BVY-97-137, Forwards Response to 971009 RAI Re Plans for Implementing ASME Code Case N560 at Vermont Yankee Nuclear Power Station

Forwards Response to 971009 RAI Re Plans for Implementing ASME Code Case N560 at Vermont Yankee Nuclear Power Station

ML20212B569
Person / Time
Site:	Vermont Yankee File:NorthStar Vermont Yankee icon.png
Issue date:	10/23/1997
From:	Reid D VERMONT YANKEE NUCLEAR POWER CORP.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
BVY-97-137, NUDOCS 9710280139
Download: ML20212B569 (114)

Text

_.

VERMONT YANKEE

.- pg )

NUCLEAR POWER CORPORATION 185 Old Ferry Road, Brattleboro, VT 05301 7002 (802) 257 5271 October 23,1997 BW 97137 United States Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

References:

(a) License No. DPR-28 (Docket No. 50 271)

(b) Letter WNPC to USNRC, BW 97 90, dated 8/6/97 (c) Letter, USNRC to WNPC, dated 10/9/97 Subsect:

Implementation of ASME Code Case N640 et Vermont Yankee Response to NRC Questions in Reference (c), NRC summarized a presentation meeting and subsequent telephone conference call detailing our plans for implementing ASME Code Case N560 at Vermont Yankee Nuclear Power Station Also described in Reference (c) were several comments and questions from the NRC staff that were to be answered by Vermont Yankee in support of our previous submittal, The enclosure to this letter provides the requested information for NRC staff review, We trust this information adequately answers your questions, however, should you require additional Information or clarification is required, please contact this office, Sincerely, VERMONT YANKEE NUCL R POWER CORP.

Dona.

A. Reid Sr. Vice President, Operations Enclosure

~f CC USNRC Region 1 Administrator h( QL-USNRC Resident inspector WNPS USNRC Project Manager - WNPS 9710280139g7 7g.

PDR ADOCK PDR P

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l RESPONSES TO REQUESTS FOR ADDITIONAL INFORMATION (RAls) FROM SEPTEMBER 17,1997 MEETING &

SEPTEMBER 23,1997 TELECON

1. SCOPE l1

1. PROVIDE WRITTEN DESCRIPTION OF TIIE SCOPE OF TIIE RELIEF REQUEST I1

2. PROVIDE WRITTEN DESCRIPTION OF WIIY LIMITING TIIE SCOPE TO CATEGORY B-J COMPONENTS IS ACCEPTABLE I1

3. PROVIDE WRITTEN DESCRIPTION OF IIOW EXEMPT PIPING IS ADDRESSED.

1-3

4. PROVIDE WRITTEN DESCRIPTION OF TIIE INTERACI' ION (OR LACK TIIEREOF) HETWEEN CLASS 1 AND CLASS 2 & 3 PIPING I-3

11. PRA/DG-1061 11-4

1. PROVIDE WRITTEN DESCRIPTION OF IIOW TIIE PROGRAM MEETS DRAFT REG GUIDE DG-1061 II-4

2. PROVIDE WRITI'EN DESCRIPTION OF TIIE EXTENT OF TIIE RELIANCE ON PRA NUMBERS AND TIIE QUALITY OF TIIE PRA II-8

3. PROVIDE WRITTEN DESCRIPTION OF TIIE EXTENT TO WIIICII INTERNAL FLOODING IMPACTS TIIE SELECTIONS II 9

4. PROVIDE WRITTEN DESCRIPTION AS TO IIOW DEFENSE IN DEPTIi, FOR EXAMPLE,TIIE DEFENSE IN DEPTII ASPECTS OF SBO,IS ADDRESSED (e.g. IIPCI, RCIC) 11 13

5. PROVIDE WRITTEN DESCRIPTION OF IIOW EXTERNAL EVENTS AI'E ADDRESSED (e.g. SEISMIC)

II-15

6. PROVIDE WRITTEN DESCRIPTION OF IIOW DEFENSE IN DEPTil IS ADDRESSED II-16

7. PROVIDE A DESCRIPTION OF TIIE ACTUAL REVIEW PROCESS WIIICII WAS UNDERTAKEN TO ASSURE TIIAT KEY INPUTS TO TIIE N560

- EVALUATION WERE NOT MISSED II-16 I

i e.

8. PROVIDE A DESCRIPTION OF TIIE INTERNAL AND EXTERNAL REVIEWS OF Tile VERMONT YANKEE PRA TIIAT WERE CONDUCTEDII-17 111. EVALUATIONMETilODOI.OGY 111-1 9 I. PROVIDE WRITTEN DESCRIPTION AS TO IIOW TIIE IMPACT OF UNKNOWN MECIIANISMS IS ADDRESSED III19

2. PROVIDE WRITTEN DESCRIPTION DESCRIBING TIIE INDEPENDENCE OF TIIE CONSEQUENCE AND DEGRADATION MECilANISM EVALUATIONS. SIIOW TilAT Ti!E CONSEQUENCE EVALUATION ASSESSES Tile SPECTRUM OF BREAK SIZES REG ARDLESS OF TIIE RESULTS OF TIIE DEGRADATION MECIIANISM EVALUATION III 27

3. PROVIDE WRITTEN DESCRIPTION AS TO TIIE EXTENT OF PREVIOUS CilEMISTRY EXCURSIONS AT VERMONT YANKEE AND TIIEIR IMPACT (IF ANY) ON TIIE ASSESSMENT 11128

4. PROVIDE WRITTEN DESCRIPTION OF TIIE BASIS FOR TIIE 10%

SELECTION CRITERIA III-28

5. PROVIDE WRI1 TEN DESCRIPTION OF Tile NUMBER OF CYCLES ASSUMED IN TIIE TIIERMAL FATIGUE SCREENING CRITERIA III30

6. REVIEW TIIE JUNE 12,1997 RAls ON TIIE EPRI METIlODOLOGY AND IDENTIFY WlIICII ONES ARE ADDRESSED BY TIIE VERMONT YANKEE SPECIFIC RAls FROM TIIE 9/23/97 MEETING III-30

7. PROVIDE A MORE DESCRIPTIVE PRESENTATION OF TIIE CONSEQUENCES METIIODOLOGY INCLUDING SEVERAL EXAMPLESIII-30

8. PROVIDE A DISCUSSION OF TIIE QUALITATIVE AND QUANTITATIVE BASIS FOR TABLE 2-2. SIIOW THAT BOTil BASES ARE CONSISTENTIII-33 JY. SEl.ECTIONS.

IV-37 I. PROVIDE WRITTEN DESCRIPTION OF THE INSPECTION METIIODS AND QUALIFICATION OF INSPECTION EQUIPMENT AND INSPECTION PERSONNEL IV-37

2. PROVIDE WRITTEN DESCRIPTION OF IIOW INSPECTION LOCATIONS WERE SELECTED PER SYSTEM IV-37

3. PROVIDE WRI1 TEN DESCRIPTION OF IIOW INSPECTION LOCATIONS WERE ALLOCATED AMONG SYSTEMS IV-38 ii

4. PROVIDE WRITTEN DESCRIPTION OF EACil LOCATION, WilETHER IT IS CURRENTLY BEING INSPECTED, WIIETHER IT WILL BE INSPECTED UNDER N560, OR NOT INSPECTED.

IV-41

5. PROVIDE WRITTEN DESCRIPTION OF THE EXAMINATION VOLUME FOR EACll LOCATION INSPECTED, CONTRAST Tile N560 VOLUME WITII TIIAT OF TIIE CURRENT PROGRAM IV-58

6. PROVIDE WRITTEN DESCRIPTION OF TIIE EXTENT TO WIIICII PDI, APPENDIX VIII. AND TIIE RELIABILITY OF DETECTION IS ADDRESSEDIV-58

7. PROVIDE WRITTEN DESCRIPTION OF THE VARIATION IN Tile INTENSITY OF AN INSPECTION (IF ANY) FOR INDIVIDUAL DEGRADATION MECilANISM (e.g. IGSCC vs. MIC)

IV-58

8. PROVIDE WRITTEN DESCRIPTION AS TO TIIE DESIRABILITY (OR LACK TilEREOF) OF INSPECTING RI',K CATEGORY 5 LOCATIONS _IV-59 Y. MONITORING V-60

1. PROVIDE WRITTEN DESCRIPTION OF MONITORING ATTRIBUTES AND RELIABILITY GOALS V-60

2. PROVIDE WRITTEN DESCRIPTION OF THE INSPECTION FREQUENCY AND OBSERVED DEGRADATION RATES V-60

3. PROVIDE WRITTEN DESCRIPTION OF HOW THE REDUCED NUMBER OF INSPECTIONS WILL NOT RESULT IN AN INCREASE IN LEAK RATESV-60

4. PROVIDE WPITTEN DESCRIPTION OF HOW AGING AND SERVICE INDUCED FAILv1RES ARE ADDRESSED V-61

5. PROVIDE WR1TTEN DESCRIPTION OF HOW THE NEW PROGRAM PROVIDES A MECriAMSM FOR TRACKING AND TRENDING OF PLANT SPECIFIC INDUSTRY DATA V-61

6. PROVIDE WRITTEN DESCRIPTION OF THE PROGRAM COMMITMENTS AND REVISIONS (i.e. FSAR, TECil SPEC, ETC.)

V-62 VI. IMPACT OFPROPOSED CHANGE VI-63

1. PROVIDE WRITTEN DESCRIPTION OF THE IMPACT ON CDF AND LERF OF THE PROPOSED CHANGE VI-63 iii

2. PROVIDE WRITTEN DESCRIPTION OF TIIE RISK IMPACT ON PLANT SAFETY VI-65

3. PROVIDE WRITTEN DESCRIPTION OF TIIE NEG ATIVE IMPACT (IF ANY) ON INTERSYSTEM LOCA IF Tile NUMBER OF INSPECTIONS IS REDUCED FROM 25% TO 10%

VI-65

4. PROVIDE WRilTEN DESCRIPTION OF Tile NEGATIVE thiPACT,IF ANV, ON CLASS 2 AND 3 PIPING ISI AS A RESULT OF TIIE PROPOSED CIIANGEVI-66

5. PROVIDE WRITTEN DESCRIPTION OF THE IMPACT ON OTIIER INSPECTION PROGRAMS SUCli AS IGSCC ( GENERIC LETTER 88-01) VI-66

6. PROVIDE WRilTEN DESCRIPTION OF TiiE IMPACT ON ACCIDENT MITIGATING SYSTEM (I.E. ASME CLASS 2) AND SUPPORT SYSTEMS (i.e.

ASME CLASS 3)

VI-67 iv 9

RESPONSES TO REQUESTS FOR ADDITIONAL INFORMATION (RAls) FROM SEPTEMBER 17,1997 MEETING SEPTEMBER 23,1997 TELECON 1.

SCOPE 1.

PROVIDE WRITTEN DESCRIPTION OF Tile SCOPE OF TIIE RELIEF REQUEST The scope of the N560 submittal encompasses all Class 1 examination category B-J piping welds excluding socket welds. The in service inspection program for all other Class 1 piping welds (e.g. examination category B-F) is unchanged, t

I 2.

PROVIDE WRITTEN DESCRIPTION OF WIIY LIMITING TIIE SCOPE TO CATEGORY B J COMPONENTS IS ACCEPTABLE This RAI raises two issues: 1) risk coverage due to the limited evaluation scope and 2) what information pertaining to out of scope piping (e.g. Class 2 or 3) is lost by reducing the number ofinspections in the N560 scope (or what negative impact can Class I piping that is no longer being tracked or trended by N560 have on Class 2 & 3 piping).

The issue of risk coverage (Item #1) is addressed as follows:

If the change to the N560 scope ofinspections is proven to result in a risk reduction (or risk neutrality) due to pressure boundary failures within the N560 scope ofinspections, and if this change does not have a negative impact on other non-N560 piping / inspections (see Item #2), then the overall change in risk will be the same (i.e. risk reduction or neutrality).

The issue of focused scope evaluations / applications has been brought up at a number ofindustry/NRC/ACRS meetings, including the latest NRC workshop on risk-informed regulation. Consensus has been that if the application improves availability and performance (i.e. risk reduction or neutrality) and does not adversely impact other systems or components, then these focused applications are acceptable.

1-1 V

From a historical perspective, the existing ASME Section XI requirements are defined separately and independently for each class ofpiping (i.e. Class 1

. requirements are defined independently of Class 2 requirements).

As to issue #2, the interaction and/or commonality between Classes of piping are a result of several factors as follows:

A. Material incompatibilities that can occur when different piping classes are

joined, B. spatial interaction, as when piping at a higher elevation leaks upon piping -

at a lower elevation, and C. environmental factors such as radiation, temperature, humidity and water chemistry control.

Item A is a result of thejoining (welding) of two materials that are chemically incompatible either in their final form (i.e. the completed weld joint) or during the welding process. This incompatibility can also be the iesult of the addition of inappropriate material during the welding process itself(e.g. inappropriate weld rod).

Vermont Yankee has replaced essentially all stainless steel Class 1 piping with IGSCC resistant material. Fabrication and installation processes used during this effort were defined so that this type ofincompatibility is avoided. The N560 degradation mechanism evaluation process specifically addresses material compatibility as an attribute in identifying a location's susceptibility to degradation. This is an improvement in identifying candidate locations for inspection over the existing code requirements, item B is typified by external chloride corrosion cracking (ECCC) of stainless steel piping. One cause of ECCC is the wetting ofinsulation containing an t

unacceptable level of chlorides. This wetting causes the chlorides to leach out and attack the subject piping. Typically, the cause of the wetting is a leaking valve stem or flanged connection. The subject piping can be the insulated piping itself or it can be adjacent and physically lower piping.

For Vermont Yankee, ECCC is not a concern as piping insulation meets the intent of Reg Guide 1.36.

Environmental factors (Item C) which impact piping reliability vary from Class 1 piping to Class 2,3 and BOP piping. Class 1 piping materials tend to be of different typs and quality than other piping. Water chemistry control is a critical parameter in minimizing a piping system's potential for degradation. Water chemistry is strictly controlled for the Class I systems and connected non-Class 1 1-2

systems stah as condensate. Other non Clasr I systems such as component cooling water, service water, and extraction steam see significantly different operating environments. As sudt, tracking and trending environmental factors for Class 1 piping reliability has minimal benefit in understanding Class 2,3 or BOP piping reliability.

3.

PROVIDE WRITTEN DESCRIPTION OF IlOW EXEMPT PIPING IS ADDRESSED.

Per article IXB-1220(a) of Section XI of the ASME Boiler and Pressure Vessel Code (B&PVC), components may be exempi from volumetric and surface examination if the rupture flow produced is within the capacity of makeup systems which are operable from on-site emergency power. For Vermont Yankee, this paragraph results in pipe sizes of 2 inch NPS and less for water piping and 1-1/2 inch NPS and less for steam piping being excluded from volumctric and l

surface examinations. This piping is still required to receive pressure and leak testing examination.

I l

As part of the Vermont Yankee N560 evaluation, all piping greater than 1 inch NPS was included. The intent of this evaluation was to assure that no high risk piping was being arbitrarily excluded from examination. The results of this evaluation are that there are no high risk locations in the exempt population. In addition, the vast majority of these location are socket welded connections and, therefore, outside the scope of the N560 evaluation.

4.

PROVIDE WRITTEN DESCRIPTION OF TIIE INTERACTION (OR LACK TIIEREOF) BETWEEN CLASS 1 AND CLASS 2 & 3 PIPING The issue raised by this RAI is addressed by our response to SCOPE, RAI 2.

1-3

II.

PRA/DG-1061

-1.

PROVIDE WRITTEN DESCRIPTION OF IlOW TIIE PROGRAM MEETS DRAFT REG GUIDE DG-1061 I

Draft Guide 1061, as well as Drafi SRP Chapter 3.9.8 (Standard Review Plan For The Review Of Risk-Informed In-service Inspection of Piping and Draft Regulatory Guide DG-1003 (An Approach For Plant Specific, Risk-Informed Decision Making: Inspection of Piping), identified five principles of risk-informed regulations. They are:

l. Meet curret regulations,

2. Maintain defense in depth,

3. Maliaain sufficient safety margins,

4. Proposed increase in risk (including cumulative effects) is small, NRC safety goals are not exceeded, and

5. - Performance-based implementation and monitoring strategies.

Principle #1: Meet Current Regulations 10CFR50.55a and Appendix A to 10CFRPart50 are the primary regulations goveming inservice inspertion of piping. The intent of these regulations, as it pertains to the N560 scope of piping, is to assure a robust reactor coolant pressure boundary. Via reference in 10CFR50.55a, Section XI to 'he ASME B&PV Code, is the implementing vehicle for these inspections. Code Case N560 is an ASME approved alternative to current Section XI requirements.

Other Section XI inspection activities such as the examination of Class I socket welded connections and dissimilar metal welds, pressure and leak testing requirements, Class 2 and 3 piping examinations, are not adversely a

'ted by r

implementation of N560.

In addition to the other Section XI activities not adversely impacted by the implementation of N560 are the augmented inspection programs, such as in response to Generic Letter 88-01 (NRC Position on IGSCC in BWR Austenitic SS piping) and Generic Letter 89-08 (Erosion / Corrosion Induced Wall Thinning).

Other plant programs, which are not strictly inspection driven but can have a dominant impact on assuring piping reliability, include the primary water chemistry control program, reactor coolant leakage, drywell and feedwater nozzle monitoring efforts all of which are unaffected by implementation of Code Case N550.

114

Principle #2: Maintain Defense in Depth The intent of the inspections mandated by ASME Section XI for category B.J.

piping welds is to identify conditions such as flaws or indications that may be precursors to leaks or ruptures in the reactor coolant pressun, 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 ofIn service Inspection Requirements for Class 1, Category B.J Pressure Retaining Welds in Piping), this method has been ineffective in identifying leaks or failures. In response to these rmdings ASME issued Code Case N560, which has a much more robust selection process founded on actual service experience with nuclear plant piping failure data.

The N560 selection process has two key ingredients. Those are 1) a determination of each location's susceptibility to degradation and 2) an assessment of the consequence of the location's failure. These two ingredients not only assure defense in depth is maintained, but actually increased over the current process.

First, by evaluating a location's susceptibility to degradation, the likelihood of finding flaws or indications that may be precursors to leaks or ruptures in the reactor coolant pressure boundary is increased. Secondly, the consequence assessment effoit has a single failure criterion so that, no matter how unlikely a failure scenario is, it is ranked high if, as a result of the failure, there is no mitigative equipment available to respond to the event. In addition, the consequence assessment takes into account equipment reliability so that poor performing equipment is not credited as much as more reliable equipment.

Additional detail on defense-in-depth principles is provided in our responses to RAI 4 and RAI 6 of this section.

Principle #3: Maintain Suflicient Safety Margins The safety function ofinterest in this evaluation is that ofreactor coolant pressure boundary integrity. Listed below are those attributes necessary for fulfilling this requirement, as well as the impact of N560 on meeting the objective:

1. Quality Design - No Change

2. Quality Fabrication-No Change

3. Quality Construction-No Change

4. - Quality Testing - No Change

5. Quality Inspection - Fewer inspections conducted at more appropriate locations using better techniques and, as necessary, expanded volumes.

In addition, augmented inspection programs, such as IGSCC and FAC will continue.

II-5

As can be seen from the a' bove summary, those attributes that are critical in

' defining and maintaining sufficient safety margins are unchanged except for a subset of the pressure boundary volumetric examinations. In this case, the augmented programs will continue, and the reduced number of volumetric Section XI exams are based upon the exceptional performance history of cate<,ry B J components, In addition, the new Section XI locations are more appropriate, usually involve larger inspection volumes, and will have better inspections conducted.

Principle H: Proposed increase in risk (including cumulative efrects) is small,

- NRC safety goals are not exceeded This issue was addressed in two ways. The first way was a direct comparison of the old Section XI Program to the N560 recommended inspection. This comparison accounted for the Conditional Core Damage Probability (CCDP) of each segment, its failure potential, and the impact of the inspection reliability.

For this case, where the N560 inspection provides for a better inspection, credit is given in the form of a higher probability of detection.

The second way accounted for the CCDP of each segment and its failure potential, but did not credit the positive aspects of the N560 selection process and associated inspection for cause techniques. This assessment assumes that every segment within a risk category (e.g. Risk Category 2) had the highest identified CCDP for that category. This conservative estimate is then compared to the DG 1061 criteria for acceptability.

The results of this assessment, which are provided in the response to IMPACT OF PROPOSED CHANGE, RAI 1, are that the N560 application provides a net positive safety impact, even with a reduction in sampling locations from 25% to 10%. This is primarily due to three factors: 1) most importantly, inspection personnel will now inspect locations susceptible to degradation, as opposed to the current Section XI inspection locations which are essentially randomly chosen,

2) the inspection techniques and qualification of personnel assure that the inspection personnel will be finely attuned to the mechanism ofinterest when conducting the examinations, and 3) the volumes inspected by the N560 Program -

are, on average, larger than typical Section XI examination volumes. (See response to SELECTIONS, RAI 5) In summary, implementation of the N560 Program will result in a safety improvement.

Even when conservative estimates of the impact of N560 are used (neglecting the positive impact of the N560 selection process and inspection for cause philosophy), the impact on risk is negligible. Calculated values are orders _of magnitude below DG-1061 acceptance criteria of 1E-06/yr. Applications of this magnitude are considered risk neutral.

II-6

Principle #5: Performance-based implementation and monitoring strategies The response to this RAI falls into three parts. They are: 1) performance-based y

implementation,2)Section XI required monitoring and feedback, and 3) other monitoring and feedback mechanisms. They are described as follows:

Performance hneed Imnlementation The basis for ASME Code Case N560 is the exceptional performance history of category B J piping welds. A detailed data review ofindustry piping failures was conducted in support of the code case. In addition, a review of Vermont Yankee specific history was conducted. Although a number ofinstances ofIGSCC were identified, these occurred prior to the piping replacement effort of the late 1980s.

With that issue resolved, Vermont Yankee category B J experience is consistent with the industry data.

On top of the exceptiond performance, N560 provides a mechanisms for identifying what locations ta inspect and what techniques to use based upon the operating performance oflike components.

Section XI Reauired Monitoring and Feedback N560 requires that the existing monitoring and feedback mechanisms provided in Section XI be maintained. These are as follows!

pressure and leak testing of all category B-J components, e

inspection results shall be compared to PSI and prior ISI e

. (IWB-3130(c),

for flaws exceeding acceptance criteria (IWB-3500),

e increase the number ofinspections to include those items scheduled for this and the next scheduled period (IWB-2430(a)),

additional inspections - all items of similar design, size and function (IWB-2430(b))

flaw - removed, repaired, replaced or analytical evaluation (IWB-3130/3140) if accepted by analytical evaluation, items shall be examined for the next three inspection periods (IWB-2420(B))

Other monitoring and feedback mechanisms

)

Vermont Yankee Technical Specification 3.6.c 11-7

Unidentiiled Reactor Coolant Leakage shall not exceed 5 gpm Total Reactor Coolant Leakage shall not exceed 25 gpm Feedwater Nozzle for bypass flow with (4) thermocouples per nozzle Drywell Monitoring Radiation Temperature Pressure Based upon the exceptional performance history of category B-J components, a detailed review ofindustry experience, and the multiple means of monitoring and providing feedback, N560 can be implemented in a streamlined yet robust manner. Also, please see the response to MONITORING, RAI 5, 2.

PROVIDE WRITTEN DESCRIPTION OF THE EXTENT OF THE RELIANCE ON PRA NUMBERS AND THE QUALITY OF THE PRA The Vermont Yankee Code Case N560's consequence evaluation made limited use of the Vermont Yankee PRA results. This was due to the simplicity of consequences associated with Class I piping. To justify this statement, the consequence types from the consequence evaluation in Table 4-1 of the Vermont Yankee Submittal, dated August 6,1997, are summarized below:

1. Large LOCA (LLOCA) is identified for 68.6% of the piping locations, and evaluated as hasing a "HIGH" consequence rank

2. Medium LOCA (MLOCA) is identified for 7.9% of the piping locations and evaluated as having a " MEDIUM" consequence rank

3. Potential LOCA (PLOCA) is identified for 4.7% of the piping locations, and evaluated as having a " LOW" consequence rank, based on a passive barrier (for example, ch:ck valve) providing isolation of a potential LOCA

4. Isolable LOCA (ILOCA) is identified for 4.7% of the piping locations, and evaluated as hasing a "HIGH" or " MEDIUM" consequence rank, based on an active barrier (for example, auto MOV closure) providing isolation of a potential LOCA

5. LOCA Outside Containment (LOCA-OC) is identified for 6.9% of the piping locations, and evaluated as having a "HIGH" or " MEDIUM" consequence rank, depending on the type ofisolation

6. Interfacing System LOCA (ISLOCA) is identified for 5.2% of the piping locations, and evaluated as having a "HIGH" consequence rank

7. Loss of Feedwater (TFWMS) is identified for 0.5% of the pipii g locations, and evaluated as having a "HIGH" consequence rank II-8

8. Effect on Shutdown Cooling (SDC)is identified for 1.7% of the piping locations, and evaluated as having a " MEDIUM" rank, based on engineering judgment.

in general 70% of the pipe segments and locations are evaluated as having a "111G11" consequence rank. Out of 69 piping segments, only 20 do not have a "IllGil" rank (mainly segments where breaks would result in a medium LOCA or a potential / isolable LOCA).

The Use of PRA Two tables in the Vermont Yankee Code Case N560 Submittal, dated August 6,1997, came directly from the Vermont Yankee PRA and are used in the consequence evaluation:

Table 2-1: Gives the contribution of difTerent initiators to Core Damage Frequency (CDF), and was used to determine CCDP for each initiator Table 3-2: Gives unavailabilities for all Vermont Yankee safety systems and

. trains credited in the Vermont Yankee PRA, and was used to determine unavailabilities (or corresponding " number") of backup trains. (See EVALUATION METHODOLOGY, RAI 8)

For ranking consequences, I through 7, Table 2-1 was used. This is because most of the postulated pipe breaks resulted in an initiator or a possible initiator.

t Consequence 8 is ranked based on engineeringjudgment. Therefore, Table 2-1 covers the majority of PRA numbers used and any reliance on the quality of the PRA.

In summary, the evaluation uses the following PRA numbers: IE frequency, contribution to CDF from different initiators, and system unavailabilities.

3.

PROVIDE WRITTEN DESCRIPTION OF TIIE EXTENT TO WIIICII INTERNAL FLOODING IMPACTS TIIE SELECTIONS Internal flooding has an effect on the consequence results for piping outside the

. primary containment (outside the Drywell). The following provides a more detailed explanation.

Piping inside Drywell - most of the Class 1 piping (89% oflocations) is located inside the Drywell where flooding has no impact on the et nsequence analysis.

Loss of coolant accidents (LOCAs) are within the design basis, and the resulting water drains into the torus where there are no flooding impacts beyond that evaluated as part of the design basis. In addition, the drywell/ torus is the preferred location for water as it is the suction source for the low pressure ECCS, II-9

_a

Piping outside Drywell-this limited Class I piping is between the Drywell wall

{

and the outside containment isolation valve (11% oflocation). Summary of this piping and how it was evaluated is provided below:

LPCI A & LPCI B (2 MOVs to Drywell, Reactor Building (RB),

e Elevation (EL) 252,6 welds on each train)

Consequences evaluated as 111011 because ofincreased potential for interfacing system LOCA (ISLOCA). (Flooding is also evaluated, see the summary below for the RB.) No degradation mechanisms are identified.

RER (MOV to Drywell, RB EL 252,5 welds) e-Consequence evaluated as 111G11 due to IELOCA (Flooding is also evaluated, see summary for RB.) Degradation mechanism TT is identified.

CSA & CSB (MOV to Drywell, RB EL 280,2 welds in each train) e Consequences evaluated, as HIGH due to ISLOCA (Flooding is also evaluated, see summary for RB.) No degradation mechanisms are identified.

FWA & FWB (Check Valve to Drywell, Steam Tunnel,2 welds in each train)

Consequence evaluated as HIGH because of the increased potential for a LOCA outside containment (LOCA-OC). (Flooding is also evaluated, see summary for Steam Tunnel.) Degradation mechanism TASCS is identified in Train B.

MS-A. MS-B. MS-C & MS-D (AOV to Drywell, Steam Tunnel,2 welds in each train)

Consequence evaluated as MEDIUM, due to LOCA-OC (Also, see summary for Steam Tunnel spatial effects.) No degradation mechanisms are identified, RCIC & HPCI Steam Supply (MOV to Drywell, Steam Tunnel,7 e

welds in RCIC line,6 welds in HPCI line)

Consequence evaluated as MEDIUM, based on both LOCA OC and potential isolable LOCA (ILOCA). (Also, see summary for Steam Tunnel.) No degradation mechanisms are identified.

REACTOR BUILDING SPATIAL EFFECTS Reactor Building (RB) propagation is to EL 213, where all ECCS and RCIC equipment is located. The events analyzed in this evaluation have the potential to 11-1 0 i

drain the suppression pool into the reactor building and flood all ECCS, Analysis of each elevation is given below.

EL 280 - core spray and reactor water cleanup piping is located here.

Propagation is through a large equipment hatch and open stairway to El 252.

Scram and ECCS actuation cabinets are in the area, but impact is more likely to be actuation success due to the "de-energize to actuate" design. Motor Control Centers, MCC 8B 'and MCC 9B, are located on this floor, but it takes about a foot of water to impact an MCC. Flooding to one foot is not credible, given the propagatica paths.

All propagation from higher elevations (e.g., El 280, which contains core spray) is into the South end of El 252. Thus, there is easy propagation through the access opening to the torus and ilPCI rooms on El 213. It has been -

estimated that >8,000 gpm is required to sustain 4 inches on the South end of El 252 where propagation would occur into both RHR comer rooms.

El 252 - LPCI and Shutdown Cooling (SDC) piping is lo::ated here. Flood i

e-

- propagation is initially through the torus access hatch (Southeast corner of torus room), CRD access (Southwest corner which includes HPCI), and under the Northwest stairway door (1 inch gap) to the RCIC room. All these paths -

lead to EL 213. MCC 89A & MCC 89B are located on floor El 252, but it takes about a foot of water to affect the MCCs. Water levels on EL 252 must reach 4 inches to overflow the berm at the RHR ceiling chases and 6 inches to overflow the stairways to the RHR comer rooms, it has been estimated that over 2,500 gpm is required to sustain 4 inches on the North end of El 252, This is due to a restricted area between the hatch enclosure area and the East end of the floor which restricts flow to the South end of the building where the torus and CRD access openings provide easy propagation to El 213.

El 213 - the torus room and HPCI comer room connect and provide a very large area for floods to collect. This is where the torus and CRD access opening on El 252, and floor drains propagate, Most of the water from El 252 and above is expected to reach this area, as described above, for El 252.

Propagation under the Northwest door at El 252 to the RCIC room at El 213 is estimated to be about 300 to 400 p.pm (assuming 4 inches of water). Water can reach the NE RHR corner room (Train A of RHR and CS) if there is a >2500 gpm break on the North end of El 252. All other breaks on the South end of El 252 and on other higher elevations require >8000 gpm to reach both RHR comer rooms (both trains of RHR and core spray).

Detection and isolations are described for two different conditions; (1) high energy LOCAs outside containment which cause initiating events and (2) independent demand challenges of mitigating system piping which lead to water being pumped into the reactor building by the mitigating system pipe failure.

I1-11

For the first condition, high-energy line breaks (llELDs) in the reactor building can be detected by higi temperatures, high radiation, and/or high water levels.

All three of these detectable elements are entry conditions into Emergency Operating Procedure EO 3105," Secondary Containment Control". This procedure directs the operators to isolate systems discharging into the area except those required to shutdown the reactor and assure adequate core cooling. If the primary system is the source and adverse conditions persist (water level reaches 12 inches in a comer room), the operators are directed to shutdown the reactor and go to OT 3100 (scram procedure). If adverse conditions persist in more than one area (water level is 12 inches in more than one corner room), the operators are also directed to UE 3102, Section RPV-ED, to depressurize the reactor. This p:ocedure ensures use of the main condenser and turbine bypass valves, if available. Large HELBs will likely result in a reactor scram due to low RPV level.

For the second condition, pipe breaks are postulated during an independent demand of a mitigating system for those systems. hat are normally isolated from reactor operating conditions. These systems include LPCI injection and core spray injection. All of this piping is located in the reactor building. This piping will pump the contents of the suppression pool into the reactor building if not isolated.

Flooding in the reactor building will be detected first by floor drain alarms and entry into OE 3105 is likely (see above). Also, loss of torus level is an entry into OE 3104. Similar to OE 3105, the operators are directed to shut down the reactor (OT 3100) and depressurize the reactor (OE 3102 RPV-ED). In addition, if the level continues to drop below 6.5 feet, the operators are further directed to line up injection sources that tde suction external to primary containment. Since environmental conditions are much less severe than LOCAs outside containment, and there is adequate detection, credit is allowed for remotely tripping the pumps and/or closing MOVs.

STEAM TUNNEL SPATIAL EFFECTS LOCAs in the stnm tunnel will propagate into the turbine building via blowout panels and also into the reactor building through a door on El 252. Water will flow toward the reactor building El 252. In the Vermont Yankee PRA, the environmental impacts on equipment in the reactor building are assumed to be minor. The spatial arrangement of critical electrical components in the reactor building is not in the direct path of steam and water release. The room on El 252 is large and vents directly to higher elevations through an equipment hatch and stairs. Still, all LOCAs in the steam tunnel are assumed to disable feedwater, main condenser, HPCI, and RCIC Feedwater breaks are conservatively assumed to drain the suppression pool and eventually fail all ECCS. This is based on the assumption that operators will cor. trol reactor water level high enough to continue pumping suppression pool through the feedwater sparger, into the steam tunnel.

11-1 2 u

o

Steam line breaks are not likely to drain the suppression pool, thus, low pressure ECCS is credited, llELBs in the steam tunnel will be detected by high area temperature, and automatic MSIV closure will also occur on high area temperature. If high area temperature persists, both IIPCI and RCIC isolation will also occur. (IIPCI and RCIC steam lines, downstream of MOV 15, isolate on several different signals including high steam line flow and high area temperature in the steam tunnel.)

Pipe breaks inside the Steam Tunnel which are not ranked as 111011 in the consequence analysis, are breaks in the MS lines, and steam supply lines to llPCI

& RCIC turbines. ADS is not affected, nor is low pressure makeup. These breaks will cause an initiator due to MSIV closure (isolation failure will result in an analyzed LOCA outside containment). For this initiator, more than 2 mitigating trains are unaffected (isolation and ADS), so, based on Table 2-3 in the August 6,1997 submittal, the corresponding consequence rank is MEDIUM.

4.

PROVIDE WRITTEN DESCRIPTION AS TO IIOW DEFENSE IN DEPTil, FOR EXAMPLE, TIIE DEFENSE IN DEPTH ASPECTS OF SBO, IS ADDRESSED (e.g. HPCI, RCIC)

Response to this and RAI 6 of this section will be contained here because both RAI 4 and RAI 6 address the same issue of defense in depth.

l In the Vermont Yankee N560 Submittal " defense in depth" is addressed in multiple ways:

every pipe section which, ifit breaks, results in a significant loss of e

redundancy, is evaluated as having a "HIGH" consequence rank. This is done independently of" frequency of challenge." In other words, even for a very unlikely challenge, breaks that lead to a loss of redundancy (zero backup trains) are evaluated as "HIGH." (See Table 2-2 in the August 6,1997 Submittal).

every pipe section which, ifit breaks, results in an increase in probability of containment bypass, is evaluated; and, if the probability of containment bypass is significant, the assigned consequence rank is always "HIGH." (See Table 4-l's shaded inputs for ISLOCA and LOCA-OC).

in the final selection, no significant reduction in inspections is recommended for all systems performing the same safety function (see summary below).

11-1 3 J

Hloh Pressure Makeun FW - no reduction in CAT 1, reduction in CAT 2 (12 to 7 inspections)

- HPCI - small reduction in CAT 4 (3 to 2 inspections)

RC'.C - reductions (only Low Category)

ADS - no effects Low Pressurc Makeun CS insignificant reduction in CAT 2 (9 to 8 inspections)

LPCl/RHR - small increase in CAT 2 (7 to 8 inspections)

As identified in the above, the proposed change does not efTect the redundancy for the two major safety functions.

Station Blacknut (SBO)

Both RCIC and HPCI are capable of operation during a station blackout until DC -

power discharges or AC power is recovered (assuming DC and vital AC success).

Failure to recover AC power within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is conservatively assumed to cause failure of RCIC and HPCI in that case, only the diesel fire pump is credited. This is not significant in the Vermont Yankee PRA for a couple of reasons: (1) the Vernon tie line makes loss of offsite power relatively low and (2) the probability of not recovering ofTsite power is greater than the combined failure probability of RCIC and HPCI.

RCIC and HPCI steam line breaks are initiating events in the current analysis; the probability of station blackout given this initiator is insignificant and requires failure of multiple backups (e.g., offsite AC, Vemon tie, and 2 diesels). Note that a steam line break in the steam tunnel with failure to isolate (credited as one backup train) could take out both HPCI and RCIC due to sustained high temperature trips, however, this would require additional failures (e.g., offsite AC, Vernon tie, and 2 diesels). These scenarios are included in the present analysis.

Even if a steam line break on demand is assumed (not presently in analysis) due to loss of oITsite power, the Vemon tie and 2 diesels still have to fail in order to reach a station blackout. Again, a steam line break in the steam tunnel with failure to isolate (a backup train) could take out both HPCI and RCIC due to sustained high temperature trips. However, a combination of challenge frequency and failure of Vemon tie and 2 diesels ensure the present Medium consequence

_ for these systems can not be exceeded by SB0 scenarios.

11-14

)

1

5.

PROVIDE WRITTEN DESCRIPTION OF llOW EXTERNAL EVENTS ARE ADDRESSEls(e.g. SEISMIC)

External events are considered last in the process to develop confidence that the consequences from such events are already enveloped. The following summarizes the process:

1" - the consecnence evaluation ranking is established based on pipe break impact on core damage frequency; CCDP is estimated based upon an existing PRA (see response to EVALUATION h1ETHODOLOGY, RAI 7 and RAI 8).

2"d - containment performance is considered, the consequence is assessed and increased to a higher category if containment performance is effected (see consideration of LOCAs Outside Containment in response to thiPACT OF PROPOSED CHANGE, RAI 3).

3'd - shutdown events are reviewed to develop confidence that the consequences from these events are already enveloped. RHR shutdown cooling suction piping was ranked into the "hiedium" consequence category based on this review.

4* - external events are evaluated. Since most of the piping is already "High" or "hiedium," it is only necessary to develop confidence that the CCDP due to external events is on the order of IE-4 or less and that containment performance is not effected. The following summarizes the rationale for confirming this conclusion:

Seismic - the mean annual frequency oflosing offsite power is less than 1E-4/yr using either the EPRI or NRC seismic hazard. The seismic capacity of piping is significantly better than for offsite power components. Also, for the cases where the pipe breaks on demand were considered, the frequency of challenge is very low (<1E-4), it is simply not credible to conceive of a scenario that is even close to a CCDP of 1E-4.

Fires - do not cause pipe breaks and can be assumed to be independent of pipe break initiating events. A more likely scenario may be the case where the pipe breaks on demand in response to a fire-induced event. The evaluation was performed to ensure that certain fire events, in combination with a postulated pipe break, do notjeopardize " single failure" criteria. The worst cases are fires in the Control Rocm or Cable Vault, which would require an alternative shutdown outside of the Control Room. This would involve RCIC operation from the RCIC Room and RHR operation from its remote shutdown panel in the Reactor Building. It is unlikely that, under this condition, a pipe break I

could disable both of those systems. Given a low fire initiator frequency, their contribution to the consequence rank of systems / trains can be neglected.

II-15 d

Other Extemals are unlikely to cause pipe breaks and have a low frequency of e

challenge. Similar to fires, the challenge frequency and available backup trains assure a CCDP ofless than IE-4. The most likely scenario would be some external cause of bsing offsite power, but this is enveloped by the current analysis.

l 6.

PROVIDE WRITTEN DESCRIPTION OF IIOW DEFENSE IN DEPTII IS l

ADDRESSED l

See response to RAI 4 of this section.

7.

PROVIDE A DESCRIPTION OF Tile ACTUAL REVIEW PROCESS WlilCII WAS UNDERTAKEN TO ASSURE TIIAT KEY INPUTS TO TIIE N560 EVALUATION WERE NOT MISSED The review proccus conducted in support of the Vermont Yankee N560 submittal was conducted in accordance with the Yankee Nuelcar Services Division (YNSD)

Engineering Manual. The YNSD engineering manual provides instructions for implementing the quality assurance requirements delineated in the Yankee Opciational Quality Assurance Program (YoQAP). The YoQAP and YNSD's implementation of the engiacering manual have been subjected to a number of intemal and external audits.

Calculations / analyses requiring quality assurance are conducted through a three tiered approach. That is, each calculation / analyses shall have a preparer, a reviewer and an approver. The responsibilities of each is as follows:

Preparer the preparer shall be technicelly competent in the subject matter. The preparer shall prepare the document in a logical manner so that a competent individual can review the work without recourse to the originator. The focus is to provide a clear, legible, accaate, defendable and retrievable document. The preparer shall ensure:

i consideration of the range of values which may be applicable for all inputs e

and select and justify the values relative to the objective of the calculation, the problem has been properly constructed and/or modeled, e

the calculational method is reasonable and defendable, e

input data are valid, verified and appropriately documented, including intemal e

and extemal interfaces, governing documents and revision level, confirmation that design inputs are consistent with the plant design bases and e

previous safety calculations and analyses, 11 16

all assumptions are identified, reasonable, consistent with plant design bases, e

justilled and are documented, the calculation is mathematically correct, e

the results are consistent with conclusions and conclusions adequately address e

calculation objective (s),

and resolution of comments provided by the independent reviewer.

e Reviewer the reviewer shall be technically competent in the subject matter and not have immediate supervisory responsibility for the preparer. The reviewer shall be responsible for independently reviewing, confirming and substantiating the calculation / analyses. The reviewer verifies that the calculation has been prepared in accordance with the YNSD engineering manual as summarized above.

The reviewer ensures that all review comments are satisfactorily incorporated or dispositioned.

Approver the approver is responsible for assuring that the calculation / analyses was performed and reviewed by qualified individuals who have technical competence in the subject matter. The approver also provides a level of oversight to assure that the calculation satisfies its objective, and is technically sound and auditable.

8.

PROVIDE A DESCRIPTION OF Tile INTERNAL AND EXTERNAL REVIEWS OF Tile VERMONT YANKEE PRA TilAT WERE CONDUCTED As described in Section 5 of the Vennont Yankee IPE submittal, a series of internal and external reviews of the IPE documentation were conducted during development of the final IPE report. Comments developed during these reviews were incorporated into the final IPE report which was submitted to the NRC.

Internal reviews were conducted by Yankee Atomic and Vermont Yankee personnel. All aspects of the analysis were reviewed by qualified, independent, in house personnel. System models (fault trees) were reviewed by a broad spectrum of Vermont Yankee and Yankee Atomic engineers, including those with expertise in the following disciplines Systems Engineering, Electrical Engineering, Mechanical Enginec!!ng, Instrumentation and Controls Engineering, and Operations. Each fault tree model was presented at a comprehensive review meeting where comments were discussed and resolved. A "high level" comprehensive overall review was provided by ERIN Engineering. This external review ensured that industry. wide experience in PRA analysis was considered in the Vermont Yankee IPE submittal.

i Specific external support for the Vermont Yankee IPE cfrort was provided by the following individuals. Steve Mays, an independent consultant with PRA 11 17

expertise, was brought in house in the initial stage of the IPE. Ilis main contribution was to establish the scope and methodology for the event tree and fault tree analysis. Edward llurns, ERIN Engineering and Research,Inc., served as an expert consultant throughout the IPE. lie had participated in numerous 11WR PRA studies, and was a major contributor to the development of the IDCOR IPE hiethodology. In addition to overall review and consulting, his contribution to the Vermont Yankee IPE concentrated on the areas of human reliability analysis and containment phenomenological analysis. JefrGabor of Gabor, Kenton, and Associates, Inc., also served as an expert consultant. lie was a major contributor to the development of the hiAAP code for deterministic analysis of accident seq"ence progression, lie was responsible for developing the Vermont Yankee hiAAP model, and for all hiAAP simulations used to support the Level I (success criteria) and Level II (release magnitude and timing) analysis.

Kamran hiokhtarian, Chicago 11 ridge and Iron, Technical Services Company, served as an expert consultant for analysis of containment ultimate strength.

The final report was reviewed by the NRC and received an SER (Ref.: Letter, NRC to Vermont Yankee," Vermont Yankee Nuclear Power Station Individual Plant Examination (IPE) - Internal Events (TAC. No, hi74484)", dated February 9,1996). The NRC SER documents the findings of reviews conducted by Science and Engineering Associates,Inc., Concord Associates, and Scientech,Inc.

Questions asked by the NRC contractors during their review of the Vermont Yankee IPE submittal are documentrd in the following letter (Ref.: Letter, NRC to VY, " Request for Additional Information (RAl) Regarding the Vennont Yankee Individual Plant Examination (IPE) Submittal (TAC No. hi74484), NVY 95 95, dated June 23,1995). The Vermont Yankee responses to these questions are provided in the following letter (Ref.: Letter, VY to NRC," Vermont Yankee Response to NRC Request for Additional Information Regarding Vermont Yankee's Individual Plant Examination (IPE)", DVY 95 114, dated October 27, 1995).

11-1 8

111.

EVALUATION METilODOLOGY 1.

PROVIDE WRITTEN DESCRIPTION AS TO IlOW TIIE IMPACT OF UNKNOWN MECilANISMS IS ADDRESSED In the EpRI approach to risk informed in service inspection, pipe segments are dermed in terms of the potential for pipe rupture and the consequences of an assumed pipe rupture. In recognition of the large uncertainties associated with attempts to quantify pipe rupture frequencies, and the conditional frequencies of core damage or large release given a rupture, a semi-quantitative matrix approach is employed as indicated in Table 111 1 1, For each segment, the potential for pipe ruptures is assessed as either high, medium or low depending on the presence or absence of the conditions necessary for identifiable damage mechanisms to degrade the pipe segment.

Table 1111 1 EPRI Risk Matrix for Classifleation of Pipe Segments for Risk Informed In-Servlee Inspection CONSEQUENCE CATEGORY RIMQln Core Melt Potential for Limiting Break Size H10H MEDIUM NQNE LQW MEDIUM B1GB LOW l'

ddiihNf Ulgd LoWRISK RISK l3 l} &,,Q x

'?

-I

,1 '.f " ; '

MEDIUM low RISK low RISK MEDluM.MM ws-i k O- 'ei, Nffg.hf SMAll low RISK low RISK low RISK MEDluM. RISK Of g

a.

it is important to note that in no circumstances is a pipe segment assumed to have no potential for pipe rupture, it is recognized that even in the absence of an identifiable damage mechanism, there is a finite probability of pipe rupture due to 111-1 9 l

causes that may be unrelated to a damage mechanism per se. As indicated in Table 11111, segments with a low potential for supture and a high assessed consequence are assigned a " medium" risk classification, in recognition of the fact that pipe rupture cannot be ruled out for such segments, llence, only when a low rupture potential is combined with a low or medium consequence, is the risk associated with the segment considered low.

'the EPRI approach to risk informed in service inspection is derived from insights from service experience on the causes of historical pipe failures (References

[EM 1) through [EM-4]). ' Ills service experience indicates that all experienced pipe failures, which include both leaks and ruptures (for convenience we use rupture to denote pipe failures whose leak rates are in excess of 50 gal / min.) are l

due to a v ell defined set of failure mechanisms that can be placed into several broad categories:

damage mechanisms such as corrosion, thermal fatigue, IOSCC, etc.

e design and construction errors and defects severe loading conditions such as water hammer, over pressurization, frozen e

pipes, and human error 7

combinations of severe loading conditions and degradation mechanisms or e

design and const uction defects Only the damage mechanism category and certain types of design and construction defects are amenable to prevention via NDE inspections, which are geared toward finding flaws. Severe loading conditions can cause pipe leaks and ruptures if the applied load exceeds the pipe capacity, whether or not there are any flaws present, it is extremely doubtful whether inspections have any impact on the probability of pipe ruptures due to severe loading conditions, unless the capacity of the pipe to withstand these transient loads has been degraded by a previously acting degradation mechanism.

111 20

The EpRI RISI classification scheme for assignment of segments to the three general classes of failure potential is depicted in Table 11112. 'The logic of this classification scheme is that if there are no known damage mechanisms present in the pipe, the potential for pipe rupture is classified as low, in this case there is Table 11112 EpH1 System for Evaluation of high confidence Pipe Rupture Potential that the potential for rupture due to

,f Con one Degradation Mechanism h, '

Large Ero6lon Corrosion (FAC) mechanism Can h water Hemme, ruled out.

The v6bration Fetigue potential for pipe MEDIUM Small Thermal Fetgue ruptures would in Corrosion Fatigue this Case be sires.CorroomnCrocong tiosCC.

determined solely TosCC, PWSCC, ECSCC) by the likelihood Corro6lon Attack (MIC. Crevios Corroslen and Pating) of occurTence of Erosion /Covitation severe loading LOW None No Degradation Mechenkms Present conditions in excess of the pipe segment capacity, which may or may not be reduced by the presence of some design and constmetion defects. Another possibility lei the occurrence of a pipe rupture due to some heretofore unknown damage mechanism, although this is considered unlikely for the reasons detailed below.

When the pipe segment has been identified as having the conditions necessary for one or more well defined damsge mechanism, the likelihood of pipe rupture is obviously higher than it otherwise would be since such damage mechanisms may lead to pipe failures directly, or they can reduce the capacity of the pipe segment to withstand transient and severe piping loads if and when they occur. Ilence, on a qualitative basis it is clear that the presence of conditions necessary for piping damage mechanisms would lead to a higher rate of occurrence of pipe failures and ruptures than the case where no such conditions are present.

EpRI has sponsored a number of completed and ongoing studies to document the service experience with piping systems in U.S. commercial nuclear power plants.

A review of this experience and the resulting insights were recently discussed in Reference [EM 4). Since then, EpRi has performed additional analysis of this service experience which is summarized in Table 11113. In this more recent analysis, the Reference [EM 3] database was screened to eliminate non pipe events and all the rupture events were reviewed for a more accurate and current l

classification. This experience covers about 2,100 reactor years of U.S. nuclear operating experience through 1995 with all known documented cases of piping system failures including leaks and ruptures.

A recent evaluation of this 111 21

experience, which has been updated since publication of Reference [EM 4],

covers about 1,100 pipe failures, which include a total of 69 cvents that were classified as pipe ruptures. A plot of the estimated mean frequencies of pipe ruptures based on the Bayes update procedure explained in Reference [EM-4) and expressed in terms of events per reactor year across all systems is presented in Figure 111 1 1.

As seen in Table 11113 and Figure 1111 1, service experience includes failure modes associated with degradation mechanisms, severe loading conditions, design and construction defects and human errors. While none are listed here as due to a combination of mechanisms, we believe that this is an artifact of the way in which the data has been recorded; judgments were made about the predominant cause in these circumstances such that most reports only list a single mechanism. Some of the observed failure mechanisms indicated in Table 11113 and Figure 11111 could have been precluded by a timely NDE inspection, whereas other failure mechanisms are not amenable to prevention via NDE inspections. The greatest opportunity for NDE inspections to reduce the likelihood of pipe ruptures is with respect to damage mechanisms which produce detectable flaws; while severe loading conditions are expected to produce pipe rupture frequencies that are essentially independent of the in service inspection program.

Of the degradation type of failure mechanism, vibrational fatigue and crosion/ corrosion are responsible for the largest contribution to rupture frequencies. These degradation mechanisms are seen to have mean rupture frequencies at least an order of magnitude greater than that for the remaining types l

degradation mechanisms. In fact, for stress corrosion cracking, crosion cavitation and corrosion fatigue the current analysis in Table 11113 has identified no reported pipe ruptures. In addition, corrosion attack and thermal fatigue have each been responsible for a single rupture in this data set.

One of the issues that EpRI has examined in the more recent analysis is the classification of" unknown" which appears in the database when the actual cause of the failure was either not known or not clearly stated in the report. A more detailed examination of more than half of the originally reported unknown failures has led to a significant reduction assigned to that category with no appearance of any new or previously unknown damage mechanism. Ilowever, the lack of information presented in some of the source reports makes it very difficult if not impossible to pinpoint the causes of each event originally listed as unknown. As discussed in Reference [EM-4) changes in reporting requirements have led to a significant reduction in the observed frequency olpipe failures with causes listed as unknown during the last decade. EpRI contacted utilities to find out the root causes associated with many of the originally listed unknown failures and in each case that was checked, the failures were traced to one of the established failure mechanisms listed on Table 11113. It is extremely doubtful whether any of the residual failures whose cause was not identified in the licensee event report or 111 22

~

other quotable reference is associated with some new or unknown failure mechanism, llowever, there have been a number ofinstances where the causes of specific events were not identified in the associated reports.

Returning to Table 11112, the EPRI system classifies pipe segments with no known degradation mechanisms as having a " low" potential for pipe rupture, and those with the physical conditions for vibrational fatigue and crosion/ corrosion as having a relatively "high" potential for rupture, in addition, segments that are found to be susceptible to water hammer with the presence of any degradation mechanisms are also classified as having a "high" potential for rupture. Water hammer is treated as a special case because it has been responsible for a significant number of pipe mptures. Even though there may be some potential for severe water hammer in many difTerent types of pipe segments in many types of systems, EPRI has examined this mechanism in great detail and has developed procedures for identifying the associated susceptibility of piping segments (Reference [EM 5]).

Segre.nts that have the potential for any damage mechanism other than vibrational fatigue or crosion/ corrosion and not found susceptible to water hammer are classified as medium potential for pipe rupture even though very few ruptures are evident in the service experience for these mechanisms. Damage mechanisms in the medium category are seen to have a large potential to " leak before break". Despite no strong evidence that ruptures from these mechanisms are very likely, the EPRI classification scheme conservatively treats the pipe rupture potential as medium and, in this sense, does not take credit for leak before break, it is recognized that segments in all three categories of pipe failure potential will have pipe rupture contributions due to severe loading conditions such as water hammer, over pressurization, frozen pipes and other types of loads such as external events. Ilowever, for practical purposes, these non-degradation related failure mechanisms are not likely to change in occurrence frequency due to changes in the inspection program since they act too quickly for NDE inspections to be of benefit.

Afler analyzing several thousand years of service experience, all pipe leaks and ruptures have been due to a well-defined set of failure mechanisms as listed in Table 1111-3. It is possible, although not considered very likely, that future experience may give rise to knowledge of new failure mechanisms not currently in the service experience. -Current experience provides a strong case that the likelihood of pipe ruptures due to new or unknown damage mechanisms would be much less than that due to any damage mechanism that is tracked in the EPRI classification scheme, ar.d certainly less than that due to severe loading conditions such as water hammer or design and construction defects. Until such hypothetical mechanisms become known and their conditions understood, it is not clear how current inspection programs can be expected to address them.

111-2 3

llowever, the EPRI classification system provides a backstop for this issue by restricting the classes of pipe rupture potential to low, medium, and high. In addition, the EPRI system pennits the elevation of the risk category from low to medium based solely on the consequences of an assumed pipe rupture, even when no degradation mechanisms are present. As a result, the classification of piping segments to classes of relative potential for ruptures is robust in light of any residuel uncertainties about currently known or unknown failure mechanisms. In addition, please see the response to h10NITORINO, RAI 5. for a discussion of Vermont Yankee's tracking and trending ofindustry data.

Conclusions in summary, the EPRI approach to RISI recognizes the large uncertainties in attempts to quantify the frequency of pipe ruptures in specific pipe segments, it makes use of more than 2,000 reactor years of service experience with piping l

systems, which has supported the development of a deep understanding of pipe failure and damage mechanisms. While yet unknown damage mechanisms may i

be postulated, their frequency of occurrence is bounded by that of the known failure mechanisms.

EPRI will continue to track the service experience to enhance these insights and, if new mechanisms are identified, appropriate inspection strategies can be intelligently evaluated and implemented.

I References Eht 1 Jamall, K., Imping Failures in ILS. Commercial Nuclear Power Plants, EPRI Interim Report TR 100380, July 1992 Ehi 2 Jamall, K., Piping Failures in U.S. Commercial Nuclear Power Plants EPRI Report TR-102266, April 1993.

Ehi 3 Bush, S.ll., et al., " Piping Failures in the United States Nuclear Power Plants: 1961 1995, SKI Report 96:20, January 1996 Ehi 4 Gosselin, Stephen R. and Karl N. Fleming, " Evaluation of Pipe Failure Potential Via Degradation hiechanism Assessment", Proceedings of ICONE 5,5* International Conference on Nuclear Engineering, hiay 26-30,1997, Nice France Ehi 5 Stone and Webster Engineering Corp., " Water llammer Prevention, hiitigation, and Accommodation", EPRI Report NP 6766, Final Report July 1992 111-2 4 l

I i

i l

l Table lit-1-3 Service Experience with Leaks and Ruptures From Different L'amage Mechanisms SKI Database (Ref. [31)

Current EPRI Database Mechanism Failure Mechanism Type of Failure Type of Failure Type I.D.

Description All Leak Rupture All Leak Rupture VF Vibration Fatigue 364 339 25 312 298 14 SC Stress Corrosion Cracking 166 166 0

151 151 0

Degradation TF Thermal Fatigue 38 38 0

38 37 1

Mechanism E-C Erosion Cavitabon not used not used not used 12 12 0

CF Corrosion Fatigue 14 14 0

11 11 0

E/C Erosion Corrosion or Flow 295 276 19 201 183 18 Accelerated Corrosion COR Corrosion Attack 72 69 3

65 64 1

Severe WH Water Hammer 35 20 15 27 18 9

Loading HE Human Error not used not used not used 14 13 1

Conditior's OVP Overpressure N/A N/A N/A 6

3 3

FP Frozen Pipes N/A N/A N/A 3

1 2

OTH Others 43 35 8

not used not used not used Other Causes D&C Design & Construchon 192 177 15 166 152 14 Defects UNK Unreported Cause 292 258 34 137 133 6

All All Failure Mechanisms 1511 1392 119 1143 1076 69 III-25 c_ - _...

j i

i i

1.0E-01 I

I i

k AMENABLE TO NDE INSp5DT10NS 5

j ONOT NPACTED BY NDE INSPECTONS

(

g 1.0E-02 O

H 1

0 j

4 s

i W

E e

j y 1.0E-03 l

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l

.i O

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i E 1.0E-04 3

F-O.

3 i

1.0E-05 Y

I E/C VF D&C WH UNK OVP FP TF COR HE SC E-C CF 4

FAILURE MECHANISM i

Figure III-1-1 Average Frequencies of Pipe Raptures From Different Failure Mechanisms Through 1995 i

i i

t i

III-26 J

)

2.

PROVIDE WRrlTEN DESCRIPTION DESCRilllNG Tile INDEPENDENCE OF Tile CONSEQUENCE AND DEGRADATION htECilANIShi EVALUATIONS. SilOW TilAT Tile CONSEQUENCE EVALUATION ASSESSES Tile SPECTRUht OF llREAK SIZES REGARDLESS OF Tile RESULTS OF Tile DEGRADATION htECIIANIShi EVALUATION The consequence evaluation assumes a large pipe break regardless of the degradation mechanism evaluation findings (e.g. degradation mechanism evaluation includes consideration of whether large or small pipe breaks are more likely); these evaluations are performed independently. The results of these independent evaluations are combined in the risk ranking process.

The pipe break size assumed in the consequence analysis is the inside pipe diameter of the piping under evaluation and, as shown in the consequence analysis, this is conservative. It is conservative because there is no credit for leak before break and the CCDP is higher for larger break sizes. This can be seen in Table 21 from the August 6,1997 submittal, where CCDP is given for SLOCA, MLOCA, and LLOCA. Also, Figure 3 1 in the consequer cc evaluation report shows how the success criteria improves for small size breaks relative to medium and large breaks.

The question could arise in the case where the pipe segment consequence category could be driven by a small leak, rather than a large break, because, in that case, all degradation mechanisms shall be assumed to lead to a "large" likelihood of PDF.

These cases were considered in the Vermont Yankee evaluation. There are no pipe segments discovered where a small leak could lead to a significant consequence, except that for large riping where small breaks could lead to a small size LOCA. Two possible cases are considered and analyzed below:

Pine rallure DM DM Consequence Rid "

Made l' resent

.Raak consequence Raak Catecon' Elsk Rank RU"TURE TF SMALL LLOCA filGil CAT 2 111G11 LEAK TF LARGE SLOCA MEDIUM CAT 3 11'.G11 In these two possible cases, the assumption of rupture or leak, results in the same risk rank. Therefore, the large break is assumed throughout the consequerce evaluation.

111 27

3.

PROVIDE WR11 TEN DESCRIPTION AS TO Tile EXTENT OF PREVIOUS CIIEhllSTRY EXCURSIONS AT VERh10NT YANKEE AND TilEIR IMPACT (IF ANY) ON TIIE ASSESSMENT Vermont Yankee has maintained excellent water chemistry throughout its operating history. The stainless steel Category B J welds were all replaced during the 1985/1986 refueling outage. Since that time, water chemistry conductivity is generally maintained below 0.1 uMho/cm, with one exception.

Following startup from our 1995 refueling outage, we experienced several spikes of high conductivity during the operating cycle. The main tu.oine and casings were replaced and returned to service without being properly cleaned.

Conductivity spikes of 1.48,0.85,0.7, and 0.65 uMho/cm lasting for 2-3 days were experienced during the operating cycle. Nominal conductivity was and is below 0.1 uMho/cm.

These spikes, while of great concern at the time, were determined to be insignl0 cant due to their relatively short duration. The additional potential for crack ;mwth when using the "EPRI BWR Water Chemistry Guidelines, i

Revision 1,"(EPRI T".103515 Rll supports this detennination.

4.

PROVIDE WRITTEN DESCRIPTION OF TIIE HASIS FOR TIIE 10%

SELECTION CRITERIA The basis for an inspection sample of 10% of category B.J Class 1 piping welds in Code Case N560 is documented in the AbME white paper prepared in support of the Code Case (ASME Section XI Task Group on ISI Optimization Report No.

92-0101, Revision 1, dated Sept.1995). The Task Group conridered the excellent perfomtance of such welds inservice, including an industry survey conducted by the Task Group, which indicated that inspections of approximately 10,000 such welds under the current ASME Section XI 25% sampling requirement, in 50 responding plants, has revealed only a small number of innocuous indications (5). The only signiacant service-induced flaws that have been observed in Class 1 piping have been detected by other augmented inspection progmms, designed to address specific, known degradation mechanisms, such as IGSCC. It was thus reasoned that, if an ISI program could be designed which looks specifically for such active degradation mechanisms in piping components, and if this program also took into account potential differences in the consequences of failure of various postulated failure locations (i.e. a risk informed approach), then a more mearungful inspection program could be designed, with a smaller inspection sample than the current, arbitrarily established,25% Code requirement.

111 28

Thejudgment of the ASME Section XI Task group was that a 10% sample, selected in a risk infomied manner, would provide at least an equivalent level of protection against piping system leakage or rupture, as the current Code 25%

sample and selection criteria. Thisjudgment was supported and supplemented by the following considerations:

There is little technical basis for the current 25% requirement, other than the fact that it is 100% divided by 4. That is,Section XI originally imposed a 100%

inspection over forty yeari, which equates to 25% cach ten year interval, in a Code change in the early 1980's, this requirement was changed to require inspection of the same 25% sample each ten years.

There is likewise little technical basis for the current selection criteria. Itclatively high stressed welds are selecced from the ASME Code stress report for the piping system.110 wever, history has shown that welds selected in this manner do not l

correlate with the few instances in which field cracking or leakage has been observed in Class 1 piping. ASMG Code stress analysis rules only address the fatigue degradation mechanism, and if the loads were properly identified and included in the stress repons, then they are shown to meet Code stress limits which contain large safety margins. Where failures have occurred in the twenty-plus year operating history of nuclear power plants, they have been instances in which either unexpected loads or degradation mechanisms have been present, and these cannot be predicted from a review of high stress locations in a stress report.

The real measure of protection against catastrophic failure of a piping system component is the combination of good design and leak before break. All of the service -induced failure mechanisms which afTect nuclear power plant piping

,cxcept one (Flow Assisted Corroshn), have been shown to be of a gradually progressing nature, which inevitably produce detectable leakage before significantly reducing the inherent safety margins of the piping relative to gross rupture. The combination of periodic leak tests required by Section XI, in conjunction with continuous leakage monitoring requirements for all primary coolant systems during operation has proven to be more than adequate protection against a large pipe break. The potential for flow assisted corrosiun, which has caused large pipe breaks without prior leakage, is minimal in Class I systems.

Special consideration of the FAC damage mechanism is included for this reason in the Code Case 560 evaluation rules, input was sought from other Code committees and individuals experienced in risk-informed evaluation and nuclear power plant performance. Specifically, a consensus of the Section XI Working Group on Implementation of Risk Based Examination was that the 10% sample was reasonable for Class 1 piping, and the code case in its current form was approved unanimously by all Code groups up to and including the Main D&PV Committee.

111-2 9

5.

PROVIDE WRITTEN DESCRIPTION OF Tile NUMBER OF CYCLES ASSUMED IN Tile TilERMAL FATIGUE SCREENING CRITERI A Thermal fatigue screening for the Vemtont Yankee Category D J Class I piping systems for application of Code Case N560 was performed in accordance with the EPRI Fatigue Management llandbook, TR 1045334,1994 These criteria are based on an assumed number of thermal cycles = 10' This high number of cycles was chosen to address potential high cycle fatigue concerns that may results from fatigue mechanisms such as thermal stratification. This results in a low allowable stress value (essentially the ASME code fatigue endurance limit), which has been translated into allowable temperature ranges used in the screening. Any location with the potential for thermal cycle magnitudes greater than the allowable temperature ranges (150 'F for Carbon Steel and 200 'F for Stainless Steel) were identified as potentially susceptible to the thermal fatigue mechanism, regardless of the actual munber of applied cycles. The screening procedure also allows for the use of more accurate computations to compute higher allowable temperature ranges foi a smaller number of cycles.

6.

REVIEW TIIE JUNE 12,1997 RAls ON TIIE EPRI METilODOLOGY AND IDENTIFY WillCll ONES ARE ADDRESSED DY Tile VERMONT YANKEE SPECIFlC RAls FROM Tile 9/23/97 MEETING Please see Attachment i for this response.

7.

PROVIDE A MORE DESCRIPTIVE PRESENTATION OF TIIE CONSEQUENCES METIlODOLOGY INCLUDING SEVERAL EXAMPLES Consequences are ranked based on the CCDP, given a pipe break. These consequence ranks are as follows:

111G11 CCDP 21E-4 MEDIUM IE-61CCDP < IE-4 LOW CCDP < lE-6 There are three configurations considered in analyzing the consequence of a pipe break or pressure boundary failure (PDF). To better describe the consequence methodology and make it more understandable, examples of those three configurations are shown below, 111 30

Note: All tables mentioned in the examples are tables from the August 6,1997 VY N560 Submittal Configuration 1: A pipe break occurs in an operating (pressurized) system, usually resulting in an initiating event (IE).

Start of the Event: Pipe Dreak Effect on Plant Operation: Initiating Event Measure of PDF Probabillry: Pipe Dreak Frequency, A[l/yr)

Measure of Consequences: CCDP [Unitless)

Measure of Risk: Core Damage Frequency (CDF) due to the break PDF CDF(PDF) = ( A

• CCDP)[l/yr)

The initiating events as consequences, can be evaluated as two cases:

Case la: The pipe break causes an initiating event equivalent to the one modeled in the PRA, in this case Table 2 1 is used for the consequence evaluation. Table 21 is straightforward. When a pipe break causes an initiating event modeled in the PRA, CCDP can be obtained direct!y from the PRA results (by dividing the CDF due to the specific IE by the frequency of that IE). For example, for a pipe break causing a Large LOCA (LLOCA), from Table 2 1, the CCDP is 6.2E-4, (CDF due to LLOCA (6.2E 8/yr)/ Frequency of LLOCA (IE-4/yr)).

Case Ib: The pipe break causes an initiating event, with an additional loss of mitigating ability (not modeled in the PRA). In this case, Table 2 3 provides a simplified way to rank consequences. (The exact results can be obtained from the PRA model by running the specific initiator case, with the mitigating system (s) assumed unavailable). Since the purnose of the conscguence evaluation is to provide only an appropriate rank for CCDP.

and not an exact number, Table 2 3 provides a conservative guide.

Example: The initiator is TFil'AfS(aplant trip with AfSIVclosure and Loss ofFeedwater). In addition, the RCIC System is lost. Two backup systems remainfor high pressure backup (see Figure 3-1), llPCI and ADS (2 of 4 SRl's). From Table 3.2, llPCI unavailability is 8.8E-2 and, therefore, can only be counted as halfofa train (the answer to the next RAI explains the reliability basisfor defining available mitigative trains).

ADS unavailability is 3.6E-4, and it can be counted as a train and one half Therefore, two backup trains are available andfrom Table 2-3, the corresponding consequence rank is "AiEDIUAf. " The rankfor the TFil'Af5 initiator by itselffrom Table 2-1, is also "AfEDIUAi, " so the resultant rank is "AfEDIUAf. "

111 31

Note: Configuration 2, which is presented below, was not applied as part of the Vennont Yankee N560 submittal because Configuration 3 was more applicable for Vennont Yankee standby systems, it is included herein, however, for completeness.

Configuration 2: A pipe break occurs in a standby system, and, after it is discovered, the plant enters the Technical Specification defined Allowed Outage Time (AOT). In the consequence evaluation, AOT is referred to as " exposure time." This is because, during the AOT, the plant's mitigating ability is reduced.

(During this " exposure time," the plant may be subjected to a spectrum of initiating events, which may require the operation of the disabled system.)

Start of the Event: Pipe Dreak Effect on the Plant Operation: Disabled Safety System /frain (Sff), Entering AOT I

Measure of PDF Probability: Pipe Dreak Frequency, A [l/yr)

Measure of Consequence : CCDP = CDF (S/r = 1)

• T, where CDF (Sff = 1) t is CDP for the year, given a loss of train / system Tc is exposure tirne (detection time + AOT)

Measure of Risk: CDF(PDF) = A

• CCDP = (A

• To

• CDF (Str = 1))[llyr]

Table 2 2 of the August 6,1997 submhbl provides a simplified way to rank consequences when a pipe break resulis in a loss of a single or multiple train / system. This table will be explained in detail in response to the next RAI. It provides a conservative, simplified substitute for the PRA importance measures (which can not be applied in their original fonn, due to exposure time, location-specific recoveries, etc.).

Example: A pipe break results in the loss ofa LPCI Train. LPCIis called upon to mitigate DB CA TIVEvents (i.e. Large LOCA). More than two backup trains are still available to satisfy the lowpressure makeupfunction (Figure 3.1), the Core Spray System, and other LPCItrain. Given an exposure time of"long AOT,"from Table 2 2, the consequence rank is " LOW. "

Configuration 3: A pipe break occurs when system operation is required by an independent demand. For example, a small LOCA event produces the need for llPCI operation, and a llPCI start results in an additional break, thereby disabling IIPCI.

Start of the Event: An Independent Initiator Effect on the Plant Operation: Safety System /frain Fails on Demand Due to PDF Measure of PDF Probability:

An Actual Measure of Probability: Pipe Failure on Demand, An 111-3 2

A Substitute Measure of PDF Probability: Fipe Failure Frequency, A [llyr)

Ap = A

• T, where T ls time between tests, or demands i

Measure of Consequences:

An Actual Measure of Consequencer: CDF(Fo)[llyr)(for a specific IE, given PDF failure on demand)

A Substitute Measure of Consequences: CCDP = CDF(Fo)

• Ti Measure of Risk: CDF(PDF) = An

• CDF (Fn)

= A

• T

• CDF (Fo) = A

• CCDP [l/yr) i NOTE: Substitute measures are introduced, so th..t the measure of PDF probability is always the same: frequency of pipe failure. Otherwise, a comparison will be necessary between frequency of failure versus failure on demand, which is not desirable.

The measure ofimportance of a system lost on demand would be similar to that in Configuration 2. The main difference is exposure time which, in this case, is considered to be the time since the last demand (either the test interval or all year).

Example: A transient with the loss offeedwater results in a PDF, disabling the HPCISystern. This event is considered a DB CAT 11 event (frequency = 0.1/yr).

Two backup trains are still availablefor the high pressure makeupfunction, RCIC and ADS (2 of 4 SRl's). The piping is not tested, so the exposure time is all year. Frorn Table 2 2, given the above characteristics, the consequence rank is "MEDIUAf. "

8.

PROVIDE A DISCUSSION OF Tile QUALITATIVE AND QUANTITATIVE BASIS FOR TABLE 2-2. SilOW TIIAT BOTil BASES ARE CONSISTENT Table 2 2 of the August 6,1977 submittal provides a simplified way to rank consequences when a pipe break results in a loss of a single or multiple trairis/ systems (no initiators). The table is based on three important factors, which, together, determine the importance of a system:

1. Ilow often is the system function called upon, or what is the " frequency of challenge,"(if all other factors are the same, systems called upon to mitigate a transient would be more important than syrtems called upon to mitigate a Large LOCA)

2. Ilow many backup systems are available for the same safety function, or what is the " number of unaffected backup trains."

3. Ilow long could the plant operate without the disabled train / system before it is shutdown, or what is the " exposure time."

111 33

_.____J

The quantitative basis for Table 2 2 is as follows:

IE Frequency IE Frequency Initiating Event Category Limits Maximum Yalue Dil CAT 11 (anticipated events)

(20.1/yr]

1/yr DB CAT 111 (infrequent events)

(0.01/yr 0.1/yr]

0.1/yr Dil CAT IV (accidents)

$0.01/yr]

0.01/yr l

l l

Exposure Time TyplealInterval Corresponding Value All Year 1 Year 1 yr Between Test 3 Months 0.25 yr l

Long AOT I Week 1.9E 2 yr l

Shon AOT I Day 2.7E 3 yr Unavailability Backup Train Unavailability Limits Mean Value 0.5 (3E 2,3E l]

1E 1 1

l3E 3,3E-2) lE 2 2

[3E 5,3E-4]

IE-4 3

[3E 7, ~$E 61 IE 6 Based on those limits, if a disabled system is needed to mitigate DB CAT 111 Initiating Evente, and it has one backup train and a week AOT (Long AOT), than the CCDP is expected to have a value of IE

• ET

• BU = 0.1/yr

• 1/50 yr

• 10 2 i

= 2E 5 and a consequence rank of" MEDIUM," as shown in Table 2 2 Corresponding quantitative values for Table 2 2 are shown in Figure 11181.

111 34

l.. -

-_J

Since the unavailability of a backup train is predenned in the methodology to have a median value of approximately 1 E 2; not all of the individual backup trains below:

Train (s)

Unavailability (U)

Corresponding " Train" Values LPCIA 9.2 E 3 1

41/2 log U)

LPCIA&B 2.5E 4 1.5 41/2 log U) llPCI 8.8E 2 0.5 41/2 log U) i introduction of this " train" values concept provides an equalizer in crediting backup trains. A train ofIIPCI (8.8E 2) can not be credited as equally as a train of LPCI (9.2E-3). This method provides a reliability basis for the mitigative function and assures quantitative defense hi depth of the plant response.

l t

11135 l

-j

l l

Figure III-8-1 Consequence Categories for Pipe Failures Resulting in System /frain Loss Affected Systems l

Number of Unaffected Backup Trains Frequency of Exposure Time to Challenge Challenge All year m _

2bE4k* we Between tests Anticipated 2.5E-05 ?

1 (1-3 months) g;; m,

Sy,

=~

-~*w""

a w

Ty'.9E45gs Long AOT ill (DB Cat II)

(1-2 weeks)

.ww: - -,.,

Short AOT(s3 days)

EE2.7E-05 s br: m.

42.7E497%q

w. :. -

..~m

.s c p.

,s. e.- +

All year

-1.0E453 i M.0E47tf infrequent s

Between tests

'W f

YR2.5E-08D3 (DB Cat Ill)

(1-3 months)

%w-Y

-- #_ g :e

.7.y - j;3 g,

-;e 2

Long AOT

' 11.9E-05 :~

.9E 07$Y A E 1.9 5 09Y -

(1-2 weeks) w%r %f m W:f -

c o-r x m.+:

~..

Short AOT(s3 days 42.7E4SE W2.7E-10f 4

n wa,

All year yk1.9E-OSiL2 Unexpected x; -

gg : ::

2 +3' : ~ g.

a Between tests

-~E47.L,;L2.'6E4feg c: -

w f 2.5E-05 7 (DB Cat IV)

(14 months) r-xm NA NW !-

Lon9 AOT

.9E4SM NR1.9E-10' (1-2 weeks) a#

qp r-Short AOT(<3 days) fl2.7E47 12.7E-09 R.

• 2.7E-11 %.

,n

-=

n.

III-36

IV.

SELECTIONS 1.

PROVIDE WRITTEN DESCRIPTION OF Ti!E INSPECTION METilODS AND QUALIFICATION OF INSPECTION EQUIPMENT AND INSPECTION PERSONNEL

'lhe inspection method in all cases for Class 1 piping welds will be ultrasonic. The ultrasonic techniques will be tailored to look for the damage mechanism that is expected based on the Vermont Yankee damage mechardsm calculation. The procedures will be revised to reflect indication evaluation for each type of damage mechanism and to reflect the extended examination volume depending on the damage mechanism as detailed in EPRI TR 106706, Chapter 7. This infonnation is also provided as Attaclunent 2 to this submittal. The qualification of techniques, eqdoment and personnel is addressed in RAI 6 of this section.

2.

PROVIDE WRITTEN DESCRIPTION OF llOW INSPECTION LOCATIONS WERE SELECTED PER SYSTEM The Code Case N560 selection process ranks each segment and, therefore, each element (i.e. location) within a segment into one of seven risk categories. These are Risk Categories 1 through 7, with Risk Category 1 being of the highest risk significance. Generally, the highest ranked locations are chosen for inspection.

Identification of the candidate locations also takes into consideration the severity of the potential degradation mechanism, the potential to have multiple degradation mechanisms within a system, ALARA considerations, previous inspection results, access, and scafrolding requirements, in addition to the aforementioned, if a segment consists of a short run of piping and has several locations, ollen only one or two locations will be chosen provided that the inspection (s) is valid for the entire segment.

As an example, the feedwater system will be discussed. This system consists of sixty nine category B.J welds. Nine locations were identified as Risk Category 1.

Due tc the risk significance of these locations, all were chosen for inspection. As these locations are susceptible to flow assisted corrosion, the examination volume for these inspections is substantially larger than for a typical Section XI exam.

Six segments consisting of 22 locations were categorized as Risk Category 2. Of these, four segments are potentially susceptible to thermal transients (TT) and two segments are potentially susceptible to TACSC. For these six segments, seven locations were chosen for inspection. The locations were chosen so that each segment has at least one location inspected and both potential degradation mechanisms are addressed (i.e. TT and TASCS). The remaining locations within IV-37

the feedwater system were ranked as either medium risk (Risk Category 4 or 5) or low risk (Risk Category 6). Therefore, a total of sixteen locations where chosen for volumetric inspection as part of the N560 Program.

3.

PROVIDE WRITTEN DESCRIPTION OF llOW INSPECTION LOCATIONS WERE ALLOCATED AMONG SYSTEMS Code Case N560 requk s a sample size of 10% of the population ofIN category welds within a system, llowever, N560 allows a redistribution of the sampling to be more heavily weighted on the higher risk systems. As can be seen from the response to RAI 2 of this section,16 of the 69 feedwater locations were chosen for inspection. This represents a sample size of 23%. Tables IV 3 1 & IV 3 2 provide a summary of how the inspection locations were distributed among systems. As can be seen from Table IV-3 1, Main Steam Drains (MSD) and the RCIC system were selected to receive only pressure and leakage testing (i.e. no volumetric exams). This is because these systems generally contain low risk locations and performance history to date has not identined any potential degradation (Risk Category 6/7, except for six Risk Category 5 locations).

The Main Steam System was a candidate for reallocation due to its risk categorization and exceptional inspection record to date. There were 105 Risk Category 4 locations (i.e. no degradation mechanism identined) and 12 locations identified as Risk Categories 6/7. The Reactor Water Cleanup System (RWCU) had only two locations identified as medium risk, one of which was selected for inspection. The Reactor Water Recirculation System (RECIRC) had only two locations identified as Risk Category 2, both of which were chosen for inspection.

In addition, two Risk Category 4 locations (i.e. no degradation mechanism) were selected for inspection.

The inspections reallocated from the above synems were distributed to the CS and the FW Systems. The FW System was discussed above. The CS System consisted of twenty Risk Category 2 locations, eight of which were selected for inspection and six Risk Category 4 locations (no degradation mechanisms were identified).

IV.38 y

Table IV-3-1 System Per System Category 1 Category 2 Category 4 Category 5 Category 6

&7 No.of No. of No. of Welds No. of Welds No. of Weids No. e. Welds No.of Welds Welds Segnients Total Old New Total Old New Total Old New Total Old New Total Old New SXI SXI SXI SXI SXI SXI SXI SXI SXI SXI 29 9

8 6

2 6

I CS 32 8

FW.

69 23 9

9 9

24 12 7

34 4

1 1

7 2

12 3

2 HPCI 19 2

12 3

ISS 29 4

p1S 117 8

MrD 8

19 6

2 2

RCIC 18.

1 18

.5 14 4

RECIRC 69 10

-2 2

53 14 2

-21 7

6 18-4 18 7

RHR 57 11 16 5

2 1

RWCU 18 4

Total:

407 77 9

9 9

67 28 23 23e 56 9

7' 2

94 27 IV-39 L__

Table IV-3-2 Welds Per System l

High Risk Medium Risk Lew Risk Regios Old New Region Region (Cat. 6 & 7)

SXI Program SXI Programs (Cat.1 & 2)

(Cct. 4 & 5)

System No.

No. -

No.

No.

No.-

No.

CS 32 26 62.5 %

~6 18.8 %

6 18.8 %

12 37.5 %

8-25.t*4 FW 69 33 47.8 %

35 50.7%

1.4 %

16 23.2 %

16 23.2 %

~ * -

12 --

63.2 %

7 36.8%

5 26 3 %

2 19.5 %

HPCI 19 MS-117 195 89.7 %

12 10 3 %

32 27.4 %

4 3.4 %

6 75.9 %

2 25.9%

2 25 #4 MSD 8

18.

100.9 %

5 27 #4 RCIC 18 RECIRC 69 2.

2.9 %

53 76 #/.

14 203 %

18 26.1 %

4 5#4 RHR 57 21 36.8 %

18-31.6 %

.18 31.6 %

18 31.6 %

6 19.5 %

2 11.1 %

-16 88.9 %

5 27 #/.

1-5.6 %

RWCU 18 Total: 407 76 18.7 %

237-58.2 %

94 23.1 %

113 27#4 41 19.1 %

IV-40

4.

PROVIDE WRITTEN DESCRIPTION OF EACII LOCATION, WilETilER IT IS CURRENTLY llEING INSPECTED, WilETilER IT WILL HE INSPECTED UNDER N560. OR NOT INSPECTED.

Table IV-4 1 provides a summary, on a system basis of each location within the N560 scope. The following discussion will also be provided on a system by-system basis.

L l

Core Soray The core spray system consists of 32 locations. Twenty of these 32 locations were not volumetrically inspected as part of the current Section XI Program, nor are they recommended for inspection as part of the N560 Program.

l The remaining twelve locations are currently being inspected as part of the l

existing Section XI Program. The N560 Program recommends that eight of these l

twelve locations be inspected. Of these four locations not being inspected as part of the N560 Program, one is a Risk Category 7 (i.e. low risk) and two a e Risk Category 4 (i.e. no degradation mechanism). The remaining location is in a Risk Category 2 segment which was identified as potentially susceptible to TASCS, As part of the N560 Program, this segment has four other locations recommended for inspection. Therefore, if TASCS is an active mechanism, and inspection history to date has shown it not to be, then inspection of these locations will identify the mechanism, i

Feedwater The feedwater system consists of 69 locations. 43 of these locations were not volumetrically inspected as part of the current Section XI Program (or FAC Program), and they are not recommended for inspection as part of the N560 Program. Filleen of the remaining 26 locations were conducted as part of the current Section XI Program (or FAC Program) and are recommended for inspection as part of the N560 Program. Of the remaining 11 locations,5 are in segments located near the RPV nozzles potentially susceptible to thermal fatigue (segments FW 003,006,009,012). Each of these segments contains other locations that will be volumetrically inspected as part of the N560 Program, in addition, Vermont Yankee monitors feedwater nozzles for bypas:: flow with four thermocouples per nozzle. Four locations (segments FW 019 & 020) are in segments that were identified as not being susceptible to degradation mechanisms.

One location (segment FW 018) is in a Risk Category 2 segment which is actually part of a continuous run of piping comprised of three segments (segments FW.

016,017 & 018). This run of piping was broken into three segments due to the difTerent consequence of failure for segment FW-017. All three segments are potentially susceptible to TASCS due to RWCU flow through the RCIC connection to feedwater during low power conditions. The volumetric inspections to be conducted on segment FW-016 will provide the necessary indication on whether TASCS is an active mechanism for these three segments. Inspection history to date has shown this not to be the case.

IV-41 w

11PCI Tne portion of the llPCI system within the scope of the N560 Program consists only of the steam supply to the llPCI turbine. The remainder of the llPCI system (e.g. turbine exhaust, pump supply and discharge) is unatted by this evaluation. Therefore, the N560 portion of the llPCI system consMs of 19 locations. Five of these locations were inspected as part of the current Section XI Program and two will continue to be inspected as part of the N560 Program. Of the remaining three locations, one is a Risk Category 4 location (no identified degradation mechanism) and the other two are Risk Category 6 locations (i.e. Iow risk). The inspection history to date has not identified any flaws or indications.

Main Steam (MS) The main steam system consists of 117 locations. 85 of these locations were not volumetrically inspected as part of the current Section XI Program nor are they recommended for inspection as part of the N560 Program.

The remaining thirty two locations are currently being inspected as part of the existing Section XI Program, of which four are recommended to be inspected as part of the N560 Program. A review of the evaluation results for the main steam system reveals that all locations were identified as not being susceptible to degradation mechanisms. This is consistent with industry performance history of this type of Class I piping as well as the Vermont Yankee inspection history for this system.

Main Steam Dmin (MSD) The MSD system consists of 8 locations,2 of these locations were inspected as part of the current Section XI Program. Given the low risk significance of this system it was felt prudent to not volumetrically inspect this system and to allocate its inspection to a more risk significant system. Please see the response to RAI 8 of this section. As with all the other systems, the MSD systems will continue to be subjected to pressure and leakage testing requirements.

Reactor Core Isolation Cooling (RCIC) The porticn of the RCIC system within the scope of the N560 Program consists only of the steam supply to the RCIC turbine. The remainder of the RCIC system (e.g. turbine exhaust, pump supply and discharge) is unaffected by this evaluation. Therefore, the N560 portion of the RCIC system consists of 18 locations, five of these locations were being inspected as part of the current Section XI Program. All locations are Risk Category 6 and were identified as being not susceptible to degradation mechanisms. Given the low risk significance of this piping and the lack of an identifiable degradatio a mechanism, it was felt prudent to not volumetrically inspect this system and to allocate its inspections to a more risk significant system. Please see the response to RAI 8 of this section. As with all the other systems, the RCIC system will continue to be subjected to pressure and leakage testing requirements.

Reactor Water Recirculat.. MECIRC) The RECIRC system consists of 69 locations.18 of these inspections were inspected as part of the current Section XI IV-42 O

Program. The results of the N560 cvaluation ranked the RECIRC system into three risk categories. There were two Risk Category 2 locations (segments RECIRC 006 & 008; high consequence and susceptible to thermal fatigue). Both these locations are recommended for inspection as part of the N560 Program and were not being inspected as part of the current Section XI Program. Filly three locations were ranked as Risk Category 4 (no degradation mechanism) and fourteen locations as Risk Category 6 (no degradation mechanism). Given that the Vermont Yankee RECIRC System has undergone an extensive piping replacement effort with resistant material, PSI and ISI results to date have not identified any degradation, and due to the lack ofidentifiable degradation mechanisms, it was felt pruder.t to allocate several inspections to higher risk systems, in order, to provide some additional monitoring of the RECIF C system, it was decided to also inspect one location on the supply side ofloop 'A' and one on the discharge side ofloop 'B'.

Residual llent hmoval(RilR) The RllR system consists of 57 locations.

Thirty eight locations are not being inspected or proposed to be inspected under the N560 Program. Eighteen of the 57 locations are currently being inspected as part of the existing Section XI Program. The N560 Program recommends that five of these eighteen locations continue to be inspected but with a larger, more appropriate, inspection volume. Also, as part of the N560 Program, an additional location (i.e. the nineteenth location) was chosen to better monitor the potential thermal fatigue mechanism at segment RilR-003. Of the thirteen previousSection XI inspections not selected in the N560 Program, eleven inspections are in segments that have no identifiable degradation mechanisms (segments RilR-002,001,005,006,007 & 008). The remaining two locations are in segments RilR 001 and 011. Under the N560 Program, at least one location in both these segments is being inspected, including expanded, more appropriate volumes.

hactor Water Cleanun (RWCU) The RWCU system consists of 18 locations.

All but two of these locations are either Risk Category 6 or 7, with no degradation mechanism (i.e. Iow risk). Of these sixteen locations, five were volumetrically inspected as part of the current Section XI Program. The remaining two locations, are Risk Category 4 (high consequence, no degradation mechanism). One of these two Risk Category 4 locations was chosen for inspection as part of the N560 Program.

IV-43 1

Tablo lV-41 Inspection Summary -

Expended Degradation Consequence Risk - In Section Xilnspection Segment ID WoldID Mechanisms -

Type Category Old New CS-001 CS4A F3 N

ISLOCA CAT 4 CS4A F3A N

lSLOCA CAT 4 Yes CS-002 CS4A-Fi N-PLOCA CAT 7 CS4A-F1A N

PLOCA CAT 7 CS4A-F2 N

PLOCA CAT 7 0 3-003 CS4A F3DW N

LLOCA CAT 4 CS-004 CS4A F3ADW TASCS LLOCA CAT 2 Yes Yes Yes CS4A-F3B TASCS LLOCA CAT 2 CS4A-F4 TASCS LLOCA CAT 2 CS4A-MF5 TASCS LLOCA CAT 2

-Yes CS4A-MFSA TASCS-LLOCA CAT 2 Yes Yes Yes CS4A-MF5B TASCS LLOCA CAT 2 CS4A MF5C-TASCS LLOCA CAT 2 CS4A-MF5D TASCS LLOCA CAT 2 Yes Yes Yes CS4A-MF6 TASCS LLOCA CAT 2 CS4A-MF6A -

TASCS LLOCA CAT 2 Yes Yes Yes CS 005 CS48-F3 N

ISLOCA

' CAT 4 CS4B-F3A N

ISLOCA CAT 4 Yes CS-006 CS4B-F1 N

PLOCA CAT 7

- CS4B F1A N

PLOCA CAT 7 Yes CS4B-F2 N

PLOCA-CAT 7 CS-007 CS48 F3DW N

LLOCA CAT 4 CS-008 -

CS4B-F3ADW TASCS LLOCA CAT 2 Yes Yes Yes CS48-F3B TASCS LLOCA CAT 2 CS48-F4 TASCS LLOCA CAT 2 CS4B-MF5 TASCS LLOCA CAT 2 Yes Yes Yes CS4B-MF5A-TASCS LLOCA CAT 2 CS4B-MF5B TASCS LLOCA CAT 2 Yes Yes Yes CS48-MF50 TASCS-LLOCA CAT 2 CS4B-MF5D TASCS LLOCA CAT 2-CS4B-MF6 TASCS LLOCA CAT 2 CS48-MF6A TASCS LLOCA CAT 2 (es Yes Yes IV-44 3

Table IV-41 Inspection Summary Expanded Degradation Consequence Risk in Section Xilnspection Segment ID Weld ID Mechanisms Type Category Old New FW-001 FW18-F4 FAC LLOCA CAT 1 Yes Yes Same FW-002 FW18-F5-SA N

LLOCA CAT 4 FW18 ?5 N

LLOCA CAT 4 FW-003 FW18-F5A-SB TT LLOCA CAT 2 FW18-F5A SA TT LLOCA CAT 2 FW18-F5A TT LLOCA CAT 2 FW18-F6 TT LLOCA CAT 2 Yes Yes Yes FW18-N4C-SW TT LLOCA CAT 2 Yes FW-004 FW19-F4 FAC LLOCA CAT 1 Yes Yes Same i

FW-005 FW19-F4A N

LLOCA CAT 4 l

FW19-F5 N

LLOCA CAT 4 FW19-F5A N

LLOCA CAT 4 FW19-F6-SA N

LLOCA CAT 4 FW19-F6 N

LLOCA CAT 4 FW-006 FW19 F6A SB TT LLOCA CAT 2 FW19 F6A-SA TT LLOCA CAT 2 Yes Yes FW19 F6A TT LLOCA CAT 2 FW19-F7 TT LLOCA CAT 2 Yes FW19-N4A SW TT LLOCA CAT 2 Yes Yes Yes FW-007 FW20 53B FAC LLOCA CAT 1 Yes Yes Same FW20-Fi FAC LLOCA CAT 1 Yes Yes Same FW20-F1B FAC LLOCA CAT 1 Yes Yes Same FW-008 FW20-F1A N

LLOCA CAT 4 FW20-F2 N

LLOCA CAT 4 FW20-F2A N

LLOCA CAT 4 FW20-F3-SA N

LLOCA CAT 4 FW20-F3 N

LLOCA CAT 4 FW-009 FW20-F3A-SB TT LLOCA CAT 2 FW20-F3A-SA TT LLOCA CAT 2 FW20-F3A TT LLOCA CAT 2 FW20-F4 '

TT LLOCA CAT 2 Yes FW20-N4D-SW TT LLOCA CAT 2 Yes Yes Yes FW-010 FW21-F1 FAC LLOCA CAT 1 Yes Yes Same FW-011 FW21-F2-SA N

LLOCA CAT 4 FW21-F2 N

LLOCA CAT 4 FW-012 FW21-F2A-SB TT LLOCA CAT 2 IV-45 J

Table ?! 41 Inspection Summary Expanded Degradation Consequence Risk in Section Xilnspection Segment ID Wold ID Mechanisms Type Category Old New FW-012 FW21-F2A-SA TT LLOCA CAT 2 FW21 F2A TT LLOCA CAT 2 Yes FW21 F3 TT LLOCA CAT 2 Yes Yes Yes FW21 N4B-SW TT LLOCA CAT 2 Yes FW-013 FW16-MF7 N

LOCA-OC CAT 4 FW16 F8 N

LOCA-OC CAT 4 FW 014 FW16-F8A N

TFWMS CAT 6 FW-015 FW16-F9 N

LLOCA CAT 4 FW16-F9A N

LLOCA CAT 4 FW16-F10 N

LLOCA CAT 4 FW-016 FW17-MF4 TASCS LOCA-OC CAT 2 Yes Yes Yes FW17-MF4A TASCS LOCA-OC CAT 2 Yes Yes Yes FW-017 FW17-FSA TASCS TFWMS CAT 5 FW-018 FW17 F6 TASCS LLOCA CAT 2 Yes FW17-F6A TASCS LLOCA CAT 2 FW-019 FW17 F7 N

LLOCA CAT 4 Yes FW-020 FW18-F2 N

LLOCA CAT 4 Yes FW18-F2A N

LLOCA CAT 4 l

FW18-F2B N

LLOCA CAT 4 l

FW18-F2C N

LLOCA CAT 4 Yes FW18-F2D N

LLOCA CAT 4 Yes i

FW18-F2E N

LLOCA CAT 4 FW18-F3 N

LLOCA CAT 4 FW-021 FW18-F3A FAC LLOCA CAT 1 Yes Yes Same FW-022 FW19-F2 N

LLOCA CAT 4 FW19-F2A N

LLOCA CAT 4 FW19-F2B N

LLOCA CAT 4 FW19-F2C N

LLOCA CAT 4 FW19-F2D N

LLOCA CAT 4 FW19-F3 N

LLOCA CAT 4 FW19-F3A N

LLOCA CAT 4 FW-023 FW19-F3B FAC LLOCA CAT 1 Yes Yes Same FW19 F3C FAC LLOCA CAT 1 Yes Yes Same IV-46 J

Table IV 41 Inspection Summary Expanded Degradation Consequence Risk In Section Xllnspection Segment ID Weld ID Mechanisms Type Category Old New HPCI-001 MS4A-Fi N

LLOCA CAT 4 Yes MS4A F1A N

LLOCA CAT 4 MS4A F1B N

LLOCA CAT 4 MS4A-F1C N

LLOCA CAT 4 MS4A-F2 N

LLOCA CAT 4 Yes Yes Yes MS4A-F2A N

LLOCA CAT 4 Yes Yes Yes MS4A-F3 N

LLOCA CAT 4 MS4A-F3A N

LLOCA CAT 4 MS4A-F3B N

LLOCA CAT 4 MS4A-F3C N

LLOCA CAT 4 MS4A-F3D N

LLOCA CAT 4 MS4A F4 N

LLOCA CAT 4 l

HPCI-002 MS4A-F5 N

ILOCA CAT 6 MS4A-FSA N

ILOCA CAT 6 Yes MS4A-F3 N

ILOCA CAT 6 MS4A-F6A N

ILOCA CAT 6 MS4A-F6B N

ILOCA CAT 6 Yes MS4A F6C N

ILOCA CAT 6 MS4A-F7 N

ILOCA CAT 6 L

IV-47

Table IV 41 Inspection Gummary Expanded Degradation Consequence Risk in Section Xllnspection Segment ID Weld ID Mechanisms Type Category Old New MS-001 MS7A-N3A SW N

LLOCA CAT 4 Yes MS7A A8 N

LLOCA CAT 4 Yes MS7A-A7D N

LLOCA CAT 4 Yes MS7A-A7C N

LLOCA CAT 4 Yes MS7A-A7B N

LLOCA CAT 4 Yes MS7A-A7A N

LLOCA CAT 4 Yes Yes Yes MS7A-A7 N

LLOCA CAT 4 MS7A-A6B N

LLOCA CAT 4 MS7A-A6A N

LLOCA CAT 4 MS7A-A6 N

LLOCA CAT 4 MS7A-A5K N

LLOCA CAT 4 MS7A-A5J N

LLOCA CAT 4 Yes MS7A-A51 N

LLOCA CAT 4 Yes MS7A-A5H N

LLOCA CAT 4 Yes MS7A-ASG N

LLOCA CAT 4 Yes l

MSiA-A5F N

LLOTA CAT 4 Yes MS7A-ASE N

LLOCA CAT 4 Yes MS7A-A5D N

LLOCA CAT 4 MS7A-ASC N

LLOCA CAT 4 MS7A-ASB N

LLOCA CAT 4 MS7A-ASA N

LLOCA CAT 4 Yes MS7A-A5 N

LLOCA CAT 4 Yes MS7A-A11 N

LLOCA CAT 4 Yes MS7A-A4A N

LLOCA CAT 4 Yes MS7A-A4 N

LLOCA CAT 4 MS-002 MS7A-A3 N

ILOCA CAT 6 Yes MS7A-A9A N

LOCA-OC CAT 6 Yes MS7A-A9 N

LOCA-OC CAT 6 Yes MS-003 MS78-N38 SW N

LLOCA CAT 4 Yes MS7B-88 N

LLOCA CAT 4 Yes MS78-87D N

LLOCA CAT 4 MS78 B7C N

LLOCA CAT 4 Yes MS78-B78 N

LLOCA CAT 4 Yes MS78 B7A N

LLOCA CAT 4 Yes MS78-B7 N

LLOCA CAT 4 MS78-B6D N

LLOCA CAT 4 MS78-B6C N

LLOCA CAT 4 MS7B-B6B N

LLOCA CAT 4 MS7B-B6A N

LLOCA CAT 4 Yes MS7B-86 N

LLOCA CAT 4 Yes Yes Yes IV-48 m_c -

Table IV 41 Inspection Summary Expanded Degradation Consequence Risk in Section Xilnsp>ction Segment ID Wold ID Mechanisms Type Category Old New MS-003 MS7B-85H N

LLOCA CAT 4 Yes MS78-B5E N

LLOCA CAT 4 MS78 B5F N

LLOCA CAT 4 MS7B-B5G N

LLOCA CAT 4 MS7B B5B N

LLOCA CAT 4 Yes MS78 BSC N

LLOCA CAT 4 MS7B BSD N

LLOCA CAT 4 MS7B-BSA N

LLOCA CAT 4 MS7B-B5 N

LLOCA CAT 4 MS78-B11 N

LLOCA CAT 4 MS78-B4C N

LLOCA CAT 4 MS7B-B4B N

LLOCA CAT 4 l

MS78-B4A N

LLOCA CAT 4 l

MS78 B4 N

LLOCA CAT 4 MS-004 MS78-B3 N

ILOCA CAT 6 MS78-B9A N

LOCA-OC CAT 6 MS78-89 N

LOCA-OC CAT 6 MS-005 MS7C-N3C-SW N

LLOCA CAT 4 Yes Yes Yes MS7C-C8 N

LLOCA CAT 4 Yes MS7C-C7D N

LLOCA CAT 4 MS7C-C7C N

LLOCA CAT 4 MS7C-C78 N

LLOCA CAT 4 MS7C-C7A N

LLOCA CAT 4 MS7C-C7 N

LLOCA CAT 4 MS7C-C6D N

LLOCA CAT 4 MS7C-C6C N

LLOCA CAT 4 MS7C-C6B N

LLOCA CAT 4 MS7C-C6A N

LLOCA CAT 4 MS7C-C6 N

LLOCA CAT 4 MS7C-C5K N

LLOCA CAT 4 MS7C-C5H N

LLOCA CAT 4 MS7C-C51 N

LLOCA CAT 4 MS7C-C5J N

LLOCA CAT 4 MS7C-CSG N

LLOCA CAT 4 MS7C-CSF N

LLOCA CAT 4 MS7C-C5E N

LLOCA CAT 4 MS70-C5B N

LLOCA CAT 4 MS7C-C5C N

LLOCA CAT 4 MS7C-CSD N

LLOCA CAT 4 MS7C-C5L N

LLOCA CAT 4 IV-49

Table IV 41 Inspection Summary Expanded Degradation Consequence Risk in Section Xilnspection Segment ID

- Wold ID Mechanisms Type Category Old New MS-005 MS7C-CSA N

LLOCA CAT 4 MS7C-C5 N

Lt.OCA CAT 4 MS7C-C11 N

LLOCA CAT 4 MS7C-C4C N

LLOCA CAT 4 MS70-C4B N

LLOCA CAT 4 MS7C-C4A N

LLOCA CAT 4 MS7C-C4 N

LLOCA CAT 4 MS-006 MS7C-C3 N

ILOCA CAT 6 MS7C-C9A N

LOCA-OC CAT 6 l

MS7C-C9 N

LOCA-OC CAT 6 MS-007 MS7D-N3D-SW N

LLOCA CAT 4 Yss MS7D-D8 N

LLOCA CAT 4 Yes Yes Yes MS7D-D7D N

LLOCA CAT 4 i

MS7D-D7C N

LLOCA CAT 4 MS70-D78 N

LLOCA CAT 4 MS7D-D7A N

LLOCA CAT 4 MS7D-D7 N

LLOCA CAT 4 MS7D-D6B N

LLOCA CAT 4 MS7D-D6A N

LLOCA CAT 4 MS7D-D6 N

LLOCA CAT 4 MS7D-D5K N

LLOCA CAT 4 MS7D-D51 N

LLOCA CAT 4 MS70-D5J N

LLOCA CAT 4 MS70-D5H N

LLOCA CAT 4 MS7D-D5F N

LLOCA CAT 4 MS7D-D5G N

LLOCA CAT 4 MS7D-D5E N

LLOCA CAT 4 MS7D-D5D N

LLOCA CAT 4 MS7D-05C N

LLOCA CAT 4 MS7D-D5B N

LLOCA CAT 4 MS7D-DSA N

LLOCA CAT 4 MS7D-D5 N

LLOCA CAT 4 MS7D-D11 N

LLOCA CAT 4 MS7D-D4 N

LLOCA CAT 4 MS-008 MS7D-D3 N

ILOCA CAT 6 MS7D-D9A N

LOCA-OC CAT 6 MS7D-D9 N

LOCA-OC CAT 6 IV-50

Table IV-41 Inspection Summary Expanded Degradation Consequence Risk i.,3ection XIlnspection -

Segment ID Weld ID Mechanisms Type Category Old New MSD-001 MSD2-F1 TASCS MLOCA CATS Yes MSD-002 MSD2 F2 TASCS PLOCA CAT 6 MSD2-F3 TASCS PLOCA CAT 6 MSD-003 MSD2 F4 TASCS LOCA-OC CAT 5 MSD2-Si TASCS MLOCA CATS MSD2-S2 TASCS MLOCA CAT 5 MSD2-S4 TASCS MLOCA CATS Yes l

MSD2-S3 TASCS MLOCA CATS IV-51

_~

Table IV 4-1 Inspection Summary Expanded Degradation Consequence Risk in Section Xllnspection Segment ID Weld ID Mechanisms Type Category Old New RCIC-001 MSSA-F1 N

MLOCA CAT 6 Yes MS5A-F1A N

MLOCA CAT 6 Yes MSSA-F1B N

MLOCA CAT 6 MSSA-F1C N

MLOCA CAT 6 MSSA-F1D N

MLOCA CAT 6 Yes MS5A F1E N

MLOCA CAT 6 Yes MS5A-F2 N

MLOCA CAT 6 MSSA F3 N

ILOCA CAT 6 MS5A F3A N

ILOCA CAT 6 MSSA-F3B N

ILOCA CAT 6 MSSA-F4 N

ILOCA CAT 6 MSSA-F4A N

LOCA-OC CAT 6 MSSA-F5 N

LOCA-OC CAT 6 MSSA-F5A N

LOCA-OC CAT 6 MSSA-F5B N

LOCA-OC CAT 6 MSSA F5C N

LOCA-OC CAT 6 MSSA-F6 N

LOCA-CC CAT 8 MS5A-F7 N

LOCA-OC CAT 6 Yes b

IV-52

Table IV 41 Inspection Summary Expanded Degradation Consequence Risk In Section Xilnspection Segment ID Weld ID Mechanisms Type Category Old New RECIRC-001 RR-N2F-1 N

LLOCA CAT 4 RR-N2F-2 N

LLOCA CAT 4 RR-N2G-1 N

LLOCA CAT 4 RR N2G-2 N

LLOCA CAT 4 RR N2H-1 N

LLOCA CAT 4 Yes RR-N2H 2 N

LLOCA CAT 4 RR N2J-1 N

LLOCA CAT 4 RR-N2J-2 N

LLOCA CAT 4 RR N2K-1 N

LLOCA CAT 4 RR N2K-2 N

LLOCA CAT 4 RECIRC-002 RR N2A-1 N

LLOCA CAT 4 Yes RR-N2A-2 N

LLOCA CAT 4 RR-N2B-1 N

LLOCA CAT 4 RR-N2B-2 N

LLOCA CAT 4 RR-N2C-1 N

LLOCA CAT 4 Yes RR-N2C-2 N

LLOCA CAT 4 Yes RR N2D-1 N

LLOCA CAT 4 Yes RR N2D 2 N

LLOCA CAT 4 Yes RR-N2E 1 N

LLOCA CAT 4 Yes Yes RR-N2E-2 N

LLOCA CAT 4 RECIRC-003 RR RH-A-1 N

LLOCA CAT 4 RR-RH-A-2 N

LLOCA CAT 4 Yes RR-RH-A-3 N

LLOCA CAT 4 RR-RH-A-4 N

LLOCA CAT 4 RECIRC-004 RR-RH-B-1 N

LLOCA CAT 4 Yes RR-RH-B-2 N

LLOCA CAT 4 RR-RH-B-3 N

LLOCA CAT 4 RR-RH-B-4 N

LLOCA CAT 4 RECIRC-005 RR-AS-1 N

LLOCA CAT 4 Yes RR AS-2 N

LLOCA CAT 4 Yes Yes Yes RR-AS-3 N

LLOCA CAT 4 RR-AS-4 N

LLOCA CAT 4 RR-AS-5 N

LLOCA CAT 4 Yes RR-AS-6 N

LLOCA CAT 4 Yes RR-AS-7 N

LLOCA CAT 4 RR-AD-8 N

LLOCA CAT 4 Yes RR-AB-1 N

LLOCA CAT 4 RR-AD-9 N

LLOCA CAT 4 RR-AD-10 N

LLOCA CAT 4 IV-53

Table IV 41 Inspection Summary Expanded Degradation Consequence Risk in Section Xllnspection Segment ID Weld ID -

Mechanisms Type Category Old New RECIRC-005 RR-AD-12 N-LLOCA CAT 4 RECIRC-006 RR-AD 13 TT LLOCA CAT 2 Yes Yes RECIRC-007 RR-BS-1 N

LLOCA CAT 4 Yes RR BS-2 N

LLOCA CAT 4 RR BS-3 N

LLOCA CAT 4 RR BS-4 N

LLOCA CAT 4 RR BS-5 N

LLOCA CAT 4 RR-BS-6 N

LLOCA CAT 4 RR-BS-7 N

LLOCA CAT 4 RR BD-8 N

LLOCA CAT 4 RR-BB-1 N

LLOCA CAT 4 RR BD-9 N

LLOCA CAT 4 i

RR BD-10 N

LLOCA CAT 4 RR BD-11 N

LLOCA CAT 4 RR BD-12 N

LLOCA CAT 4 RECIRC-008 RR-BD-13 TT LLOCA CAT 2 Yes Yes RECIRC-009 RR AB-2 N

MLOCA CAT 6 Yes RR-AB-3 N

MLOCA CAT 6 Yes RR-AB-4 N

MLOCA CAT 6 RR AB-5 N

MLOCA CAT 6 RR-AB-6 N

MLOCA CAT 6 RR-AB-7 N

MLOCA CAT 6 Yes RR-AB-8 N

MLOCA CAT 6 Yes RECIRC-010 RR-BB-2 N

MLOCA CAT 6 RR BB-3 N

MLOCA CAT 6 RR BB-4 N

MLOCA CAT 6 RR-BB-5 N

MLOCA CAT 6 RR-BB-6 N

MLOCA CAT 6 RR-BB-7 N

MLOCA CAT 6 --

RR BB-8 N

MLOCA CAT 6 IV-54

x Tat:le IV 41 Inspection Summary Expanded Degradation Consequence Risk in Section XIlnspection Segment ID Weld ID Mechanisms Type Category Old New RHR-001 RH321 TASCS LLOCA CAT 2 Yes Yes Yes X

RH32 2 TASCS LLOCA CAT 2 RH32-3 TASCS LLOCA CAT 2 RH32-4 TASCS LLOCA CAT 2 Yes Yes Yes RH32 5 TASCS LLOCA CAT 2 Yes RH32-6 TASCS LLOCA CAT 2 RH32-7 TASCS LLOCA CAT 2 RHR-002 RH32-8 N

lLOCA CATO RH32 9 N

ILOCA CAT 6 RH32-10 N

ILOCA CAT 6 RH32-11 N

ILOCA CAT 6 Yes RH32-12 N

ILOCA CAT 6 Yes RH3213 N

ILOCA CAT 6 Yes RH3214 N

ILOCA CAT 6 RHR-003 RH3315 TT ISLOCA CAT 2 Yes Yes Yes l

RH33-16 TT ISLOCA CAT 2 Yes Yes RH33-17 TT ISLOCA CAT 2 RH33-18 TT ISLOCA CAT 2 RH33-19 TT ISLOCA CAT 2 RHR-004 RH28 25 N

ISLOCA CAT 4 RH28-24 N

ISLOCA CAT 4 RH28-23 N

ISLOCA CAT 4 RH28-22 N

ISLOCA CAT 4 RH28-21 N

ISLOCA CAT 4 RH23-20 N

ISLOCA CAT 4 Yes RHR-005 RH28-19 N

PLOCA CAT 7 RH28-18 N

PLOCA CAT 7 RH28-17 N

PLOCA CAT 7 RH28-16 N

PLOCA CAT 7 RH28-15 N

PLOCA CAT 7 Yes RH28-14 N

PLOCA CAT 7 Yes RH28-12 N

PLOCA CAT 7 Yes RHR-006 RH20-19 N

ISLOCA CAT 4 RH29-18 N

ISLOCA CAT 4 RH29-17 N

ISLOCA CAT 4 RH29-16 N

ISLOCA CAT 4 RH29-15 N

ISLOCA CAT 4 RH29-14 N

ISLOCA CAT 4

.Yes RHR-007 RH29-13 N

PLOCA CAT 7 IV-55 o

Table IV-41 Inspection Summary Expanded Degradation Consequence Risk in Section Xllnspection Segment ID Weld ID Mechanisms Type Category - Old New RHR-007 PH2912 N

PLOCA CAT 7 d29-11 N

PLOCA CAT 7 RH29-10 N

PLOCA CAT 7 Yes RHR 008 RH30-8 N

LLOCA CAT 4 RH30-7 N

LLOCA CAT 4 Yes RH30-6 N

LLOCA CAT 4 Yes RH30-9 N

LLOCA CAT 4 RH30-5 N

LLOCA CAT 4 RHR-009 RH30-4 TASCS,TT LLOCA CAT 2 RH30-3 TASCS,TT LLOCA CAT 2 RH30-2 TASCS,TT LLOCA CAT 2 RH30-1 TASCS,TT LLOCA CAT 2 Yes Yes Yes RHR-010 RH31-7 N

LLOCA CAT 4 RHR-011 RH31-6 TT LLOCA CAT 2 RH31-4 TT LLOCA CAT 2 RH31-3 1T LLOCA CAT 2 RH31-2 TT LLOCA CAT 2 Yes Yes Yes RH31-1 TT LLOCA CAT 2 Yes IV-56

Table IV-41 Inspection Summary Expanded Degradation Consequence Risk In Section Xlinspection Segment ID Wold ID Mechanisms Type Category Old New RWCU-001 CU18-10 N

MLOCA CAT 6 Yes CU18 9 N

MLOCA CAT 6 Yes CU18-8 N

MLOCA CAT 6 Yes CU18-7 N

MLOCA CAT 6 CU18-6 N

MLOCA CAT 6 CU18-5 N

MLOCA CAT 6 Yes RWCU-002 CU18-4 N

ILOCA CAT 7 CU18-3 N

ILOCA CAT 7 CU18-2 N

ILOCA CAT 7 CU18-1 N

ILOCA CAT 7 CU18-F13 N

ILOCA CAT 7 CU18-F14 N

ILOCA CAT 7 CU18-F15 N

ILOCA CAT 7 Yes CU18-F16 N

ILOCA CAT 7 CU18-F17 N

ILOCA CAT 7 CU18-F18 N

ILOCA CAT 7 l

RWCU-003 CU18-F23 N

LOCA-OC CAT 4 l

CU18-F25 N

LOCA-OC CAT 4 Yes Yes IV-57

f 5.

PROVIDE WRITTEN DESCRIPTION OF TIIE EXAMINATION VOLUME FOR EACII LOCATION INSPECTED, CONTRAST TIIE N560 VOLUME WITII TIIAT OF TIIE CURRENT PROGRAM The ultrasonic examination volumes will increase. Present ASME Code examination volumes on @ing wolds NPS 4 and larger are the inner 1/3t volume extending outward from the toe of the weld 1/4 inch. As an example, for thermal fatigue and IGSCC, the examination volumes for most piping welds performed in accordance with this code case will extend outward 1/4 inch from the outward end of the counterbore. The examination volumes for these and other configurations will be as shown in EPRI TR-106706, Chapter 7. This information is also provided as Attachment 2 to this submittal.

6.

PROVIDE WRITTEN DESCRIPTION OF TIIE EXTENT TO WIIICII PDI, APPENDIX VIII, AND TIIE RELIABILITY OF DETECTION IS ADDRESSED The ultrasonic techniques and equipment will not be qualified to ASME Section XI, Appendix VIII; however, the knowledge gained through the PDI qualification process will be used to design the specific techniques and make ultrasonic procedure revisions. Vermont Yankee is not in a position to endorse the use of Appendix VIII for this code case, however, it has been our customary practice for the last couple of outages to use PDI qualified ultrasonic examiners for ASME Section XI Code components.

7.

PROVIDE WRITTEN DESCRIPTION OF TIIE VARIATION IN TIIE INTENSITY OF AN INSPECTION (IF ANY) FOR INDIVIDUAL DEGRADATION MECIIANISM (e.g. IGSCC vs. MIC)

The NDE methods used to examine piping locations will meet current ASME Section XI requirements. However, over and above those requirements, the ultrasonic techniques will be tailored to the specific damage mechanism that is expected for each location. In addition to examination volume (coverage), the techniques will address such items as scan surfaces, instrument calibration, scanning sensitivity, probable location and nature of flaws, and evaluation of signals. These parameters are traditionally controlled by Code requirements and the procedures.

However, for Code Case N560, these parameters may vary depending on the damage mechanism. For example, for flow-assisted corrosion the examination coverage may be an entire elbow and/or extended length of pipe. The ultrasonic technique will specify a longitudinal straight beam to find thinned areas. For thermal fatigue, the technique will concentrate on the thinnest areas at or near a IV-58

__-_______A

weld using an angle beam to look for circumferential radial cracking. The guidance given in EPRI TR-106706, Chapter 7, will be used to define the techniques.

8.

PROVIDE WRITTEN DESCRIPTION AS TO TIIE DESIRABILITY (OR LACK TIIEREOF) OF INSPECTING RISK CATEGORY 5 LOCATIONS There are two systems that had segments whose risk ranking was Risk Category 5 (medium consequence, medium leak potential).

The feedwater system had one segment consisting of one location that was Risk Category 5 (FW-017). This location is physically located between two other segments (FW-016 & 018) whose rank was Risk Category 2 (high consequence, medium leak potential). All three of these segments are susceptible to the TACSC degradation mechanism. This is due to the potential to have RWCU flow into the feedwater system at low power conditions via the RCIC to feedwater connection. The inspection locations in the Risk Category 2 segment were chosen so that they would capture the efTect of TASCS for the entire run of piping (i.e. all three segments) as well as capture the location with the highest consequence of failure. Therefore, due to this location (Risk Category 5) being located within the drywell and that the mechanism is being monitored via another inspection, it is not desirable to inspect this location.

The main steam drain system is the other system containing Risk Category 5 locations. This system has two segments in this category, one segment consisting of one location and the other segment consisting of five locations. Given the.

lower risk significance of these locations and that two of these locations have been previously inspected it was felt prudent to allocate inspection to higher risk category locations. In addition, these locations (3" NPS) will still be subjected to pressure and leakage testing.

IV-59 i

[

o

V.

MONITORING I.

PROVIDE WRITTEN DESCRIPTION OF MONITORING ATTRIBUTES AND RELIABILITY GOALS The issues raised by this RAls are discussed in our response to RAI #1 in the PRA/DG 1061 section, specifically Principle #5 (Performanced based implementation and monitoring strategies).

2.

PROVIDE WRITTEN DESCRIPTION OF TIIE INSPECTION FREQUENCY AND OBSERVED DEGRADATION RATES ASME Code Case N560 has as its baseline, a ten year inspection interval. This interval is the same inspection interval that has been required by ASME Section XI and implemented by the industry for over twenty years. However, as N560 is an inspection for cause based program, it is attuned to the progressive nature of some degradation mechanisms. As such, potentially aggressive mechanisms such as FAC are required to be inspected as often as necessary, to properly identify, quantify and trend any and all degradation. Therefore, the results of each FAC inspection are reviewed and as necessary more frequent inspections than once per interval are conducted.

As discussed in the response to several RAIs, the only actual or potential degradation observed in category B-J piping at Vermont Yankee has been due to IGSCC or FAC. Again as discussed previously, the IGSCC susceptible piping has been replaced as part of an extensive piping replacement project in the late 1980s. Since the piping replacement project, PSI and ISI results have identified no instances of degradation due to IGSCC. Degradation due to FAC has been tracked since the 1980s at Vermont Yankee in response to Generic Letter 89-08.

Nine locations are to be inspected as part of the N560 Program. To date, there have been no failures nor significant degradation in category B J piping due to FAC.

3 PROVIDE WRITTEN DESCRIPTION OF HOW THE REDUCED NUMBER OF INSPECTIONS WILL NOT RESULT IN AN INCREASE IN LEAK RATES The industry survey conducted by the ASME Task Group on ISI Optimization (ASME Section XI Task Group on ISI Optimization Report No. 92-01-01, Revision 1, dated Sept.1995) identified that only a minimal number ofindications (five) were detected by the ASME Section XI Class 1 piping weld inspections. A V-60 l

review of these Indications revealed that none of the five would have developed into through wall leaks had they not been found by ISI, since they were non-propagating OD or sub-surface indications. Thus, even if none of the AShiE code required inspections had been performed during the past twenty years, no additional instances of primary coolant leakage would have occurred.

Conversely, a number ofinstances ofleakage due to unexpected degradation mechanisms (such IGSCC and thermal fatigue) have occurred. They just did not occur in the 25% weld samples that are required to be inspected by AShiE Section i

l XI or were identified via the augmented inspection it is believed that, by focusing the inspections on known degradation mechanisms such as those which have lead to leakage in operating plants, the N560 inspection program will actually result in a decrease (rather than an increase) in primary coolant leakage

rates, j

4.

PROVIDE WRITTEN DESCRIPTION OF HOW AGING AND SERVICE INDUCED FAILURES ARE ADDRESSED As discussed in greater detailin the responses to RAI #1,4 and 5 of the Evaluation hiethodology section, the piping failures experienced in the industry have predominantly been as a result of service induced degradation. This service induced degradation has been almost exclusively due to mechanisms that are not addressed as part of traditional design analysis quantifications. History has shown that using stress analysis results such as quantifying the number of seismic or design basis thermal transients cycles is ineffective as a predictor of piping failure likelihood. Because of this lack of correlation, AShfE Code Case N560 provides an inspection selection method that is based upon the causes of piping failures (including service induced and age related flaws / failures) and providing for

' inspection for cause' inspection techniques that increase the likelihood of finding these flaws.

5.

PROVIDE WRITTEN DESCRIPTION OF IIOW TIIE NEW PROGRAM PROVIDES A MECIIANISM FOR TRACKING AND TRENDING OF PLANT SPECIFIC INDUSTRY DATA The results of NDE inspections are evaluated upon completion and discrepancies are documented in in-house procedures. Immediate and long-term corrective actions are identified and tracked to completion. Corrective actions may include repairs, supplemental inspections, or scheduling of subsequent examinations for future outages. Review of program adequacy may also be required.

Published industry experiences are reviewed via our fonnal Operating Experience program. These experiences are assessed for impact or significance to Vermont Yankee and action plans are then generated.

V-61

______a

In addition, Vermont Yankee participates in industry initiatives (AShiE, BWRVIP, industry seminars and workshops) in order to remain apprised of evolving NDE issues. Feedback from these interactions are evaluated and reflected in our programs.

The goal of these programs is to identify where the in-senice inspection program needs to be revised or improved or when issues need to be assessed in order to continue to better verify structural integrity of our safety class systems. Vermont Yankee's willingness to be the industry's pilot plant for AShiE Code Case N560 is representative of this goal.

6.

PROVIDE WRITTEN DESCRIPTION OF TIIE PROGRAM COMMITMENTS AND REVISIONS (i.e. FSAR, TECH SPEC, ETC.)

The Vermont Yankee Technical Specifications require inservice inspection in accordance with Section XI of the ASME Boiler and Pressure Vessel Code as required by 10CFR50.55a (g), except where specific relief has been granted by the NRC. The Technical Specifications further require that inservice inspection of i

piping identified in Generic Letter 88-01 shall be performed in accordance with the staff positions on schedule, methods, and personnel and sample expansion included in the Generic Letter.

1 As a result of this N560 Code Case relief request, the subject Technical Specifications will not require revision.

However, changes to the Vermont Yankee Final Safety Analysis Report (FSAR) will require revision.

Currently, the FSAR simply states that baseline inspections were perfonr.ed and inservice inspection will be conducted in accordance with plant Technical Specifications (i.e. ASME Section XI and, as modified by the NRC, approved reliefrequests.)

As a result of the N560 Code Case relief request, the FSAR will be revised to describe the Risk-Informed Methodology used to identify the inspection population, how inspection techniques are selected to perform the required inspection, and when the new program needs to be revised, based upon inspection results or plant and industry experience (results) with, not only components, but N560 programs.

V-62

VI.

IMPACT OF PROPOSED CIIANGE 1.

PROVIDE WRITTEN DESCRIPTION OF Tile IMPACT ON CDF AND LERF OF Tile PROPOSED CIIANGE The impact of the proposed change to risk at the Vermont Yankee plant is due 'o two opposing factors:

1. The number ofinspections is reduced. Most reductions occur in low end medium risk areas, while reductions are minimal in high risk areas.

2. The inspection techniques have improved. Inspections are for cause, designed for a specific degradation mechanism, and, therefore, the Probability of Detection (POD) of a problem (flaw) has increased.

In order to estimate a change in CDF, it is necessary to estimate the values of consequence ranks and the pressure boundary failure (PBF) likelihood rank.

Consequence ranks are defined based on the estimates of CCDP. The highest CCDP in the Vermont Yankee N560 evaluation is 2E-3, based on Interfacing System LOCA, isolated only by a closed check valve (the probability cf a check valve leaking during a year, given a quarterly test, is 6.8E-7/hr

• 1/4 yr < 2E-3).

The likelihood of PDF is determined by the presence of difTerent degradation mechanisms and the rank is based on the relative failure probability (instead of an absolute number). The relative failure probability is illustrated in response to EVALUATION METHODOLOGY, RAI 1. The basic likelihood of PBF for a piping location with no degradation mechanism present is noted as x, and is o

expected to have a value lower than 1E-8.

Based on the above:

CONSEQUENCE RANK

' 1KELillOOD OF PBF Relative PBF Rank CCDP (Max)

Rank Probability High 2E-3 Large 200 xo Medium 1E-4 Small 20 xo i

Low IE-6 None xo g

Based on the consequence and PBF likelihood rank:

VI-63

Risk Ranks; CDF [llyr]

IIIGli MEDIUM LOW CATI 4E-1 x CAT 4 2E-3 x CAT 6 IE-4 x o

o o

CAT 2 4E 2 x CAT 5 2E-3 x CAT 7 IE-6 x o

o o

CAT 3 2E-2 xo With the assumption that doing an inspection on a specific location will eliminate the risk at this location, with POD (a conservative assumption, in view of the fact that there are several factors which are impossible to inspect for and, also, that inspections are performed only once within a ten year period), the difference in risk can be estimated as follows:

RISK NO.OF NO. OF NEW (CDF)

CURRENT PROPOSED CATEGORY ll/YR]

INSPECTIONS INSPECTIONS ARISK (CDF)[1/YR]

CAT 1 4E-1 x 9

9 0

o CAT 2 4E-2 x 28 23 (28 POD - 23 POD,)

• o o

4E-2 xo CAT 3 2E-2 xo CAT 4 2E-3 x 56 9

47 POD

• 2E-3 x o

o o

CAT 5 2E-3 x 2

2 POD

• 2E-3 x o

o o

CAT 6 1E-4 x 21 21 POD,

• 1E-4 x o

o CAT 7 1E-6 x 6

6 POD

• 1 E-6 x o

o o

TOTAL 4(30.5 POD - 23 POD )

• o 1E-2 xo NOTE: In the Table above, PODg is the POD for an old inspection method, while POD, is the POD for the new inspection method. A change in POD is only considered if a degradation mechanism is present. Otherwise, POD, = POD, as o

in risk CAT 4, With the assumption that there is an improvement in POD for the N560 examinations, and it is conservatively evaluated as an increase, from PO..', = 0.4 to PODS = 0.6, and x = 1E-8, then o

ARisk = 4 * (12.2-13.8)

• 1E-2

• 1E-8 = -6.4E-10 In this conservative estimate, a reduction in risk is shown.

VI-64

As a bounding estimate, no credit is given for the improvement in inspection detection, the:cfore, POD,= PODS =1, and x =1E-8, the result of the change in o

risk will be ARisk = 4

• 7.5

• 1E-2

• 1E 8 = +3E 9 even with no credit for better inspections, the impact on risk is negligibly small, such that the application is considered " risk neutral."

2.

PROVIDE WRITTEN DESCRIPTION OF THE RISK IMPACT ON PLANT SAFETY We believe that the answer to the previous question, covering the change in CDF, and the answer to the next question, addressing containment performance, answer this question.

3.

PROVIDE WRITTEN DESCRIPTION OF THE NEGATIVE IMPACT (IF ANY) ON INTERSYSTEM LOCA IF TIIE NUMBER OF INSPECTIONS IS REDUCED FROM 25% TO 10%

In the Vermont Yankee N560 Evaluation, there are 49 piping locatioris where, if a break occurs, the potential for an Interfacing Systems LOCA (ISLOCA) or LOCA-Outside Containment (LOCA-OC) would increase.

NOTE: In the Vermont Yankee IPE analysis,ISLOCA models the "High-Low" pressure system interface, LOCA-OC models the "Iligh-High" pressure system interface.

Ofthose:

7 locations (S ISLOCA and 2 LOCA-OC) are in a High Risk Category e

(Category 2) 3 of those are currently tested,4 are proposed to be tested.

20 locations (16 ISLOCA and 4 LOCA-OC) are in a Medium Risk Category (Category 4). 4 of those are currently tested,1 is proposed to be tested.

22 locations (LOCA-OC) are in a Low Risk Category (Category 6). 3 of those are currently tested, none are proposed to be tested.

Given that there is an increase in the number ofinspections in the High Risk Category, and that all inspections will now be directed towards specific degradation mechanisms (increasing the inspection POD), the impact on VI-65

Intersystem LOCAs is positive. (A decrease in the number ofinspections in CAT 4 is less significant than the increased inspections in CAT 2, due to the smaller PDF probability, given the absence of degradation mechanisms in CAT 4, see response to RAI 1 above.)

4.

PROVIDE WRITTEN DESCRIPTION OF TIIE NEGATIVE IMPACT, IF ANY, ON CLASS 2 AND 3 PIPING ISI AS A RESULT OF Tile PROPOSED CIIANGE Please see the response to SCOPE, RAI 2.

5.

PROVIDE WRITTEN DESCRIPTION OF Tile IMPACT ON OTIIER INSPECTION PROGRAMS SUCil AS IGSCC ( GENERIC LETTER 88-01)

There are two other programs at Vermont Yankee that have a cross-over with the Code Case N560 Program. One is the Vermont Yankee Erosion-Corrosion Program. Those areas within Class 1 piping that were identified in the Vermont -

Yankee Erosion-Corrosion Program are being adopted by the N560 Program. The other program is the Generic Letter 88-01 or the NUREG 0313 IGSCC Program.

All stainless Class 1 Category B-J piping welds at Vermont Yankee have been replaced with non susceptible material and are considered Category A welds. The original ir tent of NUREG 0313 was for Category A welds to revert to the normal In-service Inspection selection program (25% when NUREG 0313 was written) and test frequency. Code Case N560 revises that Code selection criteria from 25% to a smaller selection that concentrates on susceptible !ocations. Category A welds are not considered susceptible to the IGSCC damage mechanism and, therefore, unless some other damage mechanism is identified, they revert to Risk Category 4 (High Consequence /No Identified Damage Mechanism). A sample percentage of these welds has been chosen consistent with this risk category.

The specific technical basis for eliminating IGSCC as an applicable mechanism in the Vermont Yankee Recirculation, Core Spray and RHR Systems is as follows.

All stainless steel piping has been replaced with low carbon Type 316 stainless steel.

For additional resistance, all large bore field welds have been treated with Induction Heating Stress Improvement (IIISI), and all small bore field welds were heat sink welded. All shop welds were solution annealed after welding.

Welding of the replacement piping was performed with special attention to

- eliminating conditions known to promote IGSCC. Joints were made with consumable inserts, and no ID surface grinding was permitted. All welds received 100% UT (per ASME Section XI pre-sersice requirements). There are VI-66 l

1

no geometric or metallurgical crevices in the Category B-J portion of the piping systems.

Extensive laboratory and field experience has demonstrated that low carbon Type 316 stainless steel piping materbi possesses outstanding resistance to IGSCC in the BWR environment. In the absence of crevices, no reported incidents of cracking have been observed, either in laboratory testing or in the field. When crevices are present, some limited cracking in this mater!al has been observed in the BWR environment. However, as noted above, any crevice conditions (such as in safe end to nozzle regions) are outside of the Category B-J piping scope and, therefore, are not part of this Code Case N560 application. The additional application of proven IGSCC remedies (IllSI, solution annealing, or heat sink welding) provides even greater assurance ofimmunity to IGSCC, beyond that i

associate with NUREG 0313 Category A.

6.

PROVIDE WRITTEN DESCRIPTION OF TIIE IMP'ACT ON ACCIDENT MITIGATING SYSTEM (I.E. ASME CLASS 2) AND SUPPORT SYSTEMS (i.e. ASME CLASS 3)

Please see the response to SCOPE, RAI 2.

VI-67

ATTACHMENT 1 This attachment provides a reprint of the NRC's Requ*st for Additional Information (RAI), dated

- June 12,1997, on EPRI Technical Report EPRI-TR-106706. Vermont Yankee has reviewed each RAI for applicability to the Vermont Yankee N560 submittal.

This attachment documents whether the RAI is applicable to the Vermont Yankee N560 submittal and o

addressed in the responses contained in the main body of this submittal. Each RAI is denoted with the following identifiers:

9-17 Identified during the September 17,1997 meeting and addressed in the main body of this submittal, 9 23 Identified during the September 23,1997 telecon and addressed in the main body of this submittal.

N/A Not applicable to the Vermont Yankee N560 submittal.

-l l

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk Informed VY N560 Inservice Inspection Evaluation Procedure For Piping Submittal The following are the comments and Request for Additional Infonnation (RAI) that have been developed by NRC staff reviewers who have been reviewing the " Electric Power Research Institute Risk-Informed Inservice Inspection Evaluation Procedure, EPRI TR-106706, Interim Report, June 1996." These RAls may be augmented at a later date due to further development of staff positions or questions and comments raised by further review of the EPRI methodology. The staff has attempted to remove redundant questions from the different reviewers and to order the questions generally according to the topics of the material presented in the submittal. There may be some redundancy remaining. In the responses to these questions, it is acceptable to refer to other questions for parts of answers or to other documents when appropriate.

1.

General Questions On Overview, Scope, and Probabilistic Safety Assessment G-1 The current staff position as described in the March 1997, draft Regulatory Guide DG-1961,"An Approach for Using Probabilistic Risk Assessment in Risk-Infomied Decisions on Plant Specific Changes to the Current Licensing Basis," is that while implementing risk-informed decision making, changes are expected to meet the following set of key principles:

The proposed change meets the current regulations. This principle applies 9-17 a.

unless the proposed change is explicitly related to a requested exemption or rule change (i.e., a 50.12 " specific exemption" or a 2.802 " petition for rulemaking"). Please identify how you intend to formulate your submittals to meet this principle, b.

Defense-in-depth is maintained. The staff has identified a number of 9-17 elements which should be addressed to assess whether the defense in depth principle is met. Please explain how you intend to address the following elements, or suggest and explain other elements to show that the principle is met.

A reasonable balance among prevention of core damage, prevention of 9-17 containment failure, and consequence mitigation is preserved.

Overreliance on programmatic activities to compensate for 9-17 weaknesses in plant design is avoided.

System redundancy, independence, and diversity are preserved, 9-17 commensurate with the expected frequency and consequences of challenges to the system.

Page 1 of 15 l

Comments and Request For Additionallnformation Applicable to Related To Electric Power Research Institute Risk Informed VY N560 Inservice Impection Evaluation Procedure For Piping Submittal Defenses against potential common cause failures are preserved and 9 17 the introduction of new common cause failure mechanisms is assessed.

Independence of barriers is not degraded.

9-17 Defenses against human errors are preserved.

9-17 c.

Sufficient safety margins are maintained. An acceptable set of guidelines 9-17 for assessing that sufficient safety margins are maintained are summarized below. Please explain how you intend to address the following guidelines, or suggest and explain oiher guidelines which could be used to ensure that sufficient safety margins are maintained.

Engineering codes and standards or alternatives approved for use by 9-17 the NRC are met, or deviations are justified.

Safety analysis acceptance criteria in the current licensing basis are 9-17 met, or proposed revisions provide sufficient margin to account for analysis and data uncertainty.

Proposed increases in risk and their cumulative effect are small, and 9-17 these changes do not cause the NRC Safety Goals to be exceeded.

The necessary sophistication of the evaluation, including the scope of the PRA, depends on the contribution the iisk assessment makes to the integrated decision-making, which depends to some extent on the magnitude of the potential risk impact. For changes for which a more substantial impact is possible, an in-depth and comprehensive PRA analysis of appropriate scope to derive a quantified estimate of the total impact of a proposed change will be necessary to provide adequate justification. In other applications, calculated risk importance measures or bounding estimates will be adequate. In still others, a qualitative assessment of the impact of the change on the plant's risk may be sufficient. Please explain how you intend to evaluate the risk impact of the changes which will be requested in a submittal, Performance-based implementation and monitoring categories are 9-17 e.

proposed that address uncertainties in analysis models and data, and provide for timely feedback and corrective action. Please explain how yo. methodology will address this principle.

G2 The decision criteria as to whether a proposed change in total plant risk N/A (CDF/LERF)is acceptable or not,is missint rom the guidance document.

f Page 2 of 15 V

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk Informed VY N560 Inservice Inspection Evaluation Procedure For Piping Submittal Please propose the decision criteria as to when a proposed change is acceptable and when it is not. Should the proposed changes result in a risk im, met that is not acceptable, based on the proposed decision criteria, what are the options that a licensee can take to decrease the risk impact?

G-3 Please identify and address the process by which a licensee assures that the 9-23 plant meets its licensing basis and the Probabilistic Risk Assessment (PRA)is validated to reflect the actual plant configuration and operations.

G-4 Please propose the standards by which n PRA is found acceptable (i.e., what Partial are the attributes required for the PR A to support the RI ISI analyses, 9-23 importance measures calculations, etc.). The staff must find that the PRA used to generate risk insights is of sofficient quality to support the reported results.

If modification to the PRA is required, a description of the modifications made to allow the PRA to be used for the particular application should be provided.

G-5 Please provide a detailed description of the implementation, monitoring, and 9-17 corrective action program for the RI-ISI program. Address how plant-specific, industry, and applicable international data (i.e., EPRI/ SKI data base, NPRDS, etc.) will be used in the monitoring program. In addition, please provide the following information. What are the appropriate performance characteristics to monitor? How should the SSCs performance be monitored? How will feedback from the monitoring be used to make adjustinents in implementation strategies?

G-6 Please discuss how containment integrity (LERF) is addressed in the PRA.

9-17 Also address how containment integrity is addressed when performing primary and secondary effects analyses.

G-7 The RI-ISI program needs to have a robust reliability criterion for its N/A inspection samples as well as examination methods or a combination of methods that are matched to degradation mechanism, materials, environment, stresses, discontinuities and geometric constraints that may limit the success of certain NDE techniques. It must also take into consideration the rate of success or the probability of detection of existing or service induced flaws.

Discuss your detailed approach to r.:complish the above objective.

G-8 Please address and provide examples how the uncertainties in the PRA are 9-17 quantified and considered in the decision process. This includes uncertainties related to the calculation of total core damage frequency and uncertainties related to importance measures calculations (e.g., identification of high and low safety significant segments).

Page 3 of 15 J

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk. Informed W NMO Inservice inspection Evaluation Procedure For Piping Submittal G9 Please provide a detailed description of the criteria used to select which Panial elements in a pipe segment are to be inspected. Given that the purpose of 9 17 Section XI inspections is to prevent pipe leaks, reliance on leak before btcak (no inspection of a high safety significant segment)is not acceptable. The criteria should be independent of the existing ASME 25% requirements and should be based on risk insights and degradation mechanisms. Provide examples of the primary system and a supporting system inspection strategy based on existing Section XI requirements compared with that bssed on risk insights. In addition, provide similar identified inspection programs for systems identified as high safety signincant but not presently addressed by Section XI.

G 10 On Page, 2, Section 2.2, two bullets refer to reducing the influence of N/A uncedainties in PSA models and reducing the influence of PSA model assumptions. What exactly is meant by these statements? Ilow is this accomplished when any use of PSA infonnation, by necessity, involves the assumptions made in the PSA7 G-11 Section 2.2.3 states that qualitative PSA insights are used in the risk N/A evaluation. Will th!s methodology be capable of determining whether the risk measures or surrogatmw;h as CDF and LERF increases or decrease as a result of the appr. cation of this methodology? Can the increase or decrease be quantified? If so, p! case describe how the quantif cation will be performed, or alternatively how will qualitative assessment demonstrate that risk impact is acceptably small.

G-12 In a public meeting with the industry, the NRC identified that one of its 9 17 concerns related to decreasing the number of inspections for piping is the possibility that the frequency of pipe leaks willincrease Please address how the method ensures that the frequency ofleaks will not increase. Please justify the number of inspections per risk category as providing comparable or improved level of quality and safety. Demonstrate that the predicted leak frequency for the new RI ISI program will be comparable with operating reactor data (e.g., existing Section XI perfonnance) Justify that the proposed alternative would provide an acceptable level of quality and safety.

G-13 The methodology should be benchmark against quantitative risk-infonned N/A approaches in order to demonstrate that the two methods result in similar inservice inspection programs, categorization and saft ty assurances. Please provide your plan to accomplish this.

G 14 Current staff guidance is that risk informed decisions should be based on CDF N/A and large early release frequency (LERF) information. LERF is often Page 4 of 15

Comments and Request For AdditionalInformation Applicable to Related To Elrtric Power Research Institute Risk Informed VY N560 Inservice inspection Evaluation Procedure For Piping Submittal dominated by initiating events and functional failures different than those for CDP. Please identify how EPRI intends to incorporate LERP into the consequence categoritation.

0 15 Discuss how safety margins can be assessed in the EPRI methodology. Please Partial compare the safety margins provided by the existing ASME Section XI1."1 1061 l

program and those under the EPRI methodology.

l O 16 Ilow does the RI ISI methodology assess, mon. or, and address uncertainties N/A in the analysis?

O.17 Ilow do you assure adequate safety margins in your methodology on a plant-9-17 specific basis? What are the bases and what constitutes an acceptable safety margin?

O 18 10CFR Part 50.55a(a)(3)(1) requires a demonstration that "The proposed N/A alternatives would provide an acceptable level of quality and safety" as the existing ASMB Sect on XI requirement, llow do you demonstrate that the i

EPRI method comports with that requirement? What are the bases for the arguments t i

0 19 The criteria used to establish the scope of piping addressed in the methodology N/A tr. unclear, please confirm that your scope includes:

All Class 1,2, and 3 pipes within the Current ASME Section XI programs, and Safety related stmetures, systems, or components that are relied upon to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it in a safe shutdown condition, and the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposure comparable to 100FR Part 100 guidelines.

Nonsafety related structures, systems, or components:

That are relied upon to mitigate accidents or transients or are used in plant emergency operating procedures; or Whose failure could prevent safety related structures, systems or components from fulfilling their safety-related function; or Page 5 of 15 E

Comments and Request For Additionallnformation Applicable to Related To Electric Power Research Institute Risk Informed W N560 Inservice Inspection Evaluation Procedure For Piping Submittal Whose failure could cause a reactor scram or actuation of a safety-r: lated syttems.

If the scope is different, please address where you differ, in addition, provide the details of the process used to detennine the final piping systems list for the Rl ISI program. Please address any systen.s excluded from the scope of the RI ISI program.

G 20 Please review industry experience and assess if the proposed Hi ISI program Parthl would have provided advance warning of potential failures.

9 17 G 21 Please describe what target leak rate goals (leak / weld / year) you have N/A established as appropriate performance criteria to demonstrate compliance with 10CFR Part 50.55a.

G 22 Please describe how you assure that approoriate considerations were given to N/A the uncertainties in the analyses and interpretation of the results.

G 23 Piping design and configuration may be different and large breaks may act N/A have been analyzed at plants where Leak Before Break (l.BB) has been implemented. Please describe how plants with and without LBB will be treated by the EPRI methodology.

G-24 In the September 20,1996 meeting, the NRC staff emphasized that data base N/A for degradation meel.aulsms and pipe failures should be made available to public for decisions affecting public health and safety. Please describe how this will be achieved.

G 25 in the April 29,1997 meeting with the staff, EPRI stated that a plant specific Panial PRA could be used to provide quantitative support to the consequence 9 23 categorization, and that EPRI envisions PRA quantification to be used generically to calibrate the process, and to resolve complex interactions in specific instances. Please provide details of this process.

G 26 Section 2.2.1 states that the methodology may be applied to a system or a N/A group of systems. Please describe how the total impact on risk will be determined if the methodology is applied only on a system basis.

/

II.

Consequence Evaluation C-1 Page 3-1,last paragraph, first sentence implies that the worst case break fron.

Partial a consequence standpoint is a large break. Ilowever, the last sentence of the 9-17 Page 6 of 15

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk informed VY N560 Inservice inspection Evaluation Procedure For Piping Submittal paragraph states that those systems where a small leak can cause a measurable consequence need to be identified. Please clarify.

C2 With reference to Page 2.5, how are the CCDPs calculated for the initiating N/A events? Is a different approach used for those events that occur more than once in a year? If so, how is it different? What is the basis for the CCDP ranges and the corresponding consequence category designation? What plant operational states are considered in the calculation of CCDP7 If only the power operation state is considered, what justification can be provided to exclude the other operational states (e.g., shutdown for refueling)?

i C3 llow are the conditions and inithting events unique to low power and N/A shutdown operating states considered in Table 3.17 If the consequence category, as defined in this table, differs from the category assigned by use of the range in CCDP given on Page 3 5, which is used?

C-4 is Table 3.2 applicable for low power and shutdown states? Explain your N/A response. If the consequence category, as defined in this table, differs from the category assigned by use of the range in CCDP given on Page 3 9, which is used?

C-5 On Page 3 9, last paragraph, second sentence states that each consequence N/A 7

category will be confinned by a numerical evaluation, llow will this be done?

Does use of the CCDP range imply that calculations will be performed for all pipe (segment) failures? If not, why?

C-6 With reference to Table 3,1, please explain how a pipe break that causes an N/A initiating event is classified as routine?

C-7 Section 3.2.1 states that if a postulated pipe break in a segment results in a N/A Category 11 anticipated operational occurrence, the assigned consequence category for the segment is low. Does this imply that all Category 11 initiating events are categorized as " Low" regardless of their CCDP7 is so, what is the justification for such a categorization scheme?

C-8 Is it possible that use of Table on Page 3 5 would result in a different (more N/A limiting) consequence ranking than other Tables for consequence evaluation?

If so, what jus' fication can be provided for not using Table on Page 3 57 C-9 110w are the risks of direct and indirect effects of pi r breaks addressed? Ilow Partial l

are the risk of leaks, disabling leaks and breaks addressed?

9 17 Page 7 of 15

l Comments and Request For AdditionalInformation Applicable to Helated To Electric Power Hesearch Institute Risk informed VY N560 inservice Inspection Evaluation Procedure For Piping Submittal C-10 Please justify the use of the CCDP criteria as identifying consequence w17,9 23 categories of high, medium and low, llow were the cut off criteria established?

C ll Table 3.2 addresses exposure time. The text defines exposure time as obtained Partial from the Technical Specification limits, and shall be classified as long 9 23

(>24 houu) or shon (not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). Please discuss how you use the exposure time in the risk study, is it equivalent to identifying the unavailability of a system to respond to an event? Ilow is this integrated in the risk assessment? Ilow is it weighted to other events? If modeled in a PRA, how will this tx modeled?

C 12 Please address all failure modes (e.g. small leak, large leak and break) that can 9 17 have either direct consequences (e.g. disable the system) or indirect consequences (water spray, pipe whip, etc.). Ilow are these consequences factored into the analyses?

C 13 Section 3.2.1 on Pages 3-4 to 3 6 discusses consequence categorization based Panial on the frequency of the type of Initiating Event (IE). Most of the section, 9 23 including Table 3.1, suggests categorizing pipe failure initiating events in one of the four design basis IE categories (e.g., routing, anticipated, infrequent, and limiting). Based on a general obxrvation that plants are designed to better cope with the more frequently expected IEs, the less frequent the type ofIE induced by a pipe failure, the more severe the suggested consequence category.

Quanthative guidance is also discussed in the section in the form of consequence categorization based on the Conditional Core Damage Probability (CCDP) following the pipe rupture. A text table on Page 3 5 provides quantitative guidelines for categorizing pipe failure consequeras according to ranges of the CCDP following each pipe rupture.

The two types of guidance may not yield the same result For example, the text includes guidance that BWR LOCAs should be " medium" becaus:

LOCAs in BWRs are not important contributors to plant risk. A brief review of the IPE data base indicates, however, that some BWRs have a large LOCA CCDP greater than IE N and such pipe breeks would be classified "high" accotding to the quantitative guidance critem Please clarify the relationship between the qualitative versus quantitative guidance, C-14 Section 3 2.2 includes both qualitative and quantitative geidance on 9-23 categorizing pipe failures which fail mitigating systems but do not cause Page 8 of 15 J'

Comments and l'equest For AdditionalInformation Applicable to Related To Electric Power Hesearch Institute Risk informed W N560 Inservice inspection Evaluation Procedure For Piping Submittai initiating events. The qualitative guidance is summarized in Table 3.2, and quantitative guidance is summarized in a text table on Page 3 9.

a.

On Page 3 7, plant safety functions are defined as reactivity control.

9 23 secondary heat removal, RCS inventory, etc. In the Case 1 example on l

Page 3 9 the,"more than 3 backup trains are available" includes," main and auxiliary feedwater, other train of emergency feedwater, and feed and bleed." These plant safety functions do not seem to be well defined, e.g.,

l feed and bleed may be a backup for decay heat removal but does not perform the same mitigating function as secondary heat removal. Please expand the description of plant safety functions with sufficient detail to provide workable guidance. The methodology should also provide for ensuring that all relevant plant safety functions are reviewed for each postulated mitigating system failure, b.

The quantitative guidance on the bottom of Page 3 9 refers to a

" conditional core damage probability." The failures referred to in Section 3.2.2 are, however, failures of mitigating functions without necessarily causing a plant trip. When equipment which does not cause an initiating event is set to failed and a PRA requantified, the result of the calculation a conditional core damage frequency or rate - unless the degraded sits 'lon is assumed to exist over some fixal time period.

Please clarify hat these guidelines represent and how the numerical values to be compared with the guidelines are to be calculated.

C-15 The concern that the concepts of mitigating function and backup trains are not 9 23 well enough defined to provide a workable methodology raised in question C-14(a) also applies to the " Combinations Impact Group" in Section 3.2.4.

The concern here is even greater, however, since the potential impact on plant safety for these events can also be greater. Please expand the definition of plant safety functions.

C-16 The PRA method described in the April 29,1997 meeting at the NRC 9 17 identifies CCDF as the ratio of CDF to the Initiating Event Frequency (IEF).

The accuracy of this calculation is subject to the truncation level assumed in the analysis, if the truncation level is too high, it might neglect important cut sets. Please address how you ensure that the truncation level was adequate for the analysis. One option is to require an analysis where the IEF is set to 1.0.

C-17 Please describe how you address pipe segments common to more than one Panial system, to more than one branch in the same system, etc.

9-17 Page 9 of 15

__)

Comments and Request For AdditionalInformation Appilcable to Helated To Electric Power Research Institute Risk. Informed VY N560 Inservice Inspection Evaluation Procedure For Piping Submittal C-18 Please describe how you address the consequences of leaks, disabling leaks, 9 17 and breaks. What are the criteria, consequences, andjustification. In the meeting of April 29,1997, the presentations only addressed large breaks.

C 19 When piping segments in redundant paths are subject to the same degradation 9 17 mechanism, a design basis plant transient could trigger a simultaneous failure of the piping segments. In add 41on, piping segments with degradation could fall when subject to a Safe Shutdown Earthquake (SSE). Please describe how i

the EPRI methodology addresses the consequences for common cause failures.

l C 20 in Table 3.2, consequence category in some cases changes from high to low N/A when the number of backup trains is increased from zero to one or more.

Please explain the basis for not having an intennediate category of medium in those cases.

111.

Failure Potential F1 llow does failure potential detennination process treat repaired pipes and weld N/A overlays?

F.2 llow are common cause failures in piping systems calculated in the PRA7 9-17 F-3 On Page 4-10, Section 4.3, second paragraph states that no degradation Patial mechanism was identified in the source material for 48% of the events. Does 9-17 this imply that the degradation mechanism was unknown, known but not listed, or simply not listed? Since this represents approximately half of the available data, what assurances can be provided that if the degradation mechanisms were known, Table 4.2 would not change?

F-4 in Table 4.2, what is the basis for assigning all degradation mechanisms except N/A FAC to the medium category?

F-5 The guidance would suggest that the mechanism of erosion / corrosion would N/A (by definition) be associated with a high failure potential, whereas thennal fatigue would (by definition) be a mechanism with at most a medium failure potential. As a result of this, an acceptable ISI program might inappropriately address locations with a very low probability for erosion / corrosion and but disregard locations with a veiy high probability (based perhaps on actual operating experience) of thennat fatigue or of stress corrosion cracking, liow is this prevented?

F-the methodology does not define high, medium, and low categories for 9-17 component failure potentials, not even in a relative sense as quantitative Page 10 0f 15

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Instllate Risk Informed VY N560 Inservice Inspection Evaluation Procedure For Piping Submittat categories for purposes of guidance, Thus, various components could be assigned to the same category although their failure probabilities or failure frequencies may differ by several orders of magnitude. Accordingly, the resulting rankings of components for inspection priorities may be of questionable value. Please address this concern.

F7 Please describe how you address the full range of failure mechanisms 9 17 (mechanical fatigue, thermal fatigue, nress corrosion cracking, flow assisted corrosion, etc.) that can contribute to component failures and how the l

methodology addresses them.

F8 Qualitative categories for failure potential are related to well defined numerical N/A ranges of failure frequencies or prooabilities such that the qualitative assignments of the failure potentials to categorie can be supported and/or benchmark with failure experience data and with predictions based on probabilistic structural mechanics models. Please provide such validation for your program, i

F-9 Evaluations of failure potential makes use of plant specific operating 9 17 experience and industry data bases on failure occurrences. Ilow does the program incorporate industry data? Ilow does the program provide for feedback and correction if the assumptions made are found to be inappropriate? Ilow does this program incorporate new degradation mechanisms? Ilow often is the program reassessed?

F-10 Evaluation of failure potential include degradation mechanisms which are N/A seldom experienced. Stmetural mechanics models may indicate that these mechanism, although are outside the scope of current operating experience and/or industry data bases, can contribute to the medium and low failure potential categories. The EPRI approach does not apply such analyses, llow do you assure that the conclusions from the methodology is valid for the licensed life of the plant?

F-11 Table 4.2,is not consistent with the degradation categories presented in the N/A April 29,1997 meeting with the staff. Please explain the differences.

IV.

Risk Ranking R1 liow is the impact of the risk assumptions assessed? What sensitivity studies 9 17 have been perfonned? What were the results of those sensitivity studies on categorization of pipe segments, risk, consequences, etc.?

Page 11 of 15

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk informed VY N560 Inservice Inspection Evaluation Procedure For Piping Submittal R2 llow does the consequence evaluation incorporate the contributions to risk 9 23 from pipe failures which cause initiating events, mitigating system failures, and failures that cause both (e.g., common cause initiators).

R,3k assessment addresses more than the contribution of pipe segment failing, llow does the model address opeMor actions, system interactions, common component (segment) interac:lons, etc.?

R3 Core damage frequency and large early release frequency are used by the staff N/A as a suitable metrics for making risk infonned regulatory decisions. The EPRI methodology does not use those metrics. Please describe what metrics are employed in the EpRI methodology.

R4 Ilow does the methodology identify a population of structural elements which, N/A as a group, contribute only a small fraction to the overall core damage risk associated with piping components. What fraction of the totalis that number?

R5 In comparing estimates of plant risk (i.e., calculated plant CDF and LERF) and Partial change <iin these metrics as a result of CLB changes with the acceptance 9 23 guidelines,it is necessary to take into account the uncertainties in the analysis, liow does the EPRI methodology address the uncertainties in the analysis?

R6 Please compare your categorization of pipe segments with more traditional risk N/A imponance measures, such as the Fussell Vesely and the Risk Achievement-Wonh models.

R-7 Ilow do you address the risk of a pipe segment for all modes of operation 9-17 (e.g., power, shutdown, refuelir.g. etc.)?

R8 Please provide the technical basis for the criterion used as high, medium and N/A low safety significant segments, and the criteria used for identifying high, medium and low frequency.

R9 Please describe how the probability of detection for an inspection process gets N/A factored into the risk assessment.

V.

Element Selection E1 It is not obvious from the EPRI report as to the decision criteria for selecting 9-23 which weld in a high-safety significant segment will be selected for inspection.

If a segment is composed of 10 welds, all of which have similar degradation mechanisms, which weld will be selected? Please provide the selection criteria.

This selection criteria should be as comprehensive as possible, so that the scope for the panel making the final selection will be minimized. This serves

- Page 12 of 15

Conunents and Request For AdditionalInformation Appilcable to Related To Electric Power Research Institute Risk. Informed YY N560 Inservice inspection Evaluation Procedure For Piping Submittal two purposes. First,it promotes reproducibility in the decision making process, and second,it minimizes the scope and expertise required from the panel to be within the typical expertise found at the plant.

E2 Please provide the detailed decision metrics (criteria) for selecting the location 917,923 and the number of welds to be inspected. For the pilot plant, identify the locations for primary system welds to be inspected and discuss reasons for not inspecting other welds in each segment. Also provide a schematic diagram of existing Section XI inspection locatiens and the proposed inspection locations based on RI ISI analyses.

E3 Please provide examples of considerations given to the identification of the 9 17 governing structural element within segments. Please explain why a panicular l

Iccation was selected and what other locations were considered and why the others were not selected.

VI.

Inspection Program l1 Were any cases addressed in the pilot plant study for which more than one 9 17 location contributed significantly to the overall CDF for the segment? If a large segment was to be broken into several smaller segments, would the process used on the repon lead to more ISI inspection locations?

I2 The computational models used for risk informed ISI programs should N/A encompass existing augmented inspection programs of pipes. If they do not, address the deficiencies / limitations of the analyses. While the NRC has not decided to integrate augmented inspection requirements for pipes with the RI-ISI program, efficiency may be obtained by such an integrated program. This efficiency can integrate completeness and consolidate existing regulatory requirements and climinate duplication of administrative burdens for such activities as crosion/ corrosion inspection programs. Please identify existing augmented inspection programs for pipes, the piping systems, an address how those programs can or cannot b: addressed by the risk-informed ISI programs, if the RI ISI programs can incorporate existing augmented inspection programs for piping, provide comparative examples with supporting analyses.

1-3 EPRI report focuses primarily on the first two parts that involve the 9-17 identification of where to inspect,i.e., scope definition and risk ranking. In order for the staff to appropriately review and approve this methodology, the frequency of inspection need to be defined also.

Page 13 of 15 g

iu

1. -_.-s

Comments and Request For AdditionalInformation Applicable to Related To Electric Power Research Institute Risk. Informed VY N560 InsersIce Inspection Evaluation Procedure For Piping Submittal 14 Page 1I of the NEl 96 XX Draft A, states that newly developed techniques N/A may be substituted for the methis in Table 6-1. Please clarify which document is being referenced here.

15 Page 11 of the NEl 96-XX, Draft A, states that inspections are distributed N/A across periods such that all high safety impact segments are inspected over the 10 year interval. There should be a qualifier that those segments are not subject to active degradation mechanism.

l l

l6 With reference to Page 61,2'"' paragraph, does Risk Category 1 (high N/A I

consequence, large break) imply that there would be an active degradation mechanism at work in the pipe segment? If so, what justification is offered for only looking at 25'7e of the inspection locations?

l-7 The first bullet on Page 7 3 discusses examinations, unless prohibited by N/A physical limitations, if a segment (clement)is in Risk Category I and examination is prohibited by physical limitations, what, if any, alternatives are proposed for examining the segment?

l8 What are the criteria and goals for establishing the number of inspections m a N/A pipe segment? Ilow do you correlate the number of inspections to those safety criteria / goals?

l9 What are the criteria for selecting particular locations to be included in the 9-17 sample inspected, other than a random selection. Ilow does that ensure that all significant contributions to core dt nage are addressed by the ISI program.

1-10 The criteria used for selecting the number of welds to be inspected is unclear.

N/A Code Case N 560 indicates that 10%,25%, and 50% of the piping locations will be inspected for low, medium, and high ranked segments, in the April 29, 1997 meeting,25% inspection was stated as being required for high ranked segments. Please explain the metrics and provide justification for the numbers to be inspected.

1 11 Please provide examples where the methodology does not just eliminate 9 17 requirements but identifies changes in requirements that lead to appropriate increases in inspections.

1 12 Ilow is the probability of detection of the inspection program factored into the Partial determination of the number of welds to be inspected? liow does that impact 9-17 the probability or assurance that the RI ISI inspection program provides comparable quality and safety when compared to the existing Section XI program?

Page 14 of 15 7

i Comments and Hequest For Additionallnformation Applicable to Helated To Electric Power Hesearch Institute Risk Informed VV N560 Inservice inspection Evaluation Procedure For Piping Submittal 1 13 Please provide justification for the method used to arrive at the number of 9-17

- inspections to be performed for each segment.

1 14 Please describe your performance monitoring program. Provide the basis for 9 17 the program and address how that program ensures an adequate level of quality and safety.

1 15 EPRI methodology requires inspection of 25% of elements in more safety N/A signl0 cant segments. RI ISI methodology should justify the element selection process for ISI. In addition the criteria to inspect the same elements during successive Isis should be further reviewed and justified.

Yll.

Plant Walkdown W1 Please describe the process that will be used to verify that the plant PRA 9-23 model represents the actual configuration of the plant, e.g., piping materials, wall thickness, chemistry, pipe support types and locations, weld location, types and sizes, etc.

W2 Appendix A addresses plant walkdown. What were the most significant 9 17 indirect effects identified in the study? Indicate significant changes in calculated CDP contributions, and how the resulting ISI selection would change if indirect effects are neglected.

Page 15 of 15

i Attachntent 2 l

t

7 MECHANISM SPECIFIC EXAMINATION VOLUMES AND METHODS Application of RISI uses NDE techniques that are designed to be effective for specific degradation mechanisms and examination locations.The remainder of this section describes the examination volumes and methods that are appropriate for each degrada-tion mechanism.

Tchle 7.1 provides a summary of the degradation mechanism-specific NDE methods, and the associated acceptance standards, evaluation standards, and insocetion frequencies, i

7-1

___ j

Mcchanism Spectfic Examinalion Volumes and Methods Table 7.1 Summary of Degradation Specific Inspection Requirements and Examination Methods 5 Degradation Degradation Examination Examinatip Acceptance Evaluation Mechanism Mechanism Requirement Method Standard Standard Subcategory Fig. No.

Thermal 7.1 1 Volumetric IWB 3514 lWB 3640 fatigue 7.12 or 7.13 IWB 3650 7.1 4 Corrosion Chloride cracking Affected Surface IWBC514 IWB 3640 cracking (OD)

Surface or l

Chloride cracking IWB 3650 (ID) 7.2 1 Volumetric IWB 3514 Crevice corrosion 7.2 2 Volumetric IWB 3514 7.2 3 PWSCC Visual (VT-2)

IWB 3142 IWB 3640 7.3 1 Volumetric IWB-3514 7.3 2 IGSCC 7.4 1 Volumetric IWB 3514 IWB 3640 through 7.4 5 MIC Volumetric IWB 5250(b)

Code Case or N 480 7.5 1 Visual, VT3 IWB-5250(b)

- N 480 with volume equivalent thickness Erosion-See FAC Volumetric Same as Samo as cavitation FAC FAC Flow-7.7 1 Volumetric Plant Plant accelerated through program program corrosion 7.7 7 8 The frequency of inspection for each degradation category is each inspection interval, except for the existing plant inspection programs for IGSCC and FAC, where the frequencies specified in the plant pro 5 rams are applicable.

8 Volumetric exarninations are generally performed using ultrasonics, unless otherwise indicated.

7-2

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Mechanisen Specific Exarnination Volurnes and Methods 7.1 Thermal Fatigue Affected Regions. Regions identified by TASCS or transient screening (see Section 4.2.1).

l Examination Volumes: Volumes surrounding stress concentrations (e.g., counterbores, nozzle corners) and other high-stress regions (e.g., terminal ends). If there are no stress concentrations or high-stress regions, the application volume is volume around welds.

Examination should focus on detection of cracks initiating and propagating from the inner surface.

Examination Volume Figures: See Figures 7.1-1,-2,-3, and -4. These volumes may need to be expanded, depending on the nature and extent of TASCS-type mechanisms.

Examination Methods: Volumetric The following considerations are suggested for the examination of thermal fatigue cracks:

In contrast to mechanical fatigue, thermal fatigue cracking usually initiates as many small cracks and then one of the cracks becomes predominant. It has been most com-monly observed at or near the pipe-to-nozzle weld where the wall thickness is thinner due to a counterbore or previous grinding on the inside surface. In feedwater piping, th:t predominant crack grows straight out in a radial-circumferential plana vhile the others remain small. The predominant crack tends to be located at the thircest aica and does not follow the weld fusion hne, o Examinations should be conducted from both sides of the weld even if additional surface preparation is necessary, unless prohibited by physical limitations, Scan at least 12 decibels (dB) over the standard ASME Code Section XI, Appendix o

l 111, gain.

Obtain an accurate wall thickness profile, l

o Look for excess inside-surface signals that are typical of thermal fatigue cracking, o

especially in thinne*, more susceptible areas.

The tip signal should always be lower in amplitude as compared to the corner trap o

signal, When sizing, consider the length of the indication; surface-connected cracks are o

almost always at least twice as long as they are deep, often 5 to 10 times as long.

Determine whether the suspected tip signal actually plots to be exactly above the o

l corner trap signal. For this purpose, a special reference block, with multiple parallel notches and holes above the notches, can be a useful training, reference, and qualifi-cation tool. It might be difficult to separate the signals manually, but a properly set up automated scan should be able to correctly identify the location of the signals Focused transducers or the time-of-flight-diffraction (TOFD) tecimique are recom-mended for sizing and/or characterization. TOFD works especially well for finding the deepest crack in a group of cracks.

7-3 l

Mechanisrn Specific Exarnination Volurnes and hiethads Acceptance Standard: Section XI,IWB 3514 Evaluation Standard (as applicable): Section XI, IWB - 3640 or IWB - 3650, as applicable Profile of component gg\\0-1 1/2 in. +#

-+

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(where applic blo) f s

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Figure 7.1-1 Examination Volume for Thermal Fatigue Cracking in Piping Welds less than NPS 4.

Profilo of component

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c 7-4

Mechanistn S;wfic Examirustion Volurnes and Methods o

Examination Volumo A 0-0 0 4

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Mechanisrn Spectfic Examination Volutnes and Methofs lv

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,m 4b 1/2 i or 1/3 in,

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Examination Volume for Thermal Fatigue Cracking in Weldolets and Sockolets.

7.2 Corrosion Cracking 7.2.1 Chloride Corrosion Cracking Affected Region: Austenitic steel piping and welds exposed to chloride contamination (from insulation, brackish water, or concentration of fluids containing chlorides), tem-peratures greater than 150 F, and tensile stresses.

Examination Volumes: Welds and weld heat-affected zones Examination Volume Figures: See Figure 7.2-1.

7

- - _ ~

Mechanistn Specufic Exarnination Volurnes and Methods Examination Method:

Surface for cracking that might initiate at the pipe outside surface Volumetric for cracking that might initiate at the pipe inside surface Acceptance Standard: Section XI,IWB 3514 Evaluation Standard (as applicable): Section XI,IWB - 3640 Profile of component 7

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(where applied)

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7.2.2 Crevice Corrosion Cracking Affected Region: Region where there are crevices (narrow gaps) that can deplete oxy-gen and concentrate chloride ions or other impurities, especially in welded attachments.

Examination Volumes: Volumes surrounding the weld, weld heat-affected zone, and base metal in the crevice region. Examination should focus on detection of cracks initiat-ing and propagating from the inner surface.

Evaluation Volume Figures: See Figures 7.2-2 and -3.

Examination Method: Volumetric. Crevice corrosion cracking can be detected with NDE methods similar to those used for detection of IGSCC (see Section 7.4) Care must be taken to discriminate the crevice from cracking. Discrimination between cracks and crevices should be determined by comparing responses on a mockup.

Acceptance Standard: Section XI, IWB - 3514 Evaluation Standard (as applicable): Section XI, IWB - 3640 or IWB - 3650 7-7

/

Mechartistra Specsfic Exarninatiort Volurries artd Methods 1/2" Cl*l Examination D

Volun;o A B-C D E F B

Crovice Region 3

/

^m F

E 1/2" Figure 7.2-2 Examinathn Volume for Crevice Corrosion Cracking in Nonwelded Attachment.

Examination B

Volumo A B C D l

Crovico Region I

f D

4.

.=ww w

1/2" 1/2" Figure 7.2-3 Fxamination Volume for Crevice Corrosion Cracking in Welded Attachment.

7.3 PWSCC Affected Region: Mill annealed Alloy 600, including weld and weld heat affected zones,in PWR prima y system penetrations that have been cold worked or cold worked and welded, operate at temperatures greater than 620*F, and are exposed to primary coolant.

Examination Areas: Areas surrounding the weld, weld heat-affected zone, and base metal near the cold worked or cold worked and welded regions.

Examination Volume Figures: See Figure 7.3-1 and -2.

Examination Method: Visual examination of the outside surface for evidence of boric acid residt:is typically used to detect through-wall PWSCC.

NDE techniques similar to the ultrasonic techniques used for detection of ICSCC, also may be used for detection of PWSCC. Eddy current techniques can be used when access to the inside surfc.cc of the piping is practical. It also is possible to use radiography for detection of this damage mechanism.

Acceptance Stand ard: Section XI, IWB - 3142 and IWB-3514 7-8

Mechanisrn Spectfic Exarnination Vofurnes and MetIwds Evaluation Standard (as applicable): Section XI, IWil-3640 Machined on insido Surfaco

[ ~Wolded to Clad pipo (sN N N N 4;N N w N N % % % w N S N S N N w N S N

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l Figure 7.3-1 Examination Volume for Primary Water Stress Corrosion Cracking in Pipe Connections.

7-9

hiechanisnt Specrfit E.narninatiort Volurnes artd hictiwds I

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Stainless Stcol Pipe av v7mm nv vAvA :, swsysw 1/2, nu u v v.v m mm' a

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Figure 7.3-2 Examination Volume for Primary Water Stress Corrosion Cracking in Safe Ends.

/

7.4 Intergranular Stress Corrosion Cracking (IGSCC)

Affccted Region: Welds identified to be susceptible to IGSCC, as identified in Section 4.2.4.

Examination Volames: Volumes surrounding weld and weld heat-affected zones.

Selection of welds in segments within a given risk category should be based on the relative ranking of susceptible to IGSCC as specified in NUREG-0313, Rev. 2 (e.g., the most susceptible welds are the first welds selected for examination in a segment). Ex-amination should focus on detection of cracks initiating and propagating from the inner surface.

Examination Volume Figures: See Figures 7.4-1 through -5.

7-10 w

Mechanisrn Specific Exarnination Volutnes and Methods Examination Method: Ultrasonic examination is to be conducted with procedures designed specifically for detection and characterization of IGSCC.

The IGSCC morphology is intergranular, propagating in a branch like manner a'ong the sensitized grain boundaries in the IMZ. The length of the individual branches is gener-ally proportional to the material grain size. In some pipe weldments, IGSCC penetrates the weld metal, but there have been no reported weld failures. Typically, IGSCC occurs nearer the weld fusion line in thicker wall components than in thin wall components.

The cracks are tight and branched.

In marked contrast to carbon steel or low alloy steel where a constant ultrasonic velocity is normally encountered, the clastic anisotropy in austenitic weld material caused by the columnar grain structure leads to variations in propagation. Velocity and attenua-tion variations in the different directions, beam diffraction, beam skewing, reflection, refraction, and mode conversion occur in the austenitic weld material and at its inter-l f:ces. These circumstances combine to give material noise levels that make cracks unde-tectable through austenitic weld metal when using standard shear wave ultrasonic cxamination procedures.

During examination for circumferendal cracks, anomalies, such as grain boundaries at these interfaces, reflect ultrasound to produce high material noise levels. The wavy interface scatters the sound beam in unexpected directions and/or produces undesir-cble reflections. liowever, circumferential IGSCC in the liAZ of a@nitic welds has been detected successfully with ultrasonic techniques because,in this case, the sound beam does not pass through the weld metal.

The dendritic structure of the weld acts somewhat like a wave guide diverting the shear w:ve sound beam from the intended direction. Beam divergence makes indication location difficult. When searching for axial cracks, the beam divergence is worse be-c:use almost the endre sound path lies in weld metal. The austenitic weld metal se-verely attenuates and scatters the shear wave beam and limits the effectiveness of the examination. The high attenuation limits penetration of the beam into the weld and the high material noise level prevents detection of significant flaws. The high attenuation and high noise level in the weld metal combine with the lack of good location informa-tion to make axial cracks undetectable using conventional, shear wave ultrasonic exami-nation. Shear wave examinadons are not capable of reliably detecting even large flaws in austenitic weld metal.

Examination techniques using refracted longitudinal wave methods have proven effec-tive for examination of austenitic weld materials. Longitudinal waves suffer less attenu-cuon and have a weaker dependence of velocity on anisotropy than do shear waves.

Also, better penetration can be achieved with less noise, enabling detecuon of defects in locations not examinable with shear waves. However, a shear wave beam at a lower angle always accompanies the longitudinal wave and can be a source of addidonal 7-11 I

Mechanistn Spectfic Exarnination Volurnes and Methods spurious indications that must be taken into account. Even with longitudinal waves, a high material noise level is sometimes present, which can interfere with deteetion of small amplitude indications.

~l In this application, conventional shear wave examination telles on detecting the reflec-tion from the corner formed by the flaw and the inner surface. With longitudinal waves, the corner reflection is usually weak because of mode conversion occurring at the re-flecting surfaces; however, the diffracted signal from the crack tip is of primary interest.

Where access is available to both sides of the weld, examination techniques are to be applied from the base metal on each side of the weld such that the weld and near side base metal are completely examined from the near side.

Where access to both sides of the weld is not possible, examination procedures must be modified to detect flaws oriented nominally pardlel to the weld. Detection of these flaws may be achieved using both shear and longitudinal wave techniques from one side of the weld and weld crown. The weld should be ground flush or flat topped and the weld and far side base metal should be examined using refracted longitudinal and shear wave search units by scanning across the accessible base metal and weld. As a minimum, a 45' shear and longitudinal wave should be applied from the accessible weld crown. When examining from the weld surface,it might be necessary to scan at less than 3 inches per second.

Longitudinal wave frequencies lower than 2 MHz might be required for detection of flaws on the opposite side of the weld. This is permitted, provided a minimum signal-to-noise ratio of 10 to 1 is achieved from the inside surface notch in the basic calibration block. The search unit band width should be greater than 30%

To effectively cover the examination area,it might be necessary to use shear wave search units with nominal angles of 45,60, and 70', as well as additional search units producing those ang!cs with longitudinal waves.

No techniques are currently qualified for determining the length of reflectors using./

/

either shear or longitudinal waves through austenitic weld metal.

Acceptance Standard: Section XI, IWB - 3514 Evaluation Standard: Section XI, IWB - 3640 7-12

i Mechanisrrt Specific Exarninatiort Volurnes arid Methods I

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7.5 Microbiologically influenced Corrosion (MIC)

Affected Region: Pipin; components with fluids contain ng organic material or with i

orgame material deposite.. The most vulnerable components are raw water systems, storage tanks, and transport systems. Systems witn low to intermittent flow conditions, temperatures between 20-120 F, and pH beJow 10 ara primary candidates.

Examination Volumes: Base metal, welds and weld heat-affected zones in the affected regions of carbon and low alloy, and the welds and weld heat-affected zones in the affected regions of austenitic steel. The examinations should focut. m regions whc re the degradation appears to be most prevalent as determined by visual inspection an de-scribed below in Examination Mediod section.

7-15

Mecharsistn Specifi: Exarnination Volurnes and Methods f

Examination Volume Figures: See Figure 7.5-1.

Examination Method: The examination metaod should be coupled with a monitoring program that defines the biological population found in the system. Visual techniques give indications when observations are made immediately upon opening a system. The presence of sludge / silt, metal sulfides, malodors, and general fouling / deposition are preliminary indicators of the possibility of MIC.

- It is very important when examining components for MIC degradation to identify what the damage mecnanisms will look like, as it will have a dramatic effect on the examina-tion results. For example, uniform thinning is relatively easy to detect with ultrasonic examination, while pitting or tunneling might be easier to detect with radiography and quantified with ultrasonic examination. It is possible to detect pitting and tunneling

=

with ultrasonic techniques. However, it might require slower scan speeds, higher in-h stmment gain settings, and more sensitive transducers. In severe cases, tunneling dam-Z age results in a complete loss of ultrasonic signals.

Examination personnel should also be aware cf the potential damage mechanisms so that they can select the appropriate exunination method and procedure. Ultrasonic h

examination personnel need to be aware of the signal characteristics that might be

}

associated with the damage mechanism.

For ultrasonic examinations, the complete area of interest should be examined, as MIC d unage can be random. Grid patterns can be used with the entire grid scanned and the thin reading recorded. If point thickness readings are taken,it is important to consider that the probability of detection of thin locations has been reduced, i

Acceptance Standard:IWB-3514

'dvaluation Standard: Wall thinning can be evaluated using the guidelines in ASME y

Code Case N-480. Pitting can be evaluated by using ASME Code Case N-480 where the degraded wall thickness is t - t,, and t, is determined from the relationship t, = total volume of the detected pitting in the inspected length of pipe (circumferential extent of pitting x axial extent of pitting in the inspected region). The total pitting volume of the affected region can be determined by rectangular areas that encompass the degraded i

volume of pipe material.

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1 7-17 m

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7.6 Erosion-Cavitation Affccted Region: Regions where ( p,- p,)/ Ap < 5 psi, and V > 30 ft/sec., and fluid temperature < 250 F are considered suveptible to degradation from erosion-cavitation, where p, is the static pressure downstream of the unit (pump, valve, etc.), p, is the vapor pressure, Ap is the pressure differential across the unit, and V is the flow mean 7-18 I

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Mechanism Spectfic Examination Volumes and Methods.

velocity at the inlet of the unit. Standard reducers do not create the potential for erosion.

1 degradation. Regions where flow occurs for less than 20 hrs./yr, are not considered -

susceptible to degradation from erosion-cavitation.

Examination Volumes: The volume of material, including base metal, welds, and weld

heat-affected zone, within 5D downstream of the cavitation source. If an elbow is within SD of the cavitation source, then the affected region extends to the first weld past the elbow. Examination should focus on wall thinning from the inside surface. The actual volume selected within the 5D !ength can be determined in a manner similar to that used to define the inspection region for the plant FAC inspection program (see Section 7.7).

Evaluation Volume Figures: See Section 7.7, Flow-Acelerated Corrosion (FAC).

Examination Method: Erosion-cavitation is detectable with visual, ultrasonic, or radio--

graphic examination methods. The preferred NDE method depends on the specific L

location where erosion-cavitation is expected, but may include ultrasonic thickness measurements, radiographic tangential ano double wall techniques, as well as visual examination.

Acceptance Standard: See Section 7.7, FAC.

Evaluation Standard: See Section 7.7, FAC.

7.7 Flow-Accelerated Corrosion (FAC)

Affected Region: Component base metal regions susceptible to FAC, as identified in Section 4.2.7.

E=mination Volumes: Volume of material susceptible to FAC as identified in the existing plant FAC inspection program, or for the purpose of RISI iden tified in accor-dznce with the plant FAC evaluation criteria.

Examination Volume Figures: See Figures 7.7-1 through -7.

Ex.mination Method: Volumetric. Manual ultrasonic examination is typically used to

} detect and measure component walls for single and two phase FAC. Most piping sys-

. tems that are susceptible to FAC operate at elevated temperatures, hence they have insulation that must be removed and the surface prepared prior to the ultrasonic exami-nation. Because the damage mechanism is gradual wear over an area rather than iso-1sted thickness loss, spot thickness rendir gs at predetermined locations can be done

- rather than 100% examination. The s1M th8 ckness locations should be identified in a procedure that provides a method of gc.xmg the component in a repeatable fashion.

The thickness readings should be taken at the grid intersections. It is important that the location of each thickness reading be repeated for future examinations, as thickness data is often used to identify and trend pipe wear.

7-19

_ Mechanism Specific Examination Volumes and Methods Although the ultrasonic technique used for acquiring thickness data is one of the least complicated ultrasonic techniques,it is important that adequate procedures are in pir.ce to ensure accurate repeatable results. Equipment selection is one of the more important variables associated with this technique. Transducers must be selected based on the applicable thickness range. It is also important to use an ultrasonic instrument with an A-scan presentation so that volumetric reflectors do not provide inaccurate data. Por-I table digital thickness gauges with A-scan presentations are available and have been found to provide adequate results.

As an alternative to ultrasonic examination, radiography can be used to detect and measure FAC. However, the procedure is generally limited to pipes of 6-inch NPS and less because of long exposure times for larger diameter piping. A tangential radio-graphic technique that aligns the source, pipe wall, and film can be used to obtain quantitative thickness data, however several shots are required to exandne a corapo-nent. The primary benefit of radiography is that it can be used to examine components with insulation in place, eliminating the cost associated with insulation removal and reinstallation. Radiography also provides better data on socket welded components than ultrasonics.

Acceptance Standard: According to the plant FAC program.

Evaluation Standard: According to the plant FAC program.

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7-23

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7-26

.