tanks and nuclear components, and the inseniice inspection of nuclear components and transport tanks. The user of the Code should refer to other pertinent codes, standards, laws, regulations or other relevant documents.
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CASE (continued)
N-716 CASES OF ASNIE BOILER AND PRESSURE VESSEL CODE reviewed to confirm it is applicable to the high safety significant categorization of this Case. 2 (b) Low safety significant welds shall include all other Class 2, 3, or Non-Class welds not classified as high safety significant in accordance with this Case.
3 PRESERVICE EXAMINATION REQUIREMENTS Welds classified as high safety significant require pre-service inspection. The examination volumes, techniques, and procedures shall be in accordance with Table I.'
Welds classified as low safety significant do not require preservice inspection.
4 INSERVICE INSPECTION REQUIREMENTS Low safety significant welds arc exempt from the volu-metric, surface, VT-I, and VT-3 visual examination re-quirements of Section Xl. Ten percent of the high safety significant welds shall be selected for examination. The examination requirements for these locations are defined in Table I. The existing plant FAC inspection program and localized corrosion inspection program, excluding crevice corrosion (per Table 2), shall not be credited toward the 10% requirement. The existing plant IGSCC (Categories B through G) inspection program may be credited towvard the 10% requirement, provided the re-quirements of this Case are met. Selection of welds for examination shall be as follows:
(a) The susceptibility of each high safety significant item to the degradation mechanisms listed in Table 2 shall he determined. High safety significant welds shall be assigned an item number in Table I based upon the results of the degradation mechanism evaluation. High safety significant welds identified as not susceptible shall be assigned to Item No. 111.20 of Table 1.
(b) Examinations shall be prorated equally among sys-tems to the extent practical, and each system shall individ-uially meet the following requirements:
2 If there is a previously approved, risk-inrornied inservice inspection (RI-IS!) program, the PRA quality basis for thiat application shall be reviewed to confirm it is appticable to the high safety significant catego-rization (if this Case. if there is no approved RI-ISI program) at the plant, where the regulatory authority having jurisdiction at the plant site has already accepted the use or the PRA in the RI-ISI application.
the Owner shall review the results of previous independent reviews of the PRA (including regulatory authority review) and ensure that any comments that could influence the results of the categorization are incorporated or otherwise dispositioned. EPRI TR-1006937. "Extension of the EPRI RI-IS! Melthodology to Break Exclusion Region (BER)
Programns." Rev. 0-A, provides an acceptable approach for conducting this review.
(1) A minimum of 25% of the population identified as susceptible to each item number and item number combination (e.g., R1.l I1 and RI 11.16) shall be selected.
excluding Item Nos. 111.18 and R1.20.
(2) If the examinations selected above exceed 10%
of the total number of high safety significant welds, the examinations may be reduced by prorating among each item number and item number combination, to the extent practical, such that at least 10% of the high quality sig-nificant population is inspected.
(3) If the examinations selected above are not at least 10% of the high safety significant weld population, additional welds shall be selected so that the total number selected for examination is at least 10%. The additional welds may be selected from any item number of Table I, including RI.20, within the limitations of (4)(c), (4)(d),
(4)(e), (4)(f), and (5).
(c) For the RCPB, at least two-thirds of the examina-tions shall be located between the first isolation valve (i.e.,
isolation valve closest to RPV) and the reactor pressure vessel.
(d) A minimum of 10% of the welds in that portion of the RCPB that lies outside containment (e.g., portions of the main feedwater system in BWRs) shall be selected.
(e) A minimum of 10% of the welds within the break exclusion region shall be selected.
(f When selecting welds for examination, the follow-ing shall be considered:
(1) plant-specific cracking experience (2) weld repairs (3) random selection (4) minimization of worker exposure 5
CIIANGE-IN-RISK EVALUATION A change-in-risk evaluation shall be performed prior to the initial implementation of this Case.
(a) Bounding Failure Frequency. The failure frequten-cies of 213-06 per weld-year for welds in the high failure potential category, 2E-07 per weld-year for welds in the medium failure potential category, and I E-08 per weld-year in the low failure potential category may be used as bounding failure frequencies as defined in Table 3.
(b) Conditional Risk Estimates. The estimated condi-tional core damage probability (CCDP) and conditional large early release probability (CLERP) may be used if available. Bounding values of the highest estimated CCDP and CLERP may be used if specific estimates are not available.
(c) Thle followving general equations shall be used to estimate the change-in-risk. One estimate shall be mnade for (he change in core damage frequency (CDF) and one SIJPP 9 - NC 2 (N-716)
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I-M cn TABLE 1 EXAMINATION CATEGORIES 7
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1g.
0
'-I
________EXAMINATION CATEGORY R-A Examination Extent and Frequency (Note (3)]
Item Requirement/Fig. No.
Examination Acceptance 1st Successive Defer to End of No.
Parts Examined
[Note (2))
Method Standard Interval Intervals Interval 111.10 High Safety Significant Piping Structural Elements R1.11 Elements Subject to Thermal IWB-2500-8(c) [Note (1)]
Volumetric IWB-3514 Element [Notes (2), Same as Vt Not Permissible]
Fatigue IWB-2500-9, 10, 11
[Note (8))
(4))
R1.12 Not Used R1.13 Elements Subject to
[Note (6)]
Volumetric IWB-3514 Element [Note (2)]
Same as 1st Not Permissible jErosion-Cavitation (N ote (7))
[N ote (6)]
R1.14 Elements Subject to Crevice
[Note (5))
Volumetric IWB-3514 Element [Note (2))
Same as I' Not Permissible Corrosion Cracking
[Notes (9), (10))
R1.15 Elements Subject to Primary IWB-2500-8(c) [Note (1)]
Volumetric [Notes IWB-3514 Element [Notes (2), Same as I'Not Permissible Water Stress Corrosion IWB-2500-9, 10, 11 (7), (9), (10AJ (4)]
Cracking (PWSCC)
R1.16 Elements Subject to IWB-2500-8(c) [Note (1)]
Volumetric IWB-3514 Element [Notes (2), Same as it Not Permissible Intergranular or IWB-2500-9, 10, 11
[Notes (7), (9),
(4))
Transgranular Stress (10))
Corrosion Cracking (IGSCC or TGSCC)
-R1.17 Elements Subject to Localized IWB-2500-B(a)
Visual, VT-3
[Noate (6)]
Element [Note (2))
Same as Vt Not Permissible Corrosion [Microbiologically-IWB-2500-8(b)
Internal Surfaces Influenced Corrosion (MIC)
IWB-2500-8(c) or Volumetric or Pitting]
IWB-2500-9, 10, 11
[Notes (6) or (7)]
0 Z0
-'J I¶1.10 Eleeniits Subject TO HOW Accelerated Corrosion (FAC)
NI'ote M/L LRote %7j.J irite kmIi Ndote 17)J NIote 0i,1 N~ote Mij U),
C 0
TABLEl1 EXAMINATION CATEGORIES (CONT'D 0
J,
-C, 0
M EXAMINATION CATEGORY R-A I
Examination Extent and Frequency [Note (3)]
Item Requirement/
Examination Acceptance 1st Successive Defer to End of No.
Parts Examined Fig. No. [Note (21 Method Standard Interval Intervals Interval R1.19 Elements Subject to External IWB-2500-8(a),
Surface IWB-3514 Element [Note (2)] Same as I't Not Permissible Chloride Stress Corrosion IWB-2500-8(b),
Cracking (ECSCC)
IWB3-2500-8(c),
IWB-2500-9, 10, 11 R1.20 Elements Not Subject to a IWBl-2500-8(c)
Volumetric IWB-3514 Element [Notes (2), Same as Vt Not Permissible Degradation Mechanism IWB-2500-9, 10, 11
[Notes (9), (10))
(4))]_______
NOTES:
(1)
The length of the examination volume shown In Fig. IWB-2500-8(c) shall be increased by enough distance [approximately 1/, in. (13 mm)] to include each side of the base metal thickness transition or counterbore transition.
(2)
Includes examination locations and Class 1 weld examination requirement figures that typically apply to Class 1, 2,.3, or Non-Class welds identified in accordance with 4 Inservice Inspection Requirements.
(3)
Includes essentially 100% of the examination location. When the required examination volume or area cannot be examined due to interference by another component or part geometry, limited examinations shall be evaluated for acceptability.
Acceptance of limited examinations or volumes shall not invalidate the results of the change-in-risk evaluation (see 5). Areas with acceptable limited examinations and their bases, shall be documented.
(4)
The examination shall include any longitudinal welds at the location selected for examination in Note (2). The longitudinal weld examination requirements shall be met for both transverse and parallel flaws within the examination volume defined in Note (2) for the intersecting circumferential welds.
(5) The examination volume shall Include the volume surrounding the weld, weld HAZ, and base metal, where applicable, In the crevice region. Examination should focus on detection of cracks initiating and propagating from the inner surface.
(6)
The examination volume shall include base metal, welds, and weld HAZ in the affected regions of carbon and low alloy steel, and the welds and weld HAZ of austenitic steel. Examinations shall verify the minimum wall thickness required. Acceptance criteria for localized thinning is in the course of preparation. The examination method and examination region shall be sufficient to characterize the extent of the element degradation.
(7)
In accordance with the Owner's existing programs, such as PWSCC, IGSCC, MIC, or FAC programs, as applicable.
(8)
Socket welds of any size and branch pipe connection welds NPS 2 CON 50) and smaller selected for examination require a volumetric examination of the piping base metal within 1/2 in. (13 mm) of the toe of the weld, and the fitting itself shall receive a VT-2 visual examination.
(9)
Socket welds of any size and branch pipe connection welds N PS 2 (ON 50) and smaller require only a VT-2 visual examination.
For PWSCC susceptible locations, the insulation shall be removed.
(10) VT-2 visual examinations shall be conducted during a system pressure test or a pressure test specific to that element or segment, in accordance with IWA-5000, IWB3-5000, IWC-5000, or IWD-5000, as applicable, and shall be performed during each refueling outage or at a frequency consistent with the time (e.g., 18 to 24 months) between refueling outages.
Ell II" ci"
CASE (continued)
N-716 CASES OF ASIME BOILER AND PRESSURE VESSEL CODE TABLE 2 DEGRADATION MECHANISMS Mechanisms Attributes Susceptible Regions TF TASCS piping > NPS 1 (ON 25) nozzles, branch piping
-piping segment has a slope < 45 deg from horizontal (includes elbow or tee connections, safe ends, welds, into a vertical pipe) heat affected zones (HAZ),
-potential exists for a low flow in a piping section connected to a component base metal, and regions of allowing mixing of hot and cold fluids, or potential exists for leakage flow past stress concentration a valve (i.e., in-leakage, out-leakage, cross-leakage) allowing mixing of hot and cold fluids, or potential exists for convection heating In dead-ended piping sections connected to a source of hot fluid, or potential exists for two phase (steambiater) flow, or potential exists for turbulent penetration in branch piping connected to header piping containing hot fluid with high turbulent flow
-calculated or measured AT> 50*F (28*00
-Richardson number > 4.0 TT
-operating temperature > 270'F (130'C) for stainless steel, or operating temperature > 220OF (10500) for carbon steel
-potential for relatively rapid temperature changes including cold fluid injection Into hot pipe segment, or hot fluid Injection into cold pipe segment
-I All1> 200*F (110'C) for stainless steel, or I A T11> 150OF (83*0) for carbon steel, or I A TI > A Tallowable (applicable to stainless and carbon)
SCC IGSCC evaluated In accordance with existing plant IGSCC program per NRC Generic austenitIc stainless steel welds (BWR)
Letter 88-01, or alternative (e.g., BWRVIP-075) and HAZ IGSCC operating temperature > 200*F (93'0)
(PWR) susceptible material (carbon content ý 0.035%)
tensile stress (including residual stress) is present oxygen or oxidizing species are present OR operating temperature < 200'F (93'C), the attributes above apply Initiating contaminants (e.g., thiosulfate, fluoride, chloride) are also required to be present TGSCC operating temperature > 150'F (65*C) austenitic stainless steel base tensile stress (including residual stress) is present metal, welds, and HAZ halides (e.g., fluoride or chloride) are present, or caustic (NaOH) is present oxygen or oxidizing species are present (only required to be present in conjunction with halides, not required with caustic)
ECSCC operating temperature > 150YF (65*0) an outside piping surface is within five diameters of a probable leak path (e.g.,
valve stems) and is covered with nonmetalic insulation that is not in compliance with Reg. Guide 1.36, or an outside piping surface is exposed to wetting from concentrated chloride-bearing environments (e.g., seawater, brackish water, brine)
PWSCC piping or weld material is U NS N06600, tJ06082, or W86182 nozzles, welds, and HAZ without exposed to primary water at T> 570'F (300'0) stress relief the material is mill-annealed and cold-worked, or cold-worked and welded without stress relief LC MIC operating temperature < 150'F (6500) fittings, welds, HAZ, base metal, low or intermittent flow dissimilar metal joints (e.g.,
pH < 10 welds, flanges), and regions presence/intrusion of organic material (e.g., raw water system), or water containing crevices source is not treated with biocides (e.g., refueling water tank)
PIT potential exists for low flow oxygen or oxidizing species are present Initiating contaminants (e.g., fluoride, chloride) are present cc crevice condition exists (e.g., thermal sleeves) operating temperature > 150*F (65*0) oxygen or oxidizing species are present POF RELEASE 5 (N-716)
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CASE (continued)
N-716 CASES OF ASNIE BOILER AND PRESSURE VESSEL CODE TABLE 2 DEGRADATION MECHANISMS (CONT'D)
Mechanisms Attributes Susceptible Regions FS E-C existence of cavitation source (i.e., throttling or pressure reducing valves or fittings, welds, HAZ, and base orifices) metal operating temperature < 250'F (120*C) flow present > 100 hr/yr velocity > 30 fl~s (9.1 m~s)
(Pd-P,)/AP< 5 where, Pd = static pressure downstream of the cavitation source, P, = vapor pressure, and AP = pressure difference across the cavitation source FAC 7
evaluated in accordance with existing plant FAC program Fper plant FAC program LEGEND:
Thermal Fatigue (TF)
Thermal Stratification, Cycling, and Striping (TASCS)
Thermal Transients (TT)
Stress Corrosion Cracking (SCC) lntergranular Stress Corrosion Cracking (105CC)
Transgranular Stress Corrosion Cracking (TG SCC)
External Chloride Stress Corrosion Cracking (ECSCC)
Primary Water Stress Corrosion Cracking (PWSCC)
Localized Corrosion (LC)
Microbiologically-Influenced Corrosion (M IC)
Pitting (PIT)
Crevice Corrosion (CC)
Flow Sensitive (FS)
Erosion-Cavitation (E-C)
Flow-Accelerated Corrosion (FAC)
TABLE 3 DEGRADATION MECHANISM CATEGORY Failure Degradation Potential Conditions Category Degradation Mechanism High Degradation mechanism likely to
[Note (1)]
cause a large break Large Break Flow-Accelerated Corrosion Medium Degradation mechanism likely to Small Leak Thermal Fatigue, Erosion-cause a small leak Cavitation, Corrosion, Stress Corrosion Cracking Low None None None NOTE:
(1) Segments having degradation mechanism listed in the small leak category shall be upgraded to the high failure potential large/break category If the pipe segments also have the potential for water hamnmer loads.
for large early release frequency (LERF). Thle equations only illustrate the change in CDF. The change in LERF due to application of the process shall be estimated by substituting the CLERP for CCDP in the equations.
Acor = -j (Irj -
iej)
- PFj
- CCDPj where 2*= summation of locations selected for exam-ination ZIRCDF = change in CDF due to replacing the prior deterministic 1SI program with the IS[ pro-gram developed in accordance with this Case
,j= factor of reduction in pipe rupture fre-quency at location j associated wvith the IS[ program developed by this Case
,j= factor of reduction in pipe rupture fre-quency at location j associated with the prior deterministic 1ST program PFj = piping failure frequency at location] with-Otut examination CCDPj = conditional core damage probability at lo-cation]j In terms of probability of detection
[1101j = (I - 1j)], the eqluation becomes ARcI)I: = %j (PODj -
PQZ)rj)
- PF1
- CCDP, SUPP 9 - NC 6 (N-716)
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CASE (continued)
N-716 CASES OF ASINE BOILER AND PRESSURE VESSE1, CODE where PODqj = probability of detection at location j asso-ciated with the prior deterministic 1SI program POD~j = probability of detection at location]j asso-ciated with the IS1 program developed in accordance with this Case It is acceptable to use bounding estimates for pipe failure frequency, conditional core damage probability, and conditional large early release probability, to simplify the calculations. If the bounding estimates for pipe failure frequency and conditional probability are used, the equa-tion becomes:
ARCDF = [(POD,*Nef, - PODr*Nrfi)J*PFf *CCDPC wvhere POD,, = probability of detection in the existing 151 program (may be degradation mechanism specific)
Nef, = number of examination locations in the consequencef and failure frequency c cat-egories associated with the prior determin-istic ISI program PODr = probability of detection in the 1SI program developed by this Case (may be degrada-tion mechanism specific)
INrA. = number of examination locations in the consequencef and failuhre frequency c cat-egories associated with the 1ST program developed using this Case PFf =piping failure frequency for the high, me-dium, and low failure frequency estimates CCDP, = conditional core damage probability con-sequence estimates (d) Acceptance Criteria. Any increase in CDF and LERF for each system shallI be less than I E-07 per year and I E-08 per year, respectively, and the total increase in CDF and LERF should be less than I E-06 per year and I E-07 per year respectively. If necessary, additional examinations shall be selected to meet this acceptance criteria.
6 SUCCESSIVE INSPECTIONS AND ADDITIONAL EXAMINATIONS (at) Successive Inspections. As an alternative to the successive inspection requirements of IWB-2420, IWVC-2420, or IWD-2420, the following requirements shall be met.
(1) The sequence of piping examinations estab-lished during the first inspection interval using this Case shall be repeated during each successive inspection inter-val to the extent practical. The examination sequence may be modified to optimize scaffolding, radiological, insulation removal, or other considerations, provided the percentage requirements of Tables IWB-24 II 4-Ior IWB-2412-1 are met.
(2) If piping structural elements are accepted for continued service by analytical evaluation in accordance with IWB-3 132.4 or IWB-3 142.4, before, during, or after implementation of this Case, the areas containing flaws or relevant conditions shall be reexamined during the next three inspection periods.
(3) If the reexaminations required by 6(a)(2) reveal that the flaws or relevant conditions remain essentially unchanged for three successive inspection periods, the examination schedule shall revert to the original schedule of successive inspections.
(b) Additional Examinations. As an alternative to the additional examination requirements of IWB-2430, IWC-2430, or IWVD-243O, the following requirements shall be met. Additional examinations for Item No. RI1.18 are outside the scope of this Case.
(1) Examinations performed in accordance with Table I of this Case, excluding Item No. 111.18, that reveal flaws or relevant conditions exceeding the accept-ance standards of Table IWVB-34 10-I. shall be extended to include a first sample of additional examinations during the current outage.
(it) The piping structural elements (welds) to be examined in the first sample of additional examinations shall include 1-155 elements with the same postulated degrazdation mechanism in systems whose materials and service conditions are similar to the element that exceeded the acceptance standards.
(b) Thle number of examinations required is the number of HSS elements with the same postulated degra-dation mechanism scheduled for the current inspection period. If there are not enough H-SS elements to equal this number, the Owner shall include remaining HSS elements and LSS elements tip to and including this num-ber that are Subject to thle samne degradation mechanism.
(2) If thle additional examinations required by 6(b)(1) reveal flaws or relevant conditions exceeding the aicceptance standards of Table IWB-34 10-I1, the examina-tions shall be extended to include a second sample of additional examinations during the current outage.
(a) The second sample of additional piping struc-tUral elements to be examined shall include all remaining HSS piping structural elements in Table I subject to the same degradation mechanism.
(b) The Owner shall also examine LSS piping structural elements subject to the same degradation mech-anism or document the basis for their exclusion.
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CASE (continued)
N-716 CASES OF ASMIE BOILER AND PRESSURE VESSEL CODE (3) For the inspection period followving the period in which the examination of 6(b)(1) and 6(b)(2) were completed, the examinations shall be performed as origi-nally scheduled in accordance with IWVB-2400.
7 PROGRAM UPDATES Examination selections made in accordance with this Case shall be reevaluated on the basis of inspection peri-ods that coincide with the inspection program require-ments for Inspection Program A or B of IWA-2431I or IWA-2432, as applicable. For Inspection Program B, the third inspection period reevaluation wvill serve as the sub-sequent inspection interval reevaluation. The perform-ance of each inspection period reevaluation may be accel-erated or delayed by as much as one year. Each reevaluation shall consider the cumulative effects of pre-vious reevaluations. The reevaluation shall determine if any changes to the examination selections need to be made, by evaluation of the following:
(a) plant design changes (e.g.. physical: new piping or equipment installation; programmatic: power uprating!
18 to 24 month fuel cycle; and procedural: operating procedure changes)
(b) changes in postulated conditions or assumptions (e.g., check valve seat leakage is greater than previously assumed)
(c) examination results (e.g., discovery of leakage or flaws)
(di) piping failures (e.g., plant-specific or industry occurrences of through-wall or through-weld leakage, failure due to a new degradation mechanism, or a nonpos-tulated mechanism)
(e) PRA updates that would increase the scope of (2)(a)(5) (e.g.. new initiating events, new system func-tions, more detailed model used, and initiating event and failure data changes)
(f) the impact of 7(a) through 7(e) on the change-in-risk evaluation in 5 8
OWNER'S RESPONSIBILITY (a) The Owner shall determine the appropriate classi-fication for welds in accordance with the provisions of this Case.
(b) Personnel with expertise in the following disci-plines shall be included in this process. The Owner shall ensure adequate experience levels for each discipline.
This experience shall be documented and maintained by the Owner.
(1) probabilistic risk assessment (PRA)
(2) plant operations (3) design (4) safety accident analysis (c) The results of the application of this Case (e.g.,
determination of high safety significant weld, change-in-risk evaluation) shall be documented and reviewed.
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C DR.
ENCLOSURE 3 CNRO-2006-00043 LICENSEE-IDENTIFIED COMMITMENTS to CNRO-2006-00043 Page 1 of 1
'LICENSEE-IDENTIFIED COMMITMENTS TYPE (Check one)
SCHEDULED ONE-TIME CONTINUING COMPLETION COMMITMENT ACTION COMPLIANCE DATE Request for Alternative CEP-ISI-007 pertaining to the
/Upon NRC application of Code Case N-663 will be withdrawn for approval of use at GGNS upon NRC approval of the RISB GG-ISI-002 Program submittal.