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| issue date = 09/30/1995
| issue date = 09/30/1995
| title = Repair Boundary for Parent Tube Indications within Upper Joint Zone of Hybrid Expansion Joint Sleeved Tubes.
| title = Repair Boundary for Parent Tube Indications within Upper Joint Zone of Hybrid Expansion Joint Sleeved Tubes.
| author name = CULLEN W K, KEATING R F, KUCHIRKA P J
| author name = Cullen W, Keating R, Kuchirka P
| author affiliation = WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
| author affiliation = WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
| addressee name =  
| addressee name =  
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=Text=
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{{#Wiki_filter:Westinghouse Non-Proprietary Class 3 WCAP-14447 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ)Sleeved Tubes September 1995 R.F.Keating W.K.Cullen P.J.Kuchirka WESTINGHOUSE ELECTRIC CORPORATION NUCLEAR SERVICES DIVISION P.O.BOX 158 MADISON, PENNSYLVANIA 15663-01 58@1995 WESTINGHOUSE ELECTRIC CORPORATION All Rights Reserved 9510270085 951020 PDR ADOCK 05000315 PDR'
{{#Wiki_filter:Westinghouse Non-Proprietary Class 3 WCAP-14447 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes September 1995 R. F. Keating W. K. Cullen P. J. Kuchirka WESTINGHOUSE ELECTRIC CORPORATION NUCLEAR SERVICES DIVISION P.O. BOX 158 MADISON, PENNSYLVANIA 15663-01 58
                @ 1995 WESTINGHOUSE ELECTRIC CORPORATION All Rights Reserved 9510270085 951020 PDR ADOCK 05000315
'                PDR


Westinghouse non-Proprietary Class 3~Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ)Sleeved Tubes SECTION TABLE OF CON'IENTS PAGE 1.0 Introduction 1.1 Description of the Sleeving Process 1.2 Summary of HEJ Sleeve Installations 1.3 Summary of HEJ Repair Boundary Qualified in this Report 1-1 1-1 1-2 1-2 2.0 Discussion and Conclusions 2.1 Discussion 2.2 Conclusions 2.2.1 Indication Locations 2.2.2 Allowable Indication Arc Length 2.2.3 Axial Indications 2.2.4 Primary-to-Secondary Leakage 2-1 2-1 2-2 2-2 2-2 2-2 2-2 3.0 Regulatory Requirements 3.1 Regulatory Guide l.121 3.2 Accident Condition Allowable Leak Rate 3-1 3-1 3-2 4.0 Field Experience 4.1 HEJ Sleeved Tube Indications 4.1.1 Kewaunee Nuclear Power Plant 4.1.2 Point Beach Unit 2 Nuclear Power Plant 4.1.3 Kerncentrale Doel 4 Nuclear Power Plant 4.2 Summary of Field Experiences 4-1 4-1 4-1 4-1 4-2 43 5.0 Summary of Examinations Conducted on Kewaunee Steam Generator Tubes with Hybrid Expansion Joints 5.1 Introduction 5.2 NDE Results 5.3 Leak Testing 5.4 Tensile Testing 5.5 Destructive Examination Results 5.6 Surface Chemistry 5.7 Conclusions 5-1 5-1 5-1 5-2 5-2 5-3 5-5 5-6 09/2$/9$  
Westinghouse non-Proprietary Class 3
    ~
Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes TABLE OF CON'IENTS SECTION                                                              PAGE 1.0   Introduction                                                   1-1 1.1   Description of the Sleeving Process                       1-1 1.2 Summary of HEJ Sleeve Installations                         1-2 1.3   Summary of HEJ Repair Boundary Qualified in this Report   1-2 2.0   Discussion and Conclusions                                     2-1 2.1 Discussion                                                 2-1 2.2 Conclusions                                                 2-2 2.2.1 Indication Locations                               2-2 2.2.2 Allowable Indication Arc Length                     2-2 2.2.3 Axial Indications                                   2-2 2.2.4 Primary-to-Secondary Leakage                       2-2 3.0   Regulatory Requirements                                         3-1 3.1   Regulatory Guide l. 121                                   3-1 3.2 Accident Condition Allowable Leak Rate                     3-2 4.0   Field Experience                                               4-1 4.1 HEJ Sleeved Tube Indications                               4-1 4.1.1 Kewaunee Nuclear Power Plant                       4-1 4.1.2 Point Beach Unit 2 Nuclear Power Plant             4-1 4.1.3 Kerncentrale Doel 4 Nuclear Power Plant             4-2 4.2 Summary of Field Experiences                               43 5.0   Summary of Examinations Conducted on Kewaunee Steam             5-1 Generator Tubes with Hybrid Expansion Joints 5.1 Introduction                                               5-1 5.2 NDE Results                                                 5-1 5.3 Leak Testing                                               5-2 5.4 Tensile Testing                                             5-2 5.5 Destructive Examination Results                             5-3 5.6 Surface Chemistry                                           5-5 5.7 Conclusions                                                 5-6 09/2$ /9$


Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ)Sleeved Tubes SECTION TABLE OF COÃZP24TS (Continued)
Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes TABLE OF COÃZP24TS (Continued)
PAGE 6.0 Structural Integrity and Leak Rate Evaluations 6.1 Structural Integrity Tests 6.2 Pulled Tube Structural Tests 6.3 Structural Integrity Analyses 6.4 Leak Rate Tests and Analyses 6.5 Crack Growth Rate Considerations 6.6 Additional Tube Integrity Considerations and Observations 6.7 Conclusions 6-1 6-1 6-2 6-2 6-3 6-3 6-3 6-47.0 Leak Rate Based Repair Boundary 7.1 Introduction 7.2 Sleeved Tube Dimensions 7.3 U-Bend Clearance 7.4 Leakage Potential 7.4.1 Normal Operation 7.4.2 Steam Line Break 7.5 Tubes Interior to Stayrod Locations 7.6 Distribution of Indications in the Kewaunee SGs Sleeved Tubes 7.7 Plant Operation Considerations 7.8 Summary and Conclusions 7-1 7-1 7-2 7-3 7-5 7-6 7-6 7-7 7-7 7-8 7-8 8.0 Repair Boundary for Parent Tube Indications 8.1 Compliance with draft RG 1.121 Tube Integrity Criteria 8.2 Offsite Dose Evaluation For a Postulated Main Steam Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve 8.3 Evaluation of Other Steam Loss Accidents 8.4 HEI Inspection Requirements 8-1 8-1 8-2 8-2 8-3 HEllNDEX.SEC  
SECTION                                                              PAGE 6.0   Structural Integrity and Leak Rate Evaluations                 6-1 6.1   Structural Integrity Tests                               6-1 6.2 Pulled Tube Structural Tests                               6-2 6.3 Structural Integrity Analyses                               6-2 6.4 Leak Rate Tests and Analyses                               6-3 6.5 Crack Growth Rate Considerations                           6-3 6.6 Additional Tube Integrity Considerations and Observations   6-3 6.7 Conclusions                                                 6-4 7.0   Leak Rate Based Repair Boundary                               7-1 7.1   Introduction                                             7-1 7.2   Sleeved Tube Dimensions                                 7-2 7.3   U-Bend Clearance                                         7-3 7.4   Leakage Potential                                       7-5 7.4.1 Normal Operation                                   7-6 7.4.2 Steam Line Break                                   7-6 7.5   Tubes Interior to Stayrod Locations                     7-7 7.6   Distribution of Indications in the Kewaunee SGs         7-7 Sleeved Tubes 7.7   Plant Operation Considerations                           7-8 7.8   Summary and Conclusions                                 7-8 8.0   Repair Boundary for Parent Tube Indications                     8-1 8.1   Compliance with draft RG 1.121 Tube Integrity Criteria   8-1 8.2 Offsite Dose Evaluation For a Postulated Main Steam         8-2 Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve 8.3 Evaluation of Other Steam Loss Accidents                   8-2 8.4 HEI Inspection Requirements                                 8-3 HEllNDEX.SEC


Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEW)Sleeved Tubes SECTION TABLE OF CONHMTS (Continued)
Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEW) Sleeved Tubes TABLE OF CONHMTS (Continued)
PAGE 9.0 Summary of Sleeve Degradation Limit Acceptance Criteria 9.1 Stxuctural Considerations 9.1.1 Crack Indications Below the Upper Hardroll Lower Transition 9.1.2 Sleeved Tube with Degradation Indications with Non-Dented Tube Support Plate Intersections 9.1.3 Dented Tubes 9.2 Leakage Assessment 9.3 Defense In Depth and Primary to Secondaxy Leakage Limits 9-1 9-1 9-1 9-1 9-1 9-1 9-2 10.0 References 10-1 Appendix A, Review of Prior Amendment Requests for HEI Sleeved Tubes 1.0 2.0 3.0 Discussion/Chronology of Pxior Amendment Requests Summaxy of Stxuctural Integrity and Leak Rate Evaluations 2.1 Structural Integrity Tests 2.2 Structural Integrity Analyses 2.3 Leak Rate Tests and Analyses 2.4 Crack Growth Rate Evaluations Summary$-1 A-2 A-3 A-.4 A-5 A-5 A-6 HEJ INDEX.SEC  
SECTION                                                                    PAGE 9.0     Summary of Sleeve Degradation Limit Acceptance Criteria             9-1 9.1   Stxuctural Considerations                                     9-1 9.1.1 Crack Indications Below the Upper Hardroll Lower       9-1 Transition 9.1.2 Sleeved Tube with Degradation Indications with         9-1 Non-Dented Tube Support Plate Intersections 9.1.3 Dented Tubes                                           9-1 9.2   Leakage Assessment                                           9-1 9.3   Defense In Depth and Primary to Secondaxy Leakage Limits     9-2 10.0 References                                                           10-1 Appendix A, Review     of Prior Amendment Requests for HEI Sleeved Tubes 1.0     Discussion/Chronology of Pxior Amendment Requests                   $ -1 2.0    Summaxy of Stxuctural Integrity and Leak Rate Evaluations           A-2 2.1   Structural Integrity Tests                                   A-3 2.2 Structural Integrity Analyses                                   A-.4 2.3 Leak Rate Tests and Analyses                                   A-5 2.4 Crack Growth Rate Evaluations                                   A-5 3.0    Summary                                                            A-6 HEJ INDEX.SEC


Westinghouse non-Proprietary Class 3Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HED)Sleeved Tubes 1.0 Introduction In the Spring and FaH of 1994, and the Spring of 1995, indications were found in the hybrid expansion joint (HEJ)region of Steam Generator (SG)tubes which had been sleeved using Westinghouse HEJ sleeves.As a result of these findings, analytic and test evaluations were performed'o assess the effect of the degradation on the structural, and leakage, integrity of the sleeve/tube joint relative to the requirements of the United States Nuclear Regulatory Commission's (NRC)draft Regulatory Guide (RG)1.121, Reference 10.The results of these evaluations demonstrated that tubes with implied or known crack-like circumferential parent tube indications (PIIs)located 1.1" or, farther below the bottom of the hardroll upper transi-tion, have sufficient, and significant, integrity relative to the requirements of the RG.Thus, the purpose of this report is to provide justification for a repair boundary that supersedes that specified in the original Westinghouse WCAP'ualification documents.
Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HED) Sleeved Tubes 1.0 Introduction In the Spring and FaH of 1994, and the Spring of 1995, indications were found in the hybrid expansion joint (HEJ) region of Steam Generator (SG) tubes which had been sleeved using Westinghouse HEJ sleeves. As a result of these findings, analytic and test evaluations were performed'o assess the effect of the degradation on the structural, and leakage, integrity of the sleeve/tube joint relative to the requirements of the United States Nuclear Regulatory Commission's (NRC) draft Regulatory Guide (RG) 1.121, Reference 10. The results of these evaluations demonstrated that tubes with implied or known crack-like circumferential parent tube indications (PIIs) located 1.1" or, farther below the bottom of the hardroll upper transi-tion, have sufficient, and significant, integrity relative to the requirements of the RG. Thus, the purpose of this report is to provide justification for a repair boundary that supersedes that specified in the original Westinghouse WCAP'ualification documents. A listing of United States plants with installed HEJs is provided in Table 1-1.
A listing of United States plants with installed HEJs is provided in Table 1-1.1.1 Description of the Sleeving Process In accordance with Plant Technical Specification requirements, steam generator tubes are periodically inspected for degradation using nondestructive examination (NDE)techniques.
1.1 Description   of the Sleeving Process In accordance with Plant Technical Specification requirements, steam generator tubes are periodically inspected for degradation using nondestructive examination (NDE) techniques.       If established degradation acceptance criteria are exceeded, the indication must be removed from service by plugging or repairing the tube. Tube sleeving is one repair technique used to return a tube to an operable condition.
If established degradation acceptance criteria are exceeded, the indication must be removed from service by plugging or repairing the tube.Tube sleeving is one repair technique used to return a tube to an operable condition.
In the sleeving technique, a smaller diameter tube, or sleeve, is positioned within the parent tube so as to span the degraded region. The ends of the sleeve are then secured to the parent tube forming a new pressure boundary and structural element between the attachment points.
In the sleeving technique, a smaller diameter tube, or sleeve, is positioned within the parent tube so as to span the degraded region.The ends of the sleeve are then secured to the parent tube forming a new pressure boundary and structural element between the attachment points.Sleeves may be positioned at any location along the straight length of a tube, but are typically placed to repair tube degradation at the top of, or within the tubesheet, or at tube support plate (TSP)intersections.
Sleeves may be positioned at any location along the straight length of a tube, but are typically placed to repair tube degradation at the top of, or within the tubesheet, or at tube support plate (TSP) intersections. Sleeves may be of various lengths and may be attached to the parent tube in a variety of ways. In the case of Westinghouse sleeve designs, the method of attachment is generally restricted to either a leak limiting mechanical HEJ or a hermetic Laser Welded Sleeve (LWS) joint. The type of the particular joint configuration is a function of the date of installation and/or the customer's needs and the current plant operating conditions.
Sleeves may be of various lengths and may be attached to the parent tube in a variety of ways.In the case of Westinghouse sleeve designs, the method of attachment is generally restricted to either a leak limiting mechanical HEJ or a hermetic Laser Welded Sleeve (LWS)joint.The type of the particular joint configuration is a function of the date of installation and/or the customer's needs and the current plant operating conditions.
Figure 1-1 shows a schematic of a typical HEJ tubesheet sleeve installation. Figure 1-2 illustrates the details of the upper joint along with terminology used in this report. Typical dimensions of the joint are illustrated on Figure 1-3. Note that only the sleeve/tube upper joint is referred to as a HEJ, and the sleeve is referred to as an HEJ sleeve.
Figure 1-1 shows a schematic of a typical HEJ tubesheet sleeve installation.
References 8 and 9, supplemented by References 11 and 12.
Figure 1-2 illustrates the details of the upper joint along with terminology used in this report.Typical dimensions of the joint are illustrated on Figure 1-3.Note that only the sleeve/tube upper joint is referred to as a HEJ, and the sleeve is referred to as an HEJ sleeve.References 8 and 9, supplemented by References 11 and 12.Westinghouse Commercial Atomic Power DAPLANTSV EPQKllNTRO.SEC 09/26/9S Westinghouse non-Proprietary Class 3 1.2 Summary of HEJ Sleeve Installations
Westinghouse Commercial Atomic Power DAPLANTSVEPQKllNTRO.SEC                                                                     09/26/9S
~~hown in T-2 since its in tio As s able 1 cep n in 1980, the HEJ sleeve has been successfully used to restore over 28,000 steam generator tubes to operational status.Due to decommissioning of plants and replacement of steam generators, only about 12,000 HEJ sleeves remain in service.As shown in Table 1-3, HEJ sleeves are currently in service in the United States at the D.C.Cook Unit 1, Point Beach Unit 2, Kewaunee, and Zion Unit 1 nuclear power plants.The HEJ sleeves listed in Table 1-2 were installed between April 1983 and May 1993, and have operated in the United States without incidence of significant leakage through the upper joint;Doel 4 (Belgium)experienced leakage through an upper joint crack in a parent tube in April of 1994.below the hardroll upper transition (HRUT), and lower, is the sub~ec 1.3 Summary of the HEJ Repair Boundary Qualified in this Report Until March of 1994 there had been no reports of degradation of the parent tubes or the sleeves.In 1994, degradation of the pan.nt tube of HEJ sleeved tubes was detected at the Kewaunee, Point Beach 2, and Doel 4 power plants.At Kewaunee the indications were predominantly located in the hardroll lower transition (HRLT), while at Point Beach 2 the indications were predominately in the hydraulic expansion lower transition (HELT), and at Doel 4 the two confirmed indications were located at the hydraulic expansion upper transition (HEUT).Additional degradation was reported at Kewaunee in the Spring of 1995, and three sleeve/tube joints were removed from the"B" SG for laboratory examination.
The structural and leakage integrity of HEJs in 7/8" nominal diameter tubes with indications located 1.1" t of this report.I The repair boundary is based on analytic evaluations, the results of prototypic testing, and the results of the destructive examinations and tests of the HEJ specimens removed from Kewaunee.The reference location, i.e., the bottom of the HRUT, for reckoning the repair boundary was selected based on the ease of measuring the elevation of indications relative to the that location using existing, e.g., the Westinghouse CECCO and the Zetec+Point eddy current probes, nondestructive examination (NDE)technology.
The actual location of the repair boundary is supported by the structural and leakage evaluations performed using the data from the destructive examinations of the field specimens and the prototypic testing reported in WCAP-14157 and its addendum.DAPLANTSUEEPQKJINTRO.SEC 1-2


Westinghouse non-Proprietary Class 3 Table 1-1: Sleeving Design Documents for United States Plants with HETs Design Document Subject Reference(s)
Westinghouse non-Proprietary Class 3 1.2 Summary
W CAP-9960 W CAP-11573 W CAP-11643 W CAP-11669 WCAP-12623 Point Beach Unit 2, Alloy 600 sleeves Point Beach Unit 2, Alloy 690 Sleeves Kewaunee, Alloy 690 Sleeves Zion Units 1&2, Alloy 690 Sleeves D.C.Cook Unit 1, AHoy 690 Sleeves 1,2 I 3 4,5 DM'LANTSVLEPQKBJINTRO.TBL 1-3
  ~            of HEJ    Sleeve Installations
            ~
As s hown in Table 1 -2 since its incep tion in 1980, the HEJ sleeve has been successfully used to restore over 28,000 steam generator tubes to operational status. Due to decommissioning of plants and replacement of steam generators, only about 12,000 HEJ sleeves remain in service. As shown in Table 1-3, HEJ sleeves are currently in service in the United States at the D. C. Cook Unit 1, Point Beach Unit 2, Kewaunee, and Zion Unit 1 nuclear power plants. The HEJ sleeves listed in Table 1-2 were installed between April 1983 and May 1993, and have operated in the United States without incidence of significant leakage through the upper joint; Doel 4 (Belgium) experienced leakage through an upper joint crack in a parent tube in April of 1994.
Until March of 1994 there had been no reports of degradation of the parent tubes or the sleeves. In 1994, degradation of the pan.nt tube of HEJ sleeved tubes was detected at the Kewaunee, Point Beach 2, and Doel 4 power plants. At Kewaunee the indications were predominantly located in the hardroll lower transition (HRLT), while at Point Beach 2 the indications were predominately in the hydraulic expansion lower transition (HELT), and at Doel 4 the two confirmed indications were located at the hydraulic expansion upper transition (HEUT). Additional degradation was reported at Kewaunee in the Spring of 1995, and three sleeve/tube joints were removed from the "B" SG for laboratory examination. The structural and leakage integrity of HEJs in 7/8" nominal diameter tubes with indications located 1.1" below the hardroll upper transition (HRUT), and lower, is the sub~ec t of this report.
I 1.3 Summary    of the  HEJ Repair Boundary Qualified in this Report The repair boundary is based on analytic evaluations, the results of prototypic testing, and the results of the destructive examinations and tests of the HEJ specimens removed from Kewaunee. The reference location, i.e., the bottom of the HRUT, for reckoning the repair boundary was selected based on the ease of measuring the elevation of indications relative to the that location using existing, e.g., the Westinghouse CECCO and the Zetec + Point eddy current probes, nondestructive examination (NDE) technology. The actual location of the repair boundary is supported by the structural and leakage evaluations performed using the data from the destructive examinations of the field specimens and the prototypic testing reported in WCAP-14157 and its addendum.
DAPLANTSUEEPQKJINTRO.SEC                      1-2


Westinghouse non-Proprietary Class 3 Table 1-2: Westinghouse Sleeving Experience Chronology Plant Date Installed S/G Type Number Sleeve e(1)0 Sleeves Material Length (in)Sleeve Characteristics San Onofre 2 10/80-6/81 W-27 TS 6929 600TT 27,30,36 HEJ Point Beach 1 11/81 W-44 TS 13 36 HEJQ)Indian Point 3 Point Beach 2 Millstone 2 10/82-1/83 4-6/83 7-9/83 W-44 W-44 CE-67 TS 2971 600TI'S 3000 600TI'S 2036 625/690TT 36,40,44 HEJ 36 40 Ringhals 2 05/84 W-51 TS 69021 30 Braze Millstone 2 Indian Point 3 Millstone 2 03/85 07/85 11/86 CE-67 W-44 CE-67 TS TS 635 225 625/690TT TS 2926 625/690TI'0 36,40,44 HEJ 40 Point Beach 2 10/87 W-44 TS 690TT 36 Kewaunee Zion 1 Doel 3 Point Beach 2 Kewaunee 03/88 03/88 06/88 10/88 03/89 W-51 W-51 W-51 W-44 W-51 TS TS 58 54 690TT 690TT TS 509 TS 1698 6901T 690TT TS 1940 690TT 30 30 Laser"'0,36 HEJ 30,36 HEJ 30 Point Beach 2 10/89 W-44 TS 298 690TI'6 Kewaunee 03/91 W-51 TS 691 690TT 27,30,36 Parley 2 3/92 W-51 TSP 69 690TI'0 Laser)Parley 2 D.C.Cook 1 3/92 7/92 W-51 W-51 690Tl'0 TS TS 1840 690TI'2 Laser8)30,27 HEJ Parley 1 Parley 1 9/92 9/92 W-51 W-51 TSP 148 TS 690TT 690Tl 30 12 Laser8)Laser)Doel 4 Doel 4 5/93 1994 W-E1 W-E1 TS 1752 690TT TS)11000 690TT Total>39000 Las ere)12 30,36 HEJ Notes: (1)TS=tubesheet sleeve&TSP=tube support plate sleeve.(2)Brazed sleeves also installed.
Westinghouse non-Proprietary Class 3 Table 1-1: Sleeving Design Documents for United States Plants with HETs Design Document                          Subject            Reference(s)
(3)CO, laser used for the welding process.(4)YAG laser used for the welding process.DAPLANTSU.EPQKJINTRO.TBL 1-4 Westinghouse non-Proprietary Class 3Table 1-3: HEJ Sleeves Operational Status as of 1994 Plant Date Installed S/G Type Number of Sleeves<'>
WCAP-9960                Point Beach Unit 2, Alloy 600 sleeves      1,2 I
Material Length (in)Sleeve Characteristics Point Beach 2 Point Beach 2 Kewaunee Zion 1 Point Beach 2 Kewaunee Point Beach 2 3/88 3/88 W-51 W-51 10/88 W-44 3/89 W-51 10/89 W-44 4-6/83 W-44 10/87 W-44 87 1940 47 509 1698 298 690TT 690TI'90TT 690TT 690TT 690TT 36 36 30,36 30 30 30,36 36 Kewaunee D.C.Cook1 Doel 4"'/91 7/92 5/93 W-51 W-51 W-E1 Total 1840 1752 11862 690TT 690TT 691 690TI'7,30,36 30,27 30,36 Notes;(1)Number is approximate.
WCAP-11573                Point Beach Unit 2, Alloy 690 Sleeves        3 WCAP-11643                Kewaunee, Alloy 690 Sleeves                4,5 WCAP-11669                Zion Units  1 & 2, Alloy 690 Sleeves WCAP-12623                D. C. Cook Unit 1, AHoy 690 Sleeves DM'LANTSVLEPQKBJINTRO.TBL                     1-3
(2)HEJ modified by YAG laser welding in 1994, D:1PLANTS~HEJINTRO.TBL 1-5 09/26/95


('Upper Hydraulic:
Westinghouse non-Proprietary Class 3 Table 1-2: Westinghouse Sleeving Experience Chronology Number              Sleeve Characteristics Date        S/G    Sleeve Plant                                    e(1) 0                        Length Installed    Type                        Material Sleeves                        (in)
Expansion Upper Hardroll Parent Tube~,~Sleeve.Tubesheet Lower Hydraulic Expansion!/Lower Hardroll Cladding Figure 1-1: Typical HEJ Sleeve Installation SAAPC~P95~P HEJF.001 1-6 7/30/95
San Onofre 2        10/80-6/81    W-27      TS      6929      600TT          27,30,36                  HEJ Point Beach 1          11/81      W-44      TS        13                          36            HEJQ)
Indian Point 3      10/82-1/83    W-44      TS      2971      600TI'S 36,40,44                  HEJ Point Beach 2        4-6/83      W-44                3000      600TI'S 36 Millstone 2          7-9/83    CE-67                2036    625/690TT              40 Ringhals 2            05/84      W-51      TS                69021                30              Braze Millstone 2            03/85    CE-67      TS      2926    625/690TI'0 Indian Point 3        07/85      W-44      TS        635                      36,40,44                HEJ Millstone 2            11/86    CE-67      TS        225    625/690TT              40 Point Beach 2          10/87      W-44      TS                  690TT              36 Kewaunee              03/88      W-51      TS      1940      690TT            30,36                  HEJ Zion 1                 03/88      W-51      TS        58        690TT              30 Doel 3                06/88      W-51      TS        54        690TT              30 Point Beach 2          10/88      W-44      TS        509      6901T              30      Laser"'0,36 Kewaunee              03/89    W -51      TS      1698      690TT                                    HEJ Point Beach 2          10/89      W-44      TS        298      690TI'6 Kewaunee              03/91      W-51      TS        691      690TT          27,30,36 Parley 2                3/92      W-51      TSP        69      690TI'0                      Laser)
Parley 2                3/92      W-51      TS                                              Laser8) 690TI'2 690Tl'0 D. C. Cook    1         7/92      W-51      TS      1840                        30,27                  HEJ Parley 1                9/92      W-51      TSP        148      690TT              30       Laser8)
Parley 1                9/92      W-51      TS                  690Tl              12      Laser)
Doel 4                  5/93      W-E1      TS      1752        690TT            30,36                  HEJ Doel 4                  1994      W-E1      TS    ) 11000      690TT              12      Las ere)
Total  >39000 Notes:    (1)  TS = tubesheet sleeve & TSP = tube support plate sleeve.
(2)  Brazed sleeves also installed.
(3)  CO, laser used for the welding process.
(4)  YAG laser used for the welding process.
DAPLANTSU.EPQKJINTRO.TBL                        1-4


Tube Hydraulic Expansion Upper Transition (HEUT)Sleeve Hardroll Upper Transition (HRUT)Hardroll Hardroll Lower Transition (HRLT)Bottom of the transition.
Westinghouse non-Proprietary Class 3 Table 1-3: HEJ Sleeves Operational Status as of 1994 Date        S/G    Number of              Sleeve Characteristics Plant Installed    Type    Sleeves<'>    Material      Length (in)
Hydraulic Expansion Lower Transition (HELT)Figure 1-2: Hybrid Expansion Joint ConQguration S:EAPCEAEP954AEP HEJF.001 1-7
Point Beach 2          4-6/83      W-44                                      36 Point Beach 2          10/87      W-44        87          690TT            36 Kewaunee                3/88      W-51        1940                        30,36 690TI'90TT Zion 1                  3/88      W-51        47                            30 Point Beach 2          10/88      W-44        509          690TT            30 Kewaunee                3/89      W-51        1698        690TT          30,36 Point Beach 2          10/89      W-44        298          690TT            36 Kewaunee Doel 4
        "'/91 D. C. Cook1            7/92 5/93 W-51 W-51 W-E1 691 1840 1752 690TI'7,30,36 690TT 690TT 30,27 30,36 Total      11862 Notes;    (1) Number is approximate.
(2) HEJ modified by YAG laser welding in 1994, D:1PLANTS~HEJINTRO.TBL                      1-5                                          09/26/95


Figure 1-3: Typical Dimensions of the HEJ SAAPC~P9SULEP HEJF.001 1-8 7/30/95  
('
Upper Hydraulic:                                      Upper Hardroll Expansion Parent Tube                ~
                                                    ,~      Sleeve
      . Tubesheet Lower Hydraulic Expansion Lower Hardroll
              /
Cladding Figure 1-1: Typical HEJ Sleeve Installation SAAPC~P95~P  HEJF.001                     1-6                                  7/30/95


Westinghouse non-Proprietary Class 3 2.0 Discussion and Conclusions The burst criteria of draft RG 1.121 were used to establish a repair boundary for HEJs with PTIs.The continued safe operation of the SGs is not compromised if the PTls are located below the repair boundary, i.e., 1.1" downward from the bottom of the HRUT or lower, as illustrated on Figure 2-1.A geometry based argument has been developed, Section 7.0, to support the repair boundary as established by structural considerations for PTIs in HEJ sleeved tubes.'summary of the conclusions relative to the establishment and implementation of the repair boundary for HEJ sleeved tubes in Westinghouse Model 44 and 51 SGs is provided in Section 2.2.Additional sections of this report provide a discussion of field experiences through the date of publication of this report, the details of the destructive examinations of sleeved tube sections removed from an operating SG, and structural integrity and potential leak rate considerations made to establish the repair boundary.2.1 Discussion During the Spring, 1995, outage at Kewaunee, three (3)HEJ sleeved tube sections were removed intact from SG"B" for laboratory examination.
Tube Hydraulic Expansion Upper Transition Sleeve (HEUT)
One of the sections was designated for archive retention and the remaining two sections have been destructively examined.Each of the specimens exhibited field called PTIs in the hardroll lower transition using thb+Point probe.The indications were confirmed to be extensive, circumferentially oriented, stress corrosion crack arrays (SCC)originating on the inside surface of the tube, confirming the accuracy of the detection and sizing of the NDE.No cracking of the sleeves, and no cracking in the upper transitions of the tubes was found.A detailed discussion of the results of the examinations are provided in Section 5.0 of this report.Structural tests done on two of the removed HEJ tube sections strongly supports the establishment of the repair boundary as stated in this report.As reported in References 8 and 9, structural analyses and tests were performed which demon-strated that degradation of any extent below the middle of the HRLT could be tolerated without violating draft RG 1.121 requirements for protection against burst for tubes subject to degradation.
Hardroll Upper Transition (HRUT)
References 8 and 9 also presented structural integrity and leak rate information relative to failure of the tube/sleeve joint for cracks above the middle of the hardroll if the circumferential extent did not exceed a specified limit.These latter evaluations are not directly germane to the repair boundary established herein;however, a chronological discus-sion of those evaluations, and activities proposing license amendments, is provided in Appendix A to this report.The third section sample is being retained as an archive specimen for future testing if necessary.
Hardroll Hardroll Lower Transition                          Bottom of the (HRLT)                             transition.
DAPLANTSLAEPQKJINTRO.SEC 2-1 09/26/9$
Hydraulic Expansion Lower Transition (HELT)
Figure 1-2: Hybrid Expansion Joint ConQguration S:EAPCEAEP954AEP HEJF.001                  1-7


2.2 Conclusions Westinghouse non-Proprietary Class 3 This document is applicable to the HEJs in service in SGs at D.C.Cook Unit 1, Kewaunee, Point Beach Unit 2, and Zion Unit 1.Specific conclusions relative to the location of the repair boundary, axially oriented PTIs, primary-to-secondary leakage, and the susceptibility of the upper transitions to concurrent degradation are provided in the following subsections.
Figure 1-3: Typical Dimensions of the HEJ SAAPC~P9SULEP HEJF.001                     1-8                  7/30/95
2.2.1 Indication Locations Tests conducted in joints designed to simulate a 360'hroughwall crack have shown that the upper hardroll must have additional axial load carrying capability to supplement the radial contact pressure of the sleeve-to-tube interface.
To comply with this condition, PTls in the sleeve/tube joint, i.e., the HEJ, must be limited to 1.1" and lower as reckoned downward from the bottom of the HRUT.It is to be noted that a significant database of field NDE information has been accumulated that demonstrates that the appearance of PTIs in the lower transitions of an HEJ does not imply a susceptibility of the tubes to upper transition PIIs.This is supported by the findings from the destructive examination of several HEJs removed from operating SGs in the United States and Europe.2.2.2 Allowable Indication Arc Length Testing of surrogate and field specimens has demonstrated that an HEJ with a 360'hrough-wall PTl indication at/below the middle of the HRLT will successfully withstand the loads resulting from three times the normal operating pressure differential and 1.43 times the postulated SLB pressure differential.
Therefore, there is no BOC limitation on the circumferential extent of PTls located below the repair boundary as describe in this report.2.2.3 Ax%Indications Axial indications do not independently result in a significant reduction of the axial load carrying capacity of the joint.However, without additional information, it may be supposed that the presence of axial indications may degrade the axial load carrying capability if circumferential cracking is concurxently present.In addition, axial cracks could have an effect on leakage through the sleeve-to-tube joint.Until additional information is developed, it is recommended that HEJs exhibiting axial PTIs above the bottom of the HRLT be removed from service.2.2.4 Primary-to-Secondary LeakageThe use of the specified repair boundary for PTIs should be implemented in concert with an operational leakage limit of 150 gpd and enhanced inspection criteria designed to quantify the orientation and location of potentially crack-like PTIs.Analyses have shown that the tubesheet sleeve lower hardroll joint, located at the tube entry, poses no structural or leakage DAPLANTSVLEPQlHKTRO.SEC 2-2


Westinghouse non-Proprietary Class 3 integrity concerns.The demonstration of the upper joint integrity has been demonstrated
Westinghouse non-Proprietary Class 3 2.0 Discussion and Conclusions The burst criteria of draft RG 1.121 were used to establish a repair boundary for HEJs with PTIs. The continued safe operation of the SGs is not compromised if the PTls are located below the repair boundary, i.e., 1.1" downward from the bottom of the HRUT or lower, as illustrated on Figure 2-1.
~~~~based on mechanical test programs supplemented by analytic evaluations.
A geometry    based argument has been developed, Section 7.0, to support the repair boundary as established by structural considerations for PTIs in HEJ sleeved tubes.'    summary of the conclusions relative to the establishment and implementation of the repair boundary for HEJ sleeved tubes in Westinghouse Model 44 and 51 SGs is provided in Section 2.2. Additional sections of this report provide a discussion of field experiences through the date of publication of this report, the details of the destructive examinations of sleeved tube sections removed from an operating SG, and structural integrity and potential leak rate considerations made to establish the repair boundary.
0 Potential primary-to-secondary steam generator tube leakage should be calculated for indications remaining in-service within the identified repair boundary zone.The total predicted leakage from the SG during a postulated SLB event should be compared against the allowable leakage as determined using NUTMEG-0800 calculation guidelines.
2.1 Discussion During the Spring, 1995, outage at Kewaunee, three (3) HEJ sleeved tube sections were removed intact from SG "B" for laboratory examination. One of the sections was designated for archive retention and the remaining two sections have been destructively examined. Each of the specimens exhibited field called PTIs in the hardroll lower transition using thb + Point probe. The indications were confirmed to be extensive, circumferentially oriented, stress corrosion crack arrays (SCC) originating on the inside surface of the tube, confirming the accuracy of the detection and sizing of the NDE. No cracking of the sleeves, and no cracking in the upper transitions of the tubes was found. A detailed discussion of the results of the examinations are provided in Section 5.0 of this report. Structural tests done on two of the removed HEJ tube sections strongly supports the establishment of the repair boundary as stated in this report.
DAPLANTSMEPU6 JINTRO.SEC 2-3 09/26/95 Repair Boundary for HEJ Sleeved Tubes HRUT I I Existing repair limits apply to the parent tube and the sleeve.1.1" below the bottom of the HRUT.Roll Expansion:.
As reported in References 8 and 9, structural analyses and tests were performed which demon-strated that degradation of any extent below the middle of the HRLT could be tolerated without violating draft RG 1.121 requirements for protection against burst for tubes subject to degradation. References 8 and 9 also presented structural integrity and leak rate information relative to failure of the tube/sleeve joint for cracks above the middle of the hardroll if the circumferential extent did not exceed a specified limit. These latter evaluations are not directly germane to the repair boundary established herein; however, a chronological discus-sion of those evaluations, and activities proposing license amendments, is provided in Appendix A to this report.
I I I I I I I I Revised repair limit boundary applies to sleeve only.: Repair limits'.:.apply to the::: sleeve&tube.Figure 2-1: Revised Pressure Boundary De6nition for HEJ Sleeved Tubes D:K PLAYIS EAE P 4 HEJSUMRY.FIG 2-4
The third section sample is being retained as an archive specimen for future testing  if necessary.
'
DAPLANTSLAEPQKJINTRO.SEC                       2-1                                           09/26/9$
Westinghouse non-Proprietary Class 3 3.0 Regulatory Requirements In order to repair SG tubes, an integrated qualification plan was developed to demonstrate the acceptability of the HEJ sleeve/tube joint.Documentation of the sleeve design and attendant analyses of Alloy 600 and 690 thermally treated HEJ sleeves for the repair of SG tubes are contained in Westinghouse technical reports referred to as WCAPs.These reports describe the design basis for sleeving as a repair, the testing and analysis used to support the acceptability of the repair technique, and the method used to demonstrate acceptability of the repair following its application.
A similar approach is taken in this report.The repair boundary for the parent tube in the HEJ HBLT is established such that the design basis of the sleeve/tube meets the requirements of RG 1.121.A listing of the WCAP reports applicable to the plants in question was provided in Section 1 of this report.Current WCAPs define the sleeving application and repair limits.They define the zones of in-service-inspection for the sleeve, and the limit of acceptable sleeve and sleeve joint degradation.
The sleeved tube inspection requirements and repair boundary for the HEJ are summ~in Figure 2-1.Based upon the experiences at Kewaunee, Point Beach 2, and Doel 4, it is evident that the parent tube material in the vicinity of the HEJ transitions can be subject to the development of PTls.In order to prevent the unnecessary plugging of potentially degraded sleeved tubes, the structural integrity of the degraded joints may be evaluated against the burst criteria of draft RG 1~121.In addition, the leakage integrity of the sleeved tubes with PTIs should not repre-sent a potential for offsite doses to exceed the limits defined in Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100).RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14, 15, 31 and 32 by reducing the probability and consequences of steam generator tube rupture.This is accomplished by determining the limiting safe conditions of degradation of steam generator tubing, beyond which tubes with unacceptable cracking, as established by in-service inspection, should be removed from service or repaired.The repair boundary is established such that the primary-to-secondary pressure boundary will not result in tubes with partial and/or complete throughwall PIIs outside of the boundary being returned to service.The regulatory basis for leaving the indications within the boundary limits in service is dis-cussed below.3.1 Regulatory Guide 1.121 In establishing the HEJ parent tube repair boundary, the elevation of PTls in the tube span between the tubesheet and HEJ transitions must be considered.
The main purpose of a sleeve is to bridge PTIs with a new pressure boundary.The parent tube repair boundary established by References 1 through 7 documented the potential for PTIs to exist up to 1" below the hardroll.The HEJ joint inherently provides protection to tube burst and significant leakage.The NRC staff has defined tube rupture in NVREG-0844 as an uncontrollable release of reactor coolant in excess of the normal makeup capacity.Examining the upper HEJ, tube DAPLANTSV,EPQKJINTRO.SEC 3-1 09/26/9S


Westinghouse non-Proprietary Class 3burst gould only be expected if a circumferential separation of the parent tube is postulated, and the parent tube was then pushed out of intimate contact with the sleeve due to normal operating or faulted loads.These loads are generated by the pressure differential across the tube wall, represented by the tube end cap loads.Draft RG 1.121 uses factors of safety consistent with Section III of the ASME Code.The HEJ, and areas within the HEJ where degradation has been indicated by NDE, provides an overlap of the tube and the sleeve for a length of approximately 3 inches in the free-span region above the top of the tubesheet.
Westinghouse non-Proprietary Class 3 2.2 Conclusions This document is applicable to the HEJs in service in SGs at D. C. Cook Unit 1, Kewaunee, Point Beach Unit 2, and Zion Unit 1. Specific conclusions relative to the location of the repair boundary, axially oriented PTIs, primary-to-secondary leakage, and the susceptibility of the upper transitions to concurrent degradation are provided in the following subsections.
This overlap must be considered in the overall evaluation of the proposed degradation acceptance limits.3.2 Accident Condition Allowable Leak Rate The accidents that are affected by primary-to-secondary leakage are those that include, in the activity release and offsite dose calculation, modeling of leakage and secondary steam release to the environment.
2.2.1 Indication Locations Tests conducted  in joints designed to simulate a 360'hroughwall crack have shown that the upper hardroll must have additional axial load carrying capability to supplement the radial contact pressure of the sleeve-to-tube interface. To comply with this condition, PTls in the sleeve/tube joint, i.e., the HEJ, must be limited to 1.1" and lower as reckoned downward from the bottom of the HRUT.
The postulated steam line break (SLB)accident represents the most limiting case due to the potential for increasing leakage due to the steadily increasing primaTy-to-secondary pressure differential during recovery from the accident and the direct release path to the environment provided by the break in the steam pipe.Establishment of the repair boundary includes calculation of the maximum permissible steam generator primary-to-secondary leak rate during a steam line break outside of the containment building.Standard Review Plan (NUREG-0800) methodology is used to establish the maximum permissible leak rate.This methodology has been used to justify primary.to-secondary leak rates greater than the value of 1.0 gpm normally assumed in the plants'SAR.
It is to be noted that a significant database of field NDE information has been accumulated that demonstrates that the appearance of PTIs in the lower transitions of an HEJ does not imply a susceptibility of the tubes to upper transition PIIs. This is supported by the findings from the destructive examination of several HEJs removed from operating SGs in the United States and Europe.
This methodology ha's been utilized previously by the NRC for the licensing of the steam generator tube support plate voltage based plugging criteria, described in Generic Letter 95-05.NUTMEG-0800 limits the thyroid dose to 10%of the 10 CFR 100 limit of 300 Rem for the accident initiated iodine spike case.The repair boundary established in this report considers a conservative SLB per tube leakage aHowance based on test data to account for potential leakage from PTIs left in service.The total SG SLB leak rate from all sources (including calculated leakage from TSP intersections which are addressed by Generic Letter 95-05)is summed when comparing the estimated leak rate against the value established using the methodology of NU~REG 0800.D:LPLANTSMEPQlHINTRO.SEC 3-2 10/03/95 Westinghouse non-Proprietary Class 3~~~s~)4.0 Field",Experience 4.1 HEJ'Sleeved Tube Indications s4 4.1.1 Kewaunee Nuclear Power Plant In April~of 1994, seventy-seven (77)PTIs were detected in the HEJ of sleeved tubes (based on a 100,%'inspection) in the SGs at the Kewaunee Nuclear Power Plant using the Zetec I-coil eddy current inspection probe.A detailed description of the indications and their locations is provided in Reference 8.One (1)circumferential PTI (about 34)was found at the HEUT, see Figure 1-2 for the joint designations.
2.2.2 Allowable Indication Arc Length Testing of surrogate and field specimens has demonstrated that an HEJ with a 360'hrough-wall PTl indication at/below the middle of the HRLT will successfully withstand the loads resulting from three times the normal operating pressure differential and 1.43 times the postulated SLB pressure differential. Therefore, there is no BOC limitation on the circumferential extent of PTls located below the repair boundary as describe in this report.
There was no operating leakage attributable to the presence of this indication.
2.2.3 Ax% Indications Axial indications do not independently result in a significant reduction of the axial load carrying capacity of the joint. However, without additional information, it may be supposed that the presence of axial indications may degrade the axial load carrying capability  if circumferential cracking is concurxently present. In addition, axial cracks could have an effect on leakage through the sleeve-to-tube joint. Until additional information is developed, it is recommended that HEJs exhibiting axial PTIs above the bottom of the HRLT be removed from service.
One (1)indication was found to be axial and contained within the.hardroll (HR)expansion.
2.2.4 Primary-to-Secondary Leakage The use of the specified repair boundary for PTIs should be implemented in concert with an operational leakage limit of 150 gpd and enhanced inspection criteria designed to quantify the orientation and location of potentially crack-like PTIs. Analyses have shown that the tubesheet sleeve lower hardroll joint, located at the tube entry, poses no structural or leakage DAPLANTSVLEPQlHKTRO.SEC                         2-2
No axial indications were identified above or below the HR.Two (2)indications were identified as volumetric within the hydraulic expansion below the HRLT.Sixty-two (62)indications were identified as circumferential and located at the HRLT.The xemaining eleven (11)indications were located at/below the bottom of the HELT.There wexe no instances of multiple indications in a single HEJ.The circumferential extent of the indica-tions ranged from 45'o 285, with nine (9)being judged to be greater than 200 in extent.The average elevation of the sixty-two indications was found to be 1.42" below the top of the HRUT with a standard deviation of 0.08".The calendar time of operation for the tubes following sleeving ranged from five to six years.The distribution of the indications as a~~~~~~~~~~~function of installation year is provided in Table 4-1.I In April of 1995, seven-hundred and thirty-eight (738)HEJ PTIs were detected using the Zetec+Point eddy current inspection probe.Again, a 100%inspection of the HEJs in the SGs was performed:
Five (5)circumferentially oriented PTIs were reported at the HE uppex transition.
Again, there was no leakage reported from any of the indications.
Nine (9)axially oriented PTIs were reported in the hardroll region.Six-hundred and forty-three (643)circumferential PTIs were reported at elevations ranging fmm 1.00" to 1.75" below the bottom of the HRUT.This corresponds to 0.00" to 0.75" below the nominal top of the HBLT.The remaining eighty-one (81)indictions were located at/below the HELT.One tube was reported as having multiple, i.e., two, PTIs, both of which were below the top of the HBLT.The circumferential extent of the indications ranged from 45'o 360'ased on the NDE.The average elevation of the HBLT PTIs was found to be'1.32" below the bottom of the HRUT with a standard deviation of 0.10".The sleeves had been installed in 1988, 1989, and 1991, and were fabricated from thermally treated Alloy 690 material.The distribution of'he indications as a function of installation year is provided in Table 4-2.P 4.1.2 Point Beach.Unit 2 Nuclear Power Plant In October of 1994, two-hundred and thirty (230)circumferentially oriented HEJ PTIs were detected using the Westinghouse/Ontario Hydro CECCO 3 eddy current inspection probe.All~~~~~~~~~~~~~~of the HEJs were examined on the hot leg of the SGs.A 20%sample of the HEJs examine on the cold leg side of the SGs revealed no indications.
One (1)indication was de/ected in the HEUT, seven (7)in the HRUT, eighty-eight (88)in the HBLT, and one-hundxcdsand tliirty-D:LPLANTSV,PKHEIFIELD.SEC 4-1 Westinghouse'non-Proprietary Class 3 N four (134)in the HELT.'he minimum PTI angle reported was 23 and the maximum was~~~360'.'fhe sleeves had been installed in the tubes in 1983, and were fabricated from thermally, treated Alloy 600 material.4.1.3 Kerncentrale Doel 4 Nuclear Power Plant Significant in-service leakage was detected from a PTI in SG"G" at Doel 4 in April of 1994 one week before a scheduled outage.The leak was attributed to a throughwall PTI at the HEUT.The tube/HEJ was removed from the SG along with a joint from a randomly selected tube.The indication in the leaking tube had an ID extent of-180 and an OD extent of-160'.A PTI was'ound in the other tube at the same elevation.
It consisted of three (3)separate, circumferentially adjacent cracks with an aggregate length of-5 mm (34).The deepest crack has been reported as being 90 to 100%throughwall, Reference 16.The PTfs in both tubes weie attributed to primary water stress corrosion cracking (PWSCC).A total of 1740 tubes had thermally treated Alloy 690 HEJ sleeves installed in 1993.The tubes at Doel 4 are considered to be particularly susceptible to PWSCC.During the outage the detection of significant numbers of tubes cracked at the tube/tubesheet hardroll transitions led to the decision to sleeve all of the tubes in the three SGs at that site using laser welded sleeves (LWSs), and to add a laser welded joint to each of the HEJ sleeves at an elevation above the HEUT..During the LWS campaign, fifty (50)additional HEJs were examined using the CECCO 3 probe.Nine (9)of the tubes were indicated to contain PTls.Six (6)of these were at the HEUT and the remaining three were at the HELT.None of the tubes were indicated to have multiple PTIs'.In the Summer of 1995, a CECCO 3 probe was used to inspect all of the sleeve joints in the three SGs.A+Point probe was also used to inspect 184 of the welded HEJ sleeves.A summary of all findings was not available at the time of preparation of this report.Six (6)of the weld repaired HEJ sleeved tubes were removed for destructive examination.
Two of these had been identified as having no detectable degradation (NDD)at the HEUT by the field NDE.These were confiimed to be NDD in the laboratory.
The other four HEJs exhibited PTIs by the field NDE.One of these was found to have an ID initiated throughwall crack (-0.5" on the ID and-0.25" on the OD)at the elevation of the HEUT.This tube broke during the removal operation at a tensile load of-9700 lb,.The other specimens had experienced wastage of the parent tube and the Alloy 690 sleeve at the bottom of the closed crevice, i.e., the HEUT, formed when the laser welding was effected.The wastage may likely be due to a concentration of an acidic environment in the-6" long closed crevice between the HEJ and the repair weld.Note that this information is an update of information previously presented, e.g., Refer-ence 15, where it was stated that no indications had been reported in the HRUT, An expert review of the NDE data revealed that the location information was distorted as a result of pulling the probe down into the sleeve from the tube.A reevaluation of all of the PTI elevations was performed only to identify the location of the PTIs by transition, thus average dimensional information was not available at the time of preparation of this report.DM'LANTSVLEPQKJ FIB.D.SEC 4-2 09/25/95 Westinghouse non-Proprietary Class 3 4.2 Summary of Field Experiences
~~~~~~~~~~~In summary, FIIs have been detected in HEJ sleeved tubes at three plants during a total of'our inspection outages, two at Kewaunee, one at Point Beach 2, and the initial inspection outage at Doel 4.A summary of approximately all known PTIs is provided in Table 4-3.In total, about 60.5%occur at the HRLT and 37.2%at the HELT.About 0.7%have been found at the HRUT, and the remaining 1.6%at the HEUT.These distributions are illustrated in histogram form on Figure 4-1 and in"pie" chart form on Figure 4-2.The incidence of indications at the upper transitions in plants in the United States (VS)comprises about 1.5%of the reported indications.
Thus, the distribution at Doel 4 is atypical of the occurrences in the VS.In no instances have indications been detected in the same tube at upper and lower transitions.
Approximately 75%of the known PIIs have been found in tubes in the Kewaunee SGs.Hence, it would be expected that the distribution of indications relative to elevation can be characterized by the distribution found at Kewaunee.Figure 4-3 illustrates the distributions of PTls at the last inspection outage at Kewaunee.'pproximately 1%of the indications were judged to be located within 1.1" of the bottom of the HRUT.If an eddy current positioning error of 1/16" is assumed, the number of indications above the repair boundary would be on the order of 4%.The elevation information is based on an"expert" review of 630 PTIs, or 98%of population of circumferential indications.
DAPLANTS'REP6iEJFIELD.SEC 4-3 09/25/95 Westinghouse non-Proprietary Class 3 Table 4-1: Distribution of Kewaunee 1994 HEJ Indications Removed from Service by Installation Year Installation Year 1988 1989 1991 Totals SG I I A II 46 48 SG I IB ll 17 18 Both SGs 63 66 Table 4-2: Distribution of Kewaunee 1995 HEJ Indications Removed from Service by Installation Year Installation Year 1988 1989 1991 Totals SG I I All 283 147 431 SG IIBII 152 69 226 Both SGs 435 216 657 DAPLANTSM.EPQKJ FIELD.SEC 4-4


Westinghouse non-Proprietary Class 3 TabIe 4-3: Distribution of HEJ PTIs by Transition Transition HELT Totals Volumetric Totals Kewaunee'12 480 698 10 710 Point Beach 2 134 88 230 230 Doel 4 Totals 349 568 15 939 10 951 Percent 37.2 60.5 0.7 1.6 100 Notes;1.1995 numbers based on the findings of an"expert" review of the elevations relative to the bottom of the HRUT prior to the final data becoming available.
Westinghouse non-Proprietary Class 3
DN'LANT',ECHE/I'IELD.SEC 4-5 09/25/95  
  ~
integrity concerns. The demonstration of the upper joint integrity has been demonstrated
      ~              ~
                    ~
based on mechanical test programs supplemented by analytic evaluations.
0 Potential primary-to-secondary steam generator tube leakage should be calculated for indications remaining in-service within the identified repair boundary zone. The total predicted leakage from the SG during a postulated SLB event should be compared against the allowable leakage as determined using NUTMEG-0800 calculation guidelines.
DAPLANTSMEPU6JINTRO.SEC                       2-3                                        09/26/95


Figure 4-1 600 Distribution of Circumferential PTIs by HE J Transition 600 SDoel 4, 1994 Q Point Beach 2, 1994 8Kevraunee, 1994 8c 1995 O~300 K 200 10Q 0 HELT HRLT HE J Transition HEUT D.PLAlCTSEAEP'LHEJFIELD.F1G Figure 4-2 Distribution of All Circumferential PTIs by Transition Hardroll Upper Transition Hydraulic Expansion Upper Transition Hydraulic Expansion Lower Transition Hardroll Lower Transition EIHELT=37.2%HHRLT=60.5%OHRUT=0.7%~HEUT=1.6%D: 5 PLANYSKAEP T HEJFIELD.FIG 4-7 , 08/01/95 130 120 110 Kemaunee SGs"A" 4"8" HE J PTIs vs.Distance Below'he Bottom of the HR Upper Tra.position happ 90%100 90 80 pg 70 o 60 50 40 30 20 10 0 RG 1.121 Repair Limit EK3 Both SG Indications
Repair Boundary for HEJ Sleeved Tubes HRUT                I Existing repair limits apply to the parent I                tube and the sleeve.
-Both SG Cumulative
1.1" below the bottom of the HRUT.
-----.---95%Rank Cumulative 80%O 70%ca O'a 60%0~r 0%lC 40%o 30%8 20%10%0%e o o e o e o e o e o e c4 M co co w w e e cD co o C e Upper Bin Distance Below Bottom of HR Upper Transition
Revised repair I              limit boundary applies to I
sleeve only.
I I
I I
I I            :  Repair limits Roll Expansion:.              '.:.
apply to the
:::  sleeve & tube.
Figure 2-1: Revised Pressure Boundary De6nition for HEJ Sleeved Tubes D:KPLAYISEAE P 4 HEJSUMRY.FIG           2-4


Westinghouse non-Proprietary Class 3 5.0 Summary of Examinations Conducted on Kewaunee Steam Generator Tubes with Hybrid Expansion Joints 5.1 Introduction Sections of SG tubes R2C32, R2C54 and R2C61 were removed from the hot leg side of SG"B" at Kewaunee in 1995 to characterize the operating condition of the HEJs which had been installed in these tubes in 1988.The HEJs had been installed to prevent leakage through tube corrosion at top of tubesheet (TTS)and tubesheet crevice locations.
Westinghouse non-Proprietary Class 3 3.0 Regulatory Requirements In order to repair SG tubes, an integrated qualification plan was developed to demonstrate the acceptability of the HEJ sleeve/tube joint. Documentation of the sleeve design and attendant analyses of Alloy 600 and 690 thermally treated HEJ sleeves for the repair of SG tubes are contained in Westinghouse technical reports referred to as WCAPs. These reports describe the design basis for sleeving as a repair, the testing and analysis used to support the acceptability of the repair technique, and the method used to demonstrate acceptability of the repair following its application. A similar approach is taken in this report. The repair boundary for the parent tube in the HEJ HBLT is established such that the design basis of the sleeve/tube meets the requirements of RG 1.121. A listing of the WCAP reports applicable to the plants in question was provided in Section 1 of this report.
The tubes/HEJs were cut 3" above the TTS and 3" below the first tube support plate (TSPs)and were then removed from the secondary side of the steam generator to avoid deformation that would have probably occurred from a primary side tube pull.Consequently, only the upper mechanical joints of the HEJs were available for examination.
Current WCAPs define the sleeving application and repair limits. They define the zones of in-service-inspection for the sleeve, and the limit of acceptable sleeve and sleeve joint degradation. The sleeved tube inspection requirements and repair boundary for the HEJ are summ~ in Figure 2-1.
The upper mechanical joint is described in Section 1 of this report.The tube material was mill annealed Alloy 600, and the sleeve material was thermally treated Alloy 690.The examination was conducted at the Westinghouse Science and Technology Center to characterize any tube/sleeve corrosion.
Based upon the experiences at Kewaunee, Point Beach 2, and Doel 4, it is evident that the parent tube material in the vicinity of the HEJ transitions can be subject to the development of PTls. In order to prevent the unnecessary plugging of potentially degraded sleeved tubes, the structural integrity of the degraded joints may be evaluated against the burst criteria of draft RG 1 121. In addition, the leakage integrity of the sleeved tubes with PTIs should not repre-
Field eddy current suggested the presence of significant circumferential corrosion at the hard roll lower transition (HRLT)in the upper mechanical expansion of the HEJs.After nondestructive laboratory examination by eddy current, radiography, dimensional characterization, and visual examination, one HEJ region was leak tested at elevated temperature.
      ~
Subsequently, room temperature tensile testing was conducted on two,of the HEJs, as well as on three free span sections, one from each removed tube.The third tube/HEJ section was retained intact as an archive specimen.The two HEJs which were tensile tested were then destructively examined using metallographic and SEM fractography techniques to characterize any corrosion.
sent a potential for offsite doses to exceed the limits defined in Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100).
In addition, an analysis of the OD and ID deposits, ID oxide films, and fracture face oxide films was performed using EDS, ESCA and AES tech-niques.In addition, ion chromatography and capillary electrophoresis were performed on soluble ID deposits obtained by water leaching.5.2 NDE Results Table 5-1 presents a summary of the more important field and laboratory NDE results.The field eddy current data were conducted using+Point and I coil probes, while the laboratory inspections used+Point, CECCO and RPC probes.Field and laboratory eddy current inspections produced similar data.For the+Point probe, common to both the field and lab exams, the data produced the same signals, suggesting a 360'ircumferential indication in the HRLT of tubes R2C54 and R2C61, and a 300 to 360'ircumferential indication in the HRLT of tube R2C32.These signals were suggestive of deep, even throughwall degradation.
RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14, 15, 31 and 32 by reducing the probability and consequences of steam generator tube rupture. This is accomplished by determining the limiting safe conditions of degradation of steam generator tubing, beyond which tubes with unacceptable cracking, as established by in-service inspection, should be removed from service or repaired. The repair boundary is established such that the primary-to-secondary pressure boundary will not result in tubes with partial and/or complete throughwall PIIs outside of the boundary being returned to service.
The laboratory CECCO probe data produced similar conclusions with the exception that the circumferential indication in tube R2C32 appeared to be 360'ide, rather than 300 to 360 wide.In addition, the laboratory
The regulatory basis for leaving the indications within the boundary limits in service is dis-cussed below.
+Point and CECCO probes suggested the presence of a small indication in the hydraulic expansion lower transition (HELT)of tube R2C61 (the archive specimen).
3.1 Regulatory Guide 1.121 In establishing the HEJ parent tube repair boundary, the elevation of PTls in the tube span between the tubesheet and HEJ transitions must be considered. The main purpose of a sleeve is to bridge PTIs with a new pressure boundary. The parent tube repair boundary established by References 1 through 7 documented the potential for PTIs to exist up to 1" below the hardroll. The HEJ joint inherently provides protection to tube burst and significant leakage.
There was no suggestion by field or laboratory NDE of any corrosion degradation being present in the Alloy 690 sleeve.DAPLARKVLERHE/EXAh(S.SEC 5-1 09/25/95 Westinghouse non-Proprietary Class 3 The radiographic laboratory examination detected a 270 to 360 circumferential band of short semi-continuous circumferential indications in the upper portion of the HRLT of the tube, just below the HR region in tube R2C32.These cracks were confined to a very narrow zone, less than 0.05" high, such that the individual cracks appeared to occur head-to-toe.
The NRC staff has defined tube rupture in NVREG-0844 as an uncontrollable release of reactor coolant in excess of the normal makeup capacity. Examining the upper HEJ, tube DAPLANTSV,EPQKJINTRO.SEC                       3-1                                          09/26/9S
In addition, a shorter (approximately 300 long)band of cracks was observed approximately 0.1" below the main band of cracks.tube R2C54 had two to three similar bands of short semi-continuous circumferential cracks that occurred over 350'rom the mid-to upper portion of the HRLT.Tube R2C61 had one band of short semi-continuous circumferential cracks that occurred over 360'n the mid-portion of the HRLT.The HRLT was approximately 0.25" long in the case of tube R2C32, and was approximately 0.5" long in the cases of tube R2C54 and R2C61.The HRLT apparently experienced noticeable rolldown'uring installation, especially for tubes R2C34 and R2C61.In contrast, the HRUTs for all three tubes were approximately 0.1 to 0.2" high.Dimensional characterization of the HE's showed that all three had similar hydraulic and hard roll expansion dimensions that were typical for qualified HEJ instaHations, e.g., see Figure 1-3.The hardroll regions were expanded 0.009, 0.012 and 0.009" radially above the negligibly expanded hydraulic regions for tubes R2C32, R2C54, and R2C61, respectively.
5.3 Leak Testing The R2C54 HEJ was cut to 11" long with the hardroll region centered in the specimen.The bottom 1" of the specimen was then expanded to contact with the tube and the sleeve was then welded to the tube.This seal causes any leak through the hardroll region to occur bnly through the tube HRLT cracks.Elevated temperature leak testing was then performed on tube R2C54 at a variety of conditions that ranged from nominal operating conditions to simulated SLB conditions.
No leaks were observed through the tube HRLT cracks at any of the test conditions.
The maximum test differential pressure was 2534 psi with corresponding primary and secondary side temperatures of 618 and 611'F.5.4 Tensile Testing Table 5-2 provides room temperature tensile properties obtained from a free span (FS)section of each tube.The tensile strengths for the FS section of tubes R2C34 and R2C61 are typical for Westinghouse tubing of this vintage.The tensile strength for tube R2C32 is noticeably higher than typical.Table 5-2 also provides tensile load separation data for the HEJs from tubes R2C32 and R2C54.The 11" long HEJ specimens, with their HR regions centered within the specimens, had the bottom 1" of their sleeves expanded into contact with the tubes.The bottom end was then welded such that the sleeve and the tubing below the cracking in the HRLT would not move relative to each other during the tensile test.The top portion of the.11" long specimens consisted only of tubing because the top of the sleeve ended approximately 3.3" below the top of the tubing.The HEJs were then pulled apart at 0.05" per minute with'n order to remove the rolling tool from the installed sleeve, the direction of rolling is reversed to release the rollers from contact with the ID surface of the sleeve.If the rollers do not immediately retract, additional rolling in the downward direction occurs, resulting in an elongation of the HRLT referred to as rolldown.DM'LANT',EPLHEJEXAMS.SEC 5-2 N/25/9S Westinghouse non-Proprietaxy Class 3 the separation load of the HRLT crack network being recorded.In additi th lidin of the HR region of the upper portion of the tubing being pulled over the HR region of the sleeve was also recorded.Both HEJs had high separation loads, 10,300 and 10,700 lb, respectively.
The HR sliding loads decreased continuously over the remainin HR g region.be R2C32, with the HRLT cracking located at the upper portion of the HRLT (at the bottom portion of the HR), had its sliding load start at 2800 lbs and decxease to 50 lbs at the toy portion of the sleeve HR.Tube R2C54, with the HRLT cracking located near the center of the HRLT, had a smaller diameter fracture opening that was required to pass over the s eeve HR region.Consequently, the initial sliding load was higher, 4000 lbs.The sliding oad continuously decreased to 200 lbs at the top portion of the sleeve HR.5.5 Destructive Examination Results Post-tensile test visual inspection data showed that ID origin, circumferentially oriented, corrosion cracks were present continuously around the circumference of the tube fracture faces of both HEJs that were separated by tensile testing, Figure 5-1.The two HEJ specimens were subsequently given destructive examinations which included SEM fracto h f th ace openings, visual and SEM inspection of surface features and metallography of secondaxy corrosion within the HEJ region of the tubing.The tensile fracture faces of the tubes from the two HEJ tensile specimens wexe examined by SEM.Table 5-3 presents the results of the fractographic data in the form of macrocrack length versus depth, microcrack length/average and maximum depth, and the number/location/
width of ductile or non-corroded ligaments found on the fracture face.The tube tensile separations occurred in circumferentia1 macrocracks that were composed of numerous circumferentially oriented intergranular microcracks of ID o'h t ali ed rigm a wexe gned in a single tight and narrow (<0.05" high)band in the case of tube R2C32 and in a li an m a s ghtly less tight narrow (.g)band in the case of tube R2C54 where the fracture face jumped from one circumferential crack network to a parallel one.(See radiogra hic data In S..)arge raction of the many ligaments separating the microcracks on both had ductile features.features.There were 21 ductile ligaments pxcsent in the case of tube R2C32 and*on o specimens 19 ductile ligaments present on the fracture face from tube RZC34.Many other li aments had only intergranular features.any o er ligaments had All intergranular corrosion was confined to and located in the HRLT'n in e regions.In the case of e e cracking was at the upper portion of the HRLT and in the case of tube R2C54 the cracking was located from the mid-portion of the HRLT to the upper portion of the HRLT.The fracture faces both had a maximum depth of 92%throu hwall ep s ranging rom 61%(tube R2C32)to 60%(R2C34)throughwall and with microcrack lengths that were 360 long.At some ID locations adjacent to the fracture faces, a few short circumferential microcracks were observed parallel to the fracture face.These microcracks appeared to be simple cracks, morphologically syeaking, in that the near absence f bli o o'que~~~~~g racks and bluntmg was noted.This morphology is more typical of PWSCC than of secondary side corrosion that typically occurs in caustic crevices.SEM examinations were conducted on the OD and ID surfaces of the balance of the tubing from, both tubes in the HEJ regions with the examination co tratin f din ncen g on m g cracks at DAPLAPISV,EPQKJEXAMS.SEC 5-3 Westinghouse non-Proprietary Class 3 other, locations and on characterizing deposits.No cracks were observed.ID surface deposits were thin at all HEJ locations.
Circumferential and oblique angled ID surface scratches from the honing operation used yrior to HEJ installation were clearly present below the HR.Above the HR, similar scratches were observed, but they were frequently obscured by slightly thicker, but still thin deposits.The ID deyosits on the tubes in the HR region, including those below the HR region, had the typical appearance of ID surface deposits that were located immediately above the HEJ sleeve.In the case of tube R2C32, local areas with unusual whisker-like deposits were observed just below the fracture face at the top of the HRLT and also at HRUT (hard roll upper transition).
At no local crevice location (HR or HE transitions) were thicker or diffexently colored deposits observed, such as those typically concentrated by boiling.No corrosion degradation was observed on the OD of the sleeves from both tubes when visual (30X)and SEM examinations were conducted.
In comparison, similar examinations conducted on recent Doel 4 HEJs, that had been repaired by laser welding following a cycle of operation, showed some IGA type corrosion in the sleeve and tube.The IGA grain boundaries had very thick oxide layers in both the sleeve and tube at the bottom of a local crevice region.Following SEM examination (and EDS analysis of deposits which will be presented shortly), a narrow axial metallographic section was cut from each tube through the HEJ region, primarily to obtain microhaxdness measurements from selected locations.
Table 5-4 presents this data.The microhardness at the fracture face location (HRLT)was similar to or slightly higher than other HE and HR transition locations; however, the ID-most microhardness next to'the fracture face of both tubes did include two of the three highest hardness values, when appropriately ignoring hardness values taken next to tensile shear surfaces.In addition, no cracks were observed by metallography at locations other than the fracture face location in the HRLT.After smaH ESCA-AES specimens were cut from just below the lower fracture face of tube R2C32, the remaining portions of the tubes from both HEJ specimens were deformed to open any ID origin cracks such that they could be readily observed by visual inspection (30X).The tube sections were cut axially into to two 180'ide halves.The halves were flattened to open axial cracks.None were observed at any of the hydraulically or hard roll expanded regions.The halves were then bent to open any ID surface cixcumferential cracks.Again, none were observed at any of the hydraulically or hard roll expanded regions.Finally, metallographic axial sections were made through the HRLT to the fracture face to characterize the 1GSCC that was present in the HRLT.The cracks observed were simple appearing, more similar to that expected from PWSCC than from secondary side corrosion where caustic environments are typically concentrated.
From the metallographic and SEM surface examinations conducted on the HRLT corrosion, it was concluded that the only corrosion morphology was ID origin, circumferentiaHy oriented intergranular stress corxosion cracking.The cracks were simple in morphology with only minor D/W ratios measuxed.(IGSCC morphology can be characterized by D/W ratios where the extent of IGA associated with a given crack is measured by the ratio of the crack depth, D, to the width, W, of the crack at its mid-depth.
D/W ratios greater the 20 are defined as minor.)DAPLANTSV.ERHEJEXAh(S.SEC 5-4 09/2S/95 Westinghouse non-Proprietary Class 3 The microstructures of the removed tubes varied.Tube R2C32 had a moderate to high number of carbides while tubes R2C54 and R2C61 had few carbides.For all three tubes, most carbides were distributed transgranularly rather than intergranularly, the preferxcd microstructure for PWSCC resistance.
The grain size for tube R2C54 was ASTM 8.5, typical of Westinghouse tubing of similar vintage.The grain sizes for tubes R2C32 and R2C61 were somewhat smaller, approximately ASTM 10 and 9.5, respectively, Based on laboratory testing data, these microstructures may have relatively low resistance to PWSCC.5.6 Surface Chemistry ID and OD deposit data were obtained from the two destructively examined specimens using energy dispersive spectrometry (EDS).In addition, ID and OD deposit/oxide film and fracture face oxide film data from the fracture face of tube R2C32 was obtained using ABS and ESCA techniques.
The following observations are considered the more important from the data obtained.EDS data conducted on the ID surfaces of the both tubes in the HEI regions provided minimal information since the deposits were thin and most of the EDS signal came from the base metal/oxide layer beneath the deposits.Other than the base metal elements of Ni, Cr, Fe and Tl, the only elements detected were 0, Al, S, and Si.On the OD, where deposits were thick, the deposits were rich, in Fe and 0 with some observations of Ni, Cu and Zn.The pH of many ID and OD surfaces was determined using deionized water moistened wide-range pH paper.At all locations, the pH readings were neutral.From the ESCA mid ABS data obtained on tube R2C32: 1)high concentrations of B were observed on the ID surface below the fracture face below the HR region;2)Cr was not significantly enriched or depleted on either the crack fracture face in the ID surface below the fracture face;3)low levels of Zn, Na, Mg, SI and S were also detected in addition to the expected C, 0, Ni, Cr, and Fe.Capillary electrophoresis and ion chromatography of water leached soluble ID deposits from a location just below the fracture face of tube R2C32 showed: 1)soluble cations at the following concentrations
-Na (0.97 mg/1), Mg (0.25 mg/1), K (0.21 mg/1), Ca (0.21 mg/1), and Li (0.10 mg/1);2)soluble anions at the following concentrations
-SO4 (1.71 mg/1), Cl (0.28 mg/1), and at least 7 other anions, including organic acid anions.If it is assumed that the sleeve-tube gap is locally t'4>0 then the measured concentrations obtained from the 0.15 ml of water are a factor of 100 lower than the actual crevice solution concentrations.
That would make the Li concentration in the ERLT crevice 10 mg/l, higher than found in non-concentrated primary water.D:LPLANTSiAEP6iEJEXAMS.SEC 5-5 09/25/95


Westinghouse non-Proprietary Class 3 Capillary electrophoresis and ion chromatography of water leached soluble ID deposits were also obtained for the hardroll upper transition region.This supplemental leachate test was performed subsequent to an NRC/AEP/W meeting at One White Flint North on August 10, 1995.The leachate test for the hardroll upper transition was performed identically to the leachate test for the hardroll lower transition region.The results of the test indicated that the same soluble cations were detected as for the hardroll lower transition, except they were found in significantly lower concentrations.
Westinghouse non-Proprietary Class 3 burst gould only be expected if a circumferential separation of the parent tube is postulated, and the parent tube was then pushed out of intimate contact with the sleeve due to normal operating or faulted loads. These loads are generated by the pressure differential across the tube wall, represented by the tube end cap loads. Draft RG 1.121 uses factors of safety consistent with Section III of the ASME Code. The HEJ, and areas within the HEJ where degradation has been indicated by NDE, provides an overlap of the tube and the sleeve for a length of approximately 3 inches in the free-span region above the top of the tubesheet. This overlap must be considered in the overall evaluation of the proposed degradation acceptance limits.
Potassium, however, was not detected in the hardroll upper transition.
3.2 Accident Condition Allowable Leak Rate The accidents that are affected by primary-to-secondary leakage are those that include, in the activity release and offsite dose calculation, modeling of leakage and secondary steam release to the environment. The postulated steam line break (SLB) accident represents the most limiting case due to the potential for increasing leakage due to the steadily increasing primaTy-to-secondary pressure differential during recovery from the accident and the direct release path to the environment provided by the break in the steam pipe.
Crevice pH at operating temperature was estimated from the leachate solutions using EPRI's MULTEQ~program.The results indicate that the operating temperature pH of the hardroll upper transition was 6.0 while the operating temperature pH of the hardroll lower transition was 8.3.For PWSCC, it is believed that a higher pH condition should be slightly more aggressive.
Establishment of the repair boundary includes calculation of the maximum permissible steam generator primary-to-secondary leak rate during a steam line break outside of the containment building. Standard Review Plan (NUREG-0800) methodology is used to establish the maximum permissible leak rate. This methodology has been used to justify primary.to-secondary leak rates greater than the value of 1.0 gpm normally assumed in the plants'SAR.
However, in the pH range of interest (6 to 9)the impact of pH is considered to be negligible.
This methodology ha's been utilized previously by the NRC for the licensing of the steam generator tube support plate voltage based plugging criteria, described in Generic Letter 95-05. NUTMEG-0800 limits the thyroid dose to 10% of the 10 CFR 100 limit of 300 Rem for the accident initiated iodine spike case. The repair boundary established in this report considers a conservative SLB per tube leakage aHowance based on test data to account for potential leakage from PTIs left in service. The total SG SLB leak rate from all sources (including calculated leakage from TSP intersections which are addressed by Generic Letter 95-05) is summed when comparing the estimated leak rate against the value established using the methodology of NU~REG 0800.
5.7 Conclusions The tubes in the HRLT of all three HEJs had corrosion present.Metallographic and SEM fractographic data showed that the HRLT region of the tubes had circumferentially oriented ID origin IGSCC.The individual circumferential microcracks associated with the macrocracks were simple cracks, that lacked the complexity usually associated with secondary side corrosion.
D:LPLANTSMEPQlHINTRO.SEC                       3-2                                          10/03/95
While many of the microcracks were connected by ligaments with only intergranular features, a large number of ligaments had ductile features present.The maximum depth of corrosion for the 360 long macrocracks was 92%for both tubes R2C32 and R2C54 (tube R2C61 was set aside as an archive specimen)with average depths of 61%and 60%, respectively.
Dimensional data suggested that the tubes had experienced typical expansions radially.Two of the tubes (R2C54 and R2C61)did experience significant rolldown during the hardroll procedure, as the HRLT was 0.5" long.Microhardness traces conducted in the HEJ transition locations showed little variation in hardness and values that were similar to free span locations.
One location with somewhat higher microhardness values was near the ID surface of the fracture faces of the two tubes and even there the increase was not great.The corrosion morphology observed was simple, typical of PWSCC environments rather than of secondary side crevice environments with a concentrated caustic environment.
The observed corrosion most likely resulted from an environment primarily derived from primary side water.The presence of Li and B on the tube ID surface below the HR region supports this hypothesis.
The lack of significant Cr enrichment or depletion on ID surfaces below the HR and on the crack fracture face, and the relative balance of cations and anions indicate a somewhat neutral crevice environment.
The fact that many cations and anions were found and that the estimated Li crevice concentration was higher than found in primary water also suggest that there was communication with the secondary side via a crack elsewhere in the tube.It is concluded that the observed corrosion could have been and probably was caused by a PWSCC type environment.
The results of the chemistry evaluations of the ID surfaces for the hardroll lower and hardroll upper transition regions suggest the upper transition reqion was subjected to a slightly less aggressive solution than the hardroll lower transition, but it is not believed that this solution chemistry was the driving force for the DAPLANTS'NERHEJEXAMS.SEC 5-6 l0/OS/95  


Westinghouse non-Pxoprietary Class 3 cracking.The driving force fox the cracking is believed to be attributed to a pure PWSCC effect, with the crevice chemistry representing a secondary effect.Laboratory and field eddy current probe data correlated well with the corrosion that was destructively found.The+Point and CECCO probes produced very similar and accurate results.Even the RPC laboratory data showed the presence of the corrosion in the tubes despite the presence of the sleeve between the probe and the tube.The destructive examinations verified that there were no cracks in either tube at the HRUT or the HEUT.Leak rate testing performed at elevated temperatures and pressures simulating normal operating and steam line break conditions pxoduced no leakage for the R2C54 specimen.The tensile separation loads for tubes R2C32 and R2C54 were 10,300 and 10,700 pounds, xespectively, and the sliding loads over the hard roll region started at 2800 and 4000 pounds, respectively.
Westinghouse non-Proprietary Class 3
The tensile loads were well above any safety considerations.
          ~
DAPLANYSVLEPQiHEXAMS.SEC 5-7 10/0$/95 Table 5-1: Comparison of NDE Indications Observed at Kewaunee on SG Tubes at HEJ Locations Tube/Location R2C32 R2C54 R2C61 Pield Eddy Current+Point: 300-360'irc Ind in HRLT, probably throughwall.
            )
I Coil: (1994 data only)-270'irc Ind.+Point: 300-360'irc Ind in HRLT, probably throughwall.
                              ~
I Coil: No data.+Point: 300-360'irc Ind in HRLT, probably throughwall.
4.0 Field",Experience
I Coil: 1994 data only,>270'irc indication.
                                  ~  s 4.1 HEJ'Sleeved Tube Indications s4 4.1.1 Kewaunee Nuclear Power Plant In April~of 1994,      seventy-seven (77) PTIs were detected in the HEJ of sleeved tubes (based on a 100,%'inspection) in the SGs at the Kewaunee Nuclear Power Plant using the Zetec I-coil eddy current inspection probe. A detailed description of the indications and their locations is provided in Reference 8. One (1) circumferential PTI (about 34 ) was found at the HEUT, see Figure 1-2 for the joint designations. There was no operating leakage attributable to the presence of this indication. One (1) indication was found to be axial and contained within the     .
Laboratory Eddy Current+Point: 300-360'irc Ind in HRLT, probably throughwall.
hardroll (HR) expansion. No axial indications were identified above or below the HR. Two (2) indications were identified as volumetric within the hydraulic expansion below the HRLT.
CECCO: 360'irc Iud in HRLT, probably throughwall.
Sixty-two (62) indications were identified as circumferential and located at the HRLT. The xemaining eleven (11) indications were located at/below the bottom of the HELT. There wexe no instances of multiple indications in a single HEJ. The circumferential extent of the indica-tions ranged from        45'o  285, with nine (9) being judged to be greater than 200 in extent.
RPC:>270'irc Ind at top of HRLT.+Point: 360'irc Ind in HRLT, probably throughwall.
The average elevation of the sixty-two indications was found to be 1.42" below the top of the HRUT with a standard deviation of 0.08". The calendar time of operation for the tubes
CECCO: 360'irc Ind in HRLT, probably throughwall.
                                                                    ~                    ~
RPC:>270'irc Ind in HRLT.+Point: 360'irc Ind in HRLT, probably throughwall, and small Ind at HELT.CECCO: 360'irc Ind in HRLT, probably throughwall.
following sleeving ranged from five to six years. The distribution of the indications as a
and small Ind at HELT RPC:>270'irc Ind in HRLT.Visual/Dimensional Data HRLT starts 8.25" above bottom of pulled piece or 11.25" above TTS: HRLT is 0.25" Iong;tube HR OD is 0.907"&HRLT goes 0.009" lower (radially);
                    ~
all values include variable OD deposits.HRLT starts 6.8" above bottom of pulled piece or 9.85" above TTS: HRLT is 0.50" Iong;tube HR OD is 0.903" 8c HRLT goes 0.012" lower (radially);
                                                            ~
all values include variable OD deposits.HRLT starts 6.7" above bottom of pulled piece or 9.7" above TTS: HRLT is 0.50" long;tube HR OD is 0.905"&HRLT goes 0.009" lower (radially);
                  ~        ~        ~      ~
all values include variable OD deposits.Laboratory X-Ray One to one and one-half semi-continuous Circ networks of short Inds at top of HRLT, observed over at least 270', possibly 360'.Two to three semi~ontinuous Circ networks of short crack Inds in mid-to upper portion of HRLT, observed over 360'.One semiwontinuous Circ net-work of short crack Inds in mid-portion of HRLT, observed over 360', but less continuously than for R2C32 Inds.HR=HardroH HE=Hydraulic expansion Legend of Abbreviations HELT=HE lower transition RPC=Rotating pancake coil Ind=Indication HRLT=HR lower transition TTS=Top of tubesheet Circ=Circumferential D:LPLANTStA EPONA EP-EXAM.SEC 0912$I95 Table 5-2: Tensile Data for Kewaunee SG Tube Sections Kewaunee Pxee Span Tensile Data Tube R2C32 R2C54 R2C61 Control (NX8161)Yield Strength (psi)72,200 58,600 55,400 52,300 Ultimate Tensile Strength (psi)123,300 106,700 104,000 101,500 Elongation
function of installation year is provided in Table 4-1.     ~
(%)22.0 24.5 23.1 18.5"*Broke outside of the gage length, probably reducing the elongation value.Kewaunee HEJ Tensile Data HEJ Specimen R2C32 R2C54 R2C61 Practure Load (Ibs)10,300 10,700 NA (Archive)Practure Location Top of HRLT Middle of HRLT NA (Archive)Sliding Load over HR Region (lbs)2800 decreasing to 50 4000 decreasing to 200 NA (Archive)DAPLANTSVLBPlABP-BXAM.SBC 5-9 09/25/95
I
                                                  ~    ~
In April of 1995, seven-hundred and thirty-eight (738) HEJ PTIs were detected using the Zetec + Point eddy current inspection probe. Again, a 100% inspection of the HEJs in the SGs was performed: Five (5) circumferentially oriented PTIs were reported at the HE uppex transition. Again, there was no leakage reported from any of the indications. Nine (9) axially oriented PTIs were reported in the hardroll region. Six-hundred and forty-three (643) circumferential PTIs were reported at elevations ranging fmm 1.00" to 1.75" below the bottom of the HRUT. This corresponds to 0.00" to 0.75" below the nominal top of the HBLT. The remaining eighty-one (81) indictions were located at/below the HELT. One tube was reported as having multiple, i.e., two, PTIs, both of which were below the top of the HBLT. The circumferential extent of the indications ranged from              45'o  360'ased on the NDE. The average elevation of the HBLT PTIs was found to be '1.32" below the bottom of the HRUT with a standard deviation of 0.10". The sleeves had been installed in 1988, 1989, and 1991, and were fabricated from thermally treated Alloy 690 material. The distribution of
'he indications as a function of installation year is provided in Table 4-2.
P 4.1.2 Point Beach. Unit 2 Nuclear Power Plant In October of 1994, two-hundred          and thirty (230) circumferentially oriented HEJ PTIs were detected using the Westinghouse/Ontario Hydro CECCO 3 eddy current inspection probe. All
                ~                              ~
of the HEJs were examined on the hot leg of the SGs. A 20% sample of the HEJs examine
                                                                ~
                      ~
on the cold leg side of the SGs revealed no indications. One (1) indication was de/ected in the
                                                      ~  ~                ~  ~  ~
                                                                  ~
                                                                                                ~
HEUT, seven (7) in the HRUT, eighty-eight (88) in the HBLT, and one-hundxcdsand tliirty-
                          ~                ~        ~
D:LPLANTSV,PKHEIFIELD.SEC                              4-1


Table 5-3: Kewaunee SG Tube Macrocrack Profiles for Tensile Fracture of HEJs Tube, Location R2C32, HRLT Length vs.Depth and Ductile Ligament Location (degrees/%throughwall) 00/52 22/77 Ligament 2 1 (32/92)~Maximum depth 45/88 Ligament 20 58/85 Ligament 19 9 p/8 8 LI gament 1 8 112/88 Ligaments 16&17 35/8~Ligament 1 5 158/82-Ligament 14 80/64~Ligaments 12&13 202/76 Ligament 11 225/60 Ligament 10 248/52~Ligament 9 27p/p8 Ligament 6, 7,&8 292/05 3 1 5/46 Ligament 4&5 338/9 Ligament 1, 2,&3 (Average macrocrack depth=61%over 360", maximum depth=92%)Ductile Ligament Width (in.)L21=0.004" wide L20=0.006" wide L19=0.011" wide L18=0.003" wide L16, L17=0.006", 0.011" wide L15=0.008" wide L14=0.004" wide L12, L13=0.002", 0.003" wide L11=0.039" wide L10=0.027" wide L9=0.014" wide L6, L7, L8=0.002", 0.006", 0.012" wide L4, L5=0.015", 0.022" wide Ll, L2, L3=0.015", 0.005", 0.012" wide Comments Twenty-one ligaments were observed on the circumferential macrocrack located at the top of the HRLT.All intergranular corrosion was of ID origin.DAPLANYSVLEPQEP-EXAM.SEC 5-10 09/25/95  
Westinghouse'non-Proprietary    Class 3 N
four (134) in the HELT.'he minimum PTI angle reported was 23 and the maximum was
            ~
360'.~ 'fhe sleeves had been installed in the tubes in 1983, and were fabricated from thermally,
      ~
treated Alloy 600 material.
4.1.3 Kerncentrale Doel 4 Nuclear Power Plant "G" at Doel 4 in April of 1994 Significant in-service leakage was detected from a PTI in SG one week before a scheduled outage. The leak was attributed to a throughwall PTI at the HEUT. The tube/HEJ was removed from the SG along with a joint from a randomly selected tube. The indication in the leaking tube had an ID extent of -180 and an OD extent of -160'.
A PTI was'ound in the other tube at the same elevation. It consisted of three (3) separate, circumferentially adjacent cracks with an aggregate length of -5 mm (34 ). The deepest crack has been reported as being 90 to 100% throughwall, Reference 16. The PTfs in both tubes weie attributed to primary water stress corrosion cracking (PWSCC). A total of 1740 tubes had thermally treated Alloy 690 HEJ sleeves installed in 1993.
The tubes at Doel 4 are considered to be particularly susceptible to PWSCC. During the outage the detection of significant numbers of tubes cracked at the tube/tubesheet hardroll transitions led to the decision to sleeve all of the tubes in the three SGs at that site using laser welded sleeves (LWSs), and to add a laser welded joint to each of the HEJ sleeves at an elevation above the HEUT.. During the LWS campaign, fifty (50) additional HEJs were examined using the CECCO 3 probe. Nine (9) of the tubes were indicated to contain PTls.
Six (6) of these were at the HEUT and the remaining three were at the HELT. None of the tubes were indicated to have multiple PTIs'.
In the Summer of 1995, a CECCO        3 probe was used  to inspect all of the sleeve joints in the three SGs. A + Point probe was also used to inspect 184 of the welded HEJ sleeves. A summary of all findings was not available at the time of preparation of this report. Six (6) of the weld repaired HEJ sleeved tubes were removed for destructive examination. Two of these had been identified as having no detectable degradation (NDD) at the HEUT by the field NDE. These were confiimed to be NDD in the laboratory. The other four HEJs exhibited PTIs by the field NDE. One of these was found to have an ID initiated throughwall crack
(-0.5" on the ID and -0.25" on the OD) at the elevation of the HEUT. This tube broke during the removal operation at a tensile load of -9700 lb,. The other specimens had experienced wastage of the parent tube and the Alloy 690 sleeve at the bottom of the closed crevice, i.e.,
the HEUT, formed when the laser welding was effected. The wastage may likely be due to a concentration of an acidic environment in the -6" long closed crevice between the HEJ and the repair weld.
Note that this information is an update of information previously presented, e.g., Refer-ence 15, where it was stated that no indications had been reported in the HRUT, An expert review of the NDE data revealed that the location information was distorted as a result of pulling the probe down into the sleeve from the tube. A reevaluation of all of the PTI elevations was performed only to identify the location of the PTIs by transition, thus average dimensional information was not available at the time of preparation of this report.
DM'LANTSVLEPQKJFIB.D.SEC                       4-2                                              09/25/95


Table 5-3 (Cont.): Kewaunee SG Tube Macrocrack ProCiles for Tensile Fracture of HEJs Tube, Location R2C54, HRLT Length vs.Depth and Ductile Ligament Location (degrees/%throughwall) 00/04 22/67-Ligament 17&18 45 75 Ligaments I 4, I 5, I 6 68/84 (80/92)~Maximum depth 9p/78 Ligament I 3 112/82 135/72 I 5 8/74 Ligament I 2 80/74 Ligaments I 0&I I 202/56 Ligament 9 225/16 Ligament 8 248/48-Ligament 7 27p/64 Ligament 5&6 292/78 315/70 338/22 Ligament 2, 3,&4~Ligament I&19 (Average macrocrack depth=60%over 360';maximum depth=92%)Ductile Ligament Width (in.)L17, L18=0.015", 0.005" wide L14, L15, L16=0.003", 0.008", 0.007" wide L13=0.017" wide L12=0.009" wide LIO, LII=0.017", 0.005" wide L9=0.011" wide L8=0.050" wide L7=0.002" wide LS, L6=0.009", 0.007" wide L2, L3, L4=0.008", 0.013", 0.013" wide LI, L19=0.013", 0.044" wide Comments Nineteen ductile ligaments were observed on the circum-ferential macrocrack located in the middle of the HRLT.All intergranular corrosion was of ID origin.DAPLANTSlABPLAEP-BXAM,SEC 5-11 09/25/95  
Westinghouse non-Proprietary Class 3 4.2 Summary
    ~              of Field Experiences In summary, FIIs have been detected in HEJ sleeved tubes at three plants during a total of
                                          ~                                      ~
'our inspection                                          ~                    ~ ~  ~      ~
outages, two at Kewaunee, one at Point Beach 2, and the initial inspection
        ~
outage at Doel 4. A summary of approximately all known PTIs is provided in Table 4-3. In
                                              ~                              ~
total, about 60.5% occur at the HRLT and 37.2% at the HELT. About 0.7% have been found at the HRUT, and the remaining 1.6% at the HEUT. These distributions are illustrated in histogram form on Figure 4-1 and in "pie" chart form on Figure 4-2. The incidence of indications at the upper transitions in plants in the United States (VS) comprises about 1.5%
of the reported indications. Thus, the distribution at Doel 4 is atypical of the occurrences in the VS. In no instances have indications been detected in the same tube at upper and lower transitions.
Approximately 75% of the known PIIs have been found in tubes in the Kewaunee SGs.
Hence, it would be expected that the distribution of indications relative to elevation can be characterized by the distribution found at Kewaunee. Figure 4-3 illustrates the distributions of PTls at the last inspection outage at Kewaunee.'pproximately 1% of the indications were judged to be located within 1.1" of the bottom of the HRUT. If an eddy current positioning error of 1/16" is assumed, the number of indications above the repair boundary would be on the order of 4%.
The elevation information is based on an "expert" review    of 630 PTIs, or 98% of population of circumferential indications.
DAPLANTS'REP6iEJFIELD.SEC                       4-3                                          09/25/95


Tube/Location Table 5-4: Microhardness Measurements (VHN, 500 gm load)on Kewaunee HEJ Sleeved Tubes Microhardness at Specified Depth from Tube ID Surface R2C32, HELT HRLT HRLT next to FF HR HRUT HEUT FS 4" above HEJ R2C54, HELT HRLT HRLT HR HRUT HEUT FS 4" above HEJ 0.001" 196 209 238 (IGSCC)215 186 193 198 193 196 231 (IGSCC)241 212 176 176 0.006" 193'09 228 (IGSCC)212 193 196 1864 196 196 215 (IGSCC)228 204 186 174 0.016" 183~204 218 (IGSCC)204 186 188 1794 181 181 215 (IGSCC)221 193 176 172 0.026" 181~193 252 (shear)204 186 188 1814 174 172 221 (shear)212 191 181 156 0.036" 191 204 268 (shear)209 191 196 1864 181 183 234 (shear)215 193 183 166 0.046" 196'09'o data, necked 218 198 198 188 188 188 no data, necked 206~176 s 174 Notes: 1.2.3.4, 5.6.Located 0.002" closer to the ID surface than indicated Located 0.007" closer to the ID surface than indicated Located 0.002" farther from the ID surface than indicated Located 0.005" farther from the ID surface than indicated Located 0.005" closer to the ID surface than indicated Located 0.004" closer to the ID surface than indicated D LPLANTSLABPUNP-BXAhf.SBC 5-12 09/2$/9$
Westinghouse non-Proprietary Class 3 Table 4-1: Distribution of Kewaunee 1994 HEJ Indications Removed from Service by Installation Year Installation              SG                    SG        Both Year                  II A II                I IBll    SGs 1988                    46                    17      63 1989 1991 Totals                    48                    18      66 Table 4-2: Distribution of Kewaunee 1995 HEJ Indications Removed from Service by Installation Year Installation              SG                    SG      Both Year                  II All                IIBII    SGs 1988                  283                    152      435 1989                  147                    69      216 1991 Totals                431                    226      657 DAPLANTSM.EPQKJFIELD.SEC                  4-4


Location of Cracks in HHJ Sleeved Tubes Removed from Kewaunee No cracks found or detected on any of the tube specimens removed from Kewaunee Nominal Hardroll Transition Significant Hardroll Rolldown Circumferential cracking found near/at the top of the transition Circumferential cracking found near the center of the hardroll (Also typical of laboratoty specimens)
Westinghouse non-Proprietary Class 3 TabIe 4-3: Distribution of HEJ PTIs by Transition Point Transition                                          Doel 4          Totals        Percent Kewaunee'12       Beach 2 HELT                                134                            349            37.2 480              88                            568            60.5 0.7 15            1.6 Totals              698            230                            939            100 10                                            10 Volumetric Totals              710            230                            951 Notes;    1. 1995 numbers based on the findings  of an "expert" review of the elevations relative to the bottom of the HRUT prior to the final data becoming available.
No cracks found in either of the two destructively examined tube specimens from Kewaunee Figure 5-1 D LPLANYSULEPQKJEXAMS.SEC 5-13 09/2$/95 Westinghouse non-Proprietary Class 3 6.0 Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the tube indications on the operating performance of HEJs with PTIs, test and analysis programs were performed, References 8 and 9, aimed at: 1)characterizing the effect of the observed PTIs on the axial stxength of the joint, and 2)estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach 2 tubes (no indications have been determined to be present in the Cook 1 tubes at present)was explored via axial tensile testing and hydraulic proof testing.Additional analyses results were reported in References 11 and 12.A summary of the test and analysis pxograms is provided in the following sections.The results are applicable to the four U.S.plants with installed HEJs.Plant operating parameters relative to suxuctural integrity evaluations are presented in Table 6-1.The largest operating primaxy-to-secondary differential pressure, 1535 psi, occurs in the SGs at Kewaunee, although Cook 1 is approved to operate up to 1600 psi.The smallest differential pressure, 1225 psi, occurs at Point Beach 2.The current differential pressure at Cook 1 is 1453 psi.The axial end cap loads during normal operation, and the RG 1.121 3~loads, are summarized in Table 6-2.The maximum 3d P load is 2172 lbs (could be as high as 2264 lbs)and the minimum is 1734 lb,.Since each of the plants have 7/8" nominal diameter tubes with 0.050" thickness, the end cap load during a postulated SLB event is 1516 lbs regardless of the plant.Thus, the 3~end cap load governs the analysis.6.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9).Prototypic HEJ test specimens, see Figure 6-1, were fabricated using AOoy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were perfoxmed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations.
DN'LANT',ECHE/I'IELD.SEC                       4-5                                          09/25/95
For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e.,-1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 3M end cap loading.For specimens where the tubes were completely removed by machining at the elevation corresponding to the approximate midspan of the hydraulically expanded region, i.e.,-2.25" the bottom of the HRUT, the structural capability of the joints were-3.5 to 4 times the most limiting RG 1.121 3''end cap load.The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign)was similar to that of Alloy 690 sleeves.HE/STRUC.SEC 6-1 10/03/95 Westinghouse non-Proprietary Class 3 The structural proof tests were performed on specimens which had been fabricated for leak testing.Following the leak tests, the sleeved tubes were machined to simulate a 360'ircumferential throughwaH crack at the inflection point, i.e., middle, of the hard roll.AH of the samples were then pressurized to a differential pressure of 3657 psi.The pressure was then gradually increased until slipping of the joint was noted.Initial slippage of the tubes was genexaHy detected after an increase in the pressure of about 200 to 700 psi.The maximum pressures, i.e., those achieved when the tube was ejected from the sleeve, wexe not recorded, but did approach pressures on the order of three times normal operating pressure differentials.
6.2 Pulled Tube Structural Tests Section 5.0 of this report documented the results of leak and structural tests performed on the sleeved tube specimens removed from SG"B" at Kewaunee, see Table 5-2.The tensile test results fox both tubes are higher than that predicted by for the limit load.Tube R2C32 was found to have a high flow stress,-98 ksi, and an average depth of the cracking of 61%.The cxacking was near the top of the HRLT.The estimated limit load of the remaining ligament is 5980 lbs using a net section stress approach.The measured failure load for the specimen was 10300 lbs with a remaining sliy load immediately after the failure of 2800 lbs.Estimating the actual failure load of the remaining ligament as the total failure load minus the residual sliding load yields 7500 lbs.This is about 25%higher than the value predicted by analysis.The residual sliding load is about 60%largex than the maximum of two values obtained from tests reported in WCAP-14157 for 360'lits at the top of the HRLT.The sliding load following development of a 360 fracture is about four times, or 25%o higher than the RG 1.121 requirement, the end cap load that would be experienced during normal operation of the plant with the highest differential pressure.Moreover, the sliding load is almost three times, or twice the RG 1.121 requirement, the end cap load that would result during a postulated SLB event.Tube R2C54 had a measured flow stress of-83 ksi, with an average depth of cracking of 60%o.The cracking was at the approximate middle of the HRLT, which exhibited evidence of roHdown.The measured failure load was 10700 lbs with a residual sliding strength of 4000 lbs.Thus, the ligament failure load was on the order of 6700 lbs.This is about 30%higher than the calculated ligament limit load of 5170 lbs.The residual sliding load is about equal to the lower of two values obtained from tests reported in WCAP-14157 for a 360'lit at the bottom of the HRLT, and about equal to the average of three values reported in the Addendum to WCAP-14157.
Thus, the residual sliding load for the field specimen with a 360'eparation at the inflection point is on the order of that obtained from test speciments with a 360 separation at the bottom of the HRLT.In addition, the sliding load is on the order of six times the end cay load due to normal operation and about four times the end cap load developed during a postulated SLB event.6.3 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2 HHSTRUC.SEC 6-2 09/25/95 Westinghouse non-Proprietary Class 3 (Appendix A).The purpose of the analyses was to support the development of a repair boundary which included consideration of PTIs located at the top of the HRLT.Such indica-tions are not a subject of this report.The criterion supported by this report is that aO PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent.Thus, the structural integrity analyses consist of the evaluations of the test data reported in WCAP-14157 and its addendum, and of the test data obtained from the sleeve/tube joints removed from SG"B" at Kewaunee.6.4 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the top, the midpoint and at the bottom of the HRLT.The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions.
A summary of the leak rates from specimens with the tube removed or cut at an elevation corresponding to the top of the HRLT or at the repair boundary is provided in Table 6-3.The specimens with the tube removed at the midpoint of the HRLT'xhibited a maximum leak rate of 0.016 gpm at SLB conditions.
The average leak rate for all of the specimens listed in Table 6-3 is about 0.004 gpm with a standard deviation of 0.008 gpm, thus, demonstrating a significant resistance to primary-to-secondary leakage.These tests suggest that the presence of a"lip" of tube material below the top of the HRLT provides sufficient leakage restriction.
The repair boundary determined from structural considerations, i.e., 1.1" below the bottom of the HRUT, would be expected to result in acceptable leak rates during a postulated SLB event.6.5 Crack Growth Rate Considerations Since the HEJ has been demonstrated to meet the requirements of RG 1.121 for full circumference, i.e., 360', at the elevation of the middle of the HRLT, the strength relative to those requirements is independent of crack growth rates.6.6 Additional Tube Integrity Considerations and Observations The repair boundary developed in this report does not assume any credit for the resistance to tube motion afforded by tube support plate denting.The presence of significant dents could preclude any tube integrity issues in HEJ sleeved tubes with PIIs.A review of pull forces required to remove tubes from Westinghouse Model 44 and 51 steam generators was discussed in WCAP-14157.
For tubes with no significant interface loading within the tubesheet, pull forces for tubes without detectable denting ranged from 1000 to 3000 lbs, while for tubes with detectable dents, the forces rose to 2000 to 4000 lbs.Based on the findings from the destructive and nondestructive examinations of the specimens removed from Kewaunee, Section 5.0, and from the results of accelerated corrosion tests per-Approximately 1.12 to 1.13 inch below the bottom of the HRUT.HEISTRUC.SEC 6-3


Westinghouse non-Proprietary Class 3 formed by Westinghouse, the appearance of PTIs in joints experiencing significant rolldown may be likely to occur at a lower elevation than in joints without significant rolldown.Approximately 90%of the PTIs at Kewaunee were found at distances R 1.3" from the bottom of the HRUT, thus implying the presence of significant rolldown.Hence, it is possible that transitions with significant rolldown are less resistant to PWSCC than transitions without significant rolldown.6.7 Conclusions The specified repair boundary is supported by structural and leak test data obtained from surrogate specimens (WCAP-14157 w/addendum), and by structural data obtained from specimens removed from an operating SG.Tube rupture loads well in excess of those required by RG 1.121 have been demonstrated by both the surrogate and actual HET test programs.The repair boundary results in a radial overlap of the HRLT of approximately 0.1" in length.This is a geometric configuration for which neither significant tube axial displacement nor significant tube leakage would be expected to occur during a postulated SLB event.EEJSTRUC.SEC 6-4 09/25/95 Westinghouse non-Proprietary Class 3 Table 6-1: Operating Parameters for U.S.Plants with Installed HEJs Plant SG Loops pp (psia)PE (psia)(psi)Thoc (6 Tcold Cook I Kewaunee 51 4 51 2 Point Beach 2 44 2000 2100 2250 775 715 1225 1453 1535 596.7 541.7 582.0 518.0 591.2 531.8 Zion 1 51 4 2250 725 1525 592.2 532.2 Table 6-2: Tube Pressure Loading for U.S.Plants with Installed HEJs Plant Point Beach 2 Cook 1 Kewaunee Zion 1 Normal (psi)1225 1453 1535 1525 Normal cQ'oad (lbs)578 685 724 719 3~AP Load (lbs)1743 2056'172 2158 Note: 1.The 3+dZ load at Cook 1 could be as high as 2264 lbs corresponding to an operating differential pressure of 1600 psi.2.The end cap load during a postulated SLB event is 1516 lbs independent of plant.HEJSTRUC.SEC 6-5 09/2S/9S Westinghouse non-Proprietary Class 3 Table 6-3: Summary of Applicable HEJ Leak Rates from WCAP-14157 and Addendum Sleeve Material Alloy 690 Alloy 690 Alloy 690 Alloy 690 Alloy 690 Alloy 690 Alloy 600 Alloy 600 Cut Angle 240 240 240 240 360 360 360 360 Distance from HRUT (in)1.08 1.01 1.03 1.0+-1.1-1.1-1.1~R te<>>at 1600 psi (gpm)0.0 0.0 0.0084 0.0 0.0 0.0016 0.0 0.0 Leak Rate"'t 2560 psi (gpm)0.0 9 x 10~0.0186 4.5 x 10~2 x 10~0.016 1x 10'x 10~Notes: 1.Leak rates for specimens with 240'ut angles were increased by a factor of 1.5 to estimate the leak rate for a cut angle of 360'.HBJSTRUC.SEC 6-6 10/03/95 i
Figure 4-1 Distribution of Circumferential PTIs by HEJ Transition 600 SDoel 4, 1994 600                                                Q Point Beach 2, 1994 8Kevraunee, 1994 8c 1995 O
End Cap Plug or Tensile Gripper.Tube cut at elevations from the top of the transition to below the bottom of the transition, and at various arc lengths.Tube Hardroll I Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.Figure 6-1: HEJ specimen used for tensile testing.D:KPLANTShhEPEHEJSTRUC.FlG 6-7 8/2/95
    ~ 300 K
200 10Q 0
HELT            HRLT                                    HEUT HEJ Transition D .PLAlCTSEAEP'LHEJFIELD.F1G


Westinghouse non-Proprietary Class 3 7.0 Leak Rate Based Repair Boundary 7.1 Introduction The purpose of this section of the report is to resent an alte repair boundary for HES p en an ternative method for establishing a e upper sleeve/tube joint region, but below the prim to-secondary pressure boundary at the sleeve/tube harclroH interface.
Figure 4-2 Distribution of All Circumferential PTIs by Transition Hydraulic Expansion Hardroll Upper                            Upper Transition Transition Hydraulic Expansion Lower Transition Hardroll Lower Transition EIHELT =37.2%
The rev'n o sleeved tubes from Kewaunee, an evaluation of the structural
HHRLT = 60.5%
'gin y ocumented in References 8, 9, 11 and 12.The structural evaluations directly support the identification of a repair boundary for PTl b ed of the'oint.I'.t is also possible to develop a repair boundary for PTIs in sleeve/tube oin which is not sensitive to the residual stren~~of the oint dary a function of the instaHed geometry of the tubes and th rate is developed in this section.Since the re air an e HEJs ince e repair boundary is based on geometry and total ge, it does not rel on the re i y sidual strength of the joint or on the extent of the indica-tions, or the growth rate of the indications, The repair b dary d location cation of the PTI and the constraiiiing effects of outboard neighboring tubes I The HEI consists of of a HE of the sleeve and tube over a length of 4" be'r/2 b.low h..p'.f".1-., f.How by.h~-H'w the top of the hydraulic expansion.
OHRUT = 0.7%
The existing plant T hnical repairing/plugging criteria apply to the entire length of the sleeve, and to that portion of the parent tube above the bottom of the HB of the HEI.An exam le of the plugging criteria developed at the time of the installation of h This evaluation forms the basis for the development of a repair boun dary be o s eev tu e rom service due to the presence of PTls in the re*extending downward from the upper part of the HRLT e..see the tube bundl th PXX o e T, e.g., see Pigure 7-1.The integrity of ad die ed.Tll e wi s under normal o eratin p g and postulated accident conditions is 51 a ss.e results of the evaluation a apply to sleeved tubes in Westinghouse Model 44 aild dressed: s.aspects of bundle integrity are ad-1)maintenan maintenance of a fixed tube-to-sleeve end condition in the limi circumferential indication
                                                                          ~ HEUT = 1.6%
*on in e ting case of a m~cation near the top of the lower transition of the hardroH tions, and 2'aiy--secondary leakage consistent with acc d t al~~~~~~2)limitation of rim-to-cci en an ysis assump-7-1
D: 5 PLANYSKAEPT HEJFIELD.FIG                  4-7                                      , 08/01/95


Westinghouse non-Proprietary Class 3 g)maintenance of tube integrity under postulated limiting conditions of primary-to-secondary and secondary-to-primary differential pressure.The result of the evaluation is the identification of a distance below the bottom of the HRUT for which PTls of any extent do not necessitate remedial action, e.g., plugging.The basis of the repair boundary is that the axial distance a postulated severed HEJ sleeved tube end can move is limited by the constraint afforded to the affected tube by it s outboard neighbor.Thus,"hop off" of the upper portion of a severed parent tube will be precluded, and the leakage from such tubes during a postulated SLB will be within acceptable limits.For example, for the Kewaunee SGs the total allowable primary-to-secondary leak rate from all sources during a postulated SLB event was determined in Reference 30 to be 34.0 gallons per minute (gpm), without benefit of reducing primary coolant activity.Interim plugging criteria (IPC)have been approved for dispositioning tube indications at the elevation of the tube support plates in the D.C.Cook and Kewaunee SGs.The expected contribution to the total primary-to-secondary leakage from the IPC indications is likely on the order of 1 gpm or less.Thus, approximately 33.0 gpm total leak rate from HEJ PIIs could be tolerated without exceeding the 10CFR100 limit for the Kewaunee plant.Application of the leakage based repair boundary is expected to provide the same level of protection for PTIs in HEJ sleeved tubes as that afforded by Regulatory Guide (RG)1.121 for degradation located outside the sleeve joint.Since the repair boundary does not rely on the residual strength of the joint, the calculation of margins against burst for the affected tube are not meaningful.
Kemaunee SGs "A" 4 "8" HE J PTIs vs.
For each affected tube, the repair boundary does rely on the structural capability of that tube's outboard neighbor.By restricting the application of the criteria to tubes with a structurally capable outboard neighbor.'.2 Sleeved Tube Dimensions A summary of the sleeve and tube dimensions pertinent to this evaluation were illustrated in Section 1 of this report.The tubing has a nominal outside diameter (OD)of 0.875" and a thickness of 0.050".The sleeves have an[]".The region of the hardroH is denoted by the label interference'.
Distance Below'he Bottom of the HR Upper Tra.position 130                                                                                happ 120 90%
The length of this region is governed by the length of the hardrolling tool used to create this section of the joint.For the D.C.Cook, Kewaunee, and Point Beach 2 SGs, the rollers had a flat length dimension of 1.0".Thus, the length cannot be less than 1.0" on the ID of the sleeve.In some cases the length of the hardroll is greater than 1.0" as a result of the reversal of the rolling process in order to release the roller from the inside of the sleeve.This reversal process is usually termed rolMown and the additional length of the hardroll is referred to as the rolldown length.It is not unusual for the rolldown to achieve a length of greater than-0.5" during the reversal process.The radii of the upper end of the rollers of the rolling tool were[Limitations on the use of the leak rate based repair boundary are discussed in the evaluation section of this report.HEJLEAKP.SEC 7-2
110 80%
100 90 EK3 Both SG Indications Both SG Cumulative 95% Rank Cumulative 70%
O ca O
                                                                                            'a 80                                                                                60%
pg 0
70
                                                                                      ~r 0%
o  60 lC 40%    o 50 40    RG 1.121                                                                    30%
8 30  Repair Limit 20%
20 10%
10 0                                                                               0%
eo              oc4  e M
o co eco  ow    ew  oe  ee    o cD eco  o C
e Upper Bin Distance Below Bottom of HR Upper Transition


Westinghouse non-Proprietary Class 3]*".Hence, a bounding lower limit on the radius at the OD of the sleeve in the transition is approximately 0.288".A true estimate of the radius of curvature in the axial direction is obtained by considering a hardroll transition length of 0.21" and a radial difference of 8 mils leads to the calculation of an effective radius of 1.4".The[]'", thus, the effective length of the hardroll would be about 60 mils longer before the contact pressure between the sleeve and the hardroll would be lost.This would be somewhat offset by the potential contraction of the tube during the hydraulic expansion process.The expansion of the tube is about[]*".Since the sleeves installed in the D.C.Cook, Kewaunee, and Point Beach 2 SGs were fabricated of Alloy 690, their coefficient of thermal expansion is greater than that of the tubes.This would lead to a slight increase in the interference fit during operation as further increase the effective length of the hardron, however, the expected magnitude of such an increase would not be expected to be significant.
Westinghouse non-Proprietary Class 3 5.0 Summary of Examinations Conducted on Kewaunee Steam Generator Tubes with Hybrid Expansion Joints 5.1 Introduction Sections of SG tubes R2C32, R2C54 and R2C61 were removed from the hot leg side of SG "B" at Kewaunee in 1995 to characterize the operating condition of the HEJs which had been installed in these tubes in 1988. The HEJs had been installed to prevent leakage through tube corrosion at top of tubesheet (TTS) and tubesheet crevice locations. The tubes/HEJs were cut 3" above the TTS and 3" below the first tube support plate (TSPs) and were then removed from the secondary side of the steam generator to avoid deformation that would have probably occurred from a primary side tube pull. Consequently, only the upper mechanical joints of the HEJs were available for examination. The upper mechanical joint is described in Section 1 of this report. The tube material was mill annealed Alloy 600, and the sleeve material was thermally treated Alloy 690. The examination was conducted at the Westinghouse Science and Technology Center to characterize any tube/sleeve corrosion. Field eddy current suggested the presence of significant circumferential corrosion at the hard roll lower transition (HRLT) in the upper mechanical expansion of the HEJs.
7.3 U-Bend Clearance The results of a study of SG fabrication practices, Reference 17, were evaluated in order to estimate the potential distance that a severed HEI sleeved tube end could displace in the vertical direction during normal operation or during a postulated SLB.The results of this evaluation are applicable to the development of a plugging repair boundary for PTIh in sleeved tubes.In SGs of the type installed at D.C.Cook, Kewaunee, Point Beach 2, i.e., Westing-house Model 44 and 51, the nominal vertical clearance between radially adjacent tubes at the apex of their U-bends is 0.406".The actual clearance will vary about the nominal due to tube installation tolerances during manufacture of the SGs.The potential contributing factors from the Model 44/51 SG manufacturing operations are: 1.The tube-to-tubesheet fit-up for welding.2.The tube expansion process.3.Tube dimensional tolerances on overall length, U-bend radius, tube diameter, etc.The second operation does not significantly contribute to the manufacturing process tolerance since the tube-to-tubesheet joint process for the D.C.Cook, Kewaunee, and Point Beach 2 SGs involved partial depth rolling as opposed to full depth rolling.The maximum tube-to-tube U-bend apex gap increase in the D.C.Cook, Kewaunee, and Point Beach 2 SGs as a result of the first and third operations was calculated to be[]"'.The extremes of the total manufacturing tolerance are taken to be three standard deviations from the mean, hence, one standard deviation would be[]'"".Since the installation of one tube is independent of its inboard neighbor, the standard deviation of the manufacturing clearance, i.e., the difference between two radially adjacent tubes, may be HEJLEAKP.SEC 7-3 09/25/95 Westinghouse non-Proprietary Class 3 calculated as the square root of the sum of squares of the individual standard deviations.
After nondestructive laboratory examination by eddy current, radiography, dimensional characterization, and visual examination, one HEJ region was leak tested at elevated temperature. Subsequently, room temperature tensile testing was conducted on two,of the HEJs, as well as on three free span sections, one from each removed tube. The third tube/
Thus, the standard deviation of the U-bend apex gap between two radially adjacent tubes would be[]'".An additional consideration in estimating the U-bend apex clearance between two radially adjacent tubes is due to the[]'", assuming that a primary-to-second-ary pressure difference of 2560 psi is achieved during the event.Assuming the distribution of U-bend apex gaps to be normally distributed in the SG, an upper 95%confidence bound on the apex clearance is calculated to be[]SIC The U-bend apex gap can be used to estimate the maximum upward displacement of a tube end which is assumed to be severed within the HEJ.The driving force for such displacement will be the unbalanced pressure on the interior of the tube acting on the projection of the tube cross-section area at the tangent point between the U-bend and the straight length of the tube, i.e., the severed tube end is pulled up by the force at the U-bend.Once contact has occurred with an outboard neighbor, further displacement is prevented.
HEJ section was retained intact as an archive specimen. The two HEJs which were tensile tested were then destructively examined using metallographic and SEM fractography techniques to characterize any corrosion. In addition, an analysis of the OD and ID deposits, ID oxide films, and fracture face oxide films was performed using EDS, ESCA and AES tech-niques. In addition, ion chromatography and capillary electrophoresis were performed on soluble ID deposits obtained by water leaching.
The total vertical displacement may be estimated by calculating the distance that the affected tube's tangent point may traverse by considering that the inboard tube deforms into intimate contact with the outboard tube up to the apex of the U-bend.More extreme deformation would require lateral in-plane deformation which is opposed by the internal pressure.Moreover, the extent of intimate contact would likely be limited to the point of first contact, which would be expected to occur nearer to the midway point from the tangent point to the apex.If d is the tube-to-tube clearance at the apex of the U-bend, and R is the radius of the U-bend of the affected tube, the clearance at the tangent point, D, is D=(R+d)sin-K-d.2R+d 2 (7.1)Using the upper 95%confidence bounds of the U-bend apex clearance results in upper bounds on the tangent point displacement of[]*" respectively.
5.2 NDE Results Table 5-1 presents a summary of the more important field and laboratory NDE results. The field eddy current data were conducted using + Point and I coil probes, while the laboratory inspections used + Point, CECCO and RPC probes. Field and laboratory eddy current inspections produced similar data. For the + Point probe, common to both the field and lab exams, the data produced the same signals, suggesting a 360'ircumferential indication in the HRLT of tubes R2C54 and R2C61, and a 300 to 360'ircumferential indication in the HRLT of tube R2C32. These signals were suggestive of deep, even throughwall degradation. The laboratory CECCO probe data produced similar conclusions with the exception that the circumferential indication in tube R2C32 appeared to be 360'ide, rather than 300 to 360 wide. In addition, the laboratory + Point and CECCO probes suggested the presence of a small indication in the hydraulic expansion lower transition (HELT) of tube R2C61 (the archive specimen). There was no suggestion by field or laboratory NDE of any corrosion degradation being present in the Alloy 690 sleeve.
The expected displacement would be between the two extremes.Taking the average of the apex and the maximum tangent point displacements results in expected displacement limits of[]*", with a limiting value of the expected displacement of 1.1".Since this result is based on a 95%confidence level, it would be expected that the occurrence of multiple tubes achieving this level of displacement would be very unlikely.I"urthermore, because the length of the sleeve above the bottom of the HR is on the order of 2.75", joint separation, i.e., hop-off, is precluded for tubes with PTIs below the top of the HRLT.HE/LEAKP.SEC 7-4 09/25/95 Westinghouse non-Proprietary Class 3 Since, hop-off is precluded, the pertinent basis for the development of the leak rate repair boundary is the potential leakage from tubes with throughwall, 360, PTls which could displace upward either during normal operation or during a postulated SLB.The potential displacement during a postulated SLB is greater than that during normal operation, as is the primary-to-secondary differential pressure, hence, it is appropriate to develop the repair boundary based on the consideration of potential leakage during a postulated SLB.Verticany displaced severed tube conditions are illustrated on Figure 7-2.The expected displacement for a tube end severed at the top of the hardroll lower transition would be about midway along the length of the hardroll, with a 95%confidence bound on the displacement such that the location of the severed end would be about even with the top of the hardroll.Indications below the top of the hardroll would not be expected to lead to a configuration such that the severed end could achieve an elevation coincident with the top of the hardroll.The effective length of the hardroll was estimated in the previous section to be 1.03" based on the radius of curvature in the axial direction and the elastic springback of the joint.This is about the same length as the 95%confidence level for the maximum displacement during a postulated SLB event.Since circumferential indications would not be expected above the top of the hardroll lower transition, the appearance of circumferential indications which could be postulated to lead to severing of the affected tube at elevation'n which could be exposed to the full primary-to-secondary pressure difference would be expected to be of low probability.
DAPLARKVLERHE/EXAh(S.SEC                     5-1                                          09/25/95
7.4 Leakage Potential Leak rates may be estimated from the tests that were performed, see References 8 and 9, and from calculations assuming various other geometry conditions, e.g., for a severed tube end which is elevated relative to the sleeve.It is to be noted that the maximum estimated primary-to-secondary differential pressure during a postulated SLB of 2560 psid assumes that the makeup system is capable of achieving that pressure regardless of primary-to-secondary leakage.Realistically, if one severed tube end displaced such that significant leakage occurred, the primary-to-secondary differential pressure would likely not increase further.Thus, while conservative, the consideration of a significant number of leaking tubes during a postulated SLB is not realistic.
If the postulated severed tube end is assumed to be displaced relative to the sleeve, the leak rates measured for full hardroll length engagement may be estimated by assuming the flow to be controlled by a friction factor.This is appropriate instead of estimating an annulus choke flow because of the interference fit between the sleeve and the tube in the hardroll region.The relationship between the flow, Q, the length of engagement, L, the differential pressure, d,P, and the friction factor, f, would be, AP 0=-fL (7.2)HElLPAKP.SEC 7-5 09/25/95 Westinghouse non-Proprietary Class 3 The value of f could be estimated from the leak test for which the length of engagement was 1".However, this is not necessary since a comparison of leak rates for different engagement lengths leads to the relation, L,@=0,-.L~(7.3)Thus, if the length of engagement is halved, the expected leak rate is doubled.This expres-sion may provide satisfactory estimates in the range of Q from 1.0 to 0.25 of L,, however, its use beyond that range would not be recommended since the Q,~oo as Q-4, and severed tube end effects would be expected to lead to increased radial deflection at the tube end accompa-nied by increased leakage.7.4.1 Normal Operation During normal operation, the leakage from HEI sleeved tubes with throughwall degradation extending 360'round the tube and located at the elevation of the HR lower transition would be expected to be sufficient to be detected.If the tube end does not displace, the leakage from each such joint would likely be on the order of 1 gpd or less.If the joint does displace, an increase in the leak rate would be experienced such that the plant could be shut down to address the source of the leakage.7.4.2 Steam Line Break For the initial evaluation of potential leak rate in the event of severing of the tubes, calcula-tions were performed for assumed radial gaps if the tube displaced axially upward relative to the sleeve, For a radial gap of[]*", corresponding to elevating the hardroll length of the tube to correspond to the hydraulically expanded length of the sleeve, the projected leak rate was found to be-25 gpm, References 8 and 9.If the tube displacement is limited to less than or equal to about 1.1", the-95%confidence value for tangent point contact, the lower end of the hardrolled region of the tube would still be in contact with the upper end of the hardrolled region of the sleeve.For leakage evaluation purposes, prior calculations assumed that a gap on the order of[]"', and would thus be expected to leak at a rate of 2.5 gpm.In actuality, no gap would be expected to be present for displacements less than 1.03" and the expected leak rates would be substantially less than the estimated value of 2.5 gpm.Testing has been performed for tubes machined away at the top of the hardroll lower transition, References 8 and 9.Leak rate values under these circumstances were found to be relatively insignificant when compared to the makeup capacity of the plant hydraulic system.The maximum leakage from any single indication was estimated to be bounded between 0.01 and 0.033 gpm.These estimates may be considered to bound the leak rate if as little as-1/4" of sleeve-to-tube hardroll interference remains.Using the maximum value as an average for all such tubes results in a total leak rate from 1000 leaking HEJ sleeved tubes of 33.0 gpm.The total IPC leak rate which might be expected from the limiting D.C.Cook or Kewaunee SG is HElLEAKP.SEC 7-6 09/25/95 Westinghouse non-Proprietary Class 3~~~~~~~~~~~~~~~~~~estimated.to be less than 1 gpm.Therefore, about 1000 or more HEJ sleeved tubes with PTIs ould remain in service, without expecting total leakage during a postulated SLB to exceed the 10CFR100 limit.If only the results from the three valid tests are used, i.e., 0.0, 6+10, and 0.0124 gpm, respectively, four times the maximum leak rate (assuming a displacement of about 0.8")would be 0.05 gpm.Conservatively considering this maximum leak rate to apply to all sleeved tubes leads to a total leak rate for 665 HEJ sleeved tubes of 33.0 gpm.It is to be emphasized that the average total leak rate from the 665 sleeved tubes considered here would be expected to be significantly less than the 10CFR100 limiting leak rate.More accurate estimates of the total leak rate could be developed using Monte Carlo simula-tion techniques, however, based on the conservatisrns utilized for the deterministic estimates, e.g., the probability of experiencing multiple severed tube conditions was considered to be unity, such results would be expected to be significantly less than those reported herein.I&C&7.5 Tubes Interior to Stayrod Locations Tubes interior to stayrods have no immediate outboard neighbors.
Therefore the clearance to the nearest restraint is significantly larger than for tubes with outboard neighbors, and would be expected to exceed the hop-off distance from the PTI to the top of the sleeve.Thus, the leak rate based repair boundary developed in this section is not applicable to tubes immediate-ly interior to the stayrods.7.6 Distribution of Indications in the Kewaunee SGs Sleeved Tubes The distance from the bottom of the hardroll upper transition to the elevation of the indica-tions in the Kewaunee SG tubes was measured for each indication near the elevation of the hardroll.A summary of the measured distances for each SG and for the combined SGs is provided in Table 7-3.Histogram and cumulative frequency plots of the distribution of indications in SGs"A" and"B" are provided on Figure 7-3 and Figure 7-4 respectively.
The combined distribution and cumulative frequency information for both SGs is provided on Figure 7-5.l&A total of 630 indications were considered in this evaluation.
The average distance was found to be 1.32" with a standard deviation of 0.10".The median distance was found to be 1.32".The skew and kurtosis{normalized) were found to be 0.20 and 0.58 respectively.
These last three values indicate the distribution to be relatively normal.An inspection of the plotted cumulative frequency curves indicates the distributions to be nearly symmetrical about the 50%value for the measured populations, thus supporting the judgment that the distributions are nearly normal.Hence, the probability of an indication being located within the 95%confidence bound on the potential displacement is relatively small.To be located above the~~~~~~~~~~~~~~~~~average value of the potential displacement, the indication would have to be located-4.5 standard deviations away from the mean elevation.
The distribution of indications in the Kewaunee SGs confirms the expectation that very few indications would be expected to occur at elevations where significant leakage could occur during a postulated SLB.EEJLPAKP.SEC 7-7 09/25/95  


Westinghouse non-Proprietary Class 3 7.7 Phnt Operation Considerations Other factors which would be expected to have a beneficial effect on the total leak rate that could be experienced are: 1)Adoption of a normal operation leakage limit of 150 gpd.2)Implementation of nitrogen 16 (N16)monitors for monitoring SG leakage.3)Enhanced training of operators to respond to faulted events.7.8 Summary and Conclusions Analyses have been performed which indicate that the total leakage that could reasonably be expected from the sleeved tubes with indications in the D.C.Cook, Kewaunee, and Point Beach 2 SGs during a postulated SLB would be small relative to the makeup capacity of the charging system.A comparison of the distance a severed tube end could be expected to move during normal operation or during a postulated SLB relative to the distance from the bottom of the HEJ hardroll upper transition to the indications in the D.C.Cook, Kewaunee, and Point Beach 2 sleeved tubes indicates that it is unlikely that any of the tubes could become disen-gaged from their respective sleeves if those tubes are constrained by the presence of a structurally capable outboard neighbor.For an outboard neighbor to be considered as structurally capable, it may not, if sleeved, have circumferential degradation evident above the bottom of the HEJ hardroll lower transition.
Westinghouse non-Proprietary Class 3 The radiographic laboratory examination detected a 270 to 360 circumferential band of short semi-continuous circumferential indications in the upper portion of the HRLT of the tube, just below the HR region in tube R2C32. These cracks were confined to a very narrow zone, less than 0.05" high, such that the individual cracks appeared to occur head-to-toe. In addition, a shorter (approximately 300 long) band of cracks was observed approximately 0.1" below the main band of cracks. tube R2C54 had two to three similar bands of short semi-continuous circumferential cracks that occurred over 350'rom the mid- to upper portion of the HRLT.
Tubes which are plugged may not have been so removed from service on account of circumferential degradation.
Tube R2C61 had one band of short semi-continuous circumferential cracks that occurred over 360'n the mid-portion of the HRLT.
Axial degradation has no significant effect on the axial strength of active or inactive tubes, hence the presence of axial degradation alone is not considered.
The HRLT was approximately 0.25" long in the case of tube R2C32, and was approximately 0.5" long in the cases of tube R2C54 and R2C61. The HRLT apparently experienced noticeable rolldown'uring installation, especially for tubes R2C34 and R2C61. In contrast, the HRUTs for all three tubes were approximately 0.1 to 0.2" high. Dimensional characterization of the HE's showed that all three had similar hydraulic and hard roll expansion dimensions that were typical for qualified HEJ instaHations, e.g., see Figure 1-3.
cause to consider an outboard neighbor as not structurally viable.This section documented the development of a geometry based repair boundary for PIIs in HEJ sleeved tubes.The resulting repair boundary is independent of the repair boundary developed in previous sections based on the structural integrity of the joint.Since the result obtained, 1.1", is the same as the structural repair boundary, it essentially demonstrates a defense in depth against the occurrence of a tube separation.
The hardroll regions were expanded 0.009, 0.012 and 0.009" radially above the negligibly expanded hydraulic regions for tubes R2C32, R2C54, and R2C61, respectively.
The application of the repair boundary results in expected leakage during normal operation and postulated steam line break (SLB)events within limits based on 10CFR (Code of Federal Regulations), Part 100 criteria.The conclusion of the evaluation is that based on geometry considerations alone it is accept-able to leave HEJ sleeved tubes with PIIs in service that satisfy the following requirements:
5.3 Leak Testing The R2C54 HEJ was cut to 11" long with the hardroll region centered in the specimen. The bottom 1" of the specimen was then expanded to contact with the tube and the sleeve was then welded to the tube. This seal causes any leak through the hardroll region to occur bnly through the tube HRLT cracks. Elevated temperature leak testing was then performed on tube R2C54 at a variety of conditions that ranged from nominal operating conditions to simulated SLB conditions. No leaks were observed through the tube HRLT cracks at any of the test conditions. The maximum test differential pressure was 2534 psi with corresponding primary and secondary side temperatures of 618 and 611'F.
1)The distance from the bottom of the HRUT to the PTI is greater than or equal to 1.1".2)The tube is located on the interior of the tube bundle.3)The tube is not located adjacent to and inboard of a stay rod.HEJLEAKP.SEC  
5.4 Tensile Testing Table 5-2 provides room temperature tensile properties obtained from a free span (FS) section of each tube. The tensile strengths for the FS section of tubes R2C34 and R2C61 are typical for Westinghouse tubing of this vintage. The tensile strength for tube R2C32 is noticeably higher than typical. Table 5-2 also provides tensile load separation data for the HEJs from tubes R2C32 and R2C54. The 11" long HEJ specimens, with their HR regions centered within the specimens, had the bottom 1" of their sleeves expanded into contact with the tubes.
The bottom end was then welded such that the sleeve and the tubing below the cracking in the HRLT would not move relative to each other during the tensile test. The top portion of the .
11" long specimens consisted only of tubing because the top of the sleeve ended approximately 3.3" below the top of the tubing. The HEJs were then pulled apart at 0.05" per minute with
    'n order    to remove the rolling tool from the installed sleeve, the direction of rolling is reversed to release the rollers from contact with the ID surface of the sleeve. Ifthe rollers do not immediately retract, additional rolling in the downward direction occurs, resulting in an elongation of the HRLT referred to as rolldown.
DM'LANT',EPLHEJEXAMS.SEC                       5-2                                            N/25/9S


Westinghouse non-Pxoprietary Class 3 4)The outboaxd neighboring tube is stxucturally capable, i.e., it can be expected to provide restraint against upward motion of the affected tube if the affected tube is considered to be sevexed at or below 1.1" from the bottom of the hardxoll upper transition.
Westinghouse non-Proprietaxy Class 3 the separation load of the HRLT crack network being recorded. In additi          th lidin of the HR region of the upper portion of the tubing being pulled over the HR region of the sleeve was also recorded. Both HEJs had high separation loads, 10,300 and 10,700 lb, respectively. The HR sliding loads decreased continuously over the remainin g HR region.
For example, a review of Kewaunee Nuclear Power Plant data indicates that the first three requirements are satisfied for all sleeved tubes in the SGs.Thus, only satisfaction of the last requirement would need to be specifically demonstrated if geometry was the only basis for the repair boundary.However, the development of the geometry based boundaxy is secondary to the structural based boundary, so requirements 2)through 4)would not be considered to be generally applicable.
be R2C32, with the HRLT cracking located at the upper portion of the HRLT (at the bottom portion of the HR), had its sliding load start at 2800 lbs and decxease to 50 lbs at the toy portion of the sleeve HR. Tube R2C54, with the HRLT cracking located near the center of the HRLT, had a smaller diameter fracture opening that was required to pass over the s eeve HR region. Consequently, the initial sliding load was higher, 4000 lbs. The sliding oad continuously decreased to 200 lbs at the top portion of the sleeve HR.
7-9 09/25/95
5.5 Destructive Examination Results Post-tensile test visual inspection data showed that ID origin, circumferentially oriented, corrosion cracks were present continuously around the circumference of the tube fracture faces of both HEJs that were separated by tensile testing, Figure 5-1. The two HEJ specimens were subsequently given destructive examinations which included SEM fracto          h f th ace openings, visual and SEM inspection of surface features and metallography of secondaxy corrosion within the HEJ region of the tubing.
The tensile fracture faces of the tubes from the two HEJ tensile specimens wexe examined by SEM. Table 5-3 presents the results of the fractographic data in the form of macrocrack length versus depth, microcrack length/average and maximum depth, and the number/location/
width of ductile or non-corroded ligaments found on the fracture face. The tube tensile
                                                                  'h separations occurred in circumferentia1 macrocracks that were composed of numerous circumferentially oriented intergranular microcracks of ID o rigm a t wexe aligned  ed in a single tight and narrow (< 0.05" high) band in the case of tube R2C32 an      m a s lightly less tight and in narrow (    .      g ) band in the case of tube R2C54 where the fracture face jumped from one circumferential crack network to a parallel one. (See radiogra hic data In S
  ..)
* arge raction of the many ligaments separating the microcracks on botho specimens had ductile features. There were 21 ductile ligaments pxcsent in the case of tube R2C32 and 19 ductile ligaments present on the fracture face from tube RZC34. Many          er li any oother  ligaments aments had only intergranular features.
All intergranular e
                                                                          'n corrosion was confined to and located in thee HRLT regions. In the case of e cracking was at the upper portion of the HRLT and in the case of tube R2C54 the cracking was located from the mid-portion of the HRLT to the upper portion of the HRLT. The fracture faces both had a maximum depth of 92% throu hwall ep s ranging rom 61% (tube R2C32) to 60% (R2C34) throughwall and with microcrack lengths that were 360 long. At some ID locations adjacent to the fracture faces, a few short circumferential microcracks were observed parallel to the fracture face. These microcracks appeared to be simple cracks, morphologically syeaking, in that the near absence o f o bli'que
                                            ~
g    racks and bluntmg was noted. This morphology is more typical of PWSCC than of
                                      ~
                        ~                        ~      ~
secondary side corrosion that typically occurs in caustic crevices.
SEM examinations were conducted on the OD and ID surfaces of the balance of the tubing f
from, both tubes in the HEJ regions with the examination co ncen tratin g on m din g cracks at DAPLAPISV,EPQKJEXAMS.SEC                        5-3


Westinghouse non-Proprietary Class 3 Table 7-1: Tube U-Bend Apex Clearance Dimension Nominal Pressure Difference Normal Operation Steam Line Break a.)c Average Standard Error Table 7-2: Tangent Point Clearance Dimension 50%Confidence 60%Confidence 90%Confidence 95%Confidence 99%Coilfidence Normal Operation Steam Line Break Q.C 99.5%Confidence 99.9%Confidence HEJLEAKP.SEC 7-10 09/26/95 Westinghouse non-Proprietaxy Class 3 Table 7-3: Distribution of the Distance of the Indications from the Bottom of the Kudroll Upper Transition Parameter Count Average Standard Deviation Maximum 1VRnmum Skew Kurtosis SG"A" 426 1.32 0.092 1.63 1.04 1.32 0.01 0.18 SG NBtl 212 1.31 0.106 1.75 1.00 1.30 0.52 1.03 Both SGs 638 1.32 0.100 1.75 1.00 1.32 0.20 0.58 HEJLEAKP.SEC 7-ll Westinghouse non-Proprietary Class 3 Repair Boundary illustration Alloy 600 Tube Alloy 690/600 Sleeve HRUT Hardroll and thermal interference fit.Critical Distance Measurement of 1.1" Location of PTls outside of the geometry based repair boundary Figure 7-1: Illustration of the leak based criterion for HEJ sleeved tubes.7-12
Westinghouse non-Proprietary Class 3 other, locations and on characterizing deposits. No cracks were observed. ID surface deposits were thin at all HEJ locations. Circumferential and oblique angled ID surface scratches from the honing operation used yrior to HEJ installation were clearly present below the HR. Above the HR, similar scratches were observed, but they were frequently obscured by slightly thicker, but still thin deposits. The ID deyosits on the tubes in the HR region, including those below the HR region, had the typical appearance of ID surface deposits that were located immediately above the HEJ sleeve. In the case of tube R2C32, local areas with unusual whisker-like deposits were observed just below the fracture face at the top of the HRLT and also at HRUT (hard roll upper transition). At no local crevice location (HR or HE transitions) were thicker or diffexently colored deposits observed, such as those typically concentrated by boiling.
No corrosion degradation was observed on the OD of the sleeves from both tubes when visual (30X) and SEM examinations were conducted. In comparison, similar examinations conducted on recent Doel 4 HEJs, that had been repaired by laser welding following a cycle of operation, showed some IGA type corrosion in the sleeve and tube. The IGA grain boundaries had very thick oxide layers in both the sleeve and tube at the bottom of a local crevice region.
Following SEM examination (and EDS analysis of deposits which will be presented shortly), a narrow axial metallographic section was cut from each tube through the HEJ region, primarily to obtain microhaxdness measurements from selected locations. Table 5-4 presents this data.
The microhardness at the fracture face location (HRLT) was similar to or slightly higher than other HE and HR transition locations; however, the ID-most microhardness next to 'the fracture face of both tubes did include two of the three highest hardness values, when appropriately ignoring hardness values taken next to tensile shear surfaces. In addition, no cracks were observed by metallography at locations other than the fracture face location in the HRLT. After smaH ESCA-AES specimens were cut from just below the lower fracture face of tube R2C32, the remaining portions of the tubes from both HEJ specimens were deformed to open any ID origin cracks such that they could be readily observed by visual inspection (30X). The tube sections were cut axially into to two 180'ide halves. The halves were flattened to open axial cracks. None were observed at any of the hydraulically or hard roll expanded regions. The halves were then bent to open any ID surface cixcumferential cracks.
Again, none were observed at any of the hydraulically or hard roll expanded regions.
Finally, metallographic axial sections were made through the HRLT to the fracture face to characterize the 1GSCC that was present in the HRLT. The cracks observed were simple appearing, more similar to that expected from PWSCC than from secondary side corrosion where caustic environments are typically concentrated. From the metallographic and SEM surface examinations conducted on the HRLT corrosion, it was concluded that the only corrosion morphology was ID origin, circumferentiaHy oriented intergranular stress corxosion cracking. The cracks were simple in morphology with only minor D/W ratios measuxed.
(IGSCC morphology can be characterized by D/W ratios where the extent of IGA associated with a given crack is measured by the ratio of the crack depth, D, to the width, W, of the crack at its mid-depth. D/W ratios greater the 20 are defined as minor.)
DAPLANTSV.ERHEJEXAh(S.SEC                      5-4                                        09/2S/95


Westinghouse non-Proprietary Class 3 Displaced Tube End Leak Path Small Gap 0 mils gap 8mils gap 1 mil Hardroll and thermal expansion interference fit.Displacement Distance Expected Displacement Distance Assumed severing of the parent tube at the top of the hardroll lower transition.
Westinghouse non-Proprietary Class 3 The microstructures of the removed tubes varied. Tube R2C32 had a moderate to high number of carbides while tubes R2C54 and R2C61 had few carbides. For all three tubes, most carbides were distributed transgranularly rather than intergranularly, the preferxcd microstructure for PWSCC resistance. The grain size for tube R2C54 was ASTM 8.5, typical of Westinghouse tubing of similar vintage. The grain sizes for tubes R2C32 and R2C61 were somewhat smaller, approximately ASTM 10 and 9.5, respectively, Based on laboratory testing data, these microstructures may have relatively low resistance to PWSCC.
Figure 7-2: Leak path for a moved tube segment relative to the sleeve.7-13
5.6 Surface Chemistry ID and OD deposit      data were obtained from the two destructively examined specimens using energy dispersive spectrometry (EDS). In addition, ID and OD deposit/oxide film and fracture face oxide film data from the fracture face of tube R2C32 was obtained using ABS and ESCA techniques. The following observations are considered the more important from the data obtained. EDS data conducted on the ID surfaces of the both tubes in the HEI regions provided minimal information since the deposits were thin and most of the EDS signal came from the base metal/oxide layer beneath the deposits. Other than the base metal elements of Ni, Cr, Fe and Tl, the only elements detected were 0, Al, S, and Si. On the OD, where deposits were thick, the deposits were rich, in Fe and 0 with some observations of Ni, Cu and Zn. The pH of many ID and OD surfaces was determined using deionized water moistened wide-range pH paper. At all locations, the pH readings were neutral.
From the ESCA mid ABS data obtained on tube R2C32:
: 1)  high concentrations of B were observed on the    ID surface below  the fracture face below the HR region;
: 2)  Cr was not significantly enriched or depleted on either the crack fracture face in the ID surface below the fracture  face;
: 3)  low levels of Zn, Na, Mg, SI and      S were also detected in addition to the expected C, 0, Ni, Cr, and Fe.
Capillary electrophoresis and ion chromatography of water leached soluble ID deposits from a location just below the fracture face of tube R2C32 showed:
: 1)  soluble cations at the following concentrations Na (0.97 mg/1), Mg (0.25 mg/1),        K (0.21 mg/1), Ca (0.21 mg/1), and Li (0.10 mg/1);
2)
Ifit is assumed    that the sleeve-tube gap is locally t'4>0 soluble anions at the following concentrations SO4 (1.71 mg/1), Cl (0.28 mg/1),
and at least 7 other anions, including organic acid anions.
then the measured concentrations obtained from the 0.15 ml of water are a factor of 100 lower than the actual crevice solution concentrations. That would make the Li concentration in the ERLT crevice 10 mg/l, higher than found in non-concentrated primary water.
D:LPLANTSiAEP6iEJEXAMS.SEC                        5-5                                          09/25/95


Westinghouse non-Proprietary Class 3 100 SG"A" HE J Sleeved Tube Indications vs.Distance Below the Bottom of the Hardroll Upper Transition 100%90 80 70 6 60 50 O 40 8 30 20 EZ3SG"A" Indications
Westinghouse non-Proprietary Class 3 Capillary electrophoresis and ion chromatography of water leached soluble ID deposits were also obtained for the hardroll upper transition region. This supplemental leachate test was performed subsequent to an NRC/AEP/W meeting at One White Flint North on August 10, 1995. The leachate test for the hardroll upper transition was performed identically to the leachate test for the hardroll lower transition region. The results of the test indicated that the same soluble cations were detected as for the hardroll lower transition, except they were found in significantly lower concentrations. Potassium, however, was not detected in the hardroll upper transition.
-SG"A" Cumulative 90%80%70%80%60%40%30%20%O'a 0l4 O 8 O 10 10%CQ O CO O CO O CO O CO O lQ O 0 O.IQ O W W CC CC CQ Co W'ICI IQ IQ CO CO C C H Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-3 0%100 SG"B" HE J Sleeved Tube Indications vs.Distance Below the Bottom of the Hardroll Upper Transition 100%90 80 70 g 60 IH 50 O 40 8 30 20 CO O 0$C 60%40%e 30%5 8 20%EKI SG"B" Indications 90%SG"B" Cumulative 80%70%60%10 10%O CO O CO O CO, O CO O R O CC OC M Cc M M ID CA CD CO~W W Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-4 O CO C C I 0%7-14 Westinghouse non-Proyrietaxy Class 3 SGs"A" 8s"B" HE J Sleeved Tube Indications vs.Distance Below the Bottom of the Hardroll Upper Transition 130 i00%120 110 100 ce 90 O 80 70 60 g 50 40 30 20 10 K3 Both SG Indications
Crevice pH at operating temperature was estimated from the leachate solutions using EPRI's MULTEQ~ program. The results indicate that the operating temperature pH of the hardroll upper transition was 6.0 while the operating temperature pH of the hardroll lower transition was 8.3. For PWSCC, it is believed that a higher pH condition should be slightly more aggressive. However, in the pH range of interest (6 to 9) the impact of pH is considered to be negligible.
-Both SG Cumulative 95%Conf.on SLB Criterion.
5.7 Conclusions The tubes in the HRLT of all three HEJs had corrosion present. Metallographic and SEM fractographic data showed that the HRLT region of the tubes had circumferentially oriented ID origin IGSCC. The individual circumferential microcracks associated with the macrocracks were simple cracks, that lacked the complexity usually associated with secondary side corrosion. While many of the microcracks were connected by ligaments with only intergranular features, a large number of ligaments had ductile features present. The maximum depth of corrosion for the 360 long macrocracks was 92% for both tubes R2C32 and R2C54 (tube R2C61 was set aside as an archive specimen) with average depths of 61%
O lO O Q O 10 O lO O Q O lQ o~m c4 oi cQ co M~lo M co co H rk R rl A A A A A r<Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-5 O lO 00%80%ol O V0%60%c&#x17d;0 60%Q l4 40%o 30%8 20%l0%0%7-15 os12ass
and 60%, respectively. Dimensional data suggested that the tubes had experienced typical expansions radially. Two of the tubes (R2C54 and R2C61) did experience significant rolldown during the hardroll procedure, as the HRLT was 0.5" long. Microhardness traces conducted in the HEJ transition locations showed little variation in hardness and values that were similar to free span locations. One location with somewhat higher microhardness values was near the ID surface of the fracture faces of the two tubes and even there the increase was not great. The corrosion morphology observed was simple, typical of PWSCC environments rather than of secondary side crevice environments with a concentrated caustic environment.
The observed corrosion most likely resulted from an environment primarily derived from primary side water. The presence of Li and B on the tube ID surface below the HR region supports this hypothesis. The lack of significant Cr enrichment or depletion on ID surfaces below the HR and on the crack fracture face, and the relative balance of cations and anions indicate a somewhat neutral crevice environment. The fact that many cations and anions were found and that the estimated Li crevice concentration was higher than found in primary water also suggest that there was communication with the secondary side via a crack elsewhere in the tube. It is concluded that the observed corrosion could have been and probably was caused by a PWSCC type environment. The results of the chemistry evaluations of the ID surfaces for the hardroll lower and hardroll upper transition regions suggest the upper transition reqion was subjected to a slightly less aggressive solution than the hardroll lower transition, but it is not believed that this solution chemistry was the driving force for the DAPLANTS'NERHEJEXAMS.SEC                          5-6                                          l0/OS/95


Westinghouse non-Proprietary Class 3 S.O Repair Boundary for Parent Tube Indications 8.1 Compliance with draft RG I.121 Tube Integrity Criteria To remain consistent with the licensing basis addressing structural integrity, the repair boundary must be located such that the sleeved tube meets the structural integrity (burst)requirements of RG 1.121.Por the case of the repair boundary established in this document for a HEJ sleeved tube, an RCS release rate equal to those for a postulated tube burst is only possible if a circumferential separation of the parent tube occurs and is followed by upward motion of the separated end by a distance on the order of 3".Separation of the tube can only occur if the pressure end cap loads exceed the residual holding strength of the joint.Testing of prototype and field specimens has demonstrated that the residual strength of the separated joint is on the order of greater than 4000 lbs.The maximum load applied during normal operation of the most limiting plant is 724 lbs.Thus, a margin of safety relative to normal operation is on the order of 5.5 versus the RG 1.121 requirement of a margin of 3.The axial load applied during a postulated SLB is 1060 lbs.Thus, the margin of safety during postulated accident conditions is about 3.8 versus the RG 1.121 requirement of 1.43.In order for the tube to experience leak rates on the order of those associated with a steam generator tube rupture described in the PSAR, the parent tube must experience axial motion of-3" (for degradation in the HEX HRLT).At this point the tube and sleeve would no longer be in close proximity and an unrestrained leak path would be produced.Reactor coolant system leak rates approaching those assumed in the PSAR could be realized.The diameter restrictions of the sleeve itself will limit the flow through the sleeve to values less than assumed in the PSAR.The nominal tube ID flow area is approximately 36%greater than the flow area based on the sleeve ID.For tube axial displacements less than-3" and greater than-1.5", the primary to secondary leakage is restricted by the close proximity of the tube hardrolled region and the sleeve hydraulically expanded region.For this condition, leak rates would be expected to be on the order of one third to one half of the normal makeup capacity.For axial displacements of less than-1.5", intimate contact between the tube and sleeve is provided by the installed diameters in the rolled region.The attendant leak rate would be expected to be about an order of magnitude less than that for a displacement of 1.5" to 3".It must be stressed that the repair boundary of 1.1" below the bottom of the HRUT based on residual strength considerations would be expected to result in motion being precluded from occurring.
Westinghouse non-Pxoprietary Class 3 cracking. The driving force fox the cracking is believed to be attributed to a pure PWSCC effect, with the crevice chemistry representing a secondary effect.
Furthermore, the repair boundary of 1.1" below the bottom of the HRUT based on geometric constraint considerations results in there being a very low probability that such motions would occur in the unlikely event that the residual strength was not sufficient to preclude motion.HE/CRITR.SEC 8-1 09/2$/9$
Laboratory and field eddy current probe data correlated well with the corrosion that was destructively found. The + Point and CECCO probes produced very similar and accurate results. Even the RPC laboratory data showed the presence of the corrosion in the tubes despite the presence of the sleeve between the probe and the tube. The destructive examinations verified that there were no cracks in either tube at the HRUT or the HEUT.
Leak rate testing performed at elevated temperatures and pressures simulating normal operating and steam line break conditions pxoduced no leakage for the R2C54 specimen. The tensile separation loads for tubes R2C32 and R2C54 were 10,300 and 10,700 pounds, xespectively, and the sliding loads over the hard roll region started at 2800 and 4000 pounds, respectively. The tensile loads were well above any safety considerations.
DAPLANYSVLEPQiHEXAMS.SEC                       5-7                                          10/0$ /95


Westinghouse non-Proprietary Class 3 8.2.Offsite Dose Evaluation For a Postulated Main steam Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve As stated in Section 3.0, the postulated SLB event is the most limiting faulted condition with regard to offsite dose potential.
Table 5-1: Comparison of NDE Indications Observed at Kewaunee on SG Tubes at HEJ Locations Tube/            Pield Eddy Current                          Laboratory Eddy                    Visual/Dimensional                        Laboratory Location                                                              Current                                  Data                              X-Ray R2C32          + Point: 300-360'irc Ind in              + Point: 300-360'irc Ind in        HRLT starts 8.25" above bottom of       One to one and one-half semi-HRLT, probably throughwall.              HRLT, probably throughwall.         pulled piece or 11.25" above TTS:      continuous Circ networks of I Coil: (1994 data only)        -270'irc CECCO: 360'irc Iud in HRLT,        HRLT is 0.25" Iong; tube HR OD is       short Inds at top of HRLT, Ind.                                 probably throughwall.              0.907" & HRLT goes 0.009" lower        observed over at least 270',
Following the SLB any primary-to-secondary leakage is assumed to be entirely released to the environment.
RPC: >270'irc Ind at top of         (radially); all values include variable possibly 360'.
Equilibrium primary and secondary side activities are calculated based on the Technical Specification limit.NUREG-0800 is used to calculate the maximum allowable primary-to-secondarJJ leakage limit during the event such that offsite doses remain within the licensing basis.Similar calculations have shown that the accident initiated Iodine spiking case is usually limiting.Doses are limited to 10%of the 10 CFR 100 limit of 300 Rem thyroid dose.For example, the maximum faulted loop leakage for Point Beach Unit 2 is found to be 25 gpm in the faulted loop, assuming 150 gpd leakage in each steam generator prior to the event with a maximum RCS activity level of 1.0 micro Curies per gram dose equivalent Iodine-131.
HRLT.                               OD deposits.
For Cook Unit 1, the value has been determined to be 12.6 gpm, and was approved by the NRC as part of the Voltage Based Interim Tube Support Plate Plugging Criteria for Cook Unit 1.Each tube permitted to remain in service due to application of the criteria will be assumed to contribute to the total leakage.If the total projected leakage exceeds the calculated maximum permissible value, tubes will be repaired or removed from service so that the, projected SLB leakage value is reduced below the maximum permissible limit.As an alternative th tube repair, the RCS technical specification activity level can be reduced.For Point Beach Unit 2, lowering the allowable activity level to 0.25 micro Curies per gram dose equivalent Iodine-131 supports a maximum leakage value of approximately 100 gpm.8.3 Evaluation of Other Steam Loss Accidents The MSLB event outside of containment would be expected to represent the most severe static loading and dynamic response condition upon the steam generator.
R2C54          +  Point: 300-360'irc Ind in              + Point: 360'irc Ind in HRLT,       HRLT starts 6.8" above bottom of       Two to three semi~ontinuous HRLT, probably throughwall.              probably throughwall.               pulled piece or 9.85" above TTS:        Circ networks of short crack I Coil: No data.                         CECCO: 360'irc Ind in HRLT,         HRLT is 0.50" Iong; tube HR OD is      Inds in mid- to upper portion of probably throughwall.              0.903" 8c HRLT goes 0.012" lower        HRLT, observed over 360'.
No U.S.plant has ever experienced a double ended guillotine rupture of a main steam pipe.Plants have experienced however, random instances where a steam line relief valve or safety valve have stuck open.Of these two, the safety valve would have a greater dynamic response upon the system.This event, however, produces a limited response compared to the double ended SLB, and the plant response to this condition would be bounded by the SLB condition response.In addition to a postulated SLB event or a spurious opening of a safety valve, the following moderate frequency accidents:
RPC: >270'irc Ind in HRLT.          (radially); all values include variable OD deposits.
1)uncontrolled rod withdrawal from full power, 2)loss of reactor coolant fiow, 3)loss of load, and HEJCRITR.SEC 8-2
R2C61          + Point: 300-360'irc Ind in              + Point: 360'irc  Ind in HRLT,    HRLT starts 6.7" above bottom of       One semiwontinuous Circ net-HRLT, probably throughwall.               probably throughwall, and small Ind pulled piece or 9.7" above TTS:        work of short crack Inds in mid-I Coil: 1994 data only,                   at HELT.                            HRLT is 0.50" long; tube HR OD is      portion of HRLT, observed over CECCO: 360'irc Ind in HRLT,
                                          >270'irc indication.                                                              0.905" & HRLT goes 0.009" lower        360', but less continuously than probably throughwall. and small Ind (radially); all values include variable for R2C32 Inds.
at HELT                            OD deposits.
RPC: >270'irc Ind in HRLT.
Legend    of Abbreviations HR    = HardroH                                          HELT    = HE lower transition      RPC    =  Rotating pancake coil      Ind  = Indication HE    = Hydraulic expansion                              HRLT    = HR lower transition      TTS    =  Top of tubesheet            Circ  = Circumferential D:LPLANTStA EPONA EP-EXAM.SEC                                                                                                                                         0912$ I95


Westinghouse non-Proprietary Class 3 4)loss of normal feedwater would result in higher than normal primary to secondary ressure diff steam generator tubes.All o secondary pressure differentials across the or es.of these events are rapidly occurrin tran'losure of the steam line isolation v urring transients and lead to rapid e iso ation valves and to a relatively rapid decrease of tube with PTIs a event presents the most severe loading to an HEI sleeved 8.4 HEJ Inspection Requirements A review of the curre current inspectMn criteria suggests that the HBJ parent tube be in the sleeve/tube joint.As a minimum'su stanti axial and/or circumfe mferential PTls in the region of detecting 40%to 60%deep EDM axial e jomt.a minimum, the probes used should demonstrate th ns e e capability of and circumferential notches.To assist in establishin a data b g ase for continued evaluation, indications left in th.air criteria should be inspected at the sub spec e subsequent refueling outage.e w be consistent from inspection to in locating parent tube di'pec o inspectMn the convention of t n e m cations relative to the bottom of the HR the location of the PTIs.o e HRUT should be used defining HPJCRITR.SEC 8-3 Westinghouse non-Proprietary Class 3!9.0 Summary of Sleeve Degradation Limit Acceptance Criteria 9.1 Structural Considerations Based upon the information previously identified in this report, the foHowing structural considerations are considered to be validated:
Table 5-2: Tensile Data for Kewaunee SG Tube Sections Kewaunee Pxee Span Tensile Data Yield Strength              Ultimate Tensile Strength        Elongation Tube (psi)                           (psi)                    (%)
9.1.1 Crack Indications Below the Upper HardroH Lower Transition Any crack indication, either circumferential or axial, is allowed to remain in service if the elevation of the uppermost portion of the crack is located below 1.1" below the bottom of the KRUT.9.1.2 Sleeved Tube with Degradation Indications with Non-Dented Tube Support Plate Intersections For indications in the upper hardroH lower transition, circumferential crack extent is limited to 179't BOC.A 179'OC throughwaH crack is considered representative of a 224 EOC crack.The measured RPC angle should be assumed throughwaH over its entire indicated length.Circumferential indications to which this angle limit applies are limited to the lower transition region only, and do not apply to indications in the hardroH flat area or higher.Any circumferential crack indication existing above the lower transition with a depth estimate of 40%or greater will be removed from service or repaired, consistent with current criteria.Axial cracks are permitted to remain in service if the uppermost part of the crack is located no less than 1/2 inch below the bottom of the upper hardroH transition.
R2C32                            72,200                          123,300                    22.0 R2C54                            58,600                          106,700                    24.5 R2C61                            55,400                          104,000                    23.1 Control (NX8161)                        52,300                          101,500                  18.5  "
Any axially oriented crack existing less than 1/2 inch below the bottom of the upper hardroH transition will be removed from service or repaired, consistent with current criteria.9.1.3 Dented Tubes The HEI repair boundary identified in this report does not rely on the resistive effects of dented tube support plate intersections to react any portion of the tube end cap load.9.2 Leakage Assessment For PTIs located below the HRLT, SLB leakage would be expected to be negligible and can be excluded from SLB leak rate calculations.
* Broke outside of the   gage length, probably reducing the elongation value.
For circumferential indications below 1.1" HEJCRITR.SEC 9-1
Kewaunee HEJ Tensile Data Sliding Load over Practure Load HEJ Specimen                                                    Practure Location            HR Region (Ibs)
(lbs)
R2C32                            10,300                      Top of HRLT          2800 decreasing to 50 R2C54                            10,700                    Middle of HRLT       4000 decreasing to 200 R2C61                        NA (Archive)                    NA (Archive)            NA (Archive)
DAPLANTSVLBPlABP-BXAM.SBC                                      5-9                                                     09/25/95


Westinghouse non-Proprietary Class 3below the bottom of the HRUT, but within the HRLT, SLB leakage would be expected to be limited to-0.02 gpm per indication.
Table 5-3: Kewaunee SG Tube Macrocrack Profiles for Tensile Fracture of HEJs Length vs. Depth and Ductile Ligament Width Tube, Location          Ductile Ligament Location                                              Comments (in.)
9.3 Defense In Depth and Primary to Secondary Leakage Limits The repair boundary identified in this report results in margins which significantly exceed the burst criteria of RG 1.121 and leakage requirements relating to offsite dose evaluation.
(degrees / % throughwall)
The Technical Specification normal operating primary-to-secondary leak rate limit will be lowered to 150 gpd per SG (0.1 gpm).The leak rate used in the evaluation for each plant will be selected to represent the expected leakage from an HEI which has experienced a complete circumferential separation at the elevation of the repair boundary.This level of leakage is readily detectable by plant leakage detection systems.The available axial translation limits of the tube and the relation of these limits to leakage limits are also addressed.
R2C32, HRLT        00/52                                                              Twenty-one ligaments were Ligament 2 1          L21 = 0.004" wide 22/77                                                              observed on the circumferential (32/92)    ~ Maximum depth                                        macrocrack located at the top of Ligament 20          L20 = 0.006" wide              the HRLT. All intergranular 45/88 Ligament 19          L19 = 0.011" wide              corrosion was of ID origin.
Section 7.0 of this report has demonstrated that the maximum amount of axial motion that a postulated circumferentially separated tube could be expected to experience is 1.1".Based on the distribution of indication elevations observed at Kewaunee, a postulated movement of 1.1" would still result in a length of intimate tube/sleeve contact.If the tube were postulated to move an amount on the order of, say, 2", the maximum primary to secondary leakage would be limited to about 30 gpm at SLB pressure differentials, being limited by the thin gap created between the tube ID in the hardroll region and the sleeve OD in the hydraulically expanded region.This would be an extremely unlikely event since the sleeve/tube joint would have to have insufficient residual strength and the tube would have had to have been installed at a lower extreme deviation from its nominal U-bend elevation at the same time as its outboard neighbor having been installed at an upper extreme deviation from it nominal U-bend elevation.
58/85 LIgament 18          L18 = 0.003" wide 9 p/8 8 112/88 Ligaments 16  & 17    L16, L17 = 0.006", 0.011" wide
Such a situation would not be likely to have been overlooked during fabrication, and could be expected to have resulted in contact of the tubes in the V-bend, which would have been detected during the NDE of the tubes during prior inspection outages.I"inally, the prototype testing program demonstrated that the axial friction force between the postulated separated tube and sleeve increases as the amount of slippage increases further reducing the likelihood of a tube/sleeve separation.
                                ~ Ligament  15          L15 = 0.008" wide 35/8 158/82
HEJCRITR.SEC 9-2
                                - Ligament  14          L14 = 0.004" wide
                                ~ Ligaments  12 & 13    L12, L13 = 0.002", 0.003" wide 80/64 Ligament 11          L11 = 0.039" wide 202/76 Ligament 10          L10 = 0.027" wide 225/60
                                ~  Ligament 9            L9 = 0.014" wide 248/52 27p/p8 Ligament 6, 7,  &8    L6, L7, L8 = 0.002", 0.006",
0.012" wide 292/05 3 1 5/46 Ligament 4 & 5        L4, L5 = 0.015", 0.022" wide 338/ 9 Ligament 1, 2, & 3    Ll, L2, L3 = 0.015", 0.005",
0.012" wide (Average macrocrack depth =
61% over 360", maximum depth
                      = 92%)
DAPLANYSVLEPQEP-EXAM.SEC                                       5-10                                                    09/25/95


Westinghouse non-Proprietary Class 3 10.0, Refer eaces 1.WCAP-9960 (Proprietary),"Point Beach Steam Generator Sleeving Report," Westing-house Electric Corporation (1981).2.WCAP-9960 (Proprietary), Revision 1,"Point Beach Steam Generator Sleeving Report," Westinghouse Electric Corporation (1982).3.WCAP-11573 (Proprietary),"Point Beach Unit 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).WCAP-11643 (Proprietary),"Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).5.WCAP-11643 (Proprietary), Revision 1,"Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation, November 1988.6.WCAP-11669 (Proprietary),"Zion Units 1 and 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).7.I WCAP-12623 (Proprietary),"American Electric Power D.C.Cook Unit 1 Steam Generator Sleeving Report (NIechanical Sleeves)," Westinghouse Electric Corporation (1990).WCAP-14157 (Pxoprietary),"Technical Evaluation of Hybrid Expansion Joint (HH)Sleeved Tubes With Indications Within the Upper Joint Zone," Westinghouse Electric Corporation, August, 1994.9." WCAP-14157, Addendum (Proprietary),"Supplemental Leak and Tensile Test Results for Degraded HEJ Sleeved Tubes in Model 44I51 SIG's," Westinghouse Electric Corpora-tion, Septembex, 1994.10.Regulatory Guide 1.121,"Bases For Plugging Degraded PWR Steam Generator Tubes," United States Nuclear Regulatory Commission, Issued for Comment (1976).VPNPD-94-096 I NRC-94-068 (Proprietary),"Dockets 50-266 and 50-301, Response to Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 13, 1994.10-1 09/25/9S ii Westinghouse non-Proprietary Class 3 12.NPD-94-101
Table 5-3 (Cont.): Kewaunee SG Tube Macrocrack ProCiles for Tensile Fracture of HEJs Length vs. Depth and Ductile Ligament Width Tube, Location            Ductile Ligament Location                                                Comments (in.)
/NRC-94-069 (Proprietaxy),"Dockets 50-266 and 50-301, Response to.Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 22, 1994.13.USNRC SER,"Safety Evaluation by the Office of Nuclear Reactor Regulation RElated to Amendment Request CR-175 to Facility Operating Licenses DPR-24 and DPR-27, Wisconsin Electric Power Company Point Beach Nuclear Plant, Units 1 and 2, Dockets 50-266 and 50-301," United States Nuclear Regulatory Commission, January 11, 1995.14.Wisconsin Public Service and Wisconsin Electric Power meeting with the United States Nuclear Regulatory Commission, discussion of the Point Beach SER and the responses to the RAIs, February 1, 1995.15.Wisconsin Public Service meeting with the United States Nuclear Regulatory Commission, discussion of inspection results of Kewaunee SG tubes, April 13, 1995.16.Hexnalsteen, P.,"Belgian Experience with Cixcumferential Cracking, Part 1: Genexal Overview," EPRI Workshop on Circumferential Cracking, Charlotte, North Carolina, June, 1995.17.WCAP-10949 (Proprietaxy),"Tubesheet Region Plugging Criteria for Full Depth HardroH Expanded Tubes," Westinghouse Electric Corporation (1985).18.WCAP-12244, Revision 3 (Proprietary),"Steam Generator Tube Plug Integrity Summary Report," Westinghouse Electric Corporation (November, 1998).19.Ducrile Fracture Handbook, Electric Power Research Institute, Palo Alto, California (October, 1990).20.Flesch, B, et al.,"Operating Stress and Stress Corrosion Cracking in Steam Generator Transition Zones (900-MWe PWR)," International Journal of Pressure Vessels and Piping, Vol.56, pp.213-228 (1993).21..Bandy, R., and Van Rooyen, D.,"Stress Corrosion Cracking of Inconel Alloy 600 in High Temperature Water-An Update," Corrosion, Vol.40, No.8, pp.425-430 (August, 1984).Yonezawa, T., et al.,"Effects of Metallurgical Factors on Stxess Corrosion Cracking of&#xb9;AHoys in High Temperature Water," Proceedings of the 1988 JAIF International Conference on Water Chemistry in Nuclear Power Plants, Tokyo (April, 1988).HEJREFS.SEC 10-2 Westinghouse non-Pxoprietaxy Class 3 23.Theus, G.J.,"Summary of the Babcock and Wilcox Company's Stress Coxmsion~~~~Cracking Tests of Alloy 600," EPRI WS-80-0136, EPRI Workshop on Cracking of Alloy 600 U-Bend Tubes in Steam Generators, Denver, Colorado (1980).24.Kim, V.C., and Van Rooyen, D.,"Strain Rate and Temperature Effect on the Stxess Corrosion Cracking of Inconel 600 Steam Generator Tubing in Primary Water Condi-tions," Proceedings of the Second International Symposium on Environmental Degrada-tion of Materials in Nuclear Power Systems-Water Reactors, Monterey, California, pp.448-455 (September, 1985).25.Personal communication, Darol Haxxison of Entergy to Bob Keating of Westinghouse (September 15, 1994).26.WCAP-12076 (Proprietaxy),"St.Lucie Unit 1 Steam Generator Sleeving Report (Me-chanical Sleeves)," Westinghouse Electric Corporation (November, 1988).27.NUREG/CR-3464,"The Application of Fxacture Proof Design Methods Using Tearing Instability Theory to Nuclear Piping Postulating Through Wall Cracks," United States Nuclear Regulatory Commission (September, 1983).~~~~~~~~~~~28.NUREG/CR-0838,"Stability Analysis of Circumferential Cracks in Reactor Pi)ing Systems," United States Nuclear Regulatory Commission (Febxuaxy, 1979).29.Tada, H., and Paris, P.C.,"The Stress Analysis of Cracks Handbook," Second Edition, Paris Productions Incorporated, St.Louis, Missouri (1985).30.WPS-94-587 (NTD-NSRLA-OPL-94-297),"Wisconsin Public Service Corporation, Kewaunee Nuclear Power Plant, Allowable Primary/Secondary Leak Rate During Steam Line Break for Kewaunee," Westinghouse Electric Corporation, September 30, 1994.HEJREFS.SEC 10-3 Westinghouse non-Proprietary Class 3 Appendix A Review of Prior Amendment Requests for HEJ Sleeved Tubes 1.0 Discussion/Chronology of Prior Amendment Requests When HEJ sleeved tube PTIs were first detected at Kewaunee in the Spring of 1994, analyses and tests were performed to characterize the effect of the degradation on the strength of the joint.Since no tubes had been removed for destructive examination, it was assumed that the degradation was in the form of circumferential cracking.A meeting was held with the NRC on April 19, 1994, during the inspection outage, to discuss the non-destructive examination techniques, the results of the non-destructive examinations, the results of structural analyses and tests performed on HEJs with simulated circumferential degradation below the hardroll in the parent tube, and to propose and amendment request to allow selected HEJ sleeved tubes to remain in service.It was demonstrated HEJs with circumferential cracks below the HRLT of any extent, i.e., up to 360, met the structural xcquirements of draft RG 1.121, i.e., a margin of 3 relative to burst during normal operation and a margin of 1.43 relative to burst during a postulated SLB.Leak testing results were presented that indicated that a leak rate of<1 gpm would be expected during a postulated SLB from all of the tubes with indications if they were allowed to remain in service.Thus, it was proposed that any indications below the HRLT be allowed to remain in service.Based on a structural analysis of circumferential cracks at the top of the HRLT, it was also recommended that tubes with projected crack lengths (240 at the end of the next cycle be allowed to remain in service.The NRC advised Wisconsin Public Service on April 20, 1994 that insufficient time was available to properly review the request for an amendment to the operating license.Therefore, the amendment request was not submitted to the NRC for approvaL In August, 1994, in preparation for a Fall outage, the Wisconsin Electric Power Company submitted an amendment request to the NRC to allow HEJ sleeved tubes to remain in service with PIIs below the hardroll.References 8 and 9 were included with that submittal in support of the request for an operating license amendment to allow selected HEJ sleeved tubes with PTIs to remain in service at Point Beach Unit 2.The technical bases of the submittal were similar to those developed for Kewaunee, i.e., RG 1.121 criteria would be met for any indications below the bottom of the HRLT, as would HEJs with indications with projected lengths of less than 226'n the HRLT.To support the angular extent criteria, additional existing data relative to the growth of crack in tubes were collated;these indicated that crack growth rates of 45 per cycle in the circumferential direction and 20%of the tube wall thickness per cycle in the radial direction could be considered as bounding.A series of re-quests for additional information (RAIs)were issued by the NRC which were responded to via References 11 and 12.The license amendment request was denied based on the conclusion documented in the safety evaluation report (SER), Reference 13, prepared by the office of Nuclear Reactor Regulation of the NRC.DAPLANISVLEPiHEJPNDXA.SEC A-1 09/2$/9S
(degrees / % throughwall)
R2C54, HRLT        00/04 22/67
                                - Ligament    17 & 18    L17, L18 = 0.015", 0.005" wide Nineteen ductile ligaments were observed on the circum-Ligaments  I4, I5, I 6 L14, L15, L16 = 0.003", 0.008",
45 75                                                              ferential macrocrack located in 0.007" wide 68/84                                                              the middle of the HRLT. All (80/92)  ~ Maximum depth                                          intergranular corrosion was of Ligament I3            L13 = 0.017" wide              ID origin.
9p/78 112/82 135/72 Ligament I2            L12 = 0.009" wide I5 8/74 80/74 Ligaments I 0 & I I    LIO, LII = 0.017", 0.005" wide 202/56 Ligament 9            L9 = 0.011" wide Ligament 8             L8 = 0.050" wide 225/16 248/48
                                - Ligament 7            L7 = 0.002" wide Ligament 5 & 6        LS, L6 = 0.009", 0.007" wide 27p/64 292/78 315/70                              L2, L3, L4 = 0.008", 0.013",
338/22 Ligament 2, 3, &4    0.013" wide
                                ~ Ligament I & 19         LI, L19 = 0.013", 0.044" wide (Average macrocrack depth    =  60%
over 360'; maximum depth    =
92%)
DAPLANTSlABPLAEP-BXAM,SEC                                     5-11                                                    09/25/95


Westinghouse non-Pxoprietaxy Class 3 A mepting with the NRC, initiated by W'isconsin Public Service (WPS, Kewaunee), Reference 14, was held on February 1, 1995, to verify a mutual understanding of the concerns expressed in the SER, and to discuss each of the Wisconsin Electric Power Company (WEP, Point Beach)responses to the RAIs.The conclusions reached at that meeting relative to unresolved NRC concerns were: 1.that the database employed for the potential growth calculations was insufficient for estimating the incubation time and growth rate of parent tube flaws (PTIs), 2.that the qualifications of the NDE probes used for the inspection of the parent tubes did not include a sufficient number of cracked tube specimens as opposed to the use of machined flaws in ASME NDE standards to calibrate the probes, 3.that the level of detection and the accuracy of sizing PTIs in the uppex transitions of the HEJs might not be sufficient to support the application of the criteria, and, 4.that the appearance of PTIs at the lower transition(s) is indicative of a tube that is prone to developing PIIs at the upper transitions.
Table 5-4: Microhardness Measurements (VHN, 500 gm load) on Kewaunee HEJ Sleeved Tubes Tube/Location                                      Microhardness at Specified Depth from Tube ID Surface 0.001"                0.006"            0.016"            0.026"          0.036"            0.046"
Thus, taken as a whole, the NRC was concerned that undetected PTIs at the upper transitions of tubes with PTls in the lower transition(s) could grow during the operating cycle to the extent that the structural integrity of the tube would be less than that required by the RG 1.121 at the end of the operating cycle.Another meeting between WPS and the NRC, Reference 15, was held on April 13, 1995, during the inspection outage at Kewaunee, to discuss PTIs detected using a+Point eddy current inspection probe (the previous inspection of the parent tubes was conducted using a Zetec I-coil eddy current inspection probe).Information was presented that the probe had been qualified to EPRI guidelines using both ASME standards and cracked HEJ sleeved tube specimens which had been fabricated by Westinghouse.
                                                                    ~                ~
Summaxy information was also presented to show that of over 930 total PIIs found at three plants, there were no instances of the simultaneous appearance of PTls at the lower and upper transitions.
R2C32, HELT              196              193                183              181              191 HRLT                      209                                  204 196'09'o
It was thus argued that PTIs in the lower transitions should not be cause to remove the sleeved tube from service.However, since much of this information was developed during the outage, there was insuffi-cient time for the NRC to conduct a thorough review of the information and tubes with PTIs within the HEJ region were removed from service.2.0 Summary of Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the tube indications on the operating performance of HEJs with PTls, test and analysis programs were performed, References 8 and 9, aimed at: 1)characterizing the effect of the obsexved indications on the axial strength of the joint, and DAPLANTSM,EPQKJPNDXA.SEC A-2 09/25/9$
                                                '09 193            204 HRLT next to FF          238 (IGSCC)       228 (IGSCC)         218 (IGSCC)       252 (shear)     268 (shear)           data, necked HR                        215              212                204              204            209          218 HRUT                     186              193                186              186              191        198 HEUT                      193              196                188              188              196        198 FS 4" above HEJ           198              1864                1794              1814            1864        188 R2C54, HELT              193              196                181              174            181          188 HRLT                      196              196                181              172              183        188 HRLT                     231 (IGSCC)       215 (IGSCC)         215 (IGSCC)       221 (shear)     234 (shear) no data, necked HR                      241                228                221              212            215 HRUT                    212                204                193              191            193          206~
Westinghouse non-Proprietary Class 3 2)estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach tubes (no indications have been determined to be present in the Cook 1 tubes at present)was explored via axial tensile (pull out)testing and hydraulic proof testing.Additional analyses results were reported in References 11 and 12.A summary of the test and analysis programs is provided in the following sections.The results are applicable to the four U.S.plants with installed HEJs.Plant operating parameters relative to structural integrity evaluations are presented in Table A-1.The largest operating primary-to-secondary differential pressure (1535 psi)occurs in the SGs at Kewaunee.The smallest differential pressure (1225 psi)occurs at Point Beach 2.The differential pressure at Cook 1 is 1453 psi.2.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9).Prototypic HEJ test specimens, see Figure A-l, were fabricated using Alloy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were performed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations.
HEUT                      176              186                176              181            183          176 s FS 4" above HEJ          176              174                172              156            166          174 Notes:  1. Located    0.002"  closer to the ID surface than indicated
For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e.,-1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 1.121 3'nd cap loading.For specimens where the tubes were completely removed by machining at the elevation corresponding to the approximate mid-span of the hydraulically expanded region, i.e.,-2.25" the bottom of the HRUT, the structural capability of the joints were-3.5 to 4 times the most limiting RG 1.121 361?end cap load.A second series of tests were conducted for HEJ sleeved tubes with simulated throughwall circumferential PTls of less than 360'rc.The results from these tests were documented in Reference 8.In these tests, the sleeves were installed in tube samples using prototypic techniques.
: 2. Located    0.007" closer to the ID surface than indicated
The tubes were first slit 100%throughwall over varying arc lengths from 120'o 240 at axial locations as near to the top of the HRLT as practical.
: 3. Located    0.002" farther from the ID surface than indicated 4, Located    0.005"  farther from the ID surface than indicated
The structurally prototyp-ic specimens were installed in a tensile testing machine and axially loaded to failure at a temperature of 600'F with no internal pressure.The specimens were configured such that the tube end was attached to the movable crosshead of the machine and the sleeve end was attached to the stationary base.Upon loading, the bending moment caused by the centroid of the remaining ligament being non-coincident with the axis of the tube, the loading axis, caused a smaH lateral deflection of the tube and sleeve in the direction of the slit.This small deflecting resulted in additional locking of the tube to the sleeve such that, in most cases, even The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign)was similar to that of Alloy 690 sleeves.DAPLANTSU.BF6KJPNDXA.SEC A-3 10/03/9S i
: 5. Located    0.005"  closer to the ID surface than indicated
Westinghouse non-Proprietary Class 3 with a 240'hroughwall slit, the sleeve failed in tension at about ten times the normal operation end cap load.For the specimens that did fail in the tube ligament, the failure loads were approximately twice the ultimate tensile capacity of the ligament material.Thus, the additional friction force developed at the hardroll interface of the sleeve and the tube exceeded the most limiting RG 1.121 requirement.
: 6. Located    0.004"  closer to the ID surface than indicated D LPLANTSLABPUNP-BXAhf.SBC                                          5-   12                                                        09/2$ /9$
In summary, an HEJ sleeved tube with a PTI with a non-symmetric remaining ligament(s) of about 90'as a structural integrity in excess of the most limiting RG 1.121 requirements.
The structural proof tests were performed on specimens which had been fabricated for leak testing.Following the leak tests, the sleeved tubes were machined to simulate a 360'ircumferential throughwall crack at the inflection point of the hard roll.All of the samples were then pressurized to a differential pressure of 3657 psi.The pressure was then gradually increased until slipping of the joint was noted.Initial slippage of the tubes was generally detected after an increase in the pressure of about 200 to 700 psi.The maximum pressures, i.e., those achieved when the tube was ejected ftom the sleeve, were not recorded, but did ap-proach pressures on the order of three time normal operating pressure differentials.
2.2 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2.The purpose of the analyses was to support the application of an ARC which included consider-ation of PTls located at the top of the HBLT.Such indications axe not a subject of'this report.The criterion supported by this report is that all PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent.It is worth noting that the analyses demonstrated that tubes with LTL material properties would meet the RG 1.121 3iQ?structural requirement if they were cracked 224 throughwall.
The acceptable throughwall angle is reduced to 196 if the remaining ligament is also assumed to be cracked 50%throughwall from the ID of the tube.The model employed assumed that no friction force, e.g., due to magnetite packing or corrosion product buildup within the tube-to-tube support plate crevices, would add to the resistance to axial motion of the tube or to reduce the applied load transmitted to the tube-to-sleeve joint.Reference 11 noted that in addition to a postulated SLB event or spurious opening of a safety valve, the following moderate frequency accidents:
1)uncontrolled rod withdrawal from full power, 2)loss of reactor coolant fiow, 3)loss of load, and 4)loss of normal feedwater would result in higher than normal primary to secondary pressure differentials across the steam generator tubes.The maximum pressure differential across the tubes that may be DAP~MEPQKJPNDXA.SEC A-4 10/03/95 Westinghouse non-Proprietary Class 3 experienced for steam generator loss of secondary side pressure events is 2560 psid.For items 1)through 4), the maximum pressure differential across the tubes would be expected to be less than 1800 psid.All of these events lead to closure of the steam line isolation valves and to a relatively rapid decrease of the differential pressure.Thus, the postulated SLB event presents the most severe loading to an HEJ sleeved tube with PTIs.2.3 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the midpoint and that the bottom of the HRLT.The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions.
The specimens with the tube removed at the midpoint of the HRLT'xhibited a maximum leak rate of 0.016 gpm at SLB conditions, thus, also demonstrating a significant resistance to primary-to-secondary leakage.These tests suggest that the presence of a"lip" of tube material below the top of the HRLT provides sufficient leakage restriction.
The proposed amendment would establish that any indications of tube degradation greater than 1.1" below the bottom of the HRUT would be acceptable for continued service, providing a"lip" of approximately 0.1", and would also provide the geometric configuration such that neither significant tube axial displacement nor significant tube leakage would be expected during a postulated SLB event.Leak rate tests were also conducted using HEJ sleeved tube specimens with throughwall slits extending about 240 around the circumference of the tube.The slits were located at the top of the HRLT, i.e., approximately 1.0 to 1.03" below the bottom of the HRUT.The maximum leak rate at 600 F was found to be 0.015 gpm at a differential pressure of 2450 psi.Based on the observation that one of the specimens may have exhibited leakage from one of the test fittings, a bounding SLB leak rate of 0.033 gpm per indication was established for 240 throughwall slits in the hardroH lower transition.
References 8 and 9 also documented the xesults of elevated temperature leak tests that were performed using specimens fabricated by sectioning and removing the tube section at the top of the HRLT.Since the acceptance of PTIs at the top of the HRLT is not a subject of this report, the results are not applicable and no discussion is necessary.
2.4 Crack Growth Rate Evaluations An assessment of the potential growth of the PIXs in both the circumferential and radial directions was provided in References 8, 11, and 12.The distribution of PTIs initially reported at Kewaunee was analyzed to determine if there was any apparent difference between the SGs.The average, miiiiinum, and maximum circumferential extents were similar, as were the standard deviations, and it was concluded that the distributions in each SG represented samples from the same parent population.
Since the phenomena had not been previously Approximately 1.12 to 1.13 inch below the bottom of the HRUT.DAPLANTSVEEPQKJPNDXA.SEC A-5 Westinghouse non-Proprietary Class 3 reposed, there was no historical database that could be used to estimate growth rates.For growth in the circumferential direction, an assumption was made regarding initiation and the average growth rate was estimated to be-35 per year.For analysis purposes, a rate of 45 per year was assumed.This was noted to be greater than a 95%confidence bound for ODSCC for observed growth at another plant that was operating at 614 F.In addition, the published data on crack growth rates of Alloy 600, of References 21, 22, 23 and 24, and Belgian data, were quoted to support the rate assumed of 45'er year as being conservatively bounding.It was also noted that the estimated rate was about three standard deviations above the mean of observed TI'S data.There also was, and still is, no directly measured data for the radial growth rate of circum-ferential PTIs in HEI sleeved tubes.Reference 12 presented information radial growth information for tubes based on field observations at McGuire, Doel 4, Arkansas Nuclear One, and Maine Yankee in support of a bounding rate of 21%per year in 7/8" nominal diameter tubes.Information from PWSCC of mechanical plugs was evaluated which indicated radial growth rates on the order of-17%to-23%per year in 7/8" diameter tubes depending on the material activation energy.Using the tube developed rate, it was concluded that 360 PTIs with depths of 53%(Kewaunee) to 58%(Point Beach 2)at the BOC would not exceed the RG 1.121 32ZNO, structural limit at the end of a one year cycle.Using the mechanical plug growth rates, 360'TIs with depths of 51%(Kewaunee) to 56%(Point Beach 2)would not be expected to exceed the RG 1.121 limits at EOC.Although it has been demonstrated by field experience that the occurrence of a PTl at the HRLT or HELT does not imply the presence of another PTI at either the HRUT or the HEUT, undetected PTIs at such'ocations would not be likely to violate the RG 1.121 requirements at the EOC.3.0 Summary Prior submittals for license amendments requested approval for the implementation of multiple criteria to deal with the occurrence of PTls as a function of the location of the PIIs in the HEJ.These are summarized in the following paragraphs.
1.For indications below the bottom of the HRLT, it was demonstrated that PTls of any extent did not result in degradation of the joint such that the requirements of RG 1~121 would not be met at the end of an, or any, operating cycle.This was also demonstrated for indication up to the middle of the HRLT.It was further demon-strated by test that the total leak rate from all such indications would not lead to a violation of the radiological release limits during a postulated SLB event.2.For indications at the top of the HRLT it was demonstrated that indications on the order of 2/3 of the circumference of the tube, with the remaining ligament degraded to the detection level of the NDE, could be tolerated without exceeding the require-ments of RG 1.121 at the end of the operating cycle.The acceptance criteria for the beginning of the cycle length and depth of such indications were based on assumed conservative growth rates in the circumferential and radial directions.
It was demon-strated by test and analysis that a significant number of throughwall PTIs could be DAPLANTSQ.EPQiE/PNDXA.SEC A-6 10/03/9S


Westinghouse non-Proprietary Class 3 allowed to remain in service without expecting leak rate limits to be exceeded.The information presented in the main section of this report resulting from the destructive examination of the Kewaunee tubes continues to support the application of a criterion based on item 1.The results from the destructive examination of the Kewaunee tubes do not support the implementation of criteria based on item 2, even though the indications were not thxough wall and had a residual strength in excess of RG 1.121 requirements.
Location of Cracks in HHJ Sleeved Tubes Removed from Kewaunee No cracks found or detected on any of the tube specimens removed from Kewaunee Significant Nominal                        Hardroll Hardroll                      Rolldown Transition Circumferential cracking found                                      Circumferential near/at the top                                      cracking found of the transition                                    near the center of the hardroll (Also typical of laboratoty specimens)
Since the indications extended 360'round the tube, effective circumferential growth rates of at least 50'er year were experienced as a result of the presence multiple initiation sites.However, the informa-tion obtained does not contradict the radial growth rate developed in support of item 2.Finally, the information obtained does support the detection thresholds previously considered for both the+Point and CECCO 3 probes.D LPLANTSQ.EPQKlPNDXA.SEC A-7
No cracks found in either of the two destructively examined tube specimens from Kewaunee Figure 5-1 D LPLANYSULEPQKJEXAMS.SEC             5-13                                    09/2$ /95


Westinghouse non-Proprietaxy Class 3 Table A-1: Operating Parameters for V.S.Plants with Installed HEJs Plant SG Loops PP (psia)Ps (psia)(psi)Thot ('6 Tcotd ('8 Point Beach 2 44 2000 775 1225 596.7 541.7 Cook 1 Kewaunee Zion 1 51 51 51 2100 2250 2250 715 725 1453 1535 1525 582.0 518.0 591.2 531.8 592.2 532.2 DM'LANYSlAEPalEJPNDXA.SEC A-8
Westinghouse non-Proprietary Class 3 6.0 Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the  tube indications on the operating performance of HEJs with PTIs, test and analysis programs were performed, References 8 and 9, aimed at:
: 1)  characterizing the effect of the observed PTIs on  the axial stxength of the joint, and
: 2)  estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.
Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach 2 tubes (no indications have been determined to be present in the Cook 1 tubes at present) was explored via axial tensile testing and hydraulic proof testing. Additional analyses results were reported in References 11 and 12. A summary of the test and analysis pxograms is provided in the following sections. The results are applicable to the four U.S. plants with installed HEJs. Plant operating parameters relative to suxuctural integrity evaluations are presented in Table 6-1. The largest operating primaxy-to-secondary differential pressure, 1535 psi, occurs in the SGs at Kewaunee, although Cook 1 is approved to operate up to 1600 psi. The smallest differential pressure, 1225 psi, occurs at Point Beach 2. The current differential pressure at Cook 1 is 1453 psi. The axial end cap loads during normal operation, and the RG 1.121        3~  loads, are summarized in Table 6-2.
The maximum 3d P load is 2172 lbs (could be as high as 2264 lbs) and the minimum is 1734 lb,. Since each of the plants have 7/8" nominal diameter tubes with 0.050" thickness, the end cap load during a postulated SLB event is 1516 lbs regardless of the plant. Thus, the        3~    end cap load governs the analysis.
6.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9). Prototypic HEJ test specimens, see Figure 6-1, were fabricated using AOoy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were perfoxmed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations. For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e., 1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 3M end cap loading. For specimens where the tubes were completely removed by machining at the elevation corresponding to the approximate midspan of the hydraulically expanded region, i.e.,
-2.25" the bottom of the HRUT, the structural capability of the joints were -3.5 to 4 times the most limiting RG 1.121    3''  end cap load.
The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign) was similar to that of Alloy 690 sleeves.
HE/STRUC.SEC                                     6-1                                            10/03/95


End Cap Plug or Tensile Gripper.Tube cut at elevations from the top of the transition to below the bottom of the transition, and at various arc lengths.~Tube~Hardroll Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.Figure A-I: HEJ specimen used for tensile testing.D:EPLhRKEAEPKHEJPNDXhSlG A-9 7/29/95 Circumferential Crack Structural Model.;Assumed: depth I////I I I I I I I I I I I I I Neutral Axis Throu ghwall Circumferential Crack Figure A-2: Structural model for a tube with a circumferential throughwall crack.D:K PLANTSKAEP 4 EKJPNDXAPIG A-10 7/29(95  
Westinghouse non-Proprietary Class 3 The structural proof tests were performed on specimens which had been fabricated for leak testing. Following the leak tests, the sleeved tubes were machined to simulate a throughwaH crack at the inflection point, i.e., middle, of the hard roll. AH of 360'ircumferential the samples were then pressurized to a differential pressure of 3657 psi. The pressure was then gradually increased until slipping of the joint was noted. Initial slippage of the tubes was genexaHy detected after an increase in the pressure of about 200 to 700 psi. The maximum pressures, i.e., those achieved when the tube was ejected from the sleeve, wexe not recorded, but did approach pressures on the order of three times normal operating pressure differentials.
6.2 Pulled Tube Structural Tests Section 5.0 of this report documented the results of leak and structural tests performed on the sleeved tube specimens removed from SG "B" at Kewaunee, see Table 5-2. The tensile test results fox both tubes are higher than that predicted by for the limit load. Tube R2C32 was found to have a high flow stress, -98 ksi, and an average depth of the cracking of 61%. The cxacking was near the top of the HRLT. The estimated limit load of the remaining ligament is 5980 lbs using a net section stress approach. The measured failure load for the specimen was 10300 lbs with a remaining sliy load immediately after the failure of 2800 lbs. Estimating the actual failure load of the remaining ligament as the total failure load minus the residual sliding load yields 7500 lbs. This is about 25% higher than the value predicted by analysis. The residual sliding load is about 60% largex than the maximum of two values obtained from tests reported in WCAP-14157 for 360'lits at the top of the HRLT. The sliding load following development of a 360 fracture is about four times, or 25%o higher than the RG 1.121 requirement, the end cap load that would be experienced during normal operation of the plant with the highest differential pressure. Moreover, the sliding load is almost three times, or twice the RG 1.121 requirement, the end cap load that would result during a postulated SLB event.
Tube R2C54 had a measured flow stress of -83 ksi, with an average depth of cracking of 60%o.
The cracking was at the approximate middle of the HRLT, which exhibited evidence of roHdown. The measured failure load was 10700 lbs with a residual sliding strength of 4000 lbs. Thus, the ligament failure load was on the order of 6700 lbs. This is about 30% higher than the calculated ligament limit load of 5170 lbs. The residual sliding load is about equal to the lower of two values obtained from tests reported in WCAP-14157 for a 360'lit at the bottom of the HRLT, and about equal to the average of three values reported in the Addendum to WCAP-14157. Thus, the residual sliding load for the field specimen with a 360'eparation at the inflection point is on the order of that obtained from test speciments with a 360 separation at the bottom of the HRLT. In addition, the sliding load is on the order of six times the end cay load due to normal operation and about four times the end cap load developed during a postulated SLB event.
6.3 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2 HHSTRUC.SEC                                    6-2                                                    09/25/95


4.5 Critical Axial Load vs.Through-Wall Crack Angle 7/8" x 0.050", Alloy 600 MA SG Tubes w/LTL Material Properties 4.0 3.5-Critical Angle for LTL Material---40%Through-Walt Ligament-.-RG 1.121 NOp Limit-~.-RG 1.121 SLB Limit Note: Hardroll capacity of 300 l&assumed based on lower bound of test data.P)3.0'0 o 2.5~2.0~1.5'1.0 79 KLS 1.8 27 KLEk 1.4 0.5 0.0 0 224'50 200 Crack Angular Extant (Degrees)256'50 Figure A-3 D:EPLARIS'tAEPtHEJPNDXJLZIG A-11 7/2%95
Westinghouse non-Proprietary Class 3 (Appendix A). The purpose of the analyses was to support the development of a repair boundary which included consideration of PTIs located at the top of the HRLT. Such indica-tions are not a subject of this report. The criterion supported by this report is that aO PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent. Thus, the structural integrity analyses consist of the evaluations of the test data reported in WCAP-14157 and its addendum, and of the test data obtained from the sleeve/tube joints removed from SG "B" at Kewaunee.
'60'W Circumferential cracking degrades the axial strength of the joint , to less than the require-!ments of RG1.121..,'Leak resistance is'ignificantly reduced.tW Axial cracking does not degrade the axial strength of the tube/joint.
6.4 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the top, the midpoint and at the bottom of the HRLT. The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions. A summary of the leak rates from specimens with the tube removed or cut at an elevation corresponding to the top of the HRLT or at the repair boundary is provided in Table 6-3. The specimens with the tube removed at the midpoint of the HRLT'xhibited a maximum leak rate of 0.016 gpm at SLB conditions. The average leak rate for all of the specimens listed in Table 6-3 is about 0.004 gpm with a standard deviation of 0.008 gpm, thus, demonstrating a significant resistance to primary-to-secondary leakage.
The leak resistance is degraded.HEJ Joint Critical Tube Crack Locations 360'W Circumferential cracking at this location, or below, does not degrade the axial strength of the joint to less than the require-ments of RG 1.121.Leak resistance is slightly reduced.Figure A-4: Critical tube crack locations in a HEJ.D:REPLANTS hhEPKHEJPNDXhSIG A-12 7/29/95 4
These tests suggest that the presence of a "lip" of tube material below the top of the HRLT provides sufficient leakage restriction. The repair boundary determined from structural considerations, i.e., 1.1" below the bottom of the HRUT, would be expected to result in acceptable leak rates during a postulated SLB event.
ATTACHMENT 2 TO AEP:NRC:10820 Donald C.Cook Nuclear Plant Individual Plant Examination Human Reliability Analysis Summary of Methodology Changes and Example Calculations ThIs attachment includes a summary of the changes made in the human reliability analysis methodology and example calculatIons.
6.5 Crack Growth Rate Considerations Since the HEJ has been demonstrated to meet the requirements of RG 1.121 for full circumference, i.e., 360', at the elevation of the middle of the HRLT, the strength relative to those requirements is independent of crack growth rates.
6.6 Additional Tube Integrity Considerations and Observations The repair boundary developed in this report does not assume any credit for the resistance to tube motion afforded by tube support plate denting. The presence of significant dents could preclude any tube integrity issues in HEJ sleeved tubes with PIIs. A review of pull forces required to remove tubes from Westinghouse Model 44 and 51 steam generators was discussed in WCAP-14157. For tubes with no significant interface loading within the tubesheet, pull forces for tubes without detectable denting ranged from 1000 to 3000 lbs, while for tubes with detectable dents, the forces rose to 2000 to 4000 lbs.
Based on the findings from the destructive and nondestructive examinations of the specimens removed from Kewaunee, Section 5.0, and from the results of accelerated corrosion tests per-Approximately 1.12 to 1.13 inch below the bottom of the HRUT.
HEISTRUC.SEC                                    6-3
 
Westinghouse non-Proprietary Class 3 formed by Westinghouse, the appearance of PTIs in joints experiencing significant rolldown may be likely to occur at a lower elevation than in joints without significant rolldown.
Approximately 90% of the PTIs at Kewaunee were found at distances R 1.3" from the bottom of the HRUT, thus implying the presence of significant rolldown. Hence, it is possible that transitions with significant rolldown are less resistant to PWSCC than transitions without significant rolldown.
6.7 Conclusions The specified repair boundary is supported by structural and leak test data obtained from surrogate specimens (WCAP-14157 w/addendum), and by structural data obtained from specimens removed from an operating SG. Tube rupture loads well in excess of those required by RG 1.121 have been demonstrated by both the surrogate and actual HET test programs. The repair boundary results in a radial overlap of the HRLT of approximately 0.1" in length. This is a geometric configuration for which neither significant tube axial displacement nor significant tube leakage would be expected to occur during a postulated SLB event.
EEJSTRUC.SEC                                    6-4                                        09/25/95
 
Westinghouse non-Proprietary Class 3 Table 6-1: Operating Parameters for U.S. Plants with Installed HEJs pp        PE                Thoc              Tcold Plant            SG    Loops (psia)    (psia)      (psi)  (6 Point Beach 2          44                  2000        775        1225    596.7            541.7 Cook    I          51      4          2100                  1453    582.0            518.0 Kewaunee            51      2          2250        715        1535    591.2            531.8 Zion  1          51      4          2250        725        1525    592.2            532.2 Table 6-2: Tube Pressure Loading for U.S. Plants with Installed HEJs Normal                            3~AP Load Normal cQ'oad Plant (lbs)
(psi)                                (lbs)
Point Beach 2                      1225              578                1743 Cook  1                      1453              685                2056 Kewaunee                          1535              724
                                                                                          '172 Zion  1                      1525              719                2158 Note:    1. The 3+dZ load at Cook 1 could be as high as 2264 lbs corresponding to an operating differential pressure of 1600 psi.
: 2. The end cap load during a postulated SLB event is 1516 lbs independent of plant.
HEJSTRUC.SEC                                        6-5                                            09/2S/9S
 
Westinghouse non-Proprietary Class 3 Table 6-3: Summary of Applicable HEJ Leak Rates from WCAP-14157 and Addendum Sleeve Cut Angle        Distance from      ~R      te<>> Leak  Rate"'t HRUT            at 1600 psi    2560 psi Material (in )              (gpm)        (gpm)
Alloy 690              240                1.08                0.0          0.0 Alloy 690              240                1.01                0.0        9  x 10~
Alloy 690              240                1.03              0.0084        0.0186 Alloy 690              240                1.0  +              0.0      4.5 x 10~
Alloy 690              360                1.1                0.0        2  x 10~
Alloy 690              360                1.1              0.0016        0.016 Alloy 600              360                                    0.0        1x 10' Alloy 600              360                1.1                0.0          x 10~
Notes:    1. Leak rates  for specimens with 240'ut angles were increased by a factor of 1.5 to estimate the leak rate for a cut angle of 360'.
HBJSTRUC.SEC                                    6-6                                        10/03/95
 
i End Cap Plug or Tensile Gripper.
Tube Tube cut at elevations from the top of the transition to below the bottom of the transition, and at various arc lengths.
Hardroll I
Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.
Figure 6-1: HEJ specimen used for tensile testing.
D:KPLANTShhEPEHEJSTRUC.FlG                6-7                                8/2/95
 
Westinghouse non-Proprietary Class 3 7.0 Leak Rate Based Repair Boundary 7.1 Introduction The purpose of this section of the report is to p resent    en an alteternative method for establishing a repair boundary for HES e upper sleeve/tube joint region, but below the prim to-secondary pressure boundary at the sleeve/tube harclroH interface. The                    rev'n o          sleeved tubes from Kewaunee, an evaluation of the structural y ocumented in References 8, 9, 11 and 12. The structural evaluations
                                                                                        'gin directly support the identification of a repair boundary for PTl b ed I
of the 'oint.. t is also possible to develop a repair boundary for PTIs in sleeve/tube oin which is not sensitive to the residual stren~~ of the oint rate dary            a function of the instaHed geometry of the tubes an          and the HEJs is developed in this section. Since            re air boundary is based on geometry and total ince thee repair ge, it does not rely on the re siduali    strength of the joint or on the extent of the indica-tions, or the growth rate of the indications, The repair b              dary d cation of the PTI and the constraiiiing effects of outboard neighboring tubes location                                                                                                  I The HEI consists
  /2 b.low of a HE of the                                '
sleeve and tube over a length h..p'.f ".1-., f.How by.h~-H of 4"  be r
w the top of the hydraulic expansion. The existing plant T hnical repairing/plugging criteria apply to the entire length of the sleeve, and to that portion of the parent tube above the bottom of the HB of the HEI. An exam le of the plugging criteria developed at the time of the installation of h This evaluation forms the basis for the development of a repair boun dary be o s eev      tu e rom service due to the presence of PTls in the re extending downward from the upper part oof thee HRLT              e.. see Pigure 7-1. The integrity of T, e.g.,
the tube bundl e with PXXs under normal op eratin g and postulated accident conditions is aad die ss ed.. Tlle results of the evaluation a pply to sleeved tubes in Westinghouse Model 44 aild 51                                                          s.          aspects of bundle integrity are ad-dressed:
: 1)    maintenance maintenan      of a fixed tube-to-sleeve              *on in thee end condition          limiting case of a circumferential m    ~cation near the top of the lower transition of the hardroH indication limitation of rimaiy--to--secondary leakage consistent with acc
                  ~  ~        ~
2
: 2)                                                                          ccid en t an alysis assump-tions, and 7-1
 
Westinghouse non-Proprietary Class 3 g)    maintenance  of tube integrity under            postulated limiting conditions of primary-to-secondary and secondary-to-primary differential pressure.
The result of the evaluation is the identification of a distance below the bottom of the HRUT for which PTls of any extent do not necessitate remedial action, e.g., plugging. The basis of the repair boundary is that the axial distance a postulated severed HEJ sleeved tube end can move is limited by the constraint afforded to the affected tube by it s outboard neighbor.
Thus, "hop off" of the upper portion of a severed parent tube will be precluded, and the leakage from such tubes during a postulated SLB will be within acceptable limits. For example, for the Kewaunee SGs the total allowable primary-to-secondary leak rate from all sources during a postulated SLB event was determined in Reference 30 to be 34.0 gallons per minute (gpm), without benefit of reducing primary coolant activity. Interim plugging criteria (IPC) have been approved for dispositioning tube indications at the elevation of the tube support plates in the D.C. Cook and Kewaunee SGs. The expected contribution to the total primary-to-secondary leakage from the IPC indications is likely on the order of 1 gpm or less.
Thus, approximately 33.0 gpm total leak rate from HEJ PIIs could be tolerated without exceeding the 10CFR100 limit for the Kewaunee plant.
Application of the leakage based repair boundary is expected to provide the same level of protection for PTIs in HEJ sleeved tubes as that afforded by Regulatory Guide (RG) 1.121 for degradation located outside the sleeve joint. Since the repair boundary does not rely on the residual strength of the joint, the calculation of margins against burst for the affected tube are not meaningful. For each affected tube, the repair boundary does rely on the structural capability of that tube's outboard neighbor. By restricting the application of the criteria to tubes with a structurally capable outboard neighbor.'.2 Sleeved Tube Dimensions A summary of the sleeve and tube dimensions pertinent to this evaluation were illustrated in Section 1 of this report. The tubing has a nominal outside diameter (OD) of 0.875" and a thickness of 0.050". The sleeves have an [
      ]". The region of the hardroH is denoted by the label interference'. The length of this region is governed by the length of the hardrolling tool used to create this section of the joint. For the D.C. Cook, Kewaunee, and Point Beach 2 SGs, the rollers had                    a flat length dimension of 1.0". Thus, the length cannot be less than 1.0" on the ID of the sleeve. In some cases the length of the hardroll is greater than 1.0" as a result of the reversal of the rolling process in order to release the roller from the inside of the sleeve. This reversal process is usually termed rolMown and the additional length of the hardroll is referred to as the rolldown length. It is not unusual for the rolldown to achieve a length of greater than
-0.5" during the reversal process.
The radii of the upper end of the rollers  of the rolling tool were [
Limitations on the use of the leak rate based repair boundary are discussed in the evaluation section of this report.
HEJLEAKP.SEC                                                7-2
 
Westinghouse non-Proprietary Class 3
                                                      ]*". Hence, a bounding lower limit on the radius at the OD of the sleeve in the transition is approximately 0.288". A true estimate of the radius of curvature in the axial direction is obtained by considering a hardroll transition length of 0.21" and a radial difference of 8 mils leads to the calculation of an effective radius of 1.4". The [
                                        ]'", thus, the effective length of the hardroll would be about 60 mils longer before the contact pressure between the sleeve and the hardroll would be lost. This would be somewhat offset by the potential contraction of the tube during the hydraulic expansion process. The expansion of the tube is about [
                                                    ]*". Since the sleeves installed in the D.C.
Cook, Kewaunee, and Point Beach 2 SGs were fabricated of Alloy 690, their coefficient of thermal expansion is greater than that of the tubes. This would lead to a slight increase in the interference fit during operation as further increase the effective length of the hardron, however, the expected magnitude      of such  an increase would not be expected to be significant.
7.3 U-Bend Clearance The results of a study of SG fabrication practices, Reference 17, were evaluated in order to estimate the potential distance that a severed HEI sleeved tube end could displace in the vertical direction during normal operation or during a postulated SLB. The results of this evaluation are applicable to the development of a plugging repair boundary for PTIh in sleeved tubes. In SGs of the type installed at D.C. Cook, Kewaunee, Point Beach 2, i.e., Westing-house Model 44 and 51, the nominal vertical clearance between radially adjacent tubes at the apex of their U-bends is 0.406". The actual clearance will vary about the nominal due to tube installation tolerances during manufacture of the SGs. The potential contributing factors from the Model 44/51 SG manufacturing operations are:
: 1. The tube-to-tubesheet fit-up for welding.
: 2. The tube expansion process.
: 3. Tube dimensional tolerances on overall length, U-bend radius, tube diameter, etc.
The second operation does not significantly contribute to the manufacturing process tolerance since the tube-to-tubesheet joint process for the D.C. Cook, Kewaunee, and Point Beach 2 SGs involved partial depth rolling as opposed to full depth rolling.
The maximum tube-to-tube U-bend apex gap increase in the D.C. Cook, Kewaunee, and Point Beach 2 SGs as a result of the first and third operations was calculated to be [
            ]"'. The extremes of the total manufacturing tolerance are taken to be three standard deviations from the mean, hence, one standard deviation would be [              ]'"". Since the installation of one tube is independent of its inboard neighbor, the standard deviation of the manufacturing clearance, i.e., the difference between two radially adjacent tubes, may be HEJLEAKP.SEC                                      7-3                                            09/25/95
 
Westinghouse non-Proprietary Class 3 calculated as the square root of the sum of squares of the individual standard deviations.
Thus, the standard deviation of the U-bend apex gap between two radially adjacent tubes would be [        ]'".
An additional consideration in estimating the U-bend apex clearance between two radially adjacent tubes is due to the [
                                                          ]'", assuming  that a primary-to-second-ary pressure difference of 2560 psi is achieved during the event. Assuming the distribution of U-bend apex gaps to be normally distributed in the SG, an upper 95% confidence bound on the apex clearance is calculated to be [                                            ]SIC The U-bend apex gap can be used to estimate the maximum upward displacement of a tube end which is assumed to be severed within the HEJ. The driving force for such displacement will be the unbalanced pressure on the interior of the tube acting on the projection of the tube cross-section area at the tangent point between the U-bend and the straight length of the tube, i.e., the severed tube end is pulled up by the force at the U-bend. Once contact has occurred with an outboard neighbor, further displacement is prevented. The total vertical displacement may be estimated by calculating the distance that the affected tube's tangent point may traverse by considering that the inboard tube deforms into intimate contact with the outboard tube up to the apex of the U-bend. More extreme deformation would require lateral in-plane deformation which is opposed by the internal pressure. Moreover, the extent of intimate contact would likely be limited to the point of first contact, which would be expected to occur nearer to the midway point from the tangent point to the apex. Ifd is the tube-to-tube clearance at the apex of the U-bend, and R is the radius of the U-bend of the affected tube, the clearance at the tangent point, D, is D  = (R+ d) sin 2R+d          K    d.                        (7.1) 2 Using the upper 95% confidence bounds of the U-bend apex clearance results in upper bounds on the tangent point displacement of [                        ]*" respectively. The expected displacement would be between the two extremes. Taking the average of the apex and the maximum tangent point displacements results in expected displacement limits of
[
                                                    ]*", with a limiting value of the expected displacement of 1.1". Since this result is based on a 95% confidence level, it would be expected that the occurrence of multiple tubes achieving this level of displacement would be very unlikely. I"urthermore, because the length of the sleeve above the bottom of the HR is on the order of 2.75", joint separation, i.e., hop-off, is precluded for tubes with PTIs below the top of the HRLT.
HE/LEAKP.SEC                                    7-4                                            09/25/95
 
Westinghouse non-Proprietary Class 3 Since, hop-off is precluded, the pertinent basis for the development of the leak rate repair boundary is the potential leakage from tubes with throughwall, 360, PTls which could displace upward either during normal operation or during a postulated SLB. The potential displacement during a postulated SLB is greater than that during normal operation, as is the primary-to-secondary differential pressure, hence, it is appropriate to develop the repair boundary based on the consideration of potential leakage during a postulated SLB. Verticany displaced severed tube conditions are illustrated on Figure 7-2. The expected displacement for a tube end severed at the top of the hardroll lower transition would be about midway along the length of the hardroll, with a 95% confidence bound on the displacement such that the location of the severed end would be about even with the top of the hardroll. Indications below the top of the hardroll would not be expected to lead to a configuration such that the severed end could achieve an elevation coincident with the top of the hardroll.
The effective length of the hardroll was estimated in the previous section to be 1.03" based on the radius of curvature in the axial direction and the elastic springback of the joint. This is about the same length as the 95% confidence level for the maximum displacement during a postulated SLB event. Since circumferential indications would not be expected above the top of the hardroll lower transition, the appearance of circumferential indications which could be postulated to lead to severing of the affected tube at elevation'n which could be exposed to the full primary-to-secondary pressure difference would be expected to be of low probability.
7.4 Leakage Potential Leak rates may be estimated from the tests that were performed, see References 8 and 9, and from calculations assuming various other geometry conditions, e.g., for a severed tube end which is elevated relative to the sleeve. It is to be noted that the maximum estimated primary-to-secondary differential pressure during a postulated SLB of 2560 psid assumes that the makeup system is capable of achieving that pressure regardless of primary-to-secondary leakage. Realistically, if one severed tube end displaced such that significant leakage occurred, the primary-to-secondary differential pressure would likely not increase further.
Thus, while conservative, the consideration of a significant number of leaking tubes during a postulated SLB is not realistic.
Ifthe postulated  severed tube end is assumed to be displaced relative to the sleeve, the leak rates measured for full hardroll length engagement may be estimated by assuming the flow to be controlled by a friction factor. This is appropriate instead of estimating an annulus choke flow because of the interference fit between the sleeve and the tube in the hardroll region.
The relationship between the flow, Q, the length of engagement, L, the differential pressure, d,P, and the friction factor, f, would be, 0=-  AP fL (7.2)
HElLPAKP.SEC                                  7-5                                          09/25/95
 
Westinghouse non-Proprietary Class 3 f
The value of could be estimated from the leak test for which the length of engagement was 1". However, this is not necessary since a comparison of leak rates for different engagement lengths leads to the relation, L,
                                            @    =0,.                                        (7.3)
L~
Thus, if the length of engagement is halved, the expected leak rate    is doubled. This expres-sion may provide satisfactory estimates in the range of Q from 1.0    to 0.25 of L,, however, its use beyond that range would not be recommended since the Q,~oo          as Q-4, and severed tube end effects would be expected to lead to increased radial deflection    at the tube end accompa-nied by increased leakage.
7.4.1 Normal Operation During normal operation, the leakage from HEI sleeved tubes with throughwall degradation extending 360'round the tube and located at the elevation of the HR lower transition would be expected to be sufficient to be detected. If the tube end does not displace, the leakage from each such joint would likely be on the order of 1 gpd or less. Ifthe joint does displace, an increase in the leak rate would be experienced such that the plant could be shut down to address the source  of the  leakage.
7.4.2 Steam Line Break For the initial evaluation of potential leak rate in the event of severing of the tubes, calcula-tions were performed for assumed radial gaps if the tube displaced axially upward relative to the sleeve, For a radial gap of [        ]*", corresponding to elevating the hardroll length of the tube to correspond to the hydraulically expanded length of the sleeve, the projected leak rate was found to be -25 gpm, References 8 and 9. Ifthe tube displacement is limited to less than or equal to about 1.1", the -95% confidence value for tangent point contact, the lower end of the hardrolled region of the tube would still be in contact with the upper end of the hardrolled region of the sleeve. For leakage evaluation purposes, prior calculations assumed that a gap on the order of [
                                ]"', and would thus be expected to leak at a rate of 2.5 gpm. In actuality, no gap would be expected to be present for displacements less than 1.03" and the expected leak rates would be substantially less than the estimated value of 2.5 gpm. Testing has been performed for tubes machined away at the top of the hardroll lower transition, References 8 and 9. Leak rate values under these circumstances were found to be relatively insignificant when compared to the makeup capacity of the plant hydraulic system. The maximum leakage from any single indication was estimated to be bounded between 0.01 and 0.033 gpm. These estimates may be considered to bound the leak rate if as little as -1/4" of sleeve-to-tube hardroll interference remains. Using the maximum value as an average for all such tubes results in a total leak rate from 1000 leaking HEJ sleeved tubes of 33.0 gpm. The total IPC leak rate which might be expected from the limiting D.C. Cook or Kewaunee SG is HElLEAKP.SEC                                    7-6                                          09/25/95
 
Westinghouse non-Proprietary Class 3
  ~
estimated.to be less than 1 gpm. Therefore, about 1000 or more HEJ sleeved tubes with PTIs
            ~                      ~
              ~    ~        ~            ~                    ~
ould remain in service, without expecting total leakage during a postulated SLB to exceed the 10CFR100 limit. Ifonly the results from the three valid tests are used, i.e., 0.0, 6+10,
                ~    ~                                      ~                ~
                                                                              ~    ~
                                                                                        ~    and 0.0124 gpm, respectively, four times the maximum leak rate (assuming a displacement of
                                    ~            ~                    ~
about 0.8") would be 0.05 gpm. Conservatively considering this maximum leak rate to apply to all sleeved tubes leads to a total leak rate for 665 HEJ sleeved tubes of 33.0 gpm. It is to be emphasized that the average total leak rate from the 665 sleeved tubes considered here would be expected to be significantly less than the 10CFR100 limiting leak rate.
I  &
C&
More accurate estimates of the total leak rate could be developed using Monte Carlo simula-tion techniques, however, based on the conservatisrns utilized for the deterministic estimates, e.g., the probability of experiencing multiple severed tube conditions was considered to be unity, such results would be expected to be significantly less than those reported herein.
7.5 Tubes Interior to Stayrod Locations Tubes interior to stayrods have no immediate outboard neighbors. Therefore the clearance to the nearest restraint is significantly larger than for tubes with outboard neighbors, and would be expected to exceed the hop-off distance from the PTI to the top of the sleeve.      Thus, the leak rate based repair boundary developed in this section is not applicable to tubes immediate-ly interior to the stayrods.
l 7.6 Distribution of Indications in the Kewaunee SGs Sleeved Tubes The distance from the bottom of the hardroll upper transition to the elevation of the indica-tions in the Kewaunee SG tubes was measured for each indication near the elevation of the hardroll. A summary of the measured distances for each SG and for the combined SGs is provided in Table 7-3. Histogram and cumulative frequency plots of the distribution of indications in SGs "A" and "B" are provided on Figure 7-3 and Figure 7-4 respectively. The combined distribution and cumulative frequency information for both SGs is provided on Figure 7-5.
A total of 630 indications were considered in this evaluation. The average distance was found to be 1.32" with a standard deviation of 0.10". The median distance was found to be 1.32".
The skew and kurtosis {normalized) were found to be 0.20 and 0.58 respectively. These last three values indicate the distribution to be relatively normal. An inspection of the plotted cumulative frequency curves indicates the distributions to be nearly symmetrical about the 50% value for the measured populations, thus supporting the judgment that the distributions are nearly normal. Hence, the probability of an indication being located within the 95%
confidence bound on the potential displacement is relatively small. To be located above the average value of the potential displacement, the indication would have to be located -4.5
                                  ~                  ~ ~
                                                                                            ~
                ~    ~                            ~                      ~
standard deviations away from the mean elevation. The distribution of indications in the
                                                                                  ~    ~
Kewaunee SGs confirms the expectation that very few indications would be expected to occur
          ~            ~ ~
at elevations where significant leakage could occur during a postulated SLB.
EEJLPAKP.SEC                                    7-7                                          09/25/95
 
Westinghouse non-Proprietary Class 3 7.7 Phnt Operation Considerations Other factors which would be expected to have a beneficial effect on the total leak rate that could be experienced are:
: 1)  Adoption of a normal operation leakage limit of 150 gpd.
: 2)    Implementation of nitrogen 16 (N16) monitors for monitoring SG leakage.
: 3)    Enhanced training  of operators to  respond to faulted events.
7.8 Summary and Conclusions Analyses have been performed which indicate that the total leakage that could reasonably be expected from the sleeved tubes with indications in the D.C. Cook, Kewaunee, and Point Beach 2 SGs during a postulated SLB would be small relative to the makeup capacity of the charging system. A comparison of the distance a severed tube end could be expected to move during normal operation or during a postulated SLB relative to the distance from the bottom of the HEJ hardroll upper transition to the indications in the D.C. Cook, Kewaunee, and Point Beach 2 sleeved tubes indicates that it is unlikely that any of the tubes could become disen-gaged from their respective sleeves if those tubes are constrained by the presence of a structurally capable outboard neighbor. For an outboard neighbor to be considered as structurally capable, it may not,  if sleeved, have circumferential degradation evident above the bottom of the HEJ hardroll lower transition. Tubes which are plugged may not have been so removed from service on account of circumferential degradation. Axial degradation has no significant effect on the axial strength of active or inactive tubes, hence the presence of axial degradation alone is not considered. cause to consider an outboard neighbor as not structurally viable.
This section documented the development of a geometry based repair boundary for PIIs in HEJ sleeved tubes. The resulting repair boundary is independent of the repair boundary developed in previous sections based on the structural integrity of the joint. Since the result obtained, 1.1", is the same as the structural repair boundary, it essentially demonstrates a defense in depth against the occurrence of a tube separation. The application of the repair boundary results in expected leakage during normal operation and postulated steam line break (SLB) events within limits based on 10CFR (Code of Federal Regulations), Part 100 criteria.
The conclusion of the evaluation is that based on geometry considerations alone it is accept-able to leave HEJ sleeved tubes with PIIs in service that satisfy the following requirements:
: 1)  The distance from the bottom of the HRUT to the PTI is greater than or equal to 1.1".
: 2)    The tube is located on the interior of the tube bundle.
: 3)    The tube is not located adjacent to and inboard  of a stay rod.
HEJLEAKP.SEC
 
Westinghouse non-Pxoprietary Class 3
: 4)  The outboaxd neighboring tube is stxucturally capable, i.e., it can be expected to provide restraint against upward motion of the affected tube ifthe affected tube is considered to be sevexed at or below 1.1" from the bottom of the hardxoll upper transition.
For example,  a review  of Kewaunee Nuclear Power Plant data indicates that the first three requirements are satisfied for all sleeved tubes in the SGs. Thus, only satisfaction of the last requirement would need to be specifically demonstrated if geometry was the only basis for the repair boundary. However, the development of the geometry based boundaxy is secondary to the structural based boundary, so requirements 2) through 4) would not be considered to be generally applicable.
7-9                                          09/25/95
 
Westinghouse non-Proprietary Class 3 Table 7-1: Tube U-Bend Apex Clearance Dimension              Normal            Steam Line Operation            Break Nominal                                                  a.)c Pressure Difference Average Standard Error Table 7-2: Tangent Point Clearance Dimension              Normal            Steam Line Operation            Break Q. C 50% Confidence 60% Confidence 90% Confidence 95% Confidence 99% Coilfidence 99.5% Confidence 99.9% Confidence HEJLEAKP.SEC                            7-  10                            09/26/95
 
Westinghouse non-Proprietaxy Class 3 Table 7-3: Distribution of the Distance of the Indications from the Bottom of the Kudroll Upper Transition Parameter              SG  "A"    SG NBtl      Both SGs Count                  426          212          638 Average                  1.32          1.31        1.32 Standard Deviation            0.092        0.106        0.100 Maximum                    1.63          1.75        1.75 1VRnmum                  1.04          1.00        1.00 1.32          1.30        1.32 Skew                  0.01          0.52          0.20 Kurtosis                0.18          1.03        0.58 HEJLEAKP.SEC                              7-  ll
 
Westinghouse non-Proprietary Class 3 Repair Boundary illustration Alloy 600 Tube Alloy 690/600 Sleeve HRUT Hardroll and                                    Critical Distance thermal                                          Measurement of interference fit.                                1.1" Location of PTls outside of the geometry based repair boundary Figure 7-1: Illustration of the leak based criterion for HEJ sleeved tubes.
7-  12
 
Westinghouse non-Proprietary Class 3 Displaced Tube End Leak Path Small Gap 1 mil Hardroll 0 mils                                                and thermal gap                                                  expansion interference fit.
8mils gap Displacement Distance Expected Displacement                                  Assumed severing of Distance                                      the parent tube at the top of the hardroll lower transition.
Figure 7-2: Leak path for a moved tube segment relative to the sleeve.
7-13
 
Westinghouse non-Proprietary Class 3 SG "A" HE J Sleeved Tube Indications vs.
Distance Below the Bottom of the Hardroll Upper Transition 100                                                                                100%
EZ3SG "A" Indications 90 SG "A" Cumulative 90%
80                                                                                80%
O 70                                                                                70%
                                                                                            'a 6  60                                                                                80%
0 50                                                                                60%
O l4 40                                                                                40%  O 8
30                                                                                30%
8 O
20                                                                                20%
10                                                                                10%
0%
CQ O
O W
CO W
O CC CO CC O
CQ CO Co O
W CO
                                                  'ICI O
IQ lQ IQ O
CO 0
CO O
C
                                                                                  . IQ C
H Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-3 SG "B" HE J Sleeved Tube Indications vs.
Distance Below the Bottom of the Hardroll Upper Transition 100                                                                                100%
90                                                          EKI SG "B" Indications 90%
SG "B" Cumulative 80                                                                                80%  CO O
70                                                                                70%  0$
C g  60                                                                                60%
IH  50                                                                                60%
O 40                                                                                40%  e 8
30                                                                                30%  5 8
20                                                                                20%
10                                                                                10%
0%
O    CO  O CC CO OC O
M CO, Cc O
M CO M
O ID R
CA O
CD      CO O    CO C    C
                                      ~W    W                                  I Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-4 7-  14
 
Westinghouse non-Proyrietaxy Class 3 SGs "A" 8s "B" HE J Sleeved Tube Indications vs.
Distance Below the Bottom of the Hardroll Upper Transition 130                                                                            i00%
K3 Both SG Indications 120  Both  SG Cumulative                                                      00%
110 80%  ol 100                                                                                  O ce  90                                                                            V0%
O 80                                                                            60%  c' 0
70 60%  Q 60 l4 40%  o g  50 40  95% Conf. on                                                              30%
8 30 SLB Criterion.
20%
20 l0%
10 0%
O    Q    O o    O
            ~      lO m    c4 H
oi rk cQ R
10 rl M co O
                                                    ~ O lO lo A A A A A r<
Q M
O co lQ co O lO Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-5 7-15                                      os12ass
 
Westinghouse non-Proprietary Class 3 S.O    Repair Boundary for Parent Tube Indications 8.1 Compliance with draft RG      I. 121 Tube Integrity Criteria To remain consistent with the licensing basis addressing structural integrity, the repair boundary must be located such that the sleeved tube meets the structural integrity (burst) requirements of RG 1.121. Por the case of the repair boundary established in this document for a HEJ sleeved tube, an RCS release rate equal to those for a postulated tube burst is only possible if a circumferential separation of the parent tube occurs and is followed by upward motion of the separated end by a distance on the order of 3". Separation of the tube can only occur if the pressure end cap loads exceed the residual holding strength of the joint. Testing of prototype and field specimens has demonstrated that the residual strength of the separated joint is on the order of greater than 4000 lbs. The maximum load applied during normal operation of the most limiting plant is 724 lbs. Thus, a margin of safety relative to normal operation is on the order of 5.5 versus the RG 1. 121 requirement of a margin of 3. The axial load applied during a postulated SLB is 1060 lbs. Thus, the margin of safety during postulated accident conditions is about 3.8 versus the RG 1.121 requirement of 1.43.
In order for the tube to experience leak rates on the order of those associated with a steam generator tube rupture described in the PSAR, the parent tube must experience axial motion of
-3" (for degradation in the HEX HRLT). At this point the tube and sleeve would no longer be in close proximity and an unrestrained leak path would be produced. Reactor coolant system leak rates approaching those assumed in the PSAR could be realized. The diameter restrictions of the sleeve itself will limit the flow through the sleeve to values less than assumed in the PSAR. The nominal tube ID flow area is approximately 36% greater than the flow area based on the sleeve ID. For tube axial displacements less than -3" and greater than
-1.5", the primary to secondary leakage is restricted by the close proximity of the tube hardrolled region and the sleeve hydraulically expanded region. For this condition, leak rates would be expected to be on the order of one third to one half of the normal makeup capacity.
For axial displacements of less than -1.5", intimate contact between the tube and sleeve is provided by the installed diameters in the rolled region. The attendant leak rate would be expected to be about an order of magnitude less than that for a displacement of 1.5" to 3". It must be stressed that the repair boundary of 1.1" below the bottom of the HRUT based on residual strength considerations would be expected to result in motion being precluded from occurring. Furthermore, the repair boundary of 1.1" below the bottom of the HRUT based on geometric constraint considerations results in there being a very low probability that such motions would occur in the unlikely event that the residual strength was not sufficient to preclude motion.
HE/ CRITR.SEC                                    8-1                                        09/2$ /9$
 
Westinghouse non-Proprietary Class 3 8.2  . Offsite Dose  Evaluation For a Postulated Main steam Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve As stated in Section 3.0, the postulated SLB event is the most limiting faulted condition with regard to offsite dose potential. Following the SLB any primary-to-secondary leakage is assumed to be entirely released to the environment. Equilibrium primary and secondary side activities are calculated based on the Technical Specification limit.
NUREG-0800 is used to calculate the maximum allowable primary-to-secondarJJ leakage limit during the event such that offsite doses remain within the licensing basis. Similar calculations have shown that the accident initiated Iodine spiking case is usually limiting. Doses are limited to 10% of the 10 CFR 100 limit of 300 Rem thyroid dose. For example, the maximum faulted loop leakage for Point Beach Unit 2 is found to be 25 gpm in the faulted loop, assuming 150 gpd leakage in each steam generator prior to the event with a maximum RCS activity level of 1.0 micro Curies per gram dose equivalent Iodine-131. For Cook Unit 1, the value has been determined to be 12.6 gpm, and was approved by the NRC as part of the Voltage Based Interim Tube Support Plate Plugging Criteria for Cook Unit 1. Each tube permitted to remain in service due to application of the criteria will be assumed to contribute to the total leakage. If the total projected leakage exceeds the calculated maximum permissible value, tubes will be repaired or removed from service so that the, projected SLB leakage value is reduced below the maximum permissible limit. As an alternative th tube repair, the RCS technical specification activity level can be reduced. For Point Beach Unit 2, lowering the allowable activity level to 0.25 micro Curies per gram dose equivalent Iodine-131 supports a maximum leakage value of approximately 100 gpm.
8.3 Evaluation    of Other  Steam Loss Accidents The MSLB event outside of containment would be expected to represent the most severe static loading and dynamic response condition upon the steam generator. No U.S. plant has ever experienced a double ended guillotine rupture of a main steam pipe. Plants have experienced however, random instances where a steam line relief valve or safety valve have stuck open.
Of these two, the safety valve would have a greater dynamic response upon the system. This event, however, produces a limited response compared to the double ended SLB, and the plant response to this condition would be bounded by the SLB condition response.
In addition to  a postulated SLB event or a spurious opening  of a safety valve, the following moderate frequency accidents:
: 1)  uncontrolled rod withdrawal from full power,
: 2)  loss of reactor coolant fiow,
: 3)  loss of load, and HEJCRITR.SEC                                    8-2
 
Westinghouse non-Proprietary Class 3
: 4)  loss of normal feedwater would result in higher than normal primary too secondary pressure            diff ressure differentials          across the steam generator        es. All of these events are rapidly occurrin or tubes.                                        urring transients tran              and lead to rapid of the steam linee iso  ation v isolation  valves and to a relatively rapid decrease of
                                                                                  'losure a          event presents the most severe loading to an HEI sleeved tube with PTIs 8.4 HEJ Inspection Requirements A review of the currecurrent inspectMn criteria suggests that the HBJ parent tube be in su stanti axial and/or circumfemferential PTls in the region of the sleeve/tubee jomt.
joint. As a minimum, minimum the probes used should demonstrate  ns          e th e capability of detecting 40% to 60% deep EDM axial and circumferential notches.
To assist in establishin g a data b ase for continued evaluation, indications left in                          th
                                . air criteria should be inspected  at thee subsequent          refueling outage.
t spec            sub e                                'pec too inspectMn w be consistent from inspection          in                  the convention of locating parent n tubee mdications relative to the bottom of        HR o thee HRUT    should be used defining the location of the PTIs.
HPJCRITR.SEC                                        8-3
 
Westinghouse non-Proprietary Class 3 9.0 Summary of Sleeve Degradation Limit Acceptance Criteria 9.1 Structural Considerations Based upon the information previously identified in this report, the foHowing structural considerations are considered to be validated:
9.1.1 Crack Indications Below the Upper HardroH Lower Transition Any crack indication, either circumferential or axial, is allowed to remain in service ifthe elevation of the uppermost portion of the crack is located below 1.1" below the bottom of the KRUT.
9.1.2 Sleeved Tube with Degradation Indications with Non-Dented Tube Support Plate Intersections For indications in the upper hardroH lower transition, circumferential crack extent is limited to 179't BOC. A 179'OC throughwaH crack is considered representative of a 224 EOC crack. The measured RPC angle should be assumed throughwaH over its entire indicated length. Circumferential indications to which this angle limit applies are limited to the lower transition region only, and do not apply to indications in the hardroH flat area or higher.
Any circumferential crack indication existing above the lower transition with a depth estimate of 40% or greater will be removed from service or repaired, consistent with current criteria.
Axial cracks are permitted to remain in service if the uppermost part of the crack is located no less than 1/2 inch below the bottom of the upper hardroH transition.
Any axially oriented crack existing less than 1/2 inch below the bottom of the upper hardroH transition will be removed from service or repaired, consistent with current criteria.
9.1.3 Dented Tubes The HEI repair boundary identified in this report does not rely on the resistive effects of dented tube support plate intersections to react any portion of the tube end cap load.
9.2 Leakage Assessment For PTIs located below the HRLT, SLB leakage would be expected to be negligible and can be excluded from SLB leak rate calculations. For circumferential indications below 1.1" HEJCRITR.SEC                                  9-1
 
Westinghouse non-Proprietary Class 3 below the bottom of the HRUT, but within the HRLT, SLB leakage would be expected to be limited to -0.02 gpm per indication.
9.3 Defense In Depth and Primary to Secondary Leakage Limits The repair boundary identified in this report results in margins which significantly exceed the burst criteria of RG 1.121 and leakage requirements relating to offsite dose evaluation. The Technical Specification normal operating primary-to-secondary leak rate limit will be lowered to 150 gpd per SG (0.1 gpm). The leak rate used in the evaluation for each plant will be selected to represent the expected leakage from an HEI which has experienced a complete circumferential separation at the elevation of the repair boundary. This level of leakage is readily detectable by plant leakage detection systems. The available axial translation limits of the tube and the relation of these limits to leakage limits are also addressed. Section 7.0 of this report has demonstrated that the maximum amount of axial motion that a postulated circumferentially separated tube could be expected to experience is 1.1". Based on the distribution of indication elevations observed at Kewaunee, a postulated movement of 1.1" would still result in a length of intimate tube/sleeve contact. If the tube were postulated to move an amount on the order of, say, 2", the maximum primary to secondary leakage would be limited to about 30 gpm at SLB pressure differentials, being limited by the thin gap created between the tube ID in the hardroll region and the sleeve OD in the hydraulically expanded region. This would be an extremely unlikely event since the sleeve/tube joint would have to have insufficient residual strength and the tube would have had to have been installed at a lower extreme deviation from its nominal U-bend elevation at the same time as its outboard neighbor having been installed at an upper extreme deviation from it nominal U-bend elevation. Such a situation would not be likely to have been overlooked during fabrication, and could be expected to have resulted in contact of the tubes in the V-bend, which would have been detected during the NDE of the tubes during prior inspection outages. I"inally, the prototype testing program demonstrated that the axial friction force between the postulated separated tube and sleeve increases as the amount of slippage increases further reducing the likelihood of a tube/sleeve separation.
HEJCRITR.SEC                                    9-2
 
Westinghouse non-Proprietary Class 3 10.0,    Refer eaces
: 1. WCAP-9960 (Proprietary), "Point Beach Steam Generator Sleeving Report," Westing-house Electric Corporation (1981).
: 2. WCAP-9960 (Proprietary), Revision 1, "Point Beach Steam Generator Sleeving Report,"
Westinghouse Electric Corporation (1982).
: 3. WCAP-11573 (Proprietary), "Point Beach Unit 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).
WCAP-11643 (Proprietary), "Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).
: 5. WCAP-11643 (Proprietary), Revision 1, "Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation, November 1988.
: 6. WCAP-11669 (Proprietary), "Zion Units 1 and 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).
I
: 7. WCAP-12623 (Proprietary), "American Electric Power D. C. Cook Unit 1 Steam Generator Sleeving Report (NIechanical Sleeves)," Westinghouse Electric Corporation (1990).
WCAP-14157 (Pxoprietary), "Technical Evaluation of Hybrid Expansion Joint (HH)
Sleeved Tubes With Indications Within the Upper Joint Zone," Westinghouse Electric Corporation, August, 1994.
9." WCAP-14157, Addendum (Proprietary), "Supplemental Leak and Tensile Test Results for Degraded HEJ Sleeved Tubes in Model 44I51 SIG's," Westinghouse Electric Corpora-tion, Septembex, 1994.
: 10. Regulatory Guide 1.121, "Bases For Plugging Degraded PWR Steam Generator Tubes,"
United States Nuclear Regulatory Commission, Issued for Comment (1976).
VPNPD-94-096 I NRC-94-068 (Proprietary), "Dockets 50-266 and 50-301, Response to Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 13, 1994.
10-  1                                      09/25/9S
 
i i
 
Westinghouse non-Proprietary Class 3
: 12.      NPD-94-101  / NRC-94-069    (Proprietaxy), "Dockets 50-266 and 50-301, Response to .
Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 22, 1994.
: 13. USNRC SER, "Safety Evaluation by the Office of Nuclear Reactor Regulation RElated to Amendment Request CR-175 to Facility Operating Licenses DPR-24 and DPR-27, Wisconsin Electric Power Company Point Beach Nuclear Plant, Units 1 and 2, Dockets 50-266 and 50-301," United States Nuclear Regulatory Commission, January 11, 1995.
: 14. Wisconsin Public Service and Wisconsin Electric Power meeting with the United States Nuclear Regulatory Commission, discussion of the Point Beach SER and the responses to the RAIs, February 1, 1995.
: 15. Wisconsin Public Service meeting with the United States Nuclear Regulatory Commission, discussion of inspection results of Kewaunee SG tubes, April 13, 1995.
: 16. Hexnalsteen, P., "Belgian Experience with Cixcumferential Cracking, Part 1: Genexal Overview," EPRI Workshop on Circumferential Cracking, Charlotte, North Carolina, June, 1995.
: 17. WCAP-10949 (Proprietaxy), "Tubesheet Region Plugging Criteria          for Full Depth HardroH Expanded Tubes," Westinghouse Electric Corporation (1985).
: 18. WCAP-12244, Revision 3 (Proprietary), "Steam Generator Tube Plug Integrity Summary Report," Westinghouse Electric Corporation (November, 1998).
: 19. Ducrile Fracture Handbook, Electric Power Research Institute, Palo Alto, California (October, 1990).
: 20. Flesch, B, et al., "Operating Stress and Stress Corrosion Cracking in Steam Generator Transition Zones (900-MWe PWR)," International Journal of Pressure Vessels and Piping, Vol. 56, pp. 213-228 (1993).
: 21. Bandy, R., and Van Rooyen, D., "Stress Corrosion Cracking of Inconel Alloy 600 in High Temperature Water - An Update," Corrosion, Vol. 40, No. 8, pp. 425-430 (August, 1984).
.      Yonezawa,    T., et al., "Effects of Metallurgical Factors on Stxess Corrosion Cracking of
        &#xb9;AHoys in High Temperature Water," Proceedings of the 1988 JAIF International Conference on Water Chemistry in Nuclear Power Plants, Tokyo (April, 1988).
HEJREFS.SEC                                      10-2
 
Westinghouse non-Pxoprietaxy Class 3
: 23. Theus, G. J., "Summary of the Babcock and Wilcox Company's Stress Coxmsion
    ~            ~ ~
Cracking Tests of Alloy 600," EPRI WS-80-0136, EPRI Workshop on Cracking of Alloy
                            ~
600 U-Bend Tubes in Steam Generators, Denver, Colorado (1980).
: 24. Kim, V. C., and Van Rooyen, D., "Strain Rate and Temperature Effect on the Stxess Corrosion Cracking of Inconel 600 Steam Generator Tubing in Primary Water Condi-tions," Proceedings of the Second International Symposium on Environmental Degrada-tion of Materials in Nuclear Power Systems Water Reactors, Monterey, California, pp.
448-455 (September, 1985).
: 25. Personal communication, Darol Haxxison of Entergy to Bob Keating    of Westinghouse (September 15, 1994).
: 26. WCAP-12076 (Proprietaxy), "St. Lucie Unit 1 Steam Generator Sleeving Report (Me-chanical Sleeves)," Westinghouse Electric Corporation (November, 1988).
: 27. NUREG/CR-3464, "The Application of Fxacture Proof Design Methods Using Tearing Instability Theory to Nuclear Piping Postulating Through Wall Cracks," United States Nuclear Regulatory Commission (September, 1983).
                                ~ ~        ~
: 28. NUREG/CR-0838, "Stability Analysis of Circumferential Cracks in Reactor Pi)ing
    ~
                                                              ~      ~            ~
                      ~                                      ~
Systems," United States Nuclear Regulatory Commission (Febxuaxy, 1979).
                                                          ~
                                                                              ~
: 29. Tada, H., and Paris, P. C., "The Stress Analysis of Cracks Handbook," Second Edition, Paris Productions Incorporated, St. Louis, Missouri (1985).
: 30. WPS-94-587 (NTD-NSRLA-OPL-94-297), "Wisconsin Public Service Corporation, Kewaunee Nuclear Power Plant, Allowable Primary/Secondary Leak Rate During Steam Line Break for Kewaunee," Westinghouse Electric Corporation, September 30, 1994.
HEJREFS.SEC                                  10-3
 
Westinghouse non-Proprietary Class 3 Appendix A Review of Prior Amendment Requests for HEJ Sleeved Tubes 1.0 Discussion/Chronology of Prior Amendment Requests When HEJ sleeved tube PTIs were first detected at Kewaunee in the Spring of 1994, analyses and tests were performed to characterize the effect of the degradation on the strength of the joint. Since no tubes had been removed for destructive examination, it was assumed that the degradation was in the form of circumferential cracking. A meeting was held with the NRC on April 19, 1994, during the inspection outage, to discuss the non-destructive examination techniques, the results of the non-destructive examinations, the results of structural analyses and tests performed on HEJs with simulated circumferential degradation below the hardroll in the parent tube, and to propose and amendment request to allow selected HEJ sleeved tubes to remain in service. It was demonstrated HEJs with circumferential cracks below the HRLT of any extent, i.e., up to 360, met the structural xcquirements of draft RG 1.121, i.e., a margin of 3 relative to burst during normal operation and a margin of 1.43 relative to burst during a postulated SLB. Leak testing results were presented that indicated that a leak rate of < 1 gpm would be expected during a postulated SLB from all of the tubes with indications ifthey were allowed to remain in service. Thus, it was proposed that any indications below the HRLT be allowed to remain in service. Based on a structural analysis of circumferential cracks at the top of the HRLT, it was also recommended that tubes with projected crack lengths  ( 240 at the end of the next cycle be allowed to remain in service. The NRC advised Wisconsin Public Service on April 20, 1994 that insufficient time was available to properly review the request for an amendment to the operating license. Therefore, the amendment request was not submitted to the NRC for approvaL In August, 1994, in preparation for a Fall outage, the Wisconsin Electric Power Company submitted an amendment request to the NRC to allow HEJ sleeved tubes to remain in service with PIIs below the hardroll. References 8 and 9 were included with that submittal in support of the request for an operating license amendment to allow selected HEJ sleeved tubes with PTIs to remain in service at Point Beach Unit 2. The technical bases of the submittal were similar to those developed for Kewaunee, i.e., RG 1.121 criteria would be met for any indications below the bottom of the HRLT, as would HEJs with indications with projected lengths of less than 226'n the HRLT. To support the angular extent criteria, additional existing data relative to the growth of crack in tubes were collated; these indicated that crack growth rates of 45 per cycle in the circumferential direction and 20% of the tube wall thickness per cycle in the radial direction could be considered as bounding. A series of re-quests for additional information (RAIs) were issued by the NRC which were responded to via References 11 and 12. The license amendment request was denied based on the conclusion documented in the safety evaluation report (SER), Reference 13, prepared by the office of Nuclear Reactor Regulation of the NRC.
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Westinghouse non-Pxoprietaxy Class 3 A mepting with the NRC, initiated by W'isconsin Public Service (WPS, Kewaunee), Reference 14, was held on February 1, 1995, to verify a mutual understanding of the concerns expressed in the SER, and to discuss each of the Wisconsin Electric Power Company (WEP, Point Beach) responses to the RAIs. The conclusions reached at that meeting relative to unresolved NRC concerns were:
: 1. that the database employed for the potential growth calculations was insufficient for estimating the incubation time and growth rate of parent tube flaws (PTIs),
: 2. that the qualifications of the NDE probes used for the inspection of the parent tubes did not include a sufficient number of cracked tube specimens as opposed to the use of machined flaws in ASME NDE standards to calibrate the probes,
: 3. that the level of detection and the accuracy of sizing PTIs in the uppex transitions    of the HEJs might not be sufficient to support the application of the criteria, and,
: 4. that the appearance of PTIs at the lower transition(s) is indicative  of a tube that is prone to developing PIIs at the upper transitions.
Thus, taken as a whole, the NRC was concerned that undetected PTIs at the upper transitions of tubes with PTls in the lower transition(s) could grow during the operating cycle to the extent that the structural integrity of the tube would be less than that required by the RG 1.121 at the end of the operating cycle.
Another meeting between WPS and the NRC, Reference 15, was held on April 13, 1995, during the inspection outage at Kewaunee, to discuss PTIs detected using a + Point eddy current inspection probe (the previous inspection of the parent tubes was conducted using a Zetec I-coil eddy current inspection probe). Information was presented that the probe had been qualified to EPRI guidelines using both ASME standards and cracked HEJ sleeved tube specimens which had been fabricated by Westinghouse. Summaxy information was also presented to show that of over 930 total PIIs found at three plants, there were no instances of the simultaneous appearance of PTls at the lower and upper transitions. It was thus argued that PTIs in the lower transitions should not be cause to remove the sleeved tube from service.
However, since much of this information was developed during the outage, there was insuffi-cient time for the NRC to conduct a thorough review of the information and tubes with PTIs within the HEJ region were removed from service.
2.0 Summary of Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the tube indications on the operating performance of HEJs with PTls, test and analysis programs were performed, References 8 and 9, aimed at:
: 1)  characterizing the effect  of the obsexved indications on the axial strength  of the joint, and DAPLANTSM,EPQKJPNDXA.SEC                        A-2                                            09/25/9$
 
Westinghouse non-Proprietary Class 3
: 2)  estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.
Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach tubes (no indications have been determined to be present in the Cook 1 tubes at present) was explored via axial tensile (pull out) testing and hydraulic proof testing. Additional analyses results were reported in References 11 and 12.
A summary of the test and analysis programs is provided in the following sections. The results are applicable to the four U.S. plants with installed HEJs. Plant operating parameters relative to structural integrity evaluations are presented in Table A-1. The largest operating primary-to-secondary differential pressure (1535 psi) occurs in the SGs at Kewaunee. The smallest differential pressure (1225 psi) occurs at Point Beach 2. The differential pressure at Cook 1 is 1453 psi.
2.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9). Prototypic HEJ test specimens, see Figure A-l, were fabricated using Alloy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were performed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations. For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e., 1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 1.121 cap loading. For specimens where the tubes were completely removed by machining at 3'nd the elevation corresponding to the approximate mid-span of the hydraulically expanded region, i.e., -2.25" the bottom of the HRUT, the structural capability of the joints were -3.5 to 4 times the most limiting RG 1.121 361? end cap load.
A second    series of tests were conducted for HEJ sleeved tubes with simulated throughwall circumferential PTls of less than  360'rc. The results from these tests were documented in Reference 8. In these tests, the sleeves were installed in tube samples using prototypic techniques. The tubes were first slit 100% throughwall over varying arc lengths from 120'o 240 at axial locations as near to the top of the HRLT as practical. The structurally prototyp-ic specimens were installed in a tensile testing machine and axially loaded to failure at a temperature of 600'F with no internal pressure. The specimens were configured such that the tube end was attached to the movable crosshead of the machine and the sleeve end was attached to the stationary base. Upon loading, the bending moment caused by the centroid of the remaining ligament being non-coincident with the axis of the tube, the loading axis, caused a smaH lateral deflection of the tube and sleeve in the direction of the slit. This small deflecting resulted in additional locking of the tube to the sleeve such that, in most cases, even The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign) was similar to that of Alloy 690 sleeves.
DAPLANTSU.BF6KJPNDXA.SEC                        A-3                                              10/03/9S
 
i Westinghouse non-Proprietary Class 3 with a 240'hroughwall slit, the sleeve failed in tension at about ten times the normal operation end cap load. For the specimens that did fail in the tube ligament, the failure loads were approximately twice the ultimate tensile capacity of the ligament material. Thus, the additional friction force developed at the hardroll interface of the sleeve and the tube exceeded the most limiting RG 1.121 requirement. In summary, an HEJ sleeved tube with a PTI with a non-symmetric remaining ligament(s) of about 90'as a structural integrity in excess of the most limiting RG 1.121 requirements.
The structural proof tests were performed on specimens which had been fabricated for leak testing. Following the leak tests, the sleeved tubes were machined to simulate a throughwall crack at the inflection point of the hard roll. All of the samples 360'ircumferential were  then  pressurized to a differential pressure of 3657 psi. The pressure was then gradually increased until slipping of the joint was noted. Initial slippage of the tubes was generally detected after an increase in the pressure of about 200 to 700 psi. The maximum pressures, i.e., those achieved when the tube was ejected ftom the sleeve, were not recorded, but did ap-proach pressures on the order of three time normal operating pressure differentials.
2.2 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2. The purpose of the analyses was to support the application of an ARC which included consider-ation of PTls located at the top of the HBLT. Such indications axe not a subject of'this report. The criterion supported by this report is that all PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent.
It is worth noting that  the analyses demonstrated that tubes with LTL material properties would meet the RG 1.121 3iQ? structural requirement if they were cracked 224 throughwall.
The acceptable throughwall angle is reduced to 196 if the remaining ligament is also assumed to be cracked 50% throughwall from the ID of the tube. The model employed assumed that no friction force, e.g., due to magnetite packing or corrosion product buildup within the tube-to-tube support plate crevices, would add to the resistance to axial motion of the tube or to reduce the applied load transmitted to the tube-to-sleeve joint.
Reference 11 noted that in addition to a postulated SLB event or spurious opening                        of a safety valve, the following moderate frequency accidents:
: 1)  uncontrolled rod withdrawal from full power,
: 2)  loss of reactor coolant fiow,
: 3)  loss of load, and
: 4)  loss of normal feedwater would result in higher than normal primary to secondary pressure differentials across the steam generator tubes. The maximum pressure differential across the tubes that may be DAP~MEPQKJPNDXA.SEC                              A-4                                                            10/03/95
 
Westinghouse non-Proprietary Class 3 experienced for steam generator loss of secondary side pressure events is 2560 psid. For items 1) through 4), the maximum pressure differential across the tubes would be expected to be less than 1800 psid. All of these events lead to closure of the steam line isolation valves and to a relatively rapid decrease of the differential pressure. Thus, the postulated SLB event presents the most severe loading to an HEJ sleeved tube with PTIs.
2.3 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the midpoint and that the bottom of the HRLT. The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions. The specimens with the tube removed at the midpoint of the a maximum leak rate of 0.016 gpm at SLB conditions, thus, also demonstrating a HRLT'xhibited significant resistance to primary-to-secondary leakage. These tests suggest that the presence of a "lip" of tube material below the top of the HRLT provides sufficient leakage restriction.
The proposed amendment would establish that any indications of tube degradation greater than 1.1" below the bottom of the HRUT would be acceptable for continued service, providing a "lip" of approximately 0.1", and would also provide the geometric configuration such that neither significant tube axial displacement nor significant tube leakage would be expected during a postulated SLB event.
Leak rate tests were also conducted using HEJ sleeved tube specimens with throughwall slits extending about 240 around the circumference of the tube. The slits were located at the top of the HRLT, i.e., approximately 1.0 to 1.03" below the bottom of the HRUT. The maximum leak rate at 600 F was found to be 0.015 gpm at a differential pressure of 2450 psi.
Based on the observation that one of the specimens may have exhibited leakage from one of the test fittings, a bounding SLB leak rate of 0.033 gpm per indication was established for 240 throughwall slits in the hardroH lower transition.
References 8 and 9 also documented the xesults of elevated temperature leak tests that were performed using specimens fabricated by sectioning and removing the tube section at the top of the HRLT. Since the acceptance of PTIs at the top of the HRLT is not a subject of this report, the results are not applicable and no discussion is necessary.
2.4 Crack Growth Rate Evaluations An assessment of the potential growth of the PIXs in both the circumferential and radial directions was provided in References 8, 11, and 12. The distribution of PTIs initially reported at Kewaunee was analyzed to determine if there was any apparent difference between the SGs. The average, miiiiinum, and maximum circumferential extents were similar, as were the standard deviations, and it was concluded that the distributions in each SG represented samples from the same parent population. Since the phenomena had not been previously Approximately 1.12 to 1.13 inch below the bottom of the HRUT.
DAPLANTSVEEPQKJPNDXA.SEC                      A-5
 
Westinghouse non-Proprietary Class 3 reposed, there was no historical database that could be used to estimate growth rates. For growth in the circumferential direction, an assumption was made regarding initiation and the average growth rate was estimated to be -35 per year. For analysis purposes, a rate of 45 per year was assumed. This was noted to be greater than a 95% confidence bound for ODSCC for observed growth at another plant that was operating at 614 F. In addition, the published data on crack growth rates of Alloy 600, of References 21, 22, 23 and 24, and Belgian data, were quoted to support the rate assumed of      45'er    year as being conservatively bounding. It was also noted that the estimated rate was about three standard deviations above the mean of observed TI'S data.
There also was, and still is, no directly measured data for the radial growth rate of circum-ferential PTIs in HEI sleeved tubes. Reference 12 presented information radial growth information for tubes based on field observations at McGuire, Doel 4, Arkansas Nuclear One, and Maine Yankee in support of a bounding rate of 21% per year in 7/8" nominal diameter tubes. Information from PWSCC of mechanical plugs was evaluated which indicated radial growth rates on the order of -17% to -23% per year in 7/8" diameter tubes depending on the material activation energy. Using the tube developed rate, it was concluded that 360 PTIs with depths of 53% (Kewaunee) to 58% (Point Beach 2) at the BOC would not exceed the RG 1.121 32ZNO, structural limit at the end of a one year cycle. Using the mechanical plug growth rates, 360'TIs with depths of 51% (Kewaunee) to 56% (Point Beach 2) would not be expected to exceed the RG 1.121 limits at EOC. Although it has been demonstrated by field experience that the occurrence of a PTl at the HRLT or HELT does not imply the presence of another PTI at either the HRUT or the HEUT, undetected PTIs at such'ocations would not be likely to violate the RG 1.121 requirements at the EOC.
3.0 Summary Prior submittals for license amendments requested approval for the implementation of multiple criteria to deal with the occurrence of PTls as a function of the location of the PIIs in the HEJ. These are summarized in the following paragraphs.
: 1. For indications below the bottom of the HRLT, it was demonstrated that PTls of any extent did not result in degradation of the joint such that the requirements of RG 1 121 would not be met at the end of an, or any, operating cycle. This was also
            ~
demonstrated for indication up to the middle of the HRLT. It was further demon-strated by test that the total leak rate from all such indications would not lead to a violation of the radiological release limits during a postulated SLB event.
: 2. For indications at the top of the HRLT it was demonstrated that indications on the order of 2/3 of the circumference of the tube, with the remaining ligament degraded to the detection level of the NDE, could be tolerated without exceeding the require-ments of RG 1.121 at the end of the operating cycle. The acceptance criteria for the beginning of the cycle length and depth of such indications were based on assumed conservative growth rates in the circumferential and radial directions. It was demon-strated by test and analysis that a significant number of throughwall PTIs could be DAPLANTSQ.EPQiE/PNDXA.SEC                        A-6                                          10/03/9S
 
Westinghouse non-Proprietary Class 3 allowed to remain in service without expecting leak rate limits to be exceeded.
The information presented in the main section of this report resulting from the destructive examination of the Kewaunee tubes continues to support the application of a criterion based on item 1. The results from the destructive examination of the Kewaunee tubes do not support the implementation of criteria based on item 2, even though the indications were not thxough wall and had a residual strength in excess of RG 1.121 requirements. Since the indications extended 360'round the tube, effective circumferential growth rates of at least 50'er year were experienced as a result of the presence multiple initiation sites. However, the informa-tion obtained does not contradict the radial growth rate developed in support of item 2.
Finally, the information obtained does support the detection thresholds previously considered for both the + Point and CECCO 3 probes.
D LPLANTSQ.EPQKlPNDXA.SEC                    A-7
 
Westinghouse non-Proprietaxy Class 3 Table A-1: Operating Parameters for V.S. Plants with Installed HEJs PP          Ps              Thot  Tcotd Plant            SG Loops (psia)      (psia)      (psi)  ('6  ('8 Point Beach 2        44            2000        775        1225  596.7 541.7 Cook    1          51            2100                  1453  582.0 518.0 Kewaunee            51            2250        715        1535  591.2 531.8 Zion  1          51            2250        725        1525  592.2 532.2 DM'LANYSlAEPalEJPNDXA.SEC                    A-8
 
End Cap Plug or Tensile Gripper.
Tube cut at elevations from the top of the transition to below the
                                                    ~              Tube
                                                      ~
bottom of the transition, and at various arc lengths.
Hardroll Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.
Figure A-I: HEJ specimen used for tensile testing.
D:EPLhRKEAEPKHEJPNDXhSlG                A-9                                7/29/95
 
Circumferential Crack Structural Model
                                                            .;  Assumed:
depth I
I I
                      /
                        /
                    /                I
                    /
I I
I I
I I
I I
I I
Throu ghwall Circumferential Neutral Axis                          Crack Figure A-2: Structural model for a tube with a circumferential throughwall crack.
D:KPLANTSKAEP4 EKJPNDXAPIG              A- 10                                  7/29(95
 
Critical Axial Load          vs. Through-Wall Crack Angle 7/8" x 0.050", Alloy 600 MA SG Tubes w/LTL Material Properties 4.5 4.0
                --- Critical  Angle for LTL Material 40% Through-Walt Ligament Note: Hardroll capacity of 300 l&assumed based on
                .- RG 1.121    NOp Limit                                        lower bound of test data.
                ~ . RG  1.121 SLB Limit 3.5 P) 3.0
      '0 o 2.5
      ~  2.0            1.8 79 KLS
      ~  1.5 1.4 27 KLEk
        '1.0 0.5 0.0 0                                                    200 224'50    256'50 Crack Angular Extant (Degrees)
Figure A-3 D:EPLARIS'tAEPtHEJPNDXJLZIG                          A- 11                                                7/2%95
 
              '60'W Circumferential                                  tW Axial cracking does cracking degrades the                              not degrade the axial axial strength of the joint                        strength of the tube/joint.
              ,  to less than the require-                          The leak resistance is
              ! ments of RG1.121.                                    degraded.
              .,'Leak resistance  is
                'ignificantly reduced.
360'W Circumferential cracking at this location, or below, does not degrade the axial strength of the joint to less than the require
                                                                      -ments of RG 1.121.
Leak resistance is HEJ Joint Critical                                       slightly reduced.
Tube Crack Locations Figure A-4: Critical tube crack locations in a HEJ.
D:REPLANTS hhEPKHEJPNDXhSIG                     A-12                                           7/29/95
 
4 ATTACHMENT 2 TO AEP:NRC:10820 Donald C. Cook Nuclear Plant Individual Plant Examination Human Reliability Analysis Summary of Methodology Changes and Example Calculations
 
ThIs attachment includes a summary of the changes made in the human reliability analysis methodology and example calculatIons.


==SUMMARY==
==SUMMARY==
OF METHODOLOGY CHANGES After a complete comparison of the original (Revision 0)AEPSC human reliability methods to the THERP[Reference 1]methods was performed, the AEPSC methods were updated to be more consistent with the THERP method and to reflect newer information.
OF METHODOLOGY CHANGES After a complete comparison of the original (Revision 0) AEPSC human reliability methods to the THERP [Reference 1] methods was performed, the AEPSC methods were updated to be more consistent with the THERP method and to reflect newer information. Below is a summary of the major inconsistencIes identified and their resolution in the revised (Revision 1) human reliability analysis:
Below is a summary of the major inconsistencIes identified and their resolution in the revised (Revision 1)human reliability analysis: Human reliabilit action s eciflc to se uences: Revision 0: A simplifying assumption was utilized that an operator action, such as establishing primary feed and bleed, was independent of the accident sequence.Revision 1: Sequence specific human error probabilities were calculated based on differences in timing, stress, dependence, and possible recoveries, using THERP.De endence Modelin: Revision 0: Dependence modeling was used infrequently.
Human reliabilit action     s eciflc to se uences:
Revision 1: Prior human action failures were assessed for modeling of dependent failures of subsequent actions, both within a modeled action and between different modeled actions.Performance sha in factors in dia nosis: Revision 0: Training and stress performance shaping factors were utilized for the diagnosis error frequencies.
Revision 0: A simplifying assumption was utilized that an operator action, such as establishing primary feed and bleed, was independent of the accident sequence.
Revision 1: The EPRI methodology
Revision 1: Sequence specific human error probabilities were calculated based on differences in timing, stress, dependence, and possible recoveries, using THERP.
[Reference 2]was used for diagnosis, which is consistent with THERP.Ex licit consideration of timin: Revision 0: For most cases, timing was only considered in a qualitative manner, with the diagnosis error rate being frequently based on the time needed to complete the action.Revision I: Timing was used to check if there was adequate time available to perform the action and any recovery actions.Workload was also considered as influencing the stress level.Consistent use of second erson checkin: Revision 0: Credit was generally taken for checking, to the extent needed to determine an acceptably accurate final result (i,e., once a human error failure path was found to be not the dominant path, further credits were not taken).Thus, known actions such as second person checking were inconsistently used.Revision 1: These credits were only used when the checking actions were clearly proceduralized (e.g., checker initials required), or on a case by case basis when it could be shown that the person actually makes a habit of reviewing what the operator was doing.
De endence   Modelin:
Trainin erformance sha in factors: Revision 0: Training performance shaping factors were included for execution type errors to address the impact of improved training and procedures.
Revision 0: Dependence modeling was used infrequently.
Revision 1: These generic training shaping factors were not used.Training was only considered on a case by case basis.Section 3.3 (attached) is an example of how operator training and practices were credited.References"Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications," A.D.Swain and H.E.Guttmann, NUREG/CR-1278, 1983.2."An Approach to the Analysis of Operator Actions in Probabillstlc Risk Assessment," EPRI TR-100259, EPRI Project 2847%1, Final Report, June, 1992.II.EXAMPLE CALCULATIONS The following portions from the Donald C.Cook Nuclear Plant's Human Reliability Analysis, Revision 1, are included with this attachment:
Revision 1: Prior human action failures were assessed for modeling of dependent failures of subsequent actions, both within a modeled action and between different modeled actions.
Section 3,3 High Pressure Cold Leg Recirculation'HPR)
Performance sha in factors in dia nosis:
Event Tree Level HEP Calculation Section 3.5 Depressurizatlon to Allow Low Pressure Iqjectlon (OLI)Event Tree Level HEP Calculation Attachment HPR Marked up procedure pages for Section 3.3 Attachment OLI Marked up procedure pages for Section 3.5 Figures E-8 through F 11 HPR fault trees HPR1, HPR2, HPR3 and HPR4 (only more complex fault trees, i.e,, those with AND gates, are included)Both HPR and OLI are good examples of how dependencies were treated in the analysis.The different types considered were dependencies between personnel, steps within a human failure event, and steps in different human failure events.Both cognitive and execution error dependence were considered.
Revision 0: Training and stress performance shaping factors were utilized for the diagnosis error frequencies.
The HPR fault trees are much more detailed than the majority of the HRA fault trees due to dependence with switchover to containment spray recirculation (CSR), which is performed at the same time.These switchover actions had common cognitive errors (i.e., totally dependent), and some common execution errors.These common cognitive and execution errors were quantified as totally dependent by using the same identiTiers in the corresponding fault trees.As described in Section 3.5.6, for a Medium LOCA event, OLI is required about the same time as switchover to recirculation.
Revision 1: The EPRI methodology [Reference 2] was used for diagnosis, which is consistent with THERP.
As many factors influence which comes first, it was conservatively assumed that OLI precedes switchover and switchover was considered totally dependent on OLI.For more information on the assumptions used in the analysis, see Section 3.3.3 of Attachment 1 of this submittal.
Ex licit consideration of timin:
Results are summarized in Tables 3.3-2 and 3.3-3 of Attachment 1 of this submittal.
Revision 0: For most cases, timing was only considered in a qualitative manner, with the diagnosis error rate being frequently based on the time needed to complete the action.
33 HPR-HIGH PRESSURE COLD LEG RECIRCULATION 3.3.1~Atication Small LOCA (SLO)with success of auxiliary feedwater (AF4)-HPRA (JMR)SLO with failure of auxiliary feedwater (AF4)-HPRB (JMR)Medium LOCA (MLO)with success of auxiliary feedwater (AF4)-HPRC (JMR)Transient with Steam Conversion Systems Available (TRA)-HPRD (JAJ)Transient without Steam Conversion Systems Available (TRS)-HPRE (JAJ)Large Steam Line/Feedline Break (SLB)-HPRF (JAJ)Loss of Offsite Power (LSP)-HPRG (JAJ)Steam Generator Tube Rupture (SGR)-HPRH (JAJ)Station Blackout (SBO)with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI-HPRS (JMR)SBO with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, failure of AF1, success of PBB, and success or failure of CSI-HPRT (JMR)SBO with success of AFT, success or failure of RCC, failure of AFC, success of XHR, CNU and PBB, and success or failure of CSI-HPRU (JMR)SBO with failure of AFT, success of XHR, CNU, and PBB, and success or failure of CSI-HPRV (JMR)Loss of CCW or ESW with success of RCP and RR2-HPRW (JMR)3.3.2~Dcacrt tion High pressure cold leg recirculation is required for several top events following successful ECCS high pressure injection when RWST reaches the low level setpoint of 32%.The transfer to recirculation is required to ensure a continued source of flow is available to the RCS so that core cooling is maintained following depletion of the RWST inventory.
Revision I: Timing was used to check ifthere was adequate time available to perform the action and any recovery actions. Workload was also considered as influencing the stress level.
In the HPR phase, the water that is spilled from the break collects in the lower containment, flows through course and fine mesh strainers into the recirculation sump.The CCPs and SI pumps then take suction from the recirculation sump via the residual heat removal system.During the manual switchover from the injection phase to the recirculation phase, both the RHR and SI pumps discharge line cross-tie valves are shut.This provides two separate trains of injection during the recirculation phase.3.3.3 Success Criteria and Timin Anal sis Success of this event requires one of two SI pumps and one of two CCPs to inject to one of three intact cold legs with the pump suction supplied by one of two RHR trains operating in the recirculation mode.If this top event fails, late core damage with the RCS at high pressure is postulated to occur.3.3-1  
Consistent use of second     erson checkin:
Revision 0: Credit was generally taken for checking, to the extent needed to determine an acceptably accurate final result (i,e., once a human error failure path was found to be not the dominant path, further credits were not taken). Thus, known actions such as second person checking were inconsistently used.
Revision 1: These credits were only used when the checking actions were clearly proceduralized (e.g.,
checker initials required), or on a case by case basis when it could be shown that the person actually makes a habit of reviewing what the operator was doing.
 
Trainin   erformance sha in factors:
Revision 0: Training performance shaping factors were included for execution type errors to address the impact of improved training and procedures.
Revision 1: These generic training shaping factors were not used. Training was only considered on a case by case basis. Section 3.3 (attached) is an example of how operator training and practices were credited.
References "Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications," A. D. Swain and H. E. Guttmann, NUREG/CR-1278, 1983.
: 2.       "An Approach to the Analysis of Operator Actions in Probabillstlc Risk Assessment," EPRI TR-100259, EPRI Project 2847%1, Final Report, June, 1992.
II. EXAMPLE CALCULATIONS The following portions from the Donald C. Cook Nuclear Plant's Human Reliability Analysis, Revision 1, are included with this attachment:
Section 3,3               High Pressure     Cold Leg Recirculation'HPR) Event Tree Level HEP Calculation Section 3.5               Depressurizatlon to Allow Low Pressure Iqjectlon (OLI) Event Tree Level HEP Calculation Attachment HPR           Marked up procedure pages for Section 3.3 Attachment OLI           Marked up procedure pages for Section 3.5 Figures E-8               HPR fault trees HPR1, HPR2, HPR3 and HPR4 (only more complex fault through F 11              trees, i.e,, those with AND gates, are included)
Both HPR and OLI are good examples of how dependencies were treated in the analysis. The different types considered were dependencies between personnel, steps within a human failure event, and steps in different human failure events. Both cognitive and execution error dependence were considered.
The HPR fault trees are much more detailed than the majority of the HRA fault trees due to dependence with switchover to containment spray recirculation (CSR), which is performed at the same time. These switchover actions had common cognitive errors (i.e., totally dependent), and some common execution errors. These common cognitive and execution errors were quantified as totally dependent by using the same identiTiers in the corresponding fault trees.
As described in Section 3.5.6, for a Medium LOCA event, OLI is required about the same time as switchover to recirculation. As many factors influence which comes first, it was conservatively assumed that OLI precedes switchover and switchover was considered totally dependent on OLI.
For more information on the assumptions used in the analysis, see Section 3.3.3 of Attachment 1 of this submittal. Results are summarized in Tables 3.3-2 and 3.3-3 of Attachment 1 of this submittal.
 
33     HPR - HIGH PRESSURE COLD LEG RECIRCULATION 3.3.1 ~Atication Small LOCA (SLO) with success of auxiliary feedwater (AF4) - HPRA (JMR)
SLO with failure of auxiliary feedwater (AF4) - HPRB (JMR)
Medium LOCA (MLO) with success of auxiliary feedwater (AF4) - HPRC (JMR)
Transient with Steam Conversion Systems Available (TRA) - HPRD (JAJ)
Transient without Steam Conversion Systems Available (TRS) - HPRE (JAJ)
Large Steam Line/Feedline Break (SLB) - HPRF         (JAJ)
Loss of Offsite Power (LSP) - HPRG (JAJ)
Steam Generator Tube Rupture (SGR) - HPRH           (JAJ)
Station Blackout (SBO) with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI - HPRS (JMR)
SBO with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, failure of AF1, success of PBB, and success or failure of CSI - HPRT (JMR)
SBO with success of AFT, success or failure of RCC, failure of AFC, success of XHR, CNU and PBB, and success or failure of CSI - HPRU (JMR)
SBO with failure of AFT, success of XHR, CNU, and PBB, and success or failure of CSI
        - HPRV (JMR)
Loss of CCW or ESW with success of RCP       and RR2 - HPRW     (JMR) 3.3.2 ~Dcacrt tion High pressure cold leg recirculation is required for several top events following successful ECCS high pressure injection when RWST reaches the low level setpoint of 32%. The transfer to recirculation is required to ensure a continued source of flow is available to the RCS so that core cooling is maintained following depletion of the RWST inventory. In the HPR phase, the water that is spilled from the break collects in the lower containment, flows through course and fine mesh strainers into the recirculation sump. The CCPs and SI pumps then take suction from the recirculation sump via the residual heat removal system. During the manual switchover from the injection phase to the recirculation phase, both the RHR and SI pumps discharge line cross-tie valves are shut. This provides two separate trains of injection during the recirculation phase.
3.3.3 Success Criteria and   Timin Anal sis Success   of this event requires one of two SI pumps and one of two CCPs to inject to one of three intact cold legs with the pump suction supplied by one of two RHR trains operating in the recirculation mode. If this top event fails, late core damage with the RCS at high pressure is postulated to occur.
3.3-1
 
The Event Tree Notebook provides justification for the time to switchover from accident initiation and the amount of time the operator has to complete the switchover based on useable volume of the RWST for each application of this top event. A summary of these success criteria times is presented below. Refer to the Event Tree Notebook for additional information.
For medium LOCA (MLO) and small LOCA (SLO), the time from accident initiation until switchover is required would be approximately 30 minutes, assuming all safeguards pumps initially operating. This assumes containment spray is actuated early in the accident. The time to switchover would be longer if there are equipment failures or if spray actuation is delayed. Once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment (Reference 1).
For steam generator tube rupture (SGR) events, containment spray actuation would be expected about 30 minutes following initiation of primary bleed (See Success Criteria Notebook, Table 28). Switchover to high pressure cold leg recirculation would then be required about 30 minutes after. this. This relative timing would also be expected for transient events in which bleed and feed recovery is used due to unavailability of feedwater for decay heat removal. Once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment. This time is the same as that for MLO and SLO since containment spray actuation is expected following initiation of bleed and feed.
This timing analysis is also applicable to TRA, TRS and LSP events in which bleed and feed recovery is used due to the unavailability of feedwater for decay heat removal.
For SLB events, the time from accident initiation for a large secondary break inside containment until switchover is conservatively assumed to be approximately 30 minutes. This assumes containment spray is actuated early in the accident if the break is located inside containment. Similar to MLO and SLO, once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment.
For SBO events, depending on the amount of RCP seal leakage and the resulting need for containment spray injection, the time at which switchover to cold leg recirculation would be required could be as short as 30 minutes after spray and high pressure injection are actuated to several hours if spray actuation is not required. The timing requirements for completing the switchover to cold leg recirculation is 17 minutes, similar to MLO and SLO, since high pressure injection may also be actuated.
For SSW and CCW events, the timing analysis is the same as that of SBO, recirculation may be required within 30 minutes of event initiation and completion of the switchover actions within 17 minutes.
Procedures Upon a small LOCA causing a reactor trip and SI actuation, the operators will enter E-0. At step 25, they will transfer to E-1, and at step 14 of E-1, they will transfer to ES-1.2.
The Emergency Operating Procedure used to perform switchover to cold leg recirculation is 3.3-2


The Event Tree Notebook provides justification for the time to switchover from accident initiation and the amount of time the operator has to complete the switchover based on useable volume of the RWST for each application of this top event.A summary of these success criteria times is presented below.Refer to the Event Tree Notebook for additional information.
~ 4 ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Rev. 2 ES-1.3 is entered from:
For medium LOCA (MLO)and small LOCA (SLO), the time from accident initiation until switchover is required would be approximately 30 minutes, assuming all safeguards pumps initially operating.
a)       E-1, LOSS OF REACTOR OR SECONDARY COOLANT, Rev. 5, Step 15, on low RWST level.
This assumes containment spray is actuated early in the accident.The time to switchover would be longer if there are equipment failures or if spray actuation is delayed.Once RWST level reaches 32%and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment (Reference 1).For steam generator tube rupture (SGR)events, containment spray actuation would be expected about 30 minutes following initiation of primary bleed (See Success Criteria Notebook, Table 28).Switchover to high pressure cold leg recirculation would then be required about 30 minutes after.this.This relative timing would also be expected for transient events in which bleed and feed recovery is used due to unavailability of feedwater for decay heat removal.Once RWST level reaches 32%and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment.
b)       ECA-2.1, UNCONTROLLED DEPRESSURIZATION OF ALLSTEAM GENERATORS, Rev. 4, Step 9, on low RWST level.
This time is the same as that for MLO and SLO since containment spray actuation is expected following initiation of bleed and feed.This timing analysis is also applicable to TRA, TRS and LSP events in which bleed and feed recovery is used due to the unavailability of feedwater for decay heat removal.For SLB events, the time from accident initiation for a large secondary break inside containment until switchover is conservatively assumed to be approximately 30 minutes.This assumes containment spray is actuated early in the accident if the break is located inside containment.
c)       Other procedures whenever RWST level reaches the switchover setpoint.
Similar to MLO and SLO, once RWST level reaches 32%and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment.
For a small LOCA with success of AFW, entry into ES-1.3 will occur from the caution statement at the beginning of ES-1.2, and the RWST low level alarm provides cognitive recovery. This transition could also be from the foldout page for E-1 and ES-1.2, but this is conservatively not credited. Although the check for RWST level is performed in different procedures, depending on the initiating event, the action is the same for all cases. The Cue Table is applicable to all listed applications.
For SBO events, depending on the amount of RCP seal leakage and the resulting need for containment spray injection, the time at which switchover to cold leg recirculation would be required could be as short as 30 minutes after spray and high pressure injection are actuated to several hours if spray actuation is not required.The timing requirements for completing the switchover to cold leg recirculation is 17 minutes, similar to MLO and SLO, since high pressure injection may also be actuated.For SSW and CCW events, the timing analysis is the same as that of SBO, recirculation may be required within 30 minutes of event initiation and completion of the switchover actions within 17 minutes.Procedures Upon a small LOCA causing a reactor trip and SI actuation, the operators will enter E-0.At step 25, they will transfer to E-1, and at step 14 of E-1, they will transfer to ES-1.2.The Emergency Operating Procedure used to perform switchover to cold leg recirculation is 3.3-2
3.3.5 Critical and Recove       Actions The following are the primary tasks which must be completed for satisfying the success criteria of the HPR actions:
~4 ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Rev.2 ES-1.3 is entered from: a)E-1, LOSS OF REACTOR OR SECONDARY COOLANT, Rev.5, Step 15, on low RWST level.b)ECA-2.1, UNCONTROLLED DEPRESSURIZATION OF ALL STEAM GENERATORS, Rev.4, Step 9, on low RWST level.c)Other procedures whenever RWST level reaches the switchover setpoint.For a small LOCA with success of AFW, entry into ES-1.3 will occur from the caution statement at the beginning of ES-1.2, and the RWST low level alarm provides cognitive recovery.This transition could also be from the foldout page for E-1 and ES-1.2, but this is conservatively not credited.Although the check for RWST level is performed in different procedures, depending on the initiating event, the action is the same for all cases.The Cue Table is applicable to all listed applications.
: 1.       Monitor for low RWST level and the need for establishing cold leg recirculation (Caution statement before ES-1.2) (cognitive)
3.3.5 Critical and Recove Actions The following are the primary tasks which must be completed for satisfying the success criteria of the HPR actions: 1.Monitor for low RWST level and the need for establishing cold leg recirculation (Caution statement before ES-1.2)(cognitive) 2.Reset SI (Step 1 of ES-1.3)3.Align West RHR for recirculation (Step 4 of ES-1.3)4.Align CCPs and SI pumps for recirculation (Step 5 of ES-1.3)5.Align east RHR pump for recirculation (Step 6 of ES-1.3)See Table 3.3-1, Cue Table for HPR for identification of symptoms for establishing high pressure cold leg recirculation.
: 2.       Reset SI (Step   1 of ES-1.3)
See Table 3.3-2, Subtask Analysis for HPR for identification of critical or relevant recovery actions associated with cold leg recirculation.
: 3.       Align West RHR for recirculation (Step 4 of ES-1.3)
3.3.6~Assum tiuus See sections 3.3.8, 3.3.9 and 3.3.10.3.3.7 Si nificant 0 erator Interview Findin s 1.Switchover to recirculation takes top priority above all other actions.Whenever the RWST level reaches 32%, they will stop what they are doing and immediately go to ES-1.3.The unit supervisor and RxO will not be interrupted with other tasks, and 3.3-3 others in the control room know to not get in the way.2.The unit supervisor, who is reading the procedure, will watch each step performed by the RxO, and wait until completion of the step (i.e., until valves have transferred to correct position)before going on to the next step.3.There will be at least two others in the control room who will be going through the procedure and ensuring that the steps are carried out completely (i.e., the extra US and the STA).The SS, ASS and BOPO may also be watching.4.Whenever the operators start a pump or close a suction valve, they will watch the pump amps and discharge flow.This is second nature to the operators.
: 4.       Align CCPs and SI pumps for recirculation (Step 5 of ES-1.3)
Most unit supervisors will actually start switchover before the RWST has reached 32%, so they have do not have to hurry, and will not have to deal with the confusion of the RHR pumps tripping on low-low RWST level.They are encouraged to start early.3.3.8 Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21).Tables 3.3-3 and 3.3-4 contain the calculation of the cognitive human error probability, pc, that the operators fail to recognize the need for switchover to high pressure recirculation.
: 5.       Align east RHR pump for recirculation (Step 6 of ES-1.3)
Pc was calculated in Table 3.3-3 to be 3.1E-03, without recovery.The recovered value of pc was calculated in Table 3.34 to be 1.5E-04.3.3.9 Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.(T20-x refers to Table 20-x of Reference 2.)The critical actions identified in Table 3.3-2 were reviewed to determine the dominant critical actions to be quantified.
See Table 3.3-1, Cue Table for HPR for identification     of symptoms for establishing high pressure cold leg recirculation.
Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability.
See Table 3.3-2, Subtask Analysis     for HPR for identification of critical or relevant recovery actions associated with cold leg recirculation.
Attachment HPR is a copy of the relevant portion of ES-1.3, with dominant critical steps circled.The reasons why the other critical steps (identified in Table 3.3-2)are not dominant are also included.3.3.9.1 Ste 4 Ali n West RHR Pum for Recirculation:
3.3.6 ~Assum   tiuus See sections   3.3.8, 3.3.9 and 3.3.10.
4a Sto 8c lockout W RHR PP Errors of Omission: Omit step/page:
3.3.7 Si nificant 0   erator Interview Findin   s
1.3E-03 (T20-7 03, Assumption G)Step 4 of procedure Errors of Commission:
: 1.       Switchover to recirculation takes top priority above all other actions. Whenever the RWST level reaches 32%, they will stop what they are doing and immediately go to ES-1.3. The unit supervisor and RxO will not be interrupted with other tasks, and 3.3-3
3.3-4 Select wrong control when it is dissimilar to adjacent controls: negligible (Table 20-12,&#xb9;1A gtem 1A has been added by Swain since NUREG/CR-1278))
The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the West RHR panel.4c o en recirc sum to W RHR/CTS um valve Errors of Omission: Omit step/page:
1.3E-03 (T20-7&#xb9;3, Assumption G)Step 4 of procedure Errors of Commission:
Select wrong control when it is dissimilar to adjacent controls: negligible (Table 20-12,&#xb9;1A/tern 1A has been added by Swain since NUREG/CR-1278))
This control is different from adjacent controls because it is metal and has a key in it.Total error robabilit for Ste s 4a&c: 1.3E-03+1.3E-03=2.6E-03 4d Start W RHR PP Errors of Omission: Omit step: 1.3E-03 (T20-7&#xb9;3, Assumption G)Step 4 of procedure Errors of Commission:
negligible, see Errors of Commission for Step 4a 3.3-5 Ste 5 Ali n SI Pum s and CCPs for Recirculation Si o en SI um suction from west RHR HX valve and~5'en SI um suction crosstie to CCP valves These two steps were considered as one perceptual unit.These are adjacent procedure steps and the valve controls are all right next to each other (i.e., these actions are not separated by time or location).
Errors of Omission: Omit step/page:
1.3E-03 (T20-7&#xb9;3, Assumption G)Step 5 of procedure Errors of Commission:
Select wrong control on panel from array of similar appearing controls: 1.3E-03 (T20-12&#xb9;3)All safety injection suction and discharge valves are in one area on SI control panel.Total error robabilit for Ste 5: 2.6E-03 Ste 6 Ali n East RHR Pum for Recirculation:
6b Sto&lockout East RHR PP Errors of Omission: Omit step/page:
1.3E-03 (T20-7&#xb9;3, Assumption G)Step 6 of procedure Errors of Commission:
Select wrong control when it is dissimilar to adjacent controls: negligible (Table 20-12,&#xb9;1A (item 1A has been added by Swain since NUREG/CR-1278))
The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the East RHR panel.3.3-6 6d o en recirc sum to East RHR/CTS um valve Errors of Omission: Omit step: 1.3E-03 (T20-7&#xb9;3, Assumption G)Step 6 of procedure Errors of Commission:
Select wrong control when it is dissimilar to adjacent controls: negligible (Table 20-12,&#xb9;1A (1tem 1A has been added by Swain since NUREG/CR-1278))
This control is different from adjacent controls because it is metal and has a key in it.Total error robabilit for Ste s 6b&d: 1.3E-03+1.3E-03=2.6E-03 6e Start East RHR PP Errors of Omission: Omit step: 1.3E-03 (T20-7&#xb9;3, Assumption G)Step 6 of procedure Errors of Commission:
negligible, see Errors of Commission for Step 6b 6f 0 en CCP suction from East RHR HX valve Errors of Omission: Omit step: 1.3E-03 (T20-7&#xb9;3, Assumption G)Step 6 of procedure Errors of Commission:
Select wrong control on panel from array of similar appearing controls: 3.3-7 ll'II 1.3E-03 (T20-12 P3)It is clearly labeled on the boric acid charging and letdown panel.It is at the bottom left of the panel.3.3.10 Calculation of Total Human Error Probabilit for Failure to Switchover to HPR The cognitive and execution error probabilities were calculated in sections 3.3.8 and 3.3.9 to be: pc'(HPRA)=1.5E-04 pe(steps 4a&c)=2.6E-03 pe(step 4d)=1.3E-03 pe(step 5)=2.6E-03 pe(steps 6b&d)=2.6E-03 pe(step 6e)=1.3E-03 pe(step 6f)=2.6E-03 (without stress, dependence or recovery)(without stress, dependence or recovery)(without stress, dependence or recovery)(without stress, dependence or recovery)(without stress, dependence or recovery)(without stress, dependence or recovery)In order for alignment of the east RHR train (step 6)to recover for an error in aligning the west train (step 4), the operators must recognize that there is not adequate flow from the west RHR pump train before aligning the high head pumps (step 5).The high head pumps are expected to fail quickly without a suction source (per operator interviews).
A high level of dependence is assumed, therefore, for the operators recognizing that there is a problem with the east RHR train before they align the high head pumps in step 5.This was modelled by a high dependence failure of noticing failed step 4, so performing step 6 before step 5 (i.e., human error probability
=0.5).A high level of dependence is conservative, however, as the operator and unit supervisor will be watching pump amperes when suction sources are closed (e.g., for the high head pumps)and when the RHR pumps are started (per operator interviews).
The ammeters are right above the pump controls in the control room.Also, the unit supervisor watches what the operator is doing, and waits for completion of one step before moving on to another (which can be significant, as it takes about 30 seconds for the RWST suction valves to close).A moderate level of dependence was assumed between failure of step 4 and the initial tasks in step 6.Although steps 4 and 6 are similar, they are different procedure steps, on different pages, and unless the operators realize they failed step 4, step 5 will be performed between them.An extremely high level of stress is assigned to all step 6 actions, though, as these actions are only critical if the operators failed in step 4.Per operator interviews, a minimum of two people will be watching the unit supervisor and operator go through the switchover using a copy of the procedure.
Whenever switchover is occurring, it is top priority, and almost everything else has come to a stop.The STA does not want to get in the way, so he will be going through the procedure and watching what is going on, as well as the extra unit supervisor.
The unit supervisor is not interrupted during switchover, therefore, the extra unit supervisor will be free to watch the switchover.
Several more people may also be watching, but this is conservatively not credited.If it is under an hour after event initiation, the shift supervisor may still be busy with his E-plan duties.The assistant shift supervisor may be busy in his role as contingency director, and the BOPO may not be paying close enough attention to catch a mistake.3.3-8 Only one recovery was given to the extra unit supervisor and STA.A low level of dependence was assumed between them and the unit supervisor and RxO because they are not interacting at all with the US and RxO;they are standing back and fulfilling a supervisory type role.This combined effort was equated to that of the shift supervisor in Table 204, Reference 2.Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks.Per Table 20-17, if the basic'uman error probability (BHEP)is greater than.01, the equations to use for low, moderate, and high dependence are: (1+19N)/20, (1+6N)/7, and (1+N)/2, respectively.
Per Table 20-21, if the BHEP is less than or equal to.01, HEPs of.05,.15 and.5 should be used for low, moderate, and high dependence, respectively.
Recovery due to extra unit supervisor and STA following procedure and actions=0.05 These parameters and assumptions are used below to determine the total human error probability for failure to switchover for high pressure recirculation under different conditions.
HPRA: Switchover to hi h ressure recirculation u on a small LOCA and successful AFW~AF4 (CSI status is not addressed.
If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event.The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)A moderately high level of stress was assumed for steps 4 and 5.This is a procedure that is well known and practiced by the operators, and they are not concentrating on doing anything else during this procedure, as it takes top priority.pc'(HPRA)=1.5E-04 pe'(steps 4a&c)=2.6E-03*2=5.2E-03 pe'(step 4d)=1.3E-03*2=2.6E-03 pe'(step 5)=2.6E-03*2=5.2E-03 pe'(steps 6b&d)=2.6E-03*5 with MD=(1+6*1.3E-02)/7
=1.5E-01 pe'(step 6e)=1.3E-03~5=6.5E-03 pe'(step 6f)=2.6E-03*5=1.3E-02 pe'(recognize to do step 6 before step 5)=HD=0.5 Recovery, execution errors (extra US and STA)=0.05 (HPRA-LPR-CSRHE)(REC-4A&C-MHHE)(REC--4D-MH HE)(REC---5-MHHE)(REC-6B&D-EHHE-M)(REC--6E-EHHE)(REC-6F-EHHE)(REC-6TH EN5-HE-H)(REC-US-STA
-HE-L)The total human error probability (THEP)for failing to switchover to high pressure recirculation upon a small LOCA and successful AFW (AFW)is calculated as shown in fault tree HPR1: THEP(HPRA)
=pc'fpe'(step 4)*pe'(step 6)+pe'(step 5)]*recovery(extra US or STA)3.3-9 THEP(HPRA)
=1.5E-04+[(5.2E-03+2.6E-03)*(0.5+1.4E-01+6.5E-03+1.3E-02)+5.2E-03]*5.0E-02 THEP(HPRA)
=6.7E-04 HPRB: Switchover to hi h ressure recirculation u on a small LOCA failure of AFW AF4 and success of rima bleed and feed BF1 (CSI status is not addressed.
If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event.The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)For this scenario, the operators will transition from Step 18 of E-0 to FR-H.1 to complete PBF.Due to adverse containment conditions, the operators will immediately go to step 18 of FR-H.1.They should still be in FR-H.l when RWST level reaches 32%.The caution statement after step 25 of FR-H.1 will be their cue to monitor the RWST level, with cognitive recovery provided by the alarm.It is assumed that the RxO monitoring the RWST level will have a high work load, as they will be busy with PBF and subsequent actions in FR-H.1.The only change in pc'rom pc'(HPRA)will be to tree b.The new end path will be 1 due to the high work load, which is not recovered.
pc'(HPRB)=7.5E-04+3.0E-07 pc'(HPRB)=7.5E-04 (HPRB-LPR-CSRHE)
The extremely high level of stress from primary bleed and feed is conservatively assumed to still exist.Otherwise, the actions have the same failure probabilities as HPRA.pe'(steps 4a&c)=2.6E-03~5=1.3E-02 pe'(step 4d)=1.3E-03*5=6.5E-03 pe'(step 5)=2.6E-03*5=1.3E-02 pe'(steps 6b&d)=2.6E-03*5 with MD=(1+6~1.3E-02)/7
=1.5E-01 pe'(step 6e)=1.3E-03~5=6.5E-03 pe'(step 6f)=2.6E-03*5=1.3E-02 pe'(recognize to do step 6 before step 5)=HD=0.5 Recovery, execution errors (extra US and STA)=0.05 (REC-4A&C-EHHE)(REC--4D-EH HE)(REC---5-EH HE)(REC-6B&D-EHHE-M)(REC-6E-EHHE)(REC-6F-EHHE)(REC-6TH ENS-HE-H)(REC-US-STA-HE-L)
The total human error probability (THEP)for failing to switchover to high pressure recirculation upon a small LOCA, failure of AFW (AF4), and success of PBF is calculated as shown in fault tree HPR2: THEP(HPRB)
=pc'[pe'(step 4)~pe'(step 6)+pe'(step 5)]*recovery(extra US or STA)THEP(HPRB)
=7.5E-04+[(1.3E-02+6.5E-03)*(0.5+1.4E-01+6.5E-03+1.3E-02)+1.3E-02]*5.0E-02 THEP(HPRB)
=2.0E-03 3.3-10 S 8't HPRC: Switchover to hi h ressure recirculation u on a medium LOCA and successful
~AFW AF4 (CSI status is not addressed.
If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event.The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)This is the exact same scenario as HPRA, except for the size of the LOCA.For this event, however, this difference in LOCA size is irrelevant, as the timing and flow through the procedures should be the same.The total human error probability (THEP)for failing to switchover to high pressure recirculation upon a medium LOCA and successful AFW (AFW)is the same as HPRA: THEP(HPRC)
=THEP(HPRA)
=6.7E-04 HPRD: Switchover to high pressure recirculation after a transient with steam conversion systems available (TRA), followed by loss of auxiliary feedwater (AF1), a loss of alternate secondary cooling sources (AFW from the other Unit and main feedwater-MF1, and SG depressurization combined with condensate-OA5), and success of primary feed and bleed (PBT).In this scenario, the operator initiates a LOCA when primary feed and bleed is started.Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates.Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out.This timing is similar to the development in the small LOCA event tree (SLO)on the path where high pressure injection (HP2)succeeds and auxiliary feedwater (AF4)succeeds, leading to high pressure recirculation about a half hour later.Thus, equation HPRD equals HPRA, and fault tree HPR1 is used.For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRD is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.HPRE: Switchover to high pressure recirculation after a transient with failure of steam conversion systems (TRS), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBT).In this scenario, the operator initiates a LOCA when primary feed and bleed is started.Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates.Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out.This timing is similar to the development in the small LOCA event tree (SLO)on the path where high pressure injection (HP2)succeeds and auxiliary feedwater (AF4)succeeds, leading to high pressure recirculation about a half hour later.Thus, equation HPRE equals HPRA, and fault tree HPR1 is used.For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRE is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.3.3-11 HPRF: Switchover to high pressure recirculation after a large steam/feedwater line break (SLB), followed by successful high pressure injection (HP3)and successful isolation of the faulted SG (MS1)but loss of auxiliary feedwater (AFS), countered by success of primary feed and bleed (PBS).In this scenario, the operator initiates a LOCA when primary feed and bleed is started.Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates.Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out.This timing is similar to the development in the small LOCA event tree (SLO)on the path where high pressure injection (HP2)succeeds and auxiliary feedwater (AF4)succeeds, leading to high pressure recirculation about a half hour later.Thus, equation HPRF equals HPRA, and fault tree HPR1 is used.For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRF is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.HPRG: Switchover to high pressure recirculation after a transient loss of offsite power (LSP), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBL).In this scenario, the operator initiates a LOCA when primary feed and bleed is started.Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates.Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out.This timing is similar to the development in the small LOCA event tree (SLO)on the path where high pressure injection (HP2)succeeds and auxiliary feedwater (AF4)succeeds, leading to high pressure recirculation about a half hour later.However, there may be one train equipment unavailable depending on the diesel generator (DG)response.If two diesel generators succeed, then HPR equals HPRA.If only one diesel generator succeeds, then HPR equals HPRA (in timing)but with only one train available.
Although the case for the two DG success is more likely (-95%), the case of success of only one DG (-5%)leads to more restrictive modeling and has conservatively been applied.Thus, equation HPRG equals HPRA Steps 4 and 5, as calculated in fault tree HPR4.For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRG is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.HPRH: Switchover to high pressure recirculation after a steam generator tube rupture (SGR), followed by loss of all auxiliary feedwater (AF2 and AF3), and success of primary feed and bleed (PBG).In this scenario, the operator initiates a LOCA inside of containment when primary feed and bleed is started.Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates.Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out.This timing is similar to the development in the small LOCA event tree (SLO)on the path where high pressure injection (HP2)succeeds and auxiliary feedwater (AF4)succeeds, leading to high pressure recirculation about a half hour later.Thus, HPRH equals HPRA, and fault tree HPR1 is used.3.3-12


HPRS: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU RRI and AF1 and success or failure of CSI Dependency upon CSI failure is not evaluated, because THEP for CSI is mostly due to errors of omission, which are independent for steps on different pages, with the remainder due to cognitive failures.If the operators failed to actuate CSI, switchover to recirculation is not necessary for 1.5 hours after this CSI failure.In this time, there are no other system failures.This amount of time, with no other major operator tasks, negates any cognitive dependency.
others in the control room know to not get in the way.
Early failure of RCS cooldown (RCC)is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time.This early failure should not cause'a higher level of stress at this time.RCC failure just mandated earlier power restoration, which was successful.
: 2.       The unit supervisor, who is reading the procedure, will watch each step performed by the RxO, and wait until completion of the step (i.e., until valves have transferred to correct position) before going on to the next step.
Per the Event Tree Notebook (Reference 1), with the containment spray and high head ECCS pumps injecting, there is 17 minutes available for switchover, and switchover will not be required until at least 30 minutes following completion RRI and CSI.For this scenario, everything has been successful following power restoration, and at least 30 minutes have elapsed since operators finished RRI and CSI.Power has been back for an hour, and things are under control.The operators will transfer to E-1 (LOSS OF REACTOR OR SECONDARY COOLANT)at the end of ECA-0.2 (i.e., step 14).The cue for the operators to monitor RWST level will be Step 15 of E-1.A low work load can be assumed at this time and recovery with the alarm can also be credited.This results in a value for pc'qual to that for HPRA.(The end state for tree e is all that changes (from b to c), but the value remains the same (3.0E-03).)
: 3.       There will be at least two others in the control room who will be going through the procedure and ensuring that the steps are carried out completely (i.e., the extra US and the STA). The SS, ASS and BOPO may also be watching.
pc'(HPRS)=pc'(HPRA)As things are under control, recovery due to the extra US/STA can be credited.Therefore, the total human error probability for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI is the same as that from HPRA.THEP(HPRS)
: 4.       Whenever the operators start a pump or close a suction valve, they will watch the pump amps and discharge flow. This is second nature to the operators.
=THEP(HPRA)
Most unit supervisors will actually start switchover before the RWST has reached 32%, so they have do not have to hurry, and will not have to deal with the confusion of the RHR pumps tripping on low-low RWST level. They are encouraged to start early.
Fault tree HPR1 is used.HPRT: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU and RRI failure of AF1 success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF).Therefore, as these paths include success of PBF, there is no dependence to consider.3.3-13 Failure of the containment spray system is not addressed separately.
3.3.8  Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21). Tables 3.3-3 and 3.3-4 contain the calculation of the cognitive human error probability, pc, that the operators fail to recognize the need for switchover to high pressure recirculation. Pc was calculated in Table 3.3-3 to be 3.1E-03, without recovery. The recovered value of pc was calculated in Table 3.34 to be 1.5E-04.
If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours following power recovery).
3.3.9  Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.
The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.Early failure of RCS cooldown (RCC)is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time.This early failure should not cause a higher level of stress at this time.RCC failure just mandated earlier power restoration, which was successful.
(T20-x refers to Table 20-x of Reference 2.) The critical actions identified in Table 3.3-2 were reviewed to determine the dominant critical actions to be quantified. Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability. Attachment HPR is a copy of the relevant portion of ES-1.3, with dominant critical steps circled. The reasons why the other critical steps (identified in Table 3.3-2) are not dominant are also included.
For this scenario, the operators will transition to FR-H.1 following completion of Step 10 of ECA-0.2.For hydrogen control, the operators may transfer to FR-Z.1 (per caution statement before step 27 of FR-H.1)and then return to FR-H.1.Eventually, the operators will leave FR-H.1 to transfer E-1 or to switchover to recirculation (ES-1.3).The caution statement in FR-H.1 (before step 26)should be their cue to monitor RWST level, with cognitive recovery provided by the alarm.It is assumed that the operator monitoring RWST level will have a high work load, as they will be busy with FR-H.1 and FR-Z.1.This results in a pc'qual to that for HPRB: pc'(HPRT)=pc'(HPRB)The extremely high level of stress from primary bleed and feed is conservatively assumed to still exist.Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, and failure of AF1, success of PBB, and success or failure of CSI is the same as HPRB.THEP(HPRT)
3.3.9.1          Ste  4 Ali n West RHR Pum        for Recirculation:
=THEP(HPRB)
4a      Sto  8c lockout W RHR PP Errors of Omission:
Fault tree HPR2 is used.HPRU: Switchover to hi h ressure recirculation u on a'SBO success'of AFT success or failure of RCC failure of AFC success of XHR and CNU success of PBB and success or failure of CSI See writeup for HPRT.Fault tree HPR2 is used.This is the same scenario as described in HPRT.AFW has been lost (worse case scenario)for a couple hours before power recovery, and PBB must be initiated right after completion of CSI (i.e., step 10 of ECA-0.2).Early failure of RCS cooldown (RCC)is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time.This early failure should not cause a higher level of stress at this time.RCC failure just mandated earlier power restoration, which was successful.
Omit step/page:
3.3-14 HPRV: Switchover to hi h ressure recirculation u on a SBO failure of AFT success of XHR and CNU success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF).Therefore, as this path includes success of PBF, there is no dependence to consider.Failure of the containment spray system is not addressed separately.
1.3E-03 (T20-7 03, Assumption G)
If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours following power recovery).
Step 4 of procedure Errors of Commission:
The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.An extemely high level of stress is assumed, as a blackout with failure of the TDAFP is a severe incident for the operators, and switchover is required fairly early in the accident (about 2 hours from loss of power).(This level of stress is also assumed because it follows PBB.)As described in HPRT, a high work load is assumed for the RxO for calculation of pc'.Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO, failure of AFT, success of XHR and CNU, success of PBB, and success or failure of CSI is the same as HPRT.THEP(HPRV)
3.3-4
=THEP(HPRT)
=THEP(HPRB)
Fault tree HPR2 is used.HPRW: Switchover to hi h ressure recirculation u on a loss of CCW or ESW and success of RCP and RR2 (CSI status is not addressed.
If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event.The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)HPR will not be required until very late into the event.Since the RCPs were tripped, seal failure is not actually expected until an hour or two into the event (see RCP, Section 3.25.2), at which time the containment sprays will be actuated.With both containment spray pumps operating, it takes at least 35 more minutes to reach the RWST low level.A charging pump is started (i.e., RR2A)within 30 minutes of the restoration of CCW/ESW.As a result, HPR is expected after a charging pump has been started in RR2A.At this point, things are well under control.The small LOCA through the seals is under control and CCW/ESW has been restored.A low work load is considered for the operators by the time HPR is needed.The operators will probably still be in OHP 4022.016.004 when HPR is required, since they will not leave it until after the RCS is cooled and depressurized enough to start RHR.There is not a procedure step to warn the operators to monitor RWST level, but the operators know to monitor this.Only cognitive tree b applies (data not attended to)to this situation.
End path I from tree b results in a cognitive value of 7.5E-04.No recovery is applied to this value.(Note: the path for high work load was conservatively followed, so this cognitive failure probability can be used for other scenarios.)
3.3-15


pc(HPRW)=7.5E-04 (HPRW-CSR-COGHE)
Select wrong control when    it is dissimilar to adjacent controls:
It is assumed that only one train of CCW/ESW has been restored, so HPR recovery with the second train is not credible.The operators will go to Attachment A or B of ES-1.3 via step 2 or 3, since both trains of RHR/CCW are not available.
negligible              (Table 20-12, &#xb9;1A gtem 1A has been added by Swain since NUREG/CR-1278))
The steps in these attachments are similar to the main procedure, except they will align the high head pumps to the one available train of RHR.The critical actions are still the same, with only the step numbers being different.
The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the West RHR panel.
Therefore, for simplicity, the same identifiers are used as before.(Steps 2 and 3 do not need to be evaluated because the operators would be well aware that both trains are not available, and an EOM of step 2 would be recovered by step 3 (as they are on different pages).)Due to the low work load and since things are under control, recovery with the extra US or STA is warranted.(HPRW-CSR-COGHE)(REC-4A&C-MHHE)(REC-4D-MHHE)(REC---5-MH HE)(REC-US-STA-HE-L) pc(HPRW)=7.5E-04 pe'(steps 4a&c)=2.6E-03*2=5.2E-03 pe'(step 4d)=1.3E-03*2=2.6E-03 pe'(step 5)=2.6E-03*2=5.2E-03 Recovery, execution errors (extra US and STA)=0.05 The total human error probability for failing to switchover to high pressure recirculation upon a loss of CCW or ESW and success of RCP and RR2 is calculated as shown in fault tree HPR3: THEP(HPRW)
4c      o en recirc sum    to W RHR/CTS um valve Errors of Omission:
=pc'fpe'(step 4)+pe'(step 5)]~recovery(extra US or STA)THEP(HPRW)
Omit step/page:
=7.5E-04+[(5.2E-03+2.6E-03)+5.2E-03]~5.0E-02 THEP(HPRW)
1.3E-03 (T20-7  &#xb9;3, Assumption G)
=1.4E-03 3.3.11 HPR Fault Trees Summa The basic events and cutsets (with support system failures (i.e., SUBs)set equal to 1.0E-03)for the HPR fault trees are listed below.3.3-16
Step 4  of procedure Errors of Commission:
Select wrong control when    it is dissimilar to adjacent controls:
negligible              (Table 20-12, &#xb9;1A /tern 1A has been added by Swain since NUREG/CR-1278))
This control is different from adjacent controls because it is metal and has a key in it.
Total error robabilit for Ste      s 4a & c:
1.3E-03   + 1.3E-03 = 2.6E-03 4d      Start W RHR PP Errors of Omission:
Omit step:
1.3E-03 (T20-7  &#xb9;3, Assumption G)
Step 4 of procedure Errors of Commission:
negligible, see Errors of Commission for Step 4a 3.3-5


Fault tree HPR1 (used for HPRA, HPRC, HPRD, HPRE, HPRF, HPRH, HPRS)VER 1.6 hprl.cut 10 11 1.670E-03 O.OOOE+00 HPRA-LPR-CSRHE 2 REC-US-STA.-HE.L 3 REC--4A&C.MHHE 4 REC--.-4D.MHHE 5 REC-----5.MHHE 6 REC-6THENS--HE-H 7 REC--6B&D-EHHE-M 8 REC----6E-EHHE 9 REC----6F-EHHE 10 SUB-HPR 1~1.00E-03 1 2.2.60E-04 2 3.1~50E-04 1 4.1.30E-04 3 5.6.50E-OS 3 6.3.90E-05 3 7.1.95E.05 3 8.3.38E-06 3 9.'1.69E-06 3 10.1.69E-06 3'l1.8.45E-07 3 1.000E-09 0.0000E+00 0'000E+00 0~0000E+00 0'000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0~OOOOE+00 1'000E-04 5~0000E.02 5'000E-03 2.6000E-03 5.2000E-03 5.0000E-01 1.5000E-01 6.5000E-03 1.3000E-02 1.0000E-03 SUB-HPR REC-US-STA--HE-L HPRA-LPR-CSRHE REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-----5-MHHE REC--4A&C-MHHE REC----4D-MHHE REC--4A&C-MHHE REC----4D-MHHE REC--4A&C-MHHE REC--"40 MHHE REC--4A&C-MHHE REC----4D-MHHE REC-6THEN5--HE-H REC-6THEN5--HE-H REC--6B&D-EHHE-M REC--6B&D.EHHE-M REC----6F-EHHE REC--"6F.EHHE REC----6E-EHHE REC----6E-EHHE Ver.1.71 7/25/95 9:07:40 Fault tree HPR2 used for HPRB, HPRT, HPRU, HPRV VER 1.6 hpr2.cut Ver.1.71 7/25/95 9:07:41 10 3.04 1 2 3 4 5 6 7 8 9 10 1.2~3~4.5.6.7.8.9.10.11.9E-03 O.OBOE+00 HPRB-LPR-CSRHE REC-US-STA--HE-L REC--4A&C-EHHE REC----4D-EHHE REC-----5-EHHE REC-6THEN5--HE-H REC--6B&D-EHHE-M REC----6E-EHHE REC----6F-EHHE SUB-HPR 1~OOE-03 1 7.50E-04 1 6.50E-04 2 3.25E-04 3 1.63E-04 3 9.75E-05 3 4.88E-05 3 8.45E-06 3 4'3E-06 3 4.23E-06 3 2'1E-06 3 1.000E-09 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 REC-----5-EHHE REC--4A&C-EHHE REC----4D-EHHE REC--4A&C-EHHE REC----4D-EHHE REC--4A&C-EHHE REC----40-EHHE REC--4A&C-EHHE REC----4D-EHHE 7.5000E-04 5.0000E-02 1.3000E-02 6.5000E-03
Ste  5  Ali n SI Pum  s  and CCPs for Recirculation Si      o en SI um    suction from west RHR HX valve and
'1.3000E-02 5.0000E-01 1.5000E-01 6.5000E-03 1.3000E-02 1.0000E-03 SUB-HPR HPRB-LPR-CSRHE REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L REC-6THEN5--HE-H REC-6THENS--HE-H REC--6B&D-EHHE-M REC--6B&D-EHHE-M REC----6F-EHHE REC----6F-EHHE REC----6E-EHHE REC----6E-EHHE 3.3-17 Fault tree HPR3 used for HPRW VER 1.6 hpr3.cut 6 5 2.39BE-03 O.OOOE+00 1 SUB-HPR 2 HPRM-CSR-CDGHE 3 REC-US-STA--HE-L 4 REC--4ASC-MHHE 5 REC----4D-MHHE 6 REC-----5-MHHE 1.1'OE-03 1 2.7.50E-04 3.2.60E.04 2 4.2.60E-04 2 5.1.30E-04 2 1.000E-09 1.0000E-03 7.5000E-04 5.0000E-02 5.2000E-03 2.6000E-03 5.2000E-03 SUB-HPR HPRW-CSR-COGHE REC-US-STA--HE-L REC-US-STA--HE-L REC-US-STA--HE-L 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 REC-----5-MHHE REC--4AKC.MHHE REC----4D-MHHE Ver.1.71 7/25/95 9:07:41 Fault tree HPR4 used for HPRG VER 1.6 hpr4.cut 6 5 1.799E-03 O.OOOE+00 1 SUB-HPR 2 HPRA-LPR-CSRHE 3 REC-US-STA--HE-L 4 REC--4A&C.MHHE 5 REC----4D.MHHE 6 REC-----5-MHHE 1~1.00E-03 1 2.2.60E-04 2 3~2.60E-04 2 4~1.50E-04 1 5~1.30E-04 2 1.000E-09 1~OOOOE-03 1.5000E-04 5.0000E-02 5'000E-03 2.6000E-03 5.2000E-03 SUB-HPR REC.US-STA--HE-L REC-US-STA--HE-L HPRA-LPR-CSRHE REC-US-STA--HE-L 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 0.0000E+00 REC-----5-MHHE REC--4ASC-MHHE REC----4D-MHHE Ver.1'1 7/25/95 9:07:42 3.3-18 Respond to RWST low level alarm Alarm annunciator light Respond to 1 of 1 alarm*Control room-SPY panel Monitor RWST level RWST level<32%Recognize symptoms requiring transfer to cold Control room-SPY panel and BA panel 3.3-19 EOP ES-13, Rev.2 Reset SI SI status Control room Omit action Select wrong control for SI reset button EOP ES-19, Rev.2 4a Stop 1 of 1 west RHR pump Pump status Control room Omit action Select wrong controls for west RHR pump EOP ES-13, Rev.2 4b Close 1 of 1 west RHR pump suction valve (1-IMO-320)
~5'         en SI um    suction crosstie to CCP valves These two steps were considered as one perceptual unit. These are adjacent procedure steps and the valve controls are all right next to each other (i.e., these actions are not separated by time or location).
Close 1 of 1 west RHR pump discharge crosstie valve (1-IMO-324)
Errors of Omission:
Valve position Control room Omit actions Select wrong valve controls EOP ES-12, Rev.2 4c Open 1 of 1 recirc sump valve to west RHR pump Valve position Control room Omit action Select wrong controls for recirc sump valve 3.3-20
Omit step/page:
1.3E-03 (T20-7  &#xb9;3, Assumption G)
Step 5 of procedure Errors of Commission:
Select wrong control on panel from array      of similar appearing controls:
1.3E-03         (T20-12 &#xb9;3)
All safety injection suction  and discharge valves are in one area on SI control panel.
Total error robabilit for Ste 5:
2.6E-03 Ste  6 Ali  n East RHR Pum      for Recirculation:
6b      Sto  & lockout  East RHR PP Errors of Omission:
Omit step/page:
1.3E-03 (T20-7    &#xb9;3, Assumption G)
Step 6 of procedure Errors of Commission:
Select wrong control when    it is dissimilar to adjacent controls:
negligible              (Table 20-12, &#xb9;1A (item 1A has been added by Swain since NUREG/CR-1278))
The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the East RHR panel.
3.3-6


EOP ES-13, Rev.2 4d Start 1 of 1 west RHR pump Pump status Control room Omit action Select wrong controls for west RHR pump EOP ES-19, Rev.2 5a, c Reset and close 2 of 2 CCP miniflow valves Valve switches Control room Omit actions Select wrong controls for CCP miniflow valves EOP ES-13, Rev.2 5d Verify 2 of 2 North SI pump isolation valves open (1-ICM-260, 1-IM(h316)
6d      o en recirc sum    to East RHR/CTS um valve Errors of Omission:
Valve switches Control room Omit actions Check wrong status lights EOP ES-13, Rev.2 5e Verify 2 of 2 south SI pump isolation valves open (1-ICM-265, 1-IMO-326)
Omit step:
Valve switches Control room Omit actions Check wrong status lights EOP ES-13, Rev.2 5f Close 2 of 2 SI pump discharge crosstie valves (1-IMO-270, I-IMO-275)
1.3E-03 (T20-7    &#xb9;3, Assumption G)
Pump status Control room Omit action Select wrong controls for crosstie valves 3.3-21 I'
Step 6  of procedure Errors of Commission:
EOP ES-1.3, Rev.2 5h Close 2 of 2 SI pump recirculation valves to RWST (1-1MO-262, 1-IMO-263)
Select wrong control when    it is dissimilar to adjacent controls:
Valve switches Control room Omit actions Select wrong controls for SI pump recirc valves EOP ES-1.3, Rev.2 5i Open 1 of 1 SI pump suction valve from west RHR Hx (I-IMO-350)
negligible              (Table 20-12, &#xb9;1A (1tem 1A has been added by Swain since NUREG/CR-1278))
Valve switches Control room Omit actions Select wrong controls for SI pump suction valve EOP ES-19, Rev.2 5j Open 2 of 2 SI pump suction crosstie valves to CCP (1-IMO-361, 1-IMO-362)
This control is different from adjacent controls because it is metal and has a key in it.
Valve switches Control room Omit actions Select wrong controls for SI pump suction valves EOP ES-13, Rev.2 51 Close 1 of 1 SI pump suction valve from RWST (1-IMO-261)
Total error robabilit for Ste      s 6b  & d:
Valve switch Control room Omit action Select wrong controls for SI pump suction valve 3.3-22
1.3E-03  +  1.3E-03 = 2.6E-03 6e      Start East RHR PP Errors of Omission:
Omit step:
1.3E-03 (T20-7    &#xb9;3, Assumption G)
Step 6 of procedure Errors of Commission:
negligible, see Errors of Commission for Step 6b 6f      0  en CCP suction from East RHR         HX valve Errors of Omission:
Omit step:
1.3E-03 (T20-7 &#xb9;3, Assumption G)
Step 6 of procedure Errors of Commission:
Select wrong control on panel from array      of similar appearing controls:
3.3-7


EOP ES-19, Rev.2-5m Close 2 of 2 CCP suction valves from RWST (1-IMO-910, I-IMO-911)
ll '
Valve switches Control room Omit 1 of 2 actions Select wrong controls for CCP suction valves EOP ES-13, Rev.2 5n Verify 1 of 2 CCPs running in recirc mode Pump status Control room Omit 2 of 2 actions Select wrong controls for CCPs EOP ES-13, Rev.2 5o Verify 1 of 2 SI pumps running in recirc mode Pump status Control room Omit 2 of 2 actions Select wrong controls for SI pump EOP ES-19, Rev.2 6b Stop 1 of 1 east RHR pump Pump status Control room Omit action Select wrong controls for east RHR pump 3.3-23
II
,"-;:NUMBER'.,':, EOP ES-13, Rev.2 6c Close 1 of 1 east RHR pump suction valve (1-IM0-310)
Close 1 of 1 east RHR pump discharge crosstie valve (1-IMO-314)
Valve position Control room Omit actions Select wrong valve controls EOP ES-13, Rev.2 6d Open 1 of 1 recirc sump valve to east RHB/CTS pump (1-ICM-305)
Valve position Control room Omit action Select wrong controls for recirc sump valve EOP ES-13, Rev.2 6e Start 1 of 1 east RHR pump Pump status Control room Omit action Select wrong controls for east RHR pump EOP ES-19, Rev.2 6f Open 1 of 1 CCP suction valve from east RHR Hx (1-IMO-340)
Valve position Control room Omit action Select wrong controls for CCP suction valve 3.3-24 TABLE 3.3-3 VORKSHEET FOR CALCULATION OF pc Scenario: Small LOCA with success of ECCS hi h ressure in'ection HP2 success of RCS cooldown usin AFW AF4 and success of containment s ra in ection CSI HI: HPR-Switchover to hi h ressure cold le recirculation Cue(s): RWST at low level alarm Duration of time window available for action (TW): 340 Seconds.17 min-680 sec 340 sec (per Reference 26, actions take 680 sec)Approximate start time for TW 30 Procedure and step governing HI: Caution statement at be innin of ES-1 2 A.Initial Estimate of pc pc Failure Mechanism Branch HEP pca: Availability of information
~a~ne pcb: Failure of attention d 1 5E-4 The ExO should not have much distracting him ac this point following a small LOCA (per operator interviews).
pcc'isread/miscommunicate data~na no data communicated
-just instruction to watch level~na pcd: Information misleading
~ne pce: Skip a step in procedure Caution statement is italicized and in all CAPS.3 OE-3 pcf: Misinterpret instruction pcg: Misinterpret decision logic pch: Deliberate violation~ne n~e n~e um of pca through pch I i i l pc Total reduction in TW Effective TW 3 1E-3 min.min.Check here if recovery credit claimed on page 2: xx Notes: There are two RWST level indicators for the o erators to use a chart recorder and an indicator that is ver eas to read 3.3-25
'
TABLE 3.3-4 WORKSHEET FOR CALCULATION OF pc RECOVERY FACTORS Scenario: Small LOCA with success of ECCS hi h ressure in ection HP2 success of RCS cooldown usin AFW AF4 and success of containment s ra in ection CSI HI: HPR-Switchover to hi h ressure cold le recirculation B.Recover Facto s Identif ed Alarm at low RWST level did not credit this for b because credit for alarm alread in tree C.Recovery Factors Applied to pc pc Failure Mechanism Initial HEP Recover Factor Multiply Final~b Value pca pcb 1 5E-4 1 5E-4 pcc pce 3.0E-03 alarm T20-23 1 0001 3 OE-7 This is probably the only alarm going off, and at time much later than the initial alarms, so it will get more attention.
Also, this red dot alarm is trained on as a high priority alarm.pcf pcg pch Eum of recovered pca through pch-Recovered pc 1 5E-4 Time at which all recovery factors effective~t 30 mi 3.3-26


OLI-DEPRESSURIZATION TO ALLOW LOW PRESSURE INJECTION~Attention Medium LOCA (MLO)with failure of high pressure injection (HP2)-OLIA (JMR)~Desert tion Following the occurrence of a medium LOCA, if the high head pumps fail to start or fail to provide adequate cooling (HP2), the operators, by following emergency operating procedures, would be directed to depressurize the primary system to below the shutoff head of the RHR pumps to allow the RHR pumps to inject water to the core.The most effective means to perform this action is a rapid secondary depressurization (Reference 4a).If the RCPs are not all running, other actions include starting RCPs to provide forced two-phase flow through the core and/or opening the pressurizer PORVs to depressurize the RCS.Success Criteria and Timin Anal sis Success of this event requires 450 gpm (240x10'PH per EOPs)of AFW flow for the duration of the accident.Success criteria of improved core cooling and increasing vessel inventory is achieved by actions of dumping steam from at least two of four steam generators and/or at least two of three pressurizer PORVs.These actions will allow for the start (or verify running)of at least one of two RHR pumps.The MLO Event Tree description in the Event Tree Notebook provides a detailed description of the timing analysis assumed for meeting the success criteria of this event.The success criteria is based on the identification of inadequate core cooling (ICC)symptoms (high core exit TC indication) at around 30 minutes following MLO event initiation (Reference 25, MLO-35 example).Upon identification of ICC symptoms, the operators should be ready to perform the rapid cooldown with little time delay and then perform the remaining actions.Operator actions are provided in EOP FR-C.1.Procedures The Emergency Operating Procedure used to perform this task is FR-C.1, RESPONSE TO INADEQUATE CORE COOLING, Rev.4.FR-C.1 is entered from F-0.2, Core COOLING Critical Safety Function Status Tree on a RED condition.
1.3E-03          (T20-12 P3)
For this event, entry into FR-C.1 will occur from the STA recognizing the red path from F-0.2.Operators will review the red path summary from the foldout pages when they transfer to E-1 from step 25 of E-0 and when they transfer to ES-1.2 from step 14 of E-1, but this is conservatively not credited.Critical And Recove Actions The following are the primary tasks which must be completed for success of the MLO event tree OLI top event: 1.Recognize core exit TC indications greater than 1200'F on the F-0.2, CORE 3.5-1
It is clearly labeled on the boric acid charging and letdown panel. It is at the bottom left of the panel.
~, I J I COOLING Critical Safety Function Status Tree or on the red path summary (item 2b on foldout)(cognitive) 2.Start RHR pumps (Step 5 of FR-C.1)(Per operator interviews, the RHR pumps will probably still be running, but starting them is conservatively modelled.)
3.3.10 Calculation of Total Human Error Probabilit for Failure to Switchover to HPR The cognitive and execution error probabilities were calculated in sections 3.3.8 and 3.3.9 to be:
3.Initiate RCS cooldown at maximum rate using SG steam relief valves (conservatively not taking credit for condenser steam dump)(Step 13 of FR-C.1)See Table 3.5-1, Cue Table for OLI for identification of symptoms for OLI actions, See Table 3.5-2, Subtask Analysis For OLI for identification of critical or relevant recovery actions for OLI.3.5.6~Assum tions This action will be required at about the same time that switchover to recirculation will be required.Many factors influence which will come first, therefore, it is conservatively assumed that OLI precedes LPR and CSR.(This is conservative because OLI has a much higher THEP than LPR or CSR.)3.5.7 Si nificant 0 erator Interview Findin s 1.The STA will monitor the core exit thermocouple temperatures using the plant process computer, unless conditions are abnormal, upon which they will also monitor indication on the control room back panels.The RCPs would be running when the operators reach step 12 of FR-C.1.(They will only stop the RCPs upon a medium LOCA if RCS pressure is less than 1250 psig and high head injection is available.)
pc'(HPRA) = 1.5E-04 pe(steps 4a&c) = 2.6E-03            (without stress, dependence or recovery) pe(step 4d) = 1.3E-03              (without stress, dependence or recovery) pe(step 5) = 2.6E-03                (without stress, dependence or recovery) pe(steps 6b&d) = 2.6E-03            (without stress, dependence or recovery) pe(step 6e) = 1.3E-03              (without stress, dependence or recovery) pe(step 6f) = 2.6E-03              (without stress, dependence or recovery)
Since the pumps are already running when they reach this step (" Check if RCPs Should Be Started"), they will go on to step 13.Therefore, they will not open the pressurizer PORVs (RNO column for step 12).3.The RHR pumps will probably still be running when the operators enter FR-C.1.3.5.8 Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21).Table 3.5-3 contains the calculation of the cognitive human error probability, pc, that the STA fails to recognize the red path core cooling conditions.
In order for alignment of the east RHR train (step 6) to recover for an error in aligning the west train (step 4), the operators must recognize that there is not adequate flow from the west RHR pump train before aligning the high head pumps (step 5). The high head pumps are expected to fail quickly without a suction source (per operator interviews). A high level of dependence is assumed, therefore, for the operators recognizing that there is a problem with the east RHR train before they align the high head pumps in step 5. This was modelled by a high dependence failure of noticing failed step 4, so performing step 6 before step 5 (i.e.,
Pc was calculated in Table 3.5-3 to be 6.0E-03.Recovery was not applied to this value.3.5.9 Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.(T20-x refers to Table 20-x of Reference 2.)The critical actions identified in Table 3.5-2 were reviewed to determine the dominant critical actions to be quantified.
human error probability = 0.5). A high level of dependence is conservative, however, as the operator and unit supervisor will be watching pump amperes when suction sources are closed (e.g., for the high head pumps) and when the RHR pumps are started (per operator interviews). The ammeters are right above the pump controls in the control room. Also, the unit supervisor watches what the operator is doing, and waits for completion of one step before moving on to another (which can be significant, as it takes about 30 seconds for the RWST suction valves to close).
Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability.
A moderate level of dependence      was assumed between failure of step 4 and the initial tasks in step 6. Although steps 4 and 6 are similar, they are different procedure steps, on different pages, and unless the operators realize they failed step 4, step 5 will be performed between them. An extremely high level of stress is assigned to all step 6 actions, though, as these actions are only critical if the operators failed in step 4.
Attachment OLI is a copy of the relevant portion of FR-H.1, with dominant critical steps circled.The reasons why the other critical steps (identified in Table 3.5-2)are not dominant are also included.3.5-2 I: 1'\
Per operator interviews, a minimum of two people will be watching the unit supervisor and operator go through the switchover using a copy of the procedure. Whenever switchover is occurring, it is top priority, and almost everything else has come to a stop. The STA does not want to get in the way, so he will be going through the procedure and watching what is going on, as well as the extra unit supervisor. The unit supervisor is not interrupted during switchover, therefore, the extra unit supervisor will be free to watch the switchover. Several more people may also be watching, but this is conservatively not credited. If it is under an hour after event initiation, the shift supervisor may still be busy with his E-plan duties. The assistant shift supervisor may be busy in his role as contingency director, and the BOPO may not be paying close enough attention to catch a mistake.
Ste 13 Initiate RCS Cooldown to 200'F: 13b Manuall dum steam from intact SG s usin steam relief valves Errors of Omission: Omit step/page:
3.3-8
4.2E-03 (T20-7&#xb9;4, Assumption G)Step 13 of procedure Errors of Commission:
Select wrong control when it is dissimilar to adjacent controls: 1.3E-03 (Table 20-12,&#xb9;3)The level and relief valve controls for the steam generators are well marked and different from adjacent controls on the steam generator panels.The only truly credible failure would be selecting the level control rather than the relief control.3.5.10 Calculation of Total Human Error Probabilit for Failure to De ressurize OLI The cognitive and execution error probabilities were calculated in sections 3.5.8 and 3.5.9 to be: pc'(OLIA)=6.0E-03 pe(OLI)=5.5E-03 (without stress or dependence)
OLIA: De ressurize and Start RHR followin a medium LOCA An extremely high level of stress is assumed for red path recoveries.
Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks.pc'(OLIA)=6.0E-03 pe'(OLIA)=5.5E-03~5=2.8E-02 (OLI-COG-HE)(OLI--13B-EHHE)
The total human error probability (THEP)for failing to depressurize following a medium LOCA and failure of high pressure injection is: THEP(OLIA)
=pc'pe'HEP(OLIA)
=6.0E-03+2.8E-02=3.4E-02'he corresponding fault tree is OLI1.3.5-3


3.5.11 OLI Fault Trees Summa 0 The basic events and cutsets (with support system failures (i.e., SUBs)set equal to 1.0E-03)for the OLI fault tree are listed below.Fault Tree OLI1 used for OLIA VER 1.6 ot11.cut 2 2 3.383E-02 0~OOOE+00 1 OLI-----COG-HE 2 OLI---13B-EHHE 1.2.80E-02 1 2.6.00E-03 1 1.000E-08 6.0000E-03 0.0000E+00 2.8000E-02 0.0000E+00 OLI---138-EHHE OLI-----COG-HE Ver.1.71 7/25/95 9:07:00 3.5-4 Identify symptoms of inadequate core cooling on foldout page or on F-0.2, Core Cooling Status Tree Core exit temperature
Only one recovery was given to the extra unit supervisor and STA. A low level of dependence was assumed between them and the unit supervisor and RxO because they are not interacting at all with the US and RxO; they are standing back and fulfillinga supervisory type role. This combined effort was equated to that of the shift supervisor in Table 204, Reference 2.
>1200'F-RED path Recognize red path for core exit temperature
Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks. Per Table 20-17, if the basic error probability (BHEP) is greater than .01, the equations to use for low, moderate,    'uman and high dependence are: (1+19N)/20, (1+6N)/7, and (1+N)/2, respectively. Per Table 20-21, if the BHEP is less than or equal to .01, HEPs of .05, .15 and .5 should be used for low, moderate, and high dependence, respectively.
>1200'F, and transfer to FR-C.1 Control room 3.5-5  
Recovery due to extra unit supervisor and STA following procedure and actions        = 0.05 These parameters and assumptions are used below to determine the total human error probability for failure to switchover for high pressure recirculation under different conditions.
~c~
HPRA: Switchover to hi h ressure recirculation u on a small LOCA and successful AFW
~AF4 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)
A moderately high level of stress was assumed for steps 4 and 5. This is      a procedure that is well known and practiced by the operators, and they are not concentrating on doing anything else during this procedure, as it takes top priority.
pc'(HPRA) = 1.5E-04                                                (HPRA-LPR-CSRHE) pe'(steps 4a&c) = 2.6E-03
* 2 = 5.2E-03                            (REC 4A&C-MHHE) pe'(step 4d) = 1.3E-03
* 2 = 2.6E-03                                (REC- 4D-MH HE) pe'(step 5) = 2.6E-03
* 2 = 5.2E-03                                (REC---5-MHHE) pe'(steps 6b&d) = 2.6E-03
* 5 with MD                              (REC-6B&D-EHHE-M)
                  = (1 + 6*1.3E-02)/7 = 1.5E-01 pe'(step 6e)  =  1.3E-03 ~ 5 = 6.5E-03                              (REC--6E-EHHE) pe'(step 6f) = 2.6E-03
* 5 = 1.3E-02 (REC 6F-EHHE) pe'(recognize to do step 6 before step 5) = HD = 0.5                (REC-6TH EN5 HE-H)
Recovery, execution errors (extra US and STA) = 0.05                (REC-US-STA HE-L)
The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a small LOCA and successful AFW (AFW) is calculated as shown in fault tree HPR1:
THEP(HPRA) = pc'          fpe'(step 4)
* pe'(step 6)  + pe'(step 5)]
* recovery(extra US or STA) 3.3-9
 
THEP(HPRA) = 1.5E-04 + [(5.2E-03 + 2.6E-03) * (0.5 + 1.4E-01 + 6.5E-03 + 1.3E-02)
+ 5.2E-03]
* 5.0E-02 THEP(HPRA) = 6.7E-04 HPRB: Switchover to hi h ressure recirculation u on a small LOCA failure of AFW AF4 and success of rima bleed and feed BF1 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)
For this scenario, the operators will transition from Step 18 of E-0 to FR-H.1 to complete PBF. Due to adverse containment conditions, the operators will immediately go to step 18 of FR-H.1. They should still be in FR-H.l when RWST level reaches 32%. The caution statement after step 25 of FR-H.1 will be their cue to monitor the RWST level, with cognitive recovery provided by the alarm. It is assumed that the RxO monitoring the RWST level will have a high work load, as they will be busy with PBF and subsequent actions in FR-H.1.
The only change in pc'rom pc'(HPRA) will be to tree b. The new end path will be 1 due to the high work load, which is not recovered.
pc'(HPRB) = 7.5E-04 + 3.0E-07 pc'(HPRB) = 7.5E-04                                                (HPRB-LPR-CSRHE)
The extremely high level of stress from primary bleed and feed is conservatively assumed to still exist. Otherwise, the actions have the same failure probabilities as HPRA.
pe'(steps  4a&c) = 2.6E-03 ~ 5 = 1.3E-02                          (REC-4A&C-EHHE) pe'(step  4d) = 1.3E-03
* 5 = 6.5E-03                              (REC--4D-EH HE) pe'(step  5) = 2.6E-03
* 5 = 1.3E-02                                (REC EH HE) pe'(steps  6b&d) = 2.6E-03
* 5 with MD                            (REC 6B&D-EHHE-M)
                  = (1 + 6~1.3E-02)/7 = 1.5E-01 pe'(step 6e) = 1.3E-03 ~ 5 = 6.5E-03 (REC 6E-EHHE) pe'(step 6f) = 2.6E-03
* 5 = 1.3E-02 (REC 6F-EHHE) pe'(recognize to do step 6 before step 5) = HD = 0.5                (REC-6TH ENS-HE-H)
Recovery, execution errors (extra US and STA) = 0.05                (REC-US-STA-HE-L)
The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a small LOCA, failure of AFW (AF4), and success of PBF is calculated as shown in fault tree HPR2:
THEP(HPRB) = pc'          [pe'(step 4) ~ pe'(step 6)  + pe'(step 5)]
* recovery(extra US or STA)
THEP(HPRB) = 7.5E-04        + [(1.3E-02 + 6.5E-03) * (0.5 +        1.4E-01  +  6.5E-03 +  1.3E-02)
+ 1.3E-02]
* 5.0E-02 THEP(HPRB) = 2.0E-03 3.3-10
 
S 8
  't
 
HPRC: Switchover to hi h ressure recirculation u on a medium LOCA and successful
~AFW    AF4 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)
This is the exact same scenario as HPRA, except for the size of the LOCA. For this event, however, this difference in LOCA size is irrelevant, as the timing and flow through the procedures should be the same.
The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a medium LOCA and successful AFW (AFW) is the same as HPRA:
THEP(HPRC) = THEP(HPRA) = 6.7E-04 HPRD: Switchover to high pressure recirculation after a transient with steam conversion systems available (TRA), followed by loss of auxiliary feedwater (AF1), a loss of alternate secondary cooling sources (AFW from the other Unit and main feedwater-MF1, and SG depressurization combined with condensate-OA5), and success of primary feed and bleed (PBT). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRD equals HPRA, and fault tree HPR1 is used.
For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRD is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.
HPRE: Switchover to high pressure recirculation after a transient with failure of steam conversion systems (TRS), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBT). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRE equals HPRA, and fault tree HPR1 is used.
For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRE is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.
3.3-11
 
HPRF: Switchover to high pressure recirculation after a large steam/feedwater line break (SLB), followed by successful high pressure injection (HP3) and successful isolation of the faulted SG (MS1) but loss of auxiliary feedwater (AFS), countered by success of primary feed and bleed (PBS). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRF equals HPRA, and fault tree HPR1 is used.
For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRF is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.
HPRG: Switchover to high pressure recirculation after a transient loss of offsite power (LSP), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBL). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. However, there may be one train equipment unavailable depending on the diesel generator (DG) response. If two diesel generators succeed, then HPR equals HPRA. If only one diesel generator succeeds, then HPR equals HPRA (in timing) but with only one train available. Although the case for the two DG success is more likely (-95%),
the case of success of only one DG (-5%) leads to more restrictive modeling and has conservatively been applied. Thus, equation HPRG equals HPRA Steps 4 and 5, as calculated in fault tree HPR4.
For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRG is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.
HPRH: Switchover to high pressure recirculation after a steam generator tube rupture (SGR),
followed by loss of all auxiliary feedwater (AF2 and AF3), and success of primary feed and bleed (PBG). In this scenario, the operator initiates a LOCA inside of containment when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, HPRH equals HPRA, and fault tree HPR1 is used.
3.3-12
 
HPRS: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU RRI and AF1 and success or failure of CSI Dependency upon CSI failure is not evaluated, because THEP for CSI is mostly due to errors of omission, which are independent for steps on different pages, with the remainder due to cognitive failures. If the operators failed to actuate CSI, switchover to recirculation is not necessary for 1.5 hours after this CSI failure. In this time, there are no other system failures.
This amount of time, with no other major operator tasks, negates any cognitive dependency.
Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause'a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.
Per the Event Tree Notebook (Reference 1), with the containment spray and high head ECCS pumps injecting, there is 17 minutes available for switchover, and switchover will not be required until at least 30 minutes following completion RRI and CSI.
For this scenario, everything has been successful following power restoration, and at least 30 minutes have elapsed since operators finished RRI and CSI. Power has been back for an hour, and things are under control. The operators will transfer to E-1 (LOSS OF REACTOR OR SECONDARY COOLANT) at the end of ECA-0.2 (i.e., step 14).
The cue for the operators to monitor RWST level will be Step 15 of E-1. A low work load can be assumed at this time and recovery with the alarm can also be credited. This results in a value for pc'qual to that for HPRA. (The end state for tree e is all that changes (from b to c), but the value remains the same (3.0E-03).)
pc'(HPRS) = pc'(HPRA)
As things are under control, recovery due to the extra US/STA can be credited.
Therefore, the total human error probability for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI is the same as that from HPRA.
THEP(HPRS) = THEP(HPRA)
Fault tree HPR1 is used.
HPRT: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU and RRI failure of AF1 success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF). Therefore, as these paths include success of PBF, there is no dependence to consider.
3.3-13
 
Failure of the containment spray system is not addressed separately. If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours following power recovery). The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.
Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.
For this scenario, the operators will transition to FR-H.1 following completion of Step 10 of ECA-0.2. For hydrogen control, the operators may transfer to FR-Z.1 (per caution statement before step 27 of FR-H. 1) and then return to FR-H.1. Eventually, the operators will leave FR-H.1 to transfer E-1 or to switchover to recirculation (ES-1.3). The caution statement in FR-H.1 (before step 26) should be their cue to monitor RWST level, with cognitive recovery provided by the alarm. It is assumed that the operator monitoring RWST level will have a high work load, as they will be busy with FR-H.1 and FR-Z.1. This results in a pc'qual to that for HPRB:
pc'(HPRT) = pc'(HPRB)
The extremely high level    of stress from primary bleed and feed is conservatively assumed to still exist.
Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, and failure of AF1, success of PBB, and success or failure of CSI is the same as HPRB.
THEP(HPRT) = THEP(HPRB)
Fault tree HPR2 is used.
HPRU: Switchover to hi h ressure recirculation u on a'SBO success'of AFT success or failure of RCC failure of AFC success of XHR and CNU success of PBB and success or failure of CSI See writeup    for HPRT. Fault tree HPR2 is used.
This is the same scenario as described in HPRT. AFW has been lost (worse case scenario) for a couple hours before power recovery, and PBB must be initiated right after completion of CSI (i.e., step 10 of ECA-0.2).
Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.
3.3-14
 
HPRV: Switchover to hi h ressure recirculation u on a SBO failure of AFT success of XHR and CNU success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF). Therefore, as this path includes success of PBF, there is no dependence to consider.
Failure of the containment spray system is not addressed separately. If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours following power recovery). The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.
An extemely high level of stress is assumed, as a blackout with failure of the TDAFP is a severe incident for the operators, and switchover is required fairly early in the accident (about 2 hours from loss of power). (This level of stress is also assumed because it follows PBB.)
As described in HPRT, a high work load is assumed for the RxO for calculation of pc'.
Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO, failure of AFT, success of XHR and CNU, success of PBB, and success or failure of CSI is the same as HPRT.
THEP(HPRV) = THEP(HPRT) = THEP(HPRB)
Fault tree HPR2 is used.
HPRW: Switchover to hi h ressure recirculation u on a loss of CCW or ESW and success of RCP and RR2 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)
HPR will not be required until very late into the event. Since the RCPs were tripped, seal failure is not actually expected until an hour or two into the event (see RCP, Section 3.25.2),
at which time the containment sprays will be actuated. With both containment spray pumps operating, it takes at least 35 more minutes to reach the RWST low level. A charging pump is started (i.e., RR2A) within 30 minutes of the restoration of CCW/ESW. As a result, HPR is expected after a charging pump has been started in RR2A.
At this point, things  are well under control. The small LOCA through the seals is under control and CCW/ESW has been restored. A low work load is considered for the operators by the time HPR is needed. The operators will probably still be in OHP 4022.016.004 when HPR is required, since they will not leave it until after the RCS is cooled and depressurized enough to start RHR. There is not a procedure step to warn the operators to monitor RWST level, but the operators know to monitor this. Only cognitive tree b applies (data not attended to) to this situation. End path I from tree b results in a cognitive value of 7.5E-04. No recovery is applied to this value. (Note: the path for high work load was conservatively followed, so this cognitive failure probability can be used for other scenarios.)
3.3-15
 
pc(HPRW) = 7.5E-04                                                (HPRW-CSR-COGHE)
It is assumed that only one train of CCW/ESW has been restored, so HPR recovery with the second train is not credible. The operators will go to Attachment A or B of ES-1.3 via step 2 or 3, since both trains of RHR/CCW are not available. The steps in these attachments are similar to the main procedure, except they will align the high head pumps to the one available train of RHR. The critical actions are still the same, with only the step numbers being different. Therefore, for simplicity, the same identifiers are used as before. (Steps 2 and 3 do not need to be evaluated because the operators would be well aware that both trains are not available, and an EOM of step 2 would be recovered by step 3 (as they are on different pages).) Due to the low work load and since things are under control, recovery with the extra US or STA is warranted.
pc(HPRW) = 7.5E-04                                                (HPRW-CSR-COGHE) pe'(steps 4a&c) = 2.6E-03
* 2 = 5.2E-03                          (REC-4A&C-MHHE) pe'(step 4d) = 1.3E-03
* 2 = 2.6E-03 (REC 4D-MHHE) pe'(step 5) = 2.6E-03
* 2 = 5.2E-03                              (REC- MH HE)
Recovery, execution errors (extra US and STA) = 0.05              (REC-US-STA-HE-L)
The total human error probability for failing to switchover to high pressure recirculation upon a loss of CCW or ESW and success of RCP and RR2 is calculated as shown in fault tree HPR3:
THEP(HPRW) = pc'          fpe'(step 4) + pe'(step 5)] ~ recovery(extra US or STA)
THEP(HPRW) = 7.5E-04        + [(5.2E-03 + 2.6E-03) + 5.2E-03]      ~ 5.0E-02 THEP(HPRW) = 1.4E-03 3.3.11 HPR Fault Trees Summa The basic events and cutsets (with support system failures (i.e., SUBs) set equal to 1.0E-03) for the HPR fault trees are listed below.
3.3-16
 
Fault tree HPR1 (used for HPRA, HPRC, HPRD, HPRE, HPRF, HPRH, HPRS)
VER 1.6 hprl.cut                                                                         Ver. 1.71  7/25/95  9:07:40 10    11 1.670E-03      O.OOOE+00  1.000E-09 HPRA-LPR-CSRHE            1 '000E-04      0.0000E+00 2   REC-US-STA.-HE.L        5 ~ 0000E.02      0 '000E+00 3  REC--4A&C.MHHE          5 '000E-03        0 ~ 0000E+00 4  REC--.-4D.MHHE          2.6000E-03        0 '000E+00 5  REC-----5.MHHE          5.2000E-03        0.0000E+00 6  REC-6THENS--HE-H        5.0000E-01        0.0000E+00 7  REC--6B&D-EHHE-M          1.5000E-01      0.0000E+00 8  REC----6E-EHHE          6.5000E-03        0.0000E+00 9  REC----6F-EHHE          1.3000E-02       0.0000E+00 10    SUB-HPR                  1.0000E-03        0 ~ OOOOE+00 1 ~    1.00E-03      1    SUB-HPR
: 2. 2.60E-04      2    REC-US-STA--HE-L        REC-----5-MHHE
: 3. 1 ~ 50E-04    1    HPRA-LPR-CSRHE
: 4. 1.30E-04      3    REC-US-STA--HE-L          REC--4A&C-MHHE      REC-6THEN5--HE-H
: 5. 6.50E-OS      3    REC-US-STA--HE-L          REC----4D-MHHE      REC-6THEN5--HE-H
: 6. 3.90E-05      3    REC-US-STA--HE-L          REC--4A&C-MHHE      REC--6B&D-EHHE-M
: 7. 1.95E.05      3    REC-US-STA--HE-L          REC----4D-MHHE      REC--6B&D.EHHE-M
: 8. 3.38E-06      3    REC-US-STA--HE-L          REC--4A&C-MHHE      REC----6F-EHHE
: 9.    '1.69E-06      3    REC-US-STA--HE-L          REC--"40  MHHE      REC--"6F.EHHE
: 10.      1.69E-06      3    REC-US-STA--HE-L          REC--4A&C-MHHE      REC----6E-EHHE
            'l1. 8.45E-07      3    REC-US-STA--HE-L          REC----4D-MHHE      REC----6E-EHHE Fault tree HPR2 used for HPRB, HPRT, HPRU, HPRV VER  1.6 hpr2.cut                                                                          Ver. 1.71  7/25/95  9:07:41 10        3.04 9E-03    O.OBOE+00  1.000E-09 1  HPRB-LPR-CSRHE          7.5000E-04        0.0000E+00 2   REC-US-STA--HE-L        5.0000E-02       0.0000E+00 3    REC--4A&C-EHHE          1.3000E-02        0.0000E+00 4  REC----4D-EHHE          6.5000E-03       0.0000E+00 5  REC-----5-EHHE          '1.3000E-02      0.0000E+00 6  REC-6THEN5--HE-H        5.0000E-01        0.0000E+00 7  REC--6B&D-EHHE-M        1.5000E-01        0.0000E+00 8    REC----6E-EHHE          6.5000E-03       0.0000E+00 9    REC----6F-EHHE          1.3000E-02       0.0000E+00 10    SUB-HPR                  1.0000E-03        0.0000E+00
: 1. 1 ~ OOE-03    1    SUB-HPR 2~    7.50E-04      1    HPRB-LPR-CSRHE 3~      6.50E-04      2    REC-US-STA--HE-L          REC-----5-EHHE
: 4.      3.25E-04      3    REC-US-STA--HE-L          REC--4A&C-EHHE      REC-6THEN5--HE-H
: 5.      1.63E-04      3    REC-US-STA--HE-L          REC----4D-EHHE      REC-6THENS--HE-H
: 6.      9.75E-05      3    REC-US-STA--HE-L          REC--4A&C-EHHE      REC--6B&D-EHHE-M
: 7.      4.88E-05      3    REC-US-STA--HE-L          REC----4D-EHHE      REC--6B&D-EHHE-M
: 8.      8.45E-06      3    REC-US-STA--HE-L          REC--4A&C-EHHE      REC----6F-EHHE
: 9.      4 '3E-06      3    REC-US-STA--HE-L          REC----40-EHHE      REC----6F-EHHE
: 10.      4.23E-06      3    REC-US-STA--HE-L          REC--4A&C-EHHE       REC----6E-EHHE
: 11.      2 '1E-06      3    REC-US-STA--HE-L          REC----4D-EHHE      REC----6E-EHHE 3.3-17
 
Fault tree HPR3 used for HPRW VER  1.6 hpr3.cut                                                                      Ver. 1.71 7/25/95 9:07:41 6    5 2.39BE-03    O.OOOE+00  1.000E-09 1  SUB-HPR                1.0000E-03      0.0000E+00 2  HPRM-CSR-CDGHE          7.5000E-04      0.0000E+00 3    REC-US-STA--HE-L        5.0000E-02      0.0000E+00 4    REC--4ASC-MHHE          5.2000E-03      0.0000E+00 5  REC----4D-MHHE          2.6000E-03      0.0000E+00 6    REC-----5-MHHE          5.2000E-03      0.0000E+00
: 1. 1 'OE-03      1    SUB-HPR
: 2.      7.50E-04            HPRW-CSR-COGHE
: 3.      2.60E.04      2    REC-US-STA--HE-L        REC-----5-MHHE
: 4.      2.60E-04      2    REC-US-STA--HE-L        REC--4AKC.MHHE
: 5.      1.30E-04      2    REC-US-STA--HE-L        REC----4D-MHHE Fault tree HPR4 used for HPRG VER  1.6 hpr4.cut                                                                      Ver. 1 '1 7/25/95 9:07:42 6    5 1.799E-03    O.OOOE+00  1.000E-09 1  SUB-HPR                1 ~ OOOOE-03    0.0000E+00 2    HPRA-LPR-CSRHE          1.5000E-04      0.0000E+00 3   REC-US-STA--HE-L        5.0000E-02      0.0000E+00 4    REC--4A&C.MHHE          5 '000E-03      0.0000E+00 5   REC----4D.MHHE          2.6000E-03      0.0000E+00 6    REC-----5-MHHE          5.2000E-03      0.0000E+00 1 ~    1.00E-03      1    SUB-HPR
: 2.      2.60E-04      2    REC.US-STA--HE-L        REC-----5-MHHE 3~      2.60E-04      2    REC-US-STA--HE-L        REC--4ASC-MHHE 4~      1.50E-04      1    HPRA-LPR-CSRHE 5~      1.30E-04      2    REC-US-STA--HE-L        REC----4D-MHHE 3.3-18
 
Respond to RWST low Alarm annunciator light  Respond to  1 of 1 Control level alarm                                  alarm
* room - SPY panel Monitor RWST level  RWST level < 32%        Recognize          Control symptoms           room - SPY requiring          panel and transfer to cold    BA panel 3.3-19
 
EOP      Reset SI                                      SI status      Control Omit action ES-13,                                                                  room Rev. 2                                                                          Select wrong control for SI reset button EOP    4a Stop  1  of 1 west RHR pump                  Pump status    Control Omit action ES-19,                                                                  room Rev. 2                                                                          Select wrong controls for west RHR pump EOP    4b Close  1  of 1 west RHR pump suction valve    Valve position Control Omit actions ES-13,    (1-IMO-320)                                                  room Rev. 2 Close 1 of 1 west RHR pump discharge                                  Select wrong valve crosstie valve (1-IMO-324)                                            controls EOP    4c Open    1  of 1 recirc sump valve to west      Valve position Control Omit action ES-12,    RHR pump                                                      room Rev. 2                                                                          Select wrong controls for recirc sump valve 3.3-20
 
EOP    4d  Start  1 of 1 west RHR pump                  Pump status    Control Omit action ES-13,                                                                  room Rev. 2                                                                          Select wrong controls for west RHR pump EOP    5a, c Reset and close 2  of 2 CCP miniflow        Valve switches Control Omit actions ES-19,      valves                                                      room Rev. 2                                                                          Select wrong controls for CCP miniflow valves EOP    5d  Verify 2 of 2 North SI pump isolation        Valve switches Control Omit actions ES-13,      valves open (1-ICM-260, 1-IM(h316)                          room Rev. 2                                                                          Check wrong status lights EOP    5e  Verify 2 of 2 south SI pump isolation        Valve switches Control Omit actions ES-13,      valves open (1-ICM-265, 1-IMO-326)                          room Rev. 2                                                                          Check wrong status lights EOP    5f  Close 2 of 2 SI pump discharge crosstie      Pump status    Control Omit action ES-13,      valves (1-IMO-270, I-IMO-275)                              room Rev. 2                                                                          Select wrong controls for crosstie valves 3.3-21
 
I' EOP    5h Close 2  of 2 SI pump recirculation valves      Valve switches Control Omit actions ES-1.3,    to RWST (1-1MO-262, 1-IMO-263)                                room Rev. 2                                                                            Select wrong controls for SI pump recirc valves EOP    5i Open 1 of 1 SI pump suction valve from          Valve switches Control Omit actions ES-1.3,    west RHR Hx (I-IMO-350)                                        room Rev. 2                                                                            Select wrong controls for SI pump suction valve EOP    5j Open 2 of 2 SI pump suction crosstie            Valve switches Control Omit actions ES-19,    valves to CCP (1-IMO-361, 1-IMO-362)                          room Rev. 2                                                                            Select wrong controls for SI pump suction valves EOP    51 Close 1 of 1 SI pump suction valve from        Valve switch  Control Omit action ES-13,    RWST (1-IMO-261)                                              room Rev. 2                                                                            Select wrong controls for SI pump suction valve 3.3-22
 
EOP    -5m Close 2 of 2 CCP suction valves from          Valve switches Control Omit  1 of 2 actions ES-19,    RWST (1-IMO-910, I-IMO-911)                                  room Rev. 2                                                                          Select wrong controls for CCP suction valves EOP    5n Verify 1 of 2 CCPs running in recirc mode      Pump status    Control Omit 2 of 2 actions ES-13,                                                                  room Rev. 2                                                                          Select wrong controls for CCPs EOP    5o Verify 1 of 2 SI pumps running in recirc      Pump status    Control Omit 2 of 2 actions ES-13,    mode                                                          room Rev. 2                                                                          Select wrong controls for SI pump EOP    6b Stop 1 of 1 east RHR pump                    Pump status    Control Omit action ES-19,                                                                  room Rev. 2                                                                          Select wrong controls for east RHR pump 3.3-23
 
,"-;:NUMBER'.,':,
EOP            6c Close  1 of 1 east RHR pump suction valve      Valve position Control Omit actions ES-13,            (1-IM0-310)                                                    room Rev. 2 Select wrong valve Close 1 of 1 east RHR pump discharge controls crosstie valve (1-IMO-314)
EOP            6d Open 1 of 1 recirc sump valve to east          Valve position Control Omit action ES-13,            RHB/CTS pump (1-ICM-305)                                      room Rev. 2                                                                                    Select wrong controls for recirc sump valve EOP            6e Start  1  of 1 east RHR pump                    Pump status    Control Omit action ES-13,                                                                            room Rev. 2                                                                                    Select wrong controls for east RHR pump EOP            6f Open  1  of 1 CCP suction valve from east      Valve position Control Omit action ES-19,            RHR Hx (1-IMO-340)                                            room Rev. 2                                                                                    Select wrong controls for CCP suction valve 3.3-24
 
TABLE  3.3-3 VORKSHEET FOR CALCULATION OF        pc Scenario:      Small LOCA with success of        ECCS  hi  h ressure in'ection HP2 success  of  RCS cooldown usin      AFW AF4      and success of containment s ra in ection    CSI HI:    HPR -  Switchover to  hi  h  ressure cold le      recirculation Cue(s):    RWST  at low level alarm Duration of time window available for action (TW):                340 Seconds.
17 min - 680 sec      340 sec (per Reference 26, actions take 680 sec)
Approximate    start  time  for  TW      30 Procedure and step governing HI:            Caution statement at be innin of ES-1        2 A.      Initial Estimate    of pc pc  Failure  Mechanism                                      Branch      HEP pca:  Availability of information                                  ~a          ~ne pcb:    Failure of attention                                          d        1  5E-4 The ExO    should not have much distracting him          ac  this point following  a small LOCA (per operator interviews).
pcc'isread/miscommunicate          data                            ~na        ~na no data communicated      -  just instruction to      watch  level pcd:    Information misleading                                                  ~ne pce:  Skip a step in procedure                                                3  OE-3 Caution statement is italicized and          in all  CAPS.
pcf: Misinterpret instruction                                                  ~ne pcg:  Misinterpret decision logic                                              n~e pch:  Deliberate violation                                                    n~e um  of pca through    pch    I i i l pc        3  1E-3 Total reduction in      TW          min.
Effective  TW              min.
Check here    if recovery  credit claimed    on page 2:        xx Notes:
There are two    RWST level indicators for the        o  erators to use    a chart recorder and an  indicator that is ver eas to read 3.3-25
 
TABLE  3.3-4 WORKSHEET FOR CALCULATION OF      pc RECOVERY FACTORS Scenario:      Small LOCA with success of      ECCS  hi h ressure in ection HP2 success  of  RCS  cooldown usin AFW AF4          and success of containment s ra in ection    CSI HI:    HPR -  Switchover to    hi h ressure cold le recirculation B.      Recover    Facto  s  Identif ed Alarm  at low    RWST  level did not credit this for      b  because    credit for alarm alread      in tree C. Recovery Factors Applied to pc pc  Failure            Initial                                          Multiply      Final Mechanism                HEP            Recover    Factor              ~b            Value pca pcb                    1  5E-4                                                          1 5E-4 pcc pce                    3.0E-03      alarm T20-23 1                        0001        3 OE-7 This is probably the only alarm going off, and at time much later than the initial alarms, so      it will get more attention. Also, this red dot alarm is trained on as a high priority alarm.
pcf pcg pch Eum  of recovered    pca through pch    - Recovered pc    1  5E-4 Time  at which all recovery factors effective      ~t  30 mi 3.3-26
 
OLI - DEPRESSURIZATION TO ALLOW LOW PRESSURE INJECTION
~Attention Medium LOCA (MLO) with failure of high pressure injection (HP2) - OLIA (JMR)
~Desert  tion Following the occurrence of a medium LOCA, if the high head pumps fail to start or fail to provide adequate cooling (HP2), the operators, by following emergency operating procedures, would be directed to depressurize the primary system to below the shutoff head of the RHR pumps to allow the RHR pumps to inject water to the core. The most effective means to perform this action is a rapid secondary depressurization (Reference 4a). If the RCPs are not all running, other actions include starting RCPs to provide forced two-phase flow through the core and/or opening the pressurizer PORVs to depressurize the RCS.
Success Criteria and  Timin Anal sis Success  of this event requires 450 gpm (240x10'PH per EOPs) of AFW flow for the duration of the accident. Success criteria of improved core cooling and increasing vessel inventory is achieved by actions of dumping steam from at least two of four steam generators and/or at least two of three pressurizer PORVs. These actions will allow for the start (or verify running) of at least one of two RHR pumps.
The MLO Event Tree description in the Event Tree Notebook provides a detailed description of the timing analysis assumed for meeting the success criteria of this event. The success criteria is based on the identification of inadequate core cooling (ICC) symptoms (high core exit TC indication) at around 30 minutes following MLO event initiation (Reference 25, MLO-35 example). Upon identification of ICC symptoms, the operators should be ready to perform the rapid cooldown with little time delay and then perform the remaining actions.
Operator actions are provided in EOP FR-C.1.
Procedures The Emergency Operating Procedure used to perform this task is FR-C.1, RESPONSE TO INADEQUATE CORE COOLING, Rev. 4.
FR-C.1 is entered from F-0.2, Core COOLING Critical Safety Function Status Tree on a RED condition.
For this event, entry into FR-C.1 will occur from the STA recognizing the red path from F-0.2. Operators will review the red path summary from the foldout pages when they transfer to E-1 from step 25 of E-0 and when they transfer to ES-1.2 from step 14 of E-1, but this is conservatively not credited.
Critical And Recove      Actions The following are the primary tasks which must be completed for success    of the MLO event tree OLI top event:
: 1.      Recognize core exit TC indications greater than 1200'F on the F-0.2, CORE 3.5-1
 
I
~,
J I
 
COOLING Critical Safety Function Status Tree or on the red path summary (item 2b on foldout) (cognitive)
: 2.      Start RHR pumps (Step 5 of FR-C.1) (Per operator interviews, the RHR pumps will probably still be running, but starting them is conservatively modelled.)
: 3.      Initiate RCS cooldown at maximum rate using SG steam relief valves (conservatively not taking credit for condenser steam dump) (Step 13 of FR-C.1)
See Table 3.5-1, Cue Table      for OLI for identification of symptoms for OLI actions, See Table 3.5-2, Subtask Analysis    For OLI for identification of critical or relevant recovery actions for OLI.
3.5.6 ~Assum  tions This action will be required at about the same time that switchover to recirculation will be required. Many factors influence which will come first, therefore, it is conservatively assumed that OLI precedes LPR and CSR. (This is conservative because OLI has a much higher THEP than LPR or CSR.)
3.5.7 Si nificant  0  erator Interview Findin  s
: 1.      The STA will monitor the core exit thermocouple temperatures using the plant process computer, unless conditions are abnormal, upon which they will also monitor indication on the control room back panels.
The RCPs would be running when the operators reach step 12 of FR-C.1. (They will only stop the RCPs upon a medium LOCA if RCS pressure is less than 1250 psig and high head injection is available.) Since the pumps are already running when they reach this step ("Check if RCPs Should Be Started" ), they will go on to step 13.
Therefore, they will not open the pressurizer PORVs (RNO column for step 12).
: 3.      The RHR pumps will probably still be running when the operators enter FR-C.1.
3.5.8 Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21). Table 3.5-3 contains the calculation of the cognitive human error probability, pc, that the STA fails to recognize the red path core cooling conditions. Pc was calculated in Table 3.5-3 to be 6.0E-
: 03. Recovery was not applied to this value.
3.5.9 Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.
(T20-x refers to Table 20-x of Reference 2.) The critical actions identified in Table 3.5-2 were reviewed to determine the dominant critical actions to be quantified. Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability. Attachment OLI is a copy of the relevant portion of FR-H.1, with dominant critical steps circled. The reasons why the other critical steps (identified in Table 3.5-2) are not dominant are also included.
3.5-2
 
I:
1
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Ste  13  Initiate RCS Cooldown to 200'F:
13b      Manuall dum steam from intact SG                      s usin steam relief valves Errors of Omission:
Omit step/page:
4.2E-03 (T20-7 &#xb9;4, Assumption G)
Step 13  of procedure Errors of Commission:
Select wrong control when            it is dissimilar to adjacent controls:
1.3E-03                  (Table 20-12, &#xb9;3)
The level and relief valve controls for the steam generators are well marked and different from adjacent controls on the steam generator panels. The only truly credible failure would be selecting the level control rather than the relief control.
3.5.10 Calculation of Total Human Error Probabilit for Failure to De ressurize OLI The cognitive and execution error probabilities were calculated in sections 3.5.8 and 3.5.9 to be:
pc'(OLIA) = 6.0E-03 pe(OLI)  = 5.5E-03    (without stress or dependence)
OLIA: De ressurize and Start RHR followin a medium LOCA An extremely high level of stress is assumed for red path recoveries. Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks.
pc'(OLIA) = 6.0E-03 pe'(OLIA) = 5.5E-03    ~ 5          = 2.8E-02 (OLI COG-HE)
(OLI-13B-EHHE)
The total human error probability (THEP) for failing to depressurize following a medium LOCA and failure of high pressure injection is:
THEP(OLIA) = pc'
                      = 6.0E-03 + 2.8E-02 =
pe'HEP(OLIA) 3.4E-02'he corresponding fault tree is OLI1.
3.5-3
 
3.5.11 OLI Fault Trees Summa 0        The basic events and cutsets (with support system failures (i.e., SUBs) set equal to 1.0E-03) for the OLI fault tree are listed below.
Fault Tree OLI1 used    for OLIA VER  1.6 ot11.cut                                                          Ver. 1.71  7/25/95  9:07:00 2      2 3.383E-02 0 OOOE+00 1.000E-08
                                    ~
1  OLI-----COG-HE    6.0000E-03    0.0000E+00 2 OLI---13B-EHHE      2.8000E-02    0.0000E+00
: 1. 2.80E-02    1  OLI---138-EHHE
: 2. 6.00E-03    1  OLI-----COG-HE 3.5-4
 
Identify symptoms of    Core exit temperature > 1200'F- Recognize red      Control room inadequate core cooling  RED path                         path for core exit on foldout page or on F-                                  temperature >
0.2, Core Cooling Status                                  1200'F, and Tree                                                      transfer to FR-C.1 3.5-5
 
~ c ~
I;.:;~NUMBER:.'::
I;.:;~NUMBER:.'::
EOP FR-C.1, Rev.4 EOP FR-C.1, Rev.4 sa (RNO)13b (RNO)Start RHR pumps Dump steam at maximum rate using SG steam relief valves pump status steam relief valve position indication Control room Control room Omit action Select wrong controls for RHR pumps Omit actions Select wrong controls for steam relief valves 3.5-6  
EOP           sa    Start RHR pumps                          pump status    Control Omit action FR-C.1,       (RNO)                                                          room Rev. 4                                                                                 Select wrong controls for RHR pumps EOP               13b Dump steam at maximum rate using SG      steam relief  Control Omit actions FR-C.1,         (RNO) steam relief valves                      valve position room Rev. 4                                                         indication            Select wrong controls for steam relief valves 3.5-6
 
TABLE  3.5-3 WORKSHEET FOR CALCULATION OF      pc Scenario:          Medium LOCA  with success of accumulators      and  failure of hi    h ressure      in'ection HI: OLI -          De ressurization to allow low ressure in ection Cue(s):          Red  ath conditions - foldout      a e or status tree Duration of time window available for action (TW):
Seconds'pproximate start  time  for  TW.
Procedure and step governing HI:                F-0.2 Status Tree Red Path      i.e. STA A.        Initial Estimate      of  pc pc  Failure  Mechanism                                  Branch        HEP pca:      Availability of information                                ~na          ~na pcb:      Failure of attention                                        e          3  OE-3 (assume    low workload    for  STA)
(per interview, STA will be watching computer screen for core exit thermocouple temperatures until things look abnormal, then they will check indicator on back panel -- per G. Parry, use front panel path for this tree) pcc:      Misread/miscommunicate        data                          ~na          ~na pcd:      Information misleading                                    ~na          ~na pce        Skip a step    in procedure                                b          3.0E-3 (Status trees are monitored in particular order, and paths are graphically distinct using different colors and line types.)
pcf: Misinterpret instruction                                                      n~e pcg:      Misinterpret decision logic                                              n~e pch:      Deliberate violation                                                      n~e Sum  of pca through    pc    I i i l pc          6.0E-03 Total reduction in    TW            min.
Effective TW                  min.
Check here        if recovery  credit claimed    on page 2:
Notes:
Due  to inconsistent usea        e  of the foldout    a es  er  o  erator interviews credit is conservativel            not    iven to the  US reco nizin the red ath from the foldout a es 3.5-7
 
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Title                                                                          Number 01-OHP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                            ES-1.3 STEP        ACTION/EXPECTED RESPONSE                    RESPONSE  NOT OBTAINED
: 3. Check    CCW  Pumps  - BOTH OPERABLE      IF East    CCW pump  is  INOPERABLE, THEN:
: a. Stop the East      RHR pump    and place in PULL-TO-LOCK.
: b. Go to Attachment A.
IF Mest    CCW  pump is  INOPERABLE, THEN'.
Stop the West  RHR pump    and place in PULL-TO-LOCK.
: b. Go  to Attachment  B.
CAUTION:      VHEN CONTROL POh'ER IS RESTORED FOR VALVE OPERATION, THE CONTROL POWER HUST BE LEFT ON SO ASSOCIATED INTERLOCKS 4'ILL BE OPERABLE.
: 4. Align West RHR     And CTS Pumps For Recirculation:
Qa. Stop the following pumps and place in PULL-TO-LOCKOUT position:
QWest    RHR pump
                                            ~
              ~ ,Mest  CTS pump
: b. Close the following valves concurrently:
g,. 1-1H0-320, West suction valve RHR pump Q IC.-~W tat~CL!C                .
              ~  I-IH0-225, West CTS pump suction valve from RWST
              ~  I-IM0-324, West RHR pump                                    C.
discharge crosstie valve This Step continued  on  the next page.
Page 3  of  35 Rev. 2
 
Title                                                                  Humber 01-OHP 4023.
TRANSFER TO COLQ LEG RECIRCULATION                                    ES-1.3 STEP      ACTION/EXPECTEQ RESPONSE            RESPONSE  NOT OBTAINEQ o
: c. Restore control power and open 1-ICM-306, Recirc sump to West RHR/CTS pump valve
: c. Perform the following:
: 1) Open 1-IM0-225, West CTS pump  suction valve from RWST.
: 2) IF West  CTS pump was previously running,      THEN restart the  West CTS pump.
IF  NOT, THEN  place the West CTS pump  in NEUTRAL.
: 3)  Go  to Attachment    B.
: d. IF the West    RHR pump .can NOT be started,  THEN:
: 1) IF West CTS pump was previously running, restart the West  CTS pump.
IF NOT, ~TH N place West CTS pump in NEUTRAL.
: 2) Go  to Attachment    B.
: e. Check West  CTS pump  status   e. Place West    CTS pump  in  NEUTRAL PREVIOUSLY RUNNING
: 1)  Restart the West  CTS pump
: 2) Verify  ESW  to/from  West CTS heat exchanger  valves-OPEN:
              ~ I-WMO-715
              ~ 1-WMO-717 Page 4    of 35 Rev. 2
 
Title 01-OHP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                        ES-1.3 STEP      ACTION/EXPECTED RESPONSE                  RESPONSE  NOT OBTAINED CAUTION:    ~ IF THE SI PUHP HINIFLOh'ALVES ARE CLOSED, THEN THE          SI PUHPS SHOULD BE STOPPED WHENEVER RCS PRESSURE APPROACHES THEIR SHUTOFF HEAD.
                    ~ IF RCS PRESSURE INCREASES TO 2000 PSIG, THEN A PR2 PORV SHOULD BE OPENED, AS NECESSARY, TO REDUCE RCS PRESSURE AND HAINTAIN HINIHUH CCP FLOP.
NOTE:      Hinimum  total  BIT flow  for CCP  cooling is:
                    ~ for I  CCP  -  150 gpm (160 gpm    for adverse containment)
                    ~ for 2  CCPs  -  275 gpm (2SO gpm    for adverse containment)
  '.. Align SI Pumps Recirculation:
And CCPs For
: a. Reset both  CCP  miniflow valves:
            ~  1-QMO-225
            ~  1-QMO-226
: b. Check total BIT flow      GREATER    b. Perform the following:
THAN MINIMUM NEEDED FOR CCP COOLING                                    1) Stop  all but one CCP.
: 2)  IF total BIT flow is greater than 150 gpm (160 gpm for adverse containment),  THEN go  to step Sc.
IF NOT, THEN, open the associated CCP miniflow valve and go to step 5d.
WHEN RCS  pressure is less than 1700 psig, THEN close all      miniflow valves.
                                    ~ ~ ~ilCS CCP
: c. Close both  CCP  miniflow valves:
            ~  i-q~o-225    C
                              ~
            '-gMQ-226      ~J cI8  z,(~-    ~~      ~wwd This Step continued    on the next page.
                                                                        ,Page 5 of 35 Rev. 2
 
Title                                                                              Number 01-OHP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                                ES-1.3 STEP      ACTION/EXPECTED RESPONSE                      RESPONSE    NOT OBTAINED
: d. Check the following valves            for  d. Manually open valves.
the North SI pump - OPEN
                                                          ~  1-ICM-260
          ~  l-ICM-260, North SI pump                      1-IMO-316 discharge to old le s 1          8, 4 I                          VQk~      IF  either valve remains
                                            ~
                        -AND-                            closed,  THEN  stop the North SI pump.
          ~  1-IM0-316,      RHR  and SI to RCS    cold 1      valve                  Go  to step Sg.
CP4
: e. Check the follow ng valves            for  e. Manually open valves.
the South SI pump  OPEN
                                                          ~  1-ICM-265
          ~  1-ICM-265, South SI pump                    ~  1-IMO-326 discharge    t  cold legs  2    3 IF  either valve remains
                        -AND-                            closed,  THEN  stop the South SI pump.
          ~  1-IM0-326, RHR and SI to RCS    cold le      valv                    Go  to step 5g.
                                              ~
Close SI dischar valves:
          ~  1- IMO-270
          '-IMO-275 e
                                        ~
crosstie ykLv80
                                              ~dlpVLA . P
                                                                      @~~~ $ y                a Check each SI pump        flow -          g. Stop affected SI pump(s).
GREATER THAN 70 GPM:
          ~  1-IFI-260                                  WHEN RCS    pressure is less than
            ~  1- I F I-266                                1425  psig (1150 psig for adverse containment), THEN start  SI pump(s).
Restore control power and close SI valves:
            ~  1-IMO-262 pumps  recirc to  RWST
                                                    ~+          c
            ~  1-IMO-263 i  Open    l-IM0-350, SI pump                i. Locally    open 1-IM0-350.
suction from West RHR HX valve                  DO NOT PROCEED      UNTIL 1-IMO-350 IS OPEN.
This Step continued on the next page.
Page 6  of 35 Rev. 2
 
l' Number 01-OHP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                            ES-1.3 STEP      ACTION/EXPECTED RESPONSE                  RESPONSE  NOT OBTAINED 0j. Open Sl pump to
            ~
CCP  valves:
1-IMO-361 suction crosstie
                                            /
            ~  1-IMO-362
: k. Verify I-IM0-360, SI        pump suction crosst'e      CCPs  - OP
: l. 'lose Restore    control power 1-IM0-261, SI and pump
                                                    ~~~                    Qkk/QQL e
suction from RWST
: m. Close valves:
            ~
CCP 1-IMO-910 t
suction from. RWST        ~~    quxb~
                                                                            ~l~4I V~~
            ~  1-IMO-911
                /
: n. Check    CCP's  BOTH RUNNING          n. IF  CCPs  were stopped because of  RWST  low-low level,        THEN perform the following:
: 1) Start  one CCP.
: 2) Check    total  BIT  flow-greater than    150 gpm (160 gpm  for  adverse containment)
IF NOT, THEN open associated  mini.flow valve and go  to step 5o.
                                                      ')  Check  RCS pressure than 1700 psig less IF NOT,  THEN go    to step 5o.
WHEN RCS    pressure    is less than 1700 psig,      THEN restart all    CCPs.
: 4)  Start  second CCP.
This Step continued      on the next page.
Page    7  of 35.
Rev.      2
 
Hurrher Ol-OHP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                    ES-1.3 STEP      ACTION/EXPECTED RESPONSE        RESPONSE    NOT OBTAINED
: o. Check SI pumps  BOTH RUNNING o. IF SI pumps were stopped because of, RWST low-low level, THEN perform the following:
: 1) Check    RCS    pressure - less than 1425 psig (1150 psig for adverse containment)
                                                .IF  NOT,  ~TH  N go to step 6.
WHEN RCS    pressure is less than 1425 psig (1150 psig for adverse containment, THEN do step 5o.
: 2) Check SI pump discharge crosstie valves - closed:
                                                  ~ I- IHO-270
                                                              -OR-
                                                  ~ I-IMO-275
: 3) IF SI pump discharge crosstie is isolated,          THEN start    both SI pumps.
IF NOT, THEN      start only    one SI pump.
Page 8    of  35 Rev. 2
 
Humber 01-.0HP 4023.
TRANSFER TO COLD LEG RECIRCULATION                                          ES-1.3 STEP        ACTION/EXPECTED RESPONSE                  RESPONSE  NOT OBTAINED 6   Align fast RHR      And CTS Pumps    For Reer rcul ati on:
: a. Check    RWST  Level  -  LESS THAN    a. Continue with step    7..
101m WHEN RWST level drops to IOX, TKH do steps 6b through 6h.
b    Stop the following pumps and place in    PULL-TO-LOCKOUT position:
            @East    RHR pump
            ~  East  CTS pump c.'lose      the following valves concurrently:
            ~  1-IM0-310, East    RHR pump suction valve
            ~ l-IM0-215, East CTS pump suction from RWST valve
            ~ l-IM0-314, East RHR pump                                              '~Imr discharge crosstie valve
          . Restore control power and open        d. Restore control power and 1-ICM-305, Recirc sump to East            close 1-IMQ-390 RHR pumps RHR/CTS pump valve                        suction from RW5T.
Go to step 7.
Qe./Start the East      RHR pump          e. Go to step 6g.
: f. Open 1-IMO-340      CCP  suction from East    RHR (IX valve
: g. Check East      CTS  pump-              g. Place East    CTS pump  in  NEUTRAL PREVIOUSLY RUNNING
: 1)  Restart the East    CTS pump
: 2)  Verify  ESW to/from East    CTS heat exchanger valves -    OPEN
                  ~ 1-WMO-711
                  ~ 1-WMO-713
: h. Restore control power and close 1-IMO-390 RHR      pumps suction from RW)T Page 9    of 35 Rev. 2
 
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~  ~
i                                                                          01-OHP 4023.
RESPONSE    Tp INAOEqUATE CpRE CppLING                                    FR-C.1 STEP      ACTION/EXPECTED RESppNSE
                                                    ~~
RESPONSE  NOT OBTAINEO NOTE:        Normal conditions are desired but not    requir  d  for starting the RCns.                                        is&.~
: 12. Check  if  RCPs  Should Be Started:
: a. Core  exit  TCs  GREATER THAN    a. C6 to Step 13.
1200'F.
: b. Check    if an idle RCS cooling      h. Perform the following:
loop is available:
: 1) Open  all  PR2 PORVs and
                    ~  Narrow range  SG  level              block valves.
GREATER THAN 6X (22X FOR AOVERSE CONTAINMENT)                2) +F core    exit  TCs  remain greater than 1200'F, ~TH N
                    ~ RCP  in associated  loop-              open other RCS vent paths AVAILABLE AND NOT OPERATING            to containment:
a)  PRZ  vent path valves:
                                                                  ~ 1-NSO-61 and 1-NSO-62
                                                                            -OR-
                                                                  ~ 1-NSO-63 and 1-NSO-64 b) Reactor head vent path valves:
                                                                  ~ 1-NSO-21 and 1-NSO-22
                                                                            -OR-
                                                                  ~  1-NSO-23 and 1-NSO-24
: 3) Go  to Step  13.
: c. Start RCP in one idle      RCS cooling loop.
: d. Return to Step 12a.
Page 9    of  16 Rev. 4; CS-1


TABLE 3.5-3 WORKSHEET FOR CALCULATION OF pc Scenario: Medium LOCA with success of accumulators and failure of hi h ressure in'ection HI: OLI-De ressurization to allow low ressure in ection Cue(s): Red ath conditions
Title                                                                          Hurber 01-OHP 4023.
-foldout a e or status tree Duration of time window available for action (TW): Seconds'pproximate start time for TW.Procedure and step governing HI: F-0.2 Status Tree Red Path i.e.STA A.Initial Estimate of pc pc Failure Mechanism Branch HEP pca: Availability of information
RESPONSE    TO INADEQUATE CORE COOLING                                      FR-C.1 STEP      ACTION/EXPECTED RESPONSE                    RESPONSE  NOT OBTAINED CAUTION:       DURING COOLDOVN, STEAN FLOP OF GREATER THAN 1.42x106 PPH ON TMO OR NORE SGs VILL RESULT IN A STEAPILINE ISOLATION.
~na~na pcb: 3 OE-3 Failure of attention e (assume low workload for STA)(per interview, STA will be watching computer screen for core exit thermocouple temperatures until things look abnormal, then they will check indicator on back panel--per G.Parry, use front panel path for this tree)pcc: Misread/miscommunicate data~na~na pcd: Information misleading
NOTE:         ~  Partial uncovering of   SG  tubes  is acceptable in the following steps.
~na~na pce Skip a step in procedure b 3.0E-3 (Status trees are monitored in particular order, and paths are graphically distinct using different colors and line types.)pcf: Misinterpret instruction pcg: Misinterpret decision logic pch: Deliberate violation n~e n~e n~e Sum of pca through pc I i i l pc 6.0E-03 Total reduction in TW Effective TW Check here if recovery credit claimed on page 2: min.min.Notes: Due to inconsistent usea e of the foldout a es er o erator interviews credit is conservativel not iven to the US reco nizin the red ath from the foldout a es 3.5-7
                      ~ Both steam dump control selector switches should be momentarily placed in  BYPASS INTERLOCK when Tavg decreases to 541'F.
13.~   Initiate
            ~
RCS  Cooldown To 200'F:   ~                 ~
: a. Transfer condenser steam dump to steam pressure    mode
: b.      ump steam to condenser from          b. Hanually or locally dump steam intact  SG(s) at maximum rate            from intact SG(s) at maximum rate using steam relief valves.
: c. Check     RCS  hot leg temperatures      c. Cooldown using faulted or
              -  DECREASING                              ruptured SG(s).
Page  10 of 16 Rev. 4, CS-1


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Title TRANSFER TO COLD LEG RECIRCULATION Number 01-OHP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE 3.Check CCW Pumps-BOTH OPERABLE RESPONSE NOT OBTAINED IF East CCW pump is INOPERABLE, THEN: a.Stop the East RHR pump and place in PULL-TO-LOCK.
16166 11012                      %45.516.4K-l 666--.S-MIE K--6S MIE REC 611M 4E
b.Go to Attachment A.IF Mest CCW pump is INOPERABLE, THEN'.Stop the West RHR pump and place in PULL-TO-LOCK.
b.Go to Attachment B.CAUTION: VHEN CONTROL POh'ER IS RESTORED FOR VALVE OPERATION, THE CONTROL POWER HUST BE LEFT ON SO ASSOCIATED INTERLOCKS 4'ILL BE OPERABLE.4.Align West RHR And CTS Pumps For Recirculation:
Qa.Stop the following pumps and place in PULL-TO-LOCKOUT position: QWest RHR pump~,Mest CTS pump b.Close the following valves concurrently:
g,.1-1H0-320, West RHR pump~Q IC.-~W tat~CL!C.suction valve~I-IH0-225, West CTS pump suction valve from RWST~I-IM0-324, West RHR pump C.discharge crosstie valve This Step continued on the next page.Page 3 of 35 Rev.2


Title TRANSFER TO COLQ LEG RECIRCULATION Humber 01-OHP 4023.ES-1.3 STEP ACTION/EXPECTEQ RESPONSE o c.Restore control power and open 1-ICM-306, Recirc sump to West RHR/CTS pump valve e.Check West CTS pump status-PREVIOUSLY RUNNING 1)Restart the West CTS pump 2)Verify ESW to/from West CTS heat exchanger valves-OPEN:~I-WMO-715~1-WMO-717 RESPONSE NOT OBTAINEQ c.Perform the following:
                  }R favell 1rcc Rll CO 8%2MI2 STA-fE-l      R--.S.Bff 45.5TA.+4
1)Open 1-IM0-225, West CTS pump suction valve from RWST.2)IF West CTS pump was previously running, THEN restart the West CTS pump.IF NOT, THEN place the West CTS pump in NEUTRAL.3)Go to Attachment B.d.IF the West RHR pump.can NOT be started, THEN: 1)IF West CTS pump was previously running, restart the West CTS pump.IF NOT,~TH N place West CTS pump in NEUTRAL.2)Go to Attachment B.e.Place West CTS pump in NEUTRAL Page 4 of 35 Rev.2


Title TRANSFER TO COLD LEG RECIRCULATION 01-OHP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION:~IF THE SI PUHP HINIFLOh'ALVES ARE CLOSED, THEN THE SI PUHPS SHOULD BE STOPPED WHENEVER RCS PRESSURE APPROACHES THEIR SHUTOFF HEAD.~IF RCS PRESSURE INCREASES TO 2000 PSIG, THEN A PR2 PORV SHOULD BE OPENED, AS NECESSARY, TO REDUCE RCS PRESSURE AND HAINTAIN HINIHUH CCP FLOP.NOTE: Hinimum total BIT flow for CCP cooling is:~for I CCP-150 gpm (160 gpm for adverse containment)
FIGURE E-10 HPR3 FAULT TREE HPA3  Fault Tree HPR30OOI HPR30004                        SU9-HPA    HPRW-CSR-COGHE HPR30005                AEC.US-STA--HE-L REC--(ALC-LONE AEC-- ~ ~ ID-ISE          REC- - - - INHE
~for 2 CCPs-275 gpm (2SO gpm for adverse containment)
'..Align SI Pumps And CCPs For Recirculation:
a.Reset both CCP minif low valves:~1-QMO-225~1-QMO-226 b.Check total BIT flow-GREATER THAN MINIMUM NEEDED FOR CCP COOLING b.Perform the following:
1)Stop all but one CCP.2)IF total BIT flow is greater than 150 gpm (160 gpm for adverse containment), THEN go to step Sc.IF NOT, THEN, open the associated CCP miniflow valve and go to step 5d.WHEN RCS pressure is less than 1700 psig, THEN close all CCP miniflow valves.c.Close both CCP miniflow valves:~i-q~o-225 C~'-gMQ-226~J~~~ilCS cI8 z,(~-~~~wwd This Step continued on the next page.,Page 5 of 35 Rev.2 Title TRANSFER TO COLD LEG RECIRCULATION Number 01-OHP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED d.e.Check the following valves for d.Manually open valves.the North SI pump-OPEN~1-ICM-260~l-ICM-260, North SI pump'1-IMO-316 discharge to old le s 1 8, 4 I VQk~IF either valve remains-AND-closed, THEN stop the North SI pump.~1-IM0-316, RHR and SI to RCS cold 1 valve~Go to step Sg.Check the follow ng valves for e.Manually open valves.CP4 the South SI pump-OPEN~1-ICM-265~1-ICM-265, South SI pump~1-IMO-326 discharge t cold legs 2 3 IF either valve remains-AND-closed, THEN stop the South SI pump.~1-IM0-326, RHR and SI to RCS cold le valv~Go to step 5g.Close SI dischar e crosstie@~~~$y a valves:~ykLv80~1-IMO-270~dlpVLA.P'-IMO-275 Check each SI pump flow-g.Stop affected SI pump(s).GREATER THAN 70 GPM:~1-IFI-260 WHEN RCS pressure is less than~1-I F I-266 1425 psig (1150 psig for adverse containment), THEN start SI pump(s).Restore control power and close SI pumps recirc to RWST~+c valves:~1-IMO-262~1-IMO-263 i Open l-IM0-350, SI pump suction from West RHR HX valve i.Locally open 1-IM0-350.
DO NOT PROCEED UNTIL 1-IMO-350 IS OPEN.This Step continued on the next page.Page 6 of 35 Rev.2 l'
TRANSFER TO COLD LEG RECIRCULATION Number 01-OHP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE 0 j.Open Sl pump suction crosstie to CCP valves:/~1-IMO-361~1-IMO-362 RESPONSE NOT OBTAINED k.Verify I-IM0-360, SI pump suction crosst'e CCPs-OP l.Restore control power and~~~Qkk/QQL'lose 1-IM0-261, SI pump e suction from RWST t m.Close CCP suction from.RWST~~~l~4 V~~valves: I~1-IMO-910 quxb~~1-IMO-911/n.Check CCP's-BOTH RUNNING n.IF CCPs were stopped because of RWST low-low level, THEN perform the following:
1)Start one CCP.2)Check total BIT flow-greater than 150 gpm (160 gpm for adverse containment)
IF NOT, THEN open associated mini.flow valve and go to step 5o.')Check RCS pressure-less than 1700 psig IF NOT, THEN go to step 5o.WHEN RCS pressure is less than 1700 psig, THEN restart all CCPs.4)Start second CCP.This Step continued on the next page.Page 7 of 35.Rev.2 TRANSFER TO COLD LEG RECIRCULATION Hurrher Ol-OHP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED o.Check SI pumps-BOTH RUNNING o.IF SI pumps were stopped because of, RWST low-low level, THEN perform the following:
1)Check RCS pressure-less than 1425 psig (1150 psig for adverse containment).IF NOT,~TH N go to step 6.WHEN RCS pressure is less than 1425 psig (1150 psig for adverse containment, THEN do step 5o.2)Check SI pump discharge crosstie valves-closed:~I-IHO-270-OR-~I-IMO-275 3)IF SI pump discharge crosstie is isolated, THEN start both SI pumps.IF NOT, THEN start only one SI pump.Page 8 of 35 Rev.2 TRANSFER TO COLD LEG RECIRCULATION Humber 01-.0HP 4023.ES-1.3 STEP ACTION/EXPECTED RESPONSE 6 Align fast RHR And CTS Pumps For Reer rcul ati on: a.Check RWST Level-LESS THAN 101m RESPONSE NOT OBTAINED a.Continue with step 7..WHEN RWST level drops to IOX, TKH do steps 6b through 6h.b Stop the following pumps and place in PULL-TO-LOCKOUT position:@East RHR pump~East CTS pump c.'lose the following valves concurrently:
~1-IM0-310, East RHR pump suction valve~l-IM0-215, East CTS pump suction from RWST valve~l-IM0-314, East RHR pump discharge crosstie valve.Restore control power and open d.1-ICM-305, Recirc sump to East RHR/CTS pump valve'~Imr Restore control power and close 1-IMQ-390 RHR pumps suction from RW5T.Qe./Start the East RHR pump f.Open 1-IMO-340 CCP suction from East RHR (IX valve g.Check East CTS pump-PREVIOUSLY RUNNING 1)Restart the East CTS pump 2)Verify ESW to/from East CTS heat exchanger valves-OPEN~1-WMO-711~1-WMO-713 h.Restore control power and close 1-IMO-390 RHR pumps suction from RW)T Go to step 7.e.Go to step 6g.g.Place East CTS pump in NEUTRAL Page 9 of 35 Rev.2


~~~I I i I~I I'I I I: i I~~I~~~~I~~~I I~I~~s I~E 1 I I I I I~I~~~~I~~~I 4 I~I~I~~I~I~~~s.~''
FIGURE E-11 HPR4 FAVLT TREE HPA( Fault Tree HPA(0001 HPR40004                  SUB-HPA    HPRA.LPA.CSRHE HPR40005            REC-US-STA--%-L REC----<D.NHE          REC-----54fSE
'I~~i RESPONSE Tp INAOEqUATE CpRE CppLING ituvber 01-OHP 4023.FR-C.1 STEP ACTION/EXPECTED RESppNSE RESPONSE NOT OBTAINEO 12.NOTE: Normal conditions are desired but not requir d for starting the RCns.is&.~Check if RCPs Should Be Started:~~a.Core exit TCs-GREATER THAN a.C6 to Step 13.1200'F.b.Check if an idle RCS cooling loop is available:
~Narrow range SG level-GREATER THAN 6X (22X FOR AOVERSE CONTAINMENT)
~RCP in associated loop-AVAILABLE AND NOT OPERATING c.Start RCP in one idle RCS cooling loop.d.Return to Step 12a.h.Perform the following:
1)Open all PR2 PORVs and block valves.2)+F core exit TCs remain greater than 1200'F,~TH N open other RCS vent paths to containment:
a)PRZ vent path valves:~1-NSO-61 and 1-NSO-62-OR-~1-NSO-63 and 1-NSO-64 b)Reactor head vent path valves:~1-NSO-21 and 1-NSO-22-OR-~1-NSO-23 and 1-NSO-24 3)Go to Step 13.Page 9 of 16 Rev.4;CS-1


Title RESPONSE TO INADEQUATE CORE COOLING Hurber 01-OHP 4023.FR-C.1 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: DURING COOLDOVN, STEAN FLOP OF GREATER THAN 1.42x106 PPH ON TMO OR NORE SGs VILL RESULT IN A STEAPILINE ISOLATION.
ATTACHMENT 1 TO AEP'NRC'10820 Donald C. Cook Nuclear Plant Individual Plant Examination Individual Plant Examination Revision 1
NOTE:~Partial uncovering of SG tubes is acceptable in the following steps.~Both steam dump control selector switches should be momentarily placed in BYPASS INTERLOCK when Tavg decreases to 541'F.~~13.Initiate RCS Cooldown To 200'F:~~a.Transfer condenser steam dump to steam pressure mode b.ump steam to condenser from intact SG(s)at maximum rate b.Hanually or locally dump steam from intact SG(s)at maximum rate using steam relief valves.c.Check RCS hot leg temperatures c.Cooldown using faulted or-DECREASING ruptured SG(s).Page 10 of 16 Rev.4, CS-1  
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16166 11012%45.516.4K-l 666--.S-MIE K--6S MIE REC 611M 4E
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}R favell 1rcc Rll CO 8%2MI2 STA-fE-l R--.S.Bff 45.5TA.+4 FIGURE E-10 HPR3 FAULT TREE HPA3 Fault Tree HPR30OOI HPR30004 SU9-HPA HPRW-CSR-COGHE HPR30005 AEC.US-STA--HE-L REC--(ALC-LONE AEC--~~ID-ISE REC-----5-INHE FIGURE E-11 HPR4 FAVLT TREE HPA(Fault Tree HPA(0001 HPR40004 SUB-HPA HPRA.LPA.CSRHE HPR40005 REC-US-STA--%-L REC----<D.NHE REC-----54fSE ATTACHMENT 1 TO AEP'NRC'10820 Donald C.Cook Nuclear Plant Individual Plant Examination Individual Plant Examination Revision 1
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Latest revision as of 01:18, 4 February 2020

Repair Boundary for Parent Tube Indications within Upper Joint Zone of Hybrid Expansion Joint Sleeved Tubes.
ML17332A992
Person / Time
Site: Cook American Electric Power icon.png
Issue date: 09/30/1995
From: Cullen W, Keating R, Kuchirka P
WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
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WCAP-14447, NUDOCS 9510270085
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Westinghouse Non-Proprietary Class 3 WCAP-14447 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes September 1995 R. F. Keating W. K. Cullen P. J. Kuchirka WESTINGHOUSE ELECTRIC CORPORATION NUCLEAR SERVICES DIVISION P.O. BOX 158 MADISON, PENNSYLVANIA 15663-01 58

@ 1995 WESTINGHOUSE ELECTRIC CORPORATION All Rights Reserved 9510270085 951020 PDR ADOCK 05000315

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Westinghouse non-Proprietary Class 3

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Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes TABLE OF CON'IENTS SECTION PAGE 1.0 Introduction 1-1 1.1 Description of the Sleeving Process 1-1 1.2 Summary of HEJ Sleeve Installations 1-2 1.3 Summary of HEJ Repair Boundary Qualified in this Report 1-2 2.0 Discussion and Conclusions 2-1 2.1 Discussion 2-1 2.2 Conclusions 2-2 2.2.1 Indication Locations 2-2 2.2.2 Allowable Indication Arc Length 2-2 2.2.3 Axial Indications 2-2 2.2.4 Primary-to-Secondary Leakage 2-2 3.0 Regulatory Requirements 3-1 3.1 Regulatory Guide l. 121 3-1 3.2 Accident Condition Allowable Leak Rate 3-2 4.0 Field Experience 4-1 4.1 HEJ Sleeved Tube Indications 4-1 4.1.1 Kewaunee Nuclear Power Plant 4-1 4.1.2 Point Beach Unit 2 Nuclear Power Plant 4-1 4.1.3 Kerncentrale Doel 4 Nuclear Power Plant 4-2 4.2 Summary of Field Experiences 43 5.0 Summary of Examinations Conducted on Kewaunee Steam 5-1 Generator Tubes with Hybrid Expansion Joints 5.1 Introduction 5-1 5.2 NDE Results 5-1 5.3 Leak Testing 5-2 5.4 Tensile Testing 5-2 5.5 Destructive Examination Results 5-3 5.6 Surface Chemistry 5-5 5.7 Conclusions 5-6 09/2$ /9$

Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEJ) Sleeved Tubes TABLE OF COÃZP24TS (Continued)

SECTION PAGE 6.0 Structural Integrity and Leak Rate Evaluations 6-1 6.1 Structural Integrity Tests 6-1 6.2 Pulled Tube Structural Tests 6-2 6.3 Structural Integrity Analyses 6-2 6.4 Leak Rate Tests and Analyses 6-3 6.5 Crack Growth Rate Considerations 6-3 6.6 Additional Tube Integrity Considerations and Observations 6-3 6.7 Conclusions 6-4 7.0 Leak Rate Based Repair Boundary 7-1 7.1 Introduction 7-1 7.2 Sleeved Tube Dimensions 7-2 7.3 U-Bend Clearance 7-3 7.4 Leakage Potential 7-5 7.4.1 Normal Operation 7-6 7.4.2 Steam Line Break 7-6 7.5 Tubes Interior to Stayrod Locations 7-7 7.6 Distribution of Indications in the Kewaunee SGs 7-7 Sleeved Tubes 7.7 Plant Operation Considerations 7-8 7.8 Summary and Conclusions 7-8 8.0 Repair Boundary for Parent Tube Indications 8-1 8.1 Compliance with draft RG 1.121 Tube Integrity Criteria 8-1 8.2 Offsite Dose Evaluation For a Postulated Main Steam 8-2 Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve 8.3 Evaluation of Other Steam Loss Accidents 8-2 8.4 HEI Inspection Requirements 8-3 HEllNDEX.SEC

Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HEW) Sleeved Tubes TABLE OF CONHMTS (Continued)

SECTION PAGE 9.0 Summary of Sleeve Degradation Limit Acceptance Criteria 9-1 9.1 Stxuctural Considerations 9-1 9.1.1 Crack Indications Below the Upper Hardroll Lower 9-1 Transition 9.1.2 Sleeved Tube with Degradation Indications with 9-1 Non-Dented Tube Support Plate Intersections 9.1.3 Dented Tubes 9-1 9.2 Leakage Assessment 9-1 9.3 Defense In Depth and Primary to Secondaxy Leakage Limits 9-2 10.0 References 10-1 Appendix A, Review of Prior Amendment Requests for HEI Sleeved Tubes 1.0 Discussion/Chronology of Pxior Amendment Requests $ -1 2.0 Summaxy of Stxuctural Integrity and Leak Rate Evaluations A-2 2.1 Structural Integrity Tests A-3 2.2 Structural Integrity Analyses A-.4 2.3 Leak Rate Tests and Analyses A-5 2.4 Crack Growth Rate Evaluations A-5 3.0 Summary A-6 HEJ INDEX.SEC

Westinghouse non-Proprietary Class 3 Repair Boundary for Parent Tube Indications Within the Upper Joint Zone of Hybrid Expansion Joint (HED) Sleeved Tubes 1.0 Introduction In the Spring and FaH of 1994, and the Spring of 1995, indications were found in the hybrid expansion joint (HEJ) region of Steam Generator (SG) tubes which had been sleeved using Westinghouse HEJ sleeves. As a result of these findings, analytic and test evaluations were performed'o assess the effect of the degradation on the structural, and leakage, integrity of the sleeve/tube joint relative to the requirements of the United States Nuclear Regulatory Commission's (NRC) draft Regulatory Guide (RG) 1.121, Reference 10. The results of these evaluations demonstrated that tubes with implied or known crack-like circumferential parent tube indications (PIIs) located 1.1" or, farther below the bottom of the hardroll upper transi-tion, have sufficient, and significant, integrity relative to the requirements of the RG. Thus, the purpose of this report is to provide justification for a repair boundary that supersedes that specified in the original Westinghouse WCAP'ualification documents. A listing of United States plants with installed HEJs is provided in Table 1-1.

1.1 Description of the Sleeving Process In accordance with Plant Technical Specification requirements, steam generator tubes are periodically inspected for degradation using nondestructive examination (NDE) techniques. If established degradation acceptance criteria are exceeded, the indication must be removed from service by plugging or repairing the tube. Tube sleeving is one repair technique used to return a tube to an operable condition.

In the sleeving technique, a smaller diameter tube, or sleeve, is positioned within the parent tube so as to span the degraded region. The ends of the sleeve are then secured to the parent tube forming a new pressure boundary and structural element between the attachment points.

Sleeves may be positioned at any location along the straight length of a tube, but are typically placed to repair tube degradation at the top of, or within the tubesheet, or at tube support plate (TSP) intersections. Sleeves may be of various lengths and may be attached to the parent tube in a variety of ways. In the case of Westinghouse sleeve designs, the method of attachment is generally restricted to either a leak limiting mechanical HEJ or a hermetic Laser Welded Sleeve (LWS) joint. The type of the particular joint configuration is a function of the date of installation and/or the customer's needs and the current plant operating conditions.

Figure 1-1 shows a schematic of a typical HEJ tubesheet sleeve installation. Figure 1-2 illustrates the details of the upper joint along with terminology used in this report. Typical dimensions of the joint are illustrated on Figure 1-3. Note that only the sleeve/tube upper joint is referred to as a HEJ, and the sleeve is referred to as an HEJ sleeve.

References 8 and 9, supplemented by References 11 and 12.

Westinghouse Commercial Atomic Power DAPLANTSVEPQKllNTRO.SEC 09/26/9S

Westinghouse non-Proprietary Class 3 1.2 Summary

~ of HEJ Sleeve Installations

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As s hown in Table 1 -2 since its incep tion in 1980, the HEJ sleeve has been successfully used to restore over 28,000 steam generator tubes to operational status. Due to decommissioning of plants and replacement of steam generators, only about 12,000 HEJ sleeves remain in service. As shown in Table 1-3, HEJ sleeves are currently in service in the United States at the D. C. Cook Unit 1, Point Beach Unit 2, Kewaunee, and Zion Unit 1 nuclear power plants. The HEJ sleeves listed in Table 1-2 were installed between April 1983 and May 1993, and have operated in the United States without incidence of significant leakage through the upper joint; Doel 4 (Belgium) experienced leakage through an upper joint crack in a parent tube in April of 1994.

Until March of 1994 there had been no reports of degradation of the parent tubes or the sleeves. In 1994, degradation of the pan.nt tube of HEJ sleeved tubes was detected at the Kewaunee, Point Beach 2, and Doel 4 power plants. At Kewaunee the indications were predominantly located in the hardroll lower transition (HRLT), while at Point Beach 2 the indications were predominately in the hydraulic expansion lower transition (HELT), and at Doel 4 the two confirmed indications were located at the hydraulic expansion upper transition (HEUT). Additional degradation was reported at Kewaunee in the Spring of 1995, and three sleeve/tube joints were removed from the "B" SG for laboratory examination. The structural and leakage integrity of HEJs in 7/8" nominal diameter tubes with indications located 1.1" below the hardroll upper transition (HRUT), and lower, is the sub~ec t of this report.

I 1.3 Summary of the HEJ Repair Boundary Qualified in this Report The repair boundary is based on analytic evaluations, the results of prototypic testing, and the results of the destructive examinations and tests of the HEJ specimens removed from Kewaunee. The reference location, i.e., the bottom of the HRUT, for reckoning the repair boundary was selected based on the ease of measuring the elevation of indications relative to the that location using existing, e.g., the Westinghouse CECCO and the Zetec + Point eddy current probes, nondestructive examination (NDE) technology. The actual location of the repair boundary is supported by the structural and leakage evaluations performed using the data from the destructive examinations of the field specimens and the prototypic testing reported in WCAP-14157 and its addendum.

DAPLANTSUEEPQKJINTRO.SEC 1-2

Westinghouse non-Proprietary Class 3 Table 1-1: Sleeving Design Documents for United States Plants with HETs Design Document Subject Reference(s)

WCAP-9960 Point Beach Unit 2, Alloy 600 sleeves 1,2 I

WCAP-11573 Point Beach Unit 2, Alloy 690 Sleeves 3 WCAP-11643 Kewaunee, Alloy 690 Sleeves 4,5 WCAP-11669 Zion Units 1 & 2, Alloy 690 Sleeves WCAP-12623 D. C. Cook Unit 1, AHoy 690 Sleeves DM'LANTSVLEPQKBJINTRO.TBL 1-3

Westinghouse non-Proprietary Class 3 Table 1-2: Westinghouse Sleeving Experience Chronology Number Sleeve Characteristics Date S/G Sleeve Plant e(1) 0 Length Installed Type Material Sleeves (in)

San Onofre 2 10/80-6/81 W-27 TS 6929 600TT 27,30,36 HEJ Point Beach 1 11/81 W-44 TS 13 36 HEJQ)

Indian Point 3 10/82-1/83 W-44 TS 2971 600TI'S 36,40,44 HEJ Point Beach 2 4-6/83 W-44 3000 600TI'S 36 Millstone 2 7-9/83 CE-67 2036 625/690TT 40 Ringhals 2 05/84 W-51 TS 69021 30 Braze Millstone 2 03/85 CE-67 TS 2926 625/690TI'0 Indian Point 3 07/85 W-44 TS 635 36,40,44 HEJ Millstone 2 11/86 CE-67 TS 225 625/690TT 40 Point Beach 2 10/87 W-44 TS 690TT 36 Kewaunee 03/88 W-51 TS 1940 690TT 30,36 HEJ Zion 1 03/88 W-51 TS 58 690TT 30 Doel 3 06/88 W-51 TS 54 690TT 30 Point Beach 2 10/88 W-44 TS 509 6901T 30 Laser"'0,36 Kewaunee 03/89 W -51 TS 1698 690TT HEJ Point Beach 2 10/89 W-44 TS 298 690TI'6 Kewaunee 03/91 W-51 TS 691 690TT 27,30,36 Parley 2 3/92 W-51 TSP 69 690TI'0 Laser)

Parley 2 3/92 W-51 TS Laser8) 690TI'2 690Tl'0 D. C. Cook 1 7/92 W-51 TS 1840 30,27 HEJ Parley 1 9/92 W-51 TSP 148 690TT 30 Laser8)

Parley 1 9/92 W-51 TS 690Tl 12 Laser)

Doel 4 5/93 W-E1 TS 1752 690TT 30,36 HEJ Doel 4 1994 W-E1 TS ) 11000 690TT 12 Las ere)

Total >39000 Notes: (1) TS = tubesheet sleeve & TSP = tube support plate sleeve.

(2) Brazed sleeves also installed.

(3) CO, laser used for the welding process.

(4) YAG laser used for the welding process.

DAPLANTSU.EPQKJINTRO.TBL 1-4

Westinghouse non-Proprietary Class 3 Table 1-3: HEJ Sleeves Operational Status as of 1994 Date S/G Number of Sleeve Characteristics Plant Installed Type Sleeves<'> Material Length (in)

Point Beach 2 4-6/83 W-44 36 Point Beach 2 10/87 W-44 87 690TT 36 Kewaunee 3/88 W-51 1940 30,36 690TI'90TT Zion 1 3/88 W-51 47 30 Point Beach 2 10/88 W-44 509 690TT 30 Kewaunee 3/89 W-51 1698 690TT 30,36 Point Beach 2 10/89 W-44 298 690TT 36 Kewaunee Doel 4

"'/91 D. C. Cook1 7/92 5/93 W-51 W-51 W-E1 691 1840 1752 690TI'7,30,36 690TT 690TT 30,27 30,36 Total 11862 Notes; (1) Number is approximate.

(2) HEJ modified by YAG laser welding in 1994, D:1PLANTS~HEJINTRO.TBL 1-5 09/26/95

('

Upper Hydraulic: Upper Hardroll Expansion Parent Tube ~

,~ Sleeve

. Tubesheet Lower Hydraulic Expansion Lower Hardroll

/

Cladding Figure 1-1: Typical HEJ Sleeve Installation SAAPC~P95~P HEJF.001 1-6 7/30/95

Tube Hydraulic Expansion Upper Transition Sleeve (HEUT)

Hardroll Upper Transition (HRUT)

Hardroll Hardroll Lower Transition Bottom of the (HRLT) transition.

Hydraulic Expansion Lower Transition (HELT)

Figure 1-2: Hybrid Expansion Joint ConQguration S:EAPCEAEP954AEP HEJF.001 1-7

Figure 1-3: Typical Dimensions of the HEJ SAAPC~P9SULEP HEJF.001 1-8 7/30/95

Westinghouse non-Proprietary Class 3 2.0 Discussion and Conclusions The burst criteria of draft RG 1.121 were used to establish a repair boundary for HEJs with PTIs. The continued safe operation of the SGs is not compromised if the PTls are located below the repair boundary, i.e., 1.1" downward from the bottom of the HRUT or lower, as illustrated on Figure 2-1.

A geometry based argument has been developed, Section 7.0, to support the repair boundary as established by structural considerations for PTIs in HEJ sleeved tubes.' summary of the conclusions relative to the establishment and implementation of the repair boundary for HEJ sleeved tubes in Westinghouse Model 44 and 51 SGs is provided in Section 2.2. Additional sections of this report provide a discussion of field experiences through the date of publication of this report, the details of the destructive examinations of sleeved tube sections removed from an operating SG, and structural integrity and potential leak rate considerations made to establish the repair boundary.

2.1 Discussion During the Spring, 1995, outage at Kewaunee, three (3) HEJ sleeved tube sections were removed intact from SG "B" for laboratory examination. One of the sections was designated for archive retention and the remaining two sections have been destructively examined. Each of the specimens exhibited field called PTIs in the hardroll lower transition using thb + Point probe. The indications were confirmed to be extensive, circumferentially oriented, stress corrosion crack arrays (SCC) originating on the inside surface of the tube, confirming the accuracy of the detection and sizing of the NDE. No cracking of the sleeves, and no cracking in the upper transitions of the tubes was found. A detailed discussion of the results of the examinations are provided in Section 5.0 of this report. Structural tests done on two of the removed HEJ tube sections strongly supports the establishment of the repair boundary as stated in this report.

As reported in References 8 and 9, structural analyses and tests were performed which demon-strated that degradation of any extent below the middle of the HRLT could be tolerated without violating draft RG 1.121 requirements for protection against burst for tubes subject to degradation. References 8 and 9 also presented structural integrity and leak rate information relative to failure of the tube/sleeve joint for cracks above the middle of the hardroll if the circumferential extent did not exceed a specified limit. These latter evaluations are not directly germane to the repair boundary established herein; however, a chronological discus-sion of those evaluations, and activities proposing license amendments, is provided in Appendix A to this report.

The third section sample is being retained as an archive specimen for future testing if necessary.

DAPLANTSLAEPQKJINTRO.SEC 2-1 09/26/9$

Westinghouse non-Proprietary Class 3 2.2 Conclusions This document is applicable to the HEJs in service in SGs at D. C. Cook Unit 1, Kewaunee, Point Beach Unit 2, and Zion Unit 1. Specific conclusions relative to the location of the repair boundary, axially oriented PTIs, primary-to-secondary leakage, and the susceptibility of the upper transitions to concurrent degradation are provided in the following subsections.

2.2.1 Indication Locations Tests conducted in joints designed to simulate a 360'hroughwall crack have shown that the upper hardroll must have additional axial load carrying capability to supplement the radial contact pressure of the sleeve-to-tube interface. To comply with this condition, PTls in the sleeve/tube joint, i.e., the HEJ, must be limited to 1.1" and lower as reckoned downward from the bottom of the HRUT.

It is to be noted that a significant database of field NDE information has been accumulated that demonstrates that the appearance of PTIs in the lower transitions of an HEJ does not imply a susceptibility of the tubes to upper transition PIIs. This is supported by the findings from the destructive examination of several HEJs removed from operating SGs in the United States and Europe.

2.2.2 Allowable Indication Arc Length Testing of surrogate and field specimens has demonstrated that an HEJ with a 360'hrough-wall PTl indication at/below the middle of the HRLT will successfully withstand the loads resulting from three times the normal operating pressure differential and 1.43 times the postulated SLB pressure differential. Therefore, there is no BOC limitation on the circumferential extent of PTls located below the repair boundary as describe in this report.

2.2.3 Ax% Indications Axial indications do not independently result in a significant reduction of the axial load carrying capacity of the joint. However, without additional information, it may be supposed that the presence of axial indications may degrade the axial load carrying capability if circumferential cracking is concurxently present. In addition, axial cracks could have an effect on leakage through the sleeve-to-tube joint. Until additional information is developed, it is recommended that HEJs exhibiting axial PTIs above the bottom of the HRLT be removed from service.

2.2.4 Primary-to-Secondary Leakage The use of the specified repair boundary for PTIs should be implemented in concert with an operational leakage limit of 150 gpd and enhanced inspection criteria designed to quantify the orientation and location of potentially crack-like PTIs. Analyses have shown that the tubesheet sleeve lower hardroll joint, located at the tube entry, poses no structural or leakage DAPLANTSVLEPQlHKTRO.SEC 2-2

Westinghouse non-Proprietary Class 3

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integrity concerns. The demonstration of the upper joint integrity has been demonstrated

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based on mechanical test programs supplemented by analytic evaluations.

0 Potential primary-to-secondary steam generator tube leakage should be calculated for indications remaining in-service within the identified repair boundary zone. The total predicted leakage from the SG during a postulated SLB event should be compared against the allowable leakage as determined using NUTMEG-0800 calculation guidelines.

DAPLANTSMEPU6JINTRO.SEC 2-3 09/26/95

Repair Boundary for HEJ Sleeved Tubes HRUT I Existing repair limits apply to the parent I tube and the sleeve.

1.1" below the bottom of the HRUT.

Revised repair I limit boundary applies to I

sleeve only.

I I

I I

I I  : Repair limits Roll Expansion:. '.:.

apply to the

sleeve & tube.

Figure 2-1: Revised Pressure Boundary De6nition for HEJ Sleeved Tubes D:KPLAYISEAE P 4 HEJSUMRY.FIG 2-4

Westinghouse non-Proprietary Class 3 3.0 Regulatory Requirements In order to repair SG tubes, an integrated qualification plan was developed to demonstrate the acceptability of the HEJ sleeve/tube joint. Documentation of the sleeve design and attendant analyses of Alloy 600 and 690 thermally treated HEJ sleeves for the repair of SG tubes are contained in Westinghouse technical reports referred to as WCAPs. These reports describe the design basis for sleeving as a repair, the testing and analysis used to support the acceptability of the repair technique, and the method used to demonstrate acceptability of the repair following its application. A similar approach is taken in this report. The repair boundary for the parent tube in the HEJ HBLT is established such that the design basis of the sleeve/tube meets the requirements of RG 1.121. A listing of the WCAP reports applicable to the plants in question was provided in Section 1 of this report.

Current WCAPs define the sleeving application and repair limits. They define the zones of in-service-inspection for the sleeve, and the limit of acceptable sleeve and sleeve joint degradation. The sleeved tube inspection requirements and repair boundary for the HEJ are summ~ in Figure 2-1.

Based upon the experiences at Kewaunee, Point Beach 2, and Doel 4, it is evident that the parent tube material in the vicinity of the HEJ transitions can be subject to the development of PTls. In order to prevent the unnecessary plugging of potentially degraded sleeved tubes, the structural integrity of the degraded joints may be evaluated against the burst criteria of draft RG 1 121. In addition, the leakage integrity of the sleeved tubes with PTIs should not repre-

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sent a potential for offsite doses to exceed the limits defined in Title 10 of the Code of Federal Regulations Part 100 (10 CFR 100).

RG 1.121 describes a method acceptable to the NRC staff for meeting General Design Criteria 14, 15, 31 and 32 by reducing the probability and consequences of steam generator tube rupture. This is accomplished by determining the limiting safe conditions of degradation of steam generator tubing, beyond which tubes with unacceptable cracking, as established by in-service inspection, should be removed from service or repaired. The repair boundary is established such that the primary-to-secondary pressure boundary will not result in tubes with partial and/or complete throughwall PIIs outside of the boundary being returned to service.

The regulatory basis for leaving the indications within the boundary limits in service is dis-cussed below.

3.1 Regulatory Guide 1.121 In establishing the HEJ parent tube repair boundary, the elevation of PTls in the tube span between the tubesheet and HEJ transitions must be considered. The main purpose of a sleeve is to bridge PTIs with a new pressure boundary. The parent tube repair boundary established by References 1 through 7 documented the potential for PTIs to exist up to 1" below the hardroll. The HEJ joint inherently provides protection to tube burst and significant leakage.

The NRC staff has defined tube rupture in NVREG-0844 as an uncontrollable release of reactor coolant in excess of the normal makeup capacity. Examining the upper HEJ, tube DAPLANTSV,EPQKJINTRO.SEC 3-1 09/26/9S

Westinghouse non-Proprietary Class 3 burst gould only be expected if a circumferential separation of the parent tube is postulated, and the parent tube was then pushed out of intimate contact with the sleeve due to normal operating or faulted loads. These loads are generated by the pressure differential across the tube wall, represented by the tube end cap loads. Draft RG 1.121 uses factors of safety consistent with Section III of the ASME Code. The HEJ, and areas within the HEJ where degradation has been indicated by NDE, provides an overlap of the tube and the sleeve for a length of approximately 3 inches in the free-span region above the top of the tubesheet. This overlap must be considered in the overall evaluation of the proposed degradation acceptance limits.

3.2 Accident Condition Allowable Leak Rate The accidents that are affected by primary-to-secondary leakage are those that include, in the activity release and offsite dose calculation, modeling of leakage and secondary steam release to the environment. The postulated steam line break (SLB) accident represents the most limiting case due to the potential for increasing leakage due to the steadily increasing primaTy-to-secondary pressure differential during recovery from the accident and the direct release path to the environment provided by the break in the steam pipe.

Establishment of the repair boundary includes calculation of the maximum permissible steam generator primary-to-secondary leak rate during a steam line break outside of the containment building. Standard Review Plan (NUREG-0800) methodology is used to establish the maximum permissible leak rate. This methodology has been used to justify primary.to-secondary leak rates greater than the value of 1.0 gpm normally assumed in the plants'SAR.

This methodology ha's been utilized previously by the NRC for the licensing of the steam generator tube support plate voltage based plugging criteria, described in Generic Letter 95-05. NUTMEG-0800 limits the thyroid dose to 10% of the 10 CFR 100 limit of 300 Rem for the accident initiated iodine spike case. The repair boundary established in this report considers a conservative SLB per tube leakage aHowance based on test data to account for potential leakage from PTIs left in service. The total SG SLB leak rate from all sources (including calculated leakage from TSP intersections which are addressed by Generic Letter 95-05) is summed when comparing the estimated leak rate against the value established using the methodology of NU~REG 0800.

D:LPLANTSMEPQlHINTRO.SEC 3-2 10/03/95

Westinghouse non-Proprietary Class 3

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4.0 Field",Experience

~ s 4.1 HEJ'Sleeved Tube Indications s4 4.1.1 Kewaunee Nuclear Power Plant In April~of 1994, seventy-seven (77) PTIs were detected in the HEJ of sleeved tubes (based on a 100,%'inspection) in the SGs at the Kewaunee Nuclear Power Plant using the Zetec I-coil eddy current inspection probe. A detailed description of the indications and their locations is provided in Reference 8. One (1) circumferential PTI (about 34 ) was found at the HEUT, see Figure 1-2 for the joint designations. There was no operating leakage attributable to the presence of this indication. One (1) indication was found to be axial and contained within the .

hardroll (HR) expansion. No axial indications were identified above or below the HR. Two (2) indications were identified as volumetric within the hydraulic expansion below the HRLT.

Sixty-two (62) indications were identified as circumferential and located at the HRLT. The xemaining eleven (11) indications were located at/below the bottom of the HELT. There wexe no instances of multiple indications in a single HEJ. The circumferential extent of the indica-tions ranged from 45'o 285, with nine (9) being judged to be greater than 200 in extent.

The average elevation of the sixty-two indications was found to be 1.42" below the top of the HRUT with a standard deviation of 0.08". The calendar time of operation for the tubes

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following sleeving ranged from five to six years. The distribution of the indications as a

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function of installation year is provided in Table 4-1. ~

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In April of 1995, seven-hundred and thirty-eight (738) HEJ PTIs were detected using the Zetec + Point eddy current inspection probe. Again, a 100% inspection of the HEJs in the SGs was performed: Five (5) circumferentially oriented PTIs were reported at the HE uppex transition. Again, there was no leakage reported from any of the indications. Nine (9) axially oriented PTIs were reported in the hardroll region. Six-hundred and forty-three (643) circumferential PTIs were reported at elevations ranging fmm 1.00" to 1.75" below the bottom of the HRUT. This corresponds to 0.00" to 0.75" below the nominal top of the HBLT. The remaining eighty-one (81) indictions were located at/below the HELT. One tube was reported as having multiple, i.e., two, PTIs, both of which were below the top of the HBLT. The circumferential extent of the indications ranged from 45'o 360'ased on the NDE. The average elevation of the HBLT PTIs was found to be '1.32" below the bottom of the HRUT with a standard deviation of 0.10". The sleeves had been installed in 1988, 1989, and 1991, and were fabricated from thermally treated Alloy 690 material. The distribution of

'he indications as a function of installation year is provided in Table 4-2.

P 4.1.2 Point Beach. Unit 2 Nuclear Power Plant In October of 1994, two-hundred and thirty (230) circumferentially oriented HEJ PTIs were detected using the Westinghouse/Ontario Hydro CECCO 3 eddy current inspection probe. All

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of the HEJs were examined on the hot leg of the SGs. A 20% sample of the HEJs examine

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on the cold leg side of the SGs revealed no indications. One (1) indication was de/ected in the

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HEUT, seven (7) in the HRUT, eighty-eight (88) in the HBLT, and one-hundxcdsand tliirty-

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D:LPLANTSV,PKHEIFIELD.SEC 4-1

Westinghouse'non-Proprietary Class 3 N

four (134) in the HELT.'he minimum PTI angle reported was 23 and the maximum was

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360'.~ 'fhe sleeves had been installed in the tubes in 1983, and were fabricated from thermally,

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treated Alloy 600 material.

4.1.3 Kerncentrale Doel 4 Nuclear Power Plant "G" at Doel 4 in April of 1994 Significant in-service leakage was detected from a PTI in SG one week before a scheduled outage. The leak was attributed to a throughwall PTI at the HEUT. The tube/HEJ was removed from the SG along with a joint from a randomly selected tube. The indication in the leaking tube had an ID extent of -180 and an OD extent of -160'.

A PTI was'ound in the other tube at the same elevation. It consisted of three (3) separate, circumferentially adjacent cracks with an aggregate length of -5 mm (34 ). The deepest crack has been reported as being 90 to 100% throughwall, Reference 16. The PTfs in both tubes weie attributed to primary water stress corrosion cracking (PWSCC). A total of 1740 tubes had thermally treated Alloy 690 HEJ sleeves installed in 1993.

The tubes at Doel 4 are considered to be particularly susceptible to PWSCC. During the outage the detection of significant numbers of tubes cracked at the tube/tubesheet hardroll transitions led to the decision to sleeve all of the tubes in the three SGs at that site using laser welded sleeves (LWSs), and to add a laser welded joint to each of the HEJ sleeves at an elevation above the HEUT.. During the LWS campaign, fifty (50) additional HEJs were examined using the CECCO 3 probe. Nine (9) of the tubes were indicated to contain PTls.

Six (6) of these were at the HEUT and the remaining three were at the HELT. None of the tubes were indicated to have multiple PTIs'.

In the Summer of 1995, a CECCO 3 probe was used to inspect all of the sleeve joints in the three SGs. A + Point probe was also used to inspect 184 of the welded HEJ sleeves. A summary of all findings was not available at the time of preparation of this report. Six (6) of the weld repaired HEJ sleeved tubes were removed for destructive examination. Two of these had been identified as having no detectable degradation (NDD) at the HEUT by the field NDE. These were confiimed to be NDD in the laboratory. The other four HEJs exhibited PTIs by the field NDE. One of these was found to have an ID initiated throughwall crack

(-0.5" on the ID and -0.25" on the OD) at the elevation of the HEUT. This tube broke during the removal operation at a tensile load of -9700 lb,. The other specimens had experienced wastage of the parent tube and the Alloy 690 sleeve at the bottom of the closed crevice, i.e.,

the HEUT, formed when the laser welding was effected. The wastage may likely be due to a concentration of an acidic environment in the -6" long closed crevice between the HEJ and the repair weld.

Note that this information is an update of information previously presented, e.g., Refer-ence 15, where it was stated that no indications had been reported in the HRUT, An expert review of the NDE data revealed that the location information was distorted as a result of pulling the probe down into the sleeve from the tube. A reevaluation of all of the PTI elevations was performed only to identify the location of the PTIs by transition, thus average dimensional information was not available at the time of preparation of this report.

DM'LANTSVLEPQKJFIB.D.SEC 4-2 09/25/95

Westinghouse non-Proprietary Class 3 4.2 Summary

~ of Field Experiences In summary, FIIs have been detected in HEJ sleeved tubes at three plants during a total of

~ ~

'our inspection ~ ~ ~ ~ ~

outages, two at Kewaunee, one at Point Beach 2, and the initial inspection

~

outage at Doel 4. A summary of approximately all known PTIs is provided in Table 4-3. In

~ ~

total, about 60.5% occur at the HRLT and 37.2% at the HELT. About 0.7% have been found at the HRUT, and the remaining 1.6% at the HEUT. These distributions are illustrated in histogram form on Figure 4-1 and in "pie" chart form on Figure 4-2. The incidence of indications at the upper transitions in plants in the United States (VS) comprises about 1.5%

of the reported indications. Thus, the distribution at Doel 4 is atypical of the occurrences in the VS. In no instances have indications been detected in the same tube at upper and lower transitions.

Approximately 75% of the known PIIs have been found in tubes in the Kewaunee SGs.

Hence, it would be expected that the distribution of indications relative to elevation can be characterized by the distribution found at Kewaunee. Figure 4-3 illustrates the distributions of PTls at the last inspection outage at Kewaunee.'pproximately 1% of the indications were judged to be located within 1.1" of the bottom of the HRUT. If an eddy current positioning error of 1/16" is assumed, the number of indications above the repair boundary would be on the order of 4%.

The elevation information is based on an "expert" review of 630 PTIs, or 98% of population of circumferential indications.

DAPLANTS'REP6iEJFIELD.SEC 4-3 09/25/95

Westinghouse non-Proprietary Class 3 Table 4-1: Distribution of Kewaunee 1994 HEJ Indications Removed from Service by Installation Year Installation SG SG Both Year II A II I IBll SGs 1988 46 17 63 1989 1991 Totals 48 18 66 Table 4-2: Distribution of Kewaunee 1995 HEJ Indications Removed from Service by Installation Year Installation SG SG Both Year II All IIBII SGs 1988 283 152 435 1989 147 69 216 1991 Totals 431 226 657 DAPLANTSM.EPQKJFIELD.SEC 4-4

Westinghouse non-Proprietary Class 3 TabIe 4-3: Distribution of HEJ PTIs by Transition Point Transition Doel 4 Totals Percent Kewaunee'12 Beach 2 HELT 134 349 37.2 480 88 568 60.5 0.7 15 1.6 Totals 698 230 939 100 10 10 Volumetric Totals 710 230 951 Notes; 1. 1995 numbers based on the findings of an "expert" review of the elevations relative to the bottom of the HRUT prior to the final data becoming available.

DN'LANT',ECHE/I'IELD.SEC 4-5 09/25/95

Figure 4-1 Distribution of Circumferential PTIs by HEJ Transition 600 SDoel 4, 1994 600 Q Point Beach 2, 1994 8Kevraunee, 1994 8c 1995 O

~ 300 K

200 10Q 0

HELT HRLT HEUT HEJ Transition D .PLAlCTSEAEP'LHEJFIELD.F1G

Figure 4-2 Distribution of All Circumferential PTIs by Transition Hydraulic Expansion Hardroll Upper Upper Transition Transition Hydraulic Expansion Lower Transition Hardroll Lower Transition EIHELT =37.2%

HHRLT = 60.5%

OHRUT = 0.7%

~ HEUT = 1.6%

D: 5 PLANYSKAEPT HEJFIELD.FIG 4-7 , 08/01/95

Kemaunee SGs "A" 4 "8" HE J PTIs vs.

Distance Below'he Bottom of the HR Upper Tra.position 130 happ 120 90%

110 80%

100 90 EK3 Both SG Indications Both SG Cumulative 95% Rank Cumulative 70%

O ca O

'a 80 60%

pg 0

70

~r 0%

o 60 lC 40% o 50 40 RG 1.121 30%

8 30 Repair Limit 20%

20 10%

10 0 0%

eo oc4 e M

o co eco ow ew oe ee o cD eco o C

e Upper Bin Distance Below Bottom of HR Upper Transition

Westinghouse non-Proprietary Class 3 5.0 Summary of Examinations Conducted on Kewaunee Steam Generator Tubes with Hybrid Expansion Joints 5.1 Introduction Sections of SG tubes R2C32, R2C54 and R2C61 were removed from the hot leg side of SG "B" at Kewaunee in 1995 to characterize the operating condition of the HEJs which had been installed in these tubes in 1988. The HEJs had been installed to prevent leakage through tube corrosion at top of tubesheet (TTS) and tubesheet crevice locations. The tubes/HEJs were cut 3" above the TTS and 3" below the first tube support plate (TSPs) and were then removed from the secondary side of the steam generator to avoid deformation that would have probably occurred from a primary side tube pull. Consequently, only the upper mechanical joints of the HEJs were available for examination. The upper mechanical joint is described in Section 1 of this report. The tube material was mill annealed Alloy 600, and the sleeve material was thermally treated Alloy 690. The examination was conducted at the Westinghouse Science and Technology Center to characterize any tube/sleeve corrosion. Field eddy current suggested the presence of significant circumferential corrosion at the hard roll lower transition (HRLT) in the upper mechanical expansion of the HEJs.

After nondestructive laboratory examination by eddy current, radiography, dimensional characterization, and visual examination, one HEJ region was leak tested at elevated temperature. Subsequently, room temperature tensile testing was conducted on two,of the HEJs, as well as on three free span sections, one from each removed tube. The third tube/

HEJ section was retained intact as an archive specimen. The two HEJs which were tensile tested were then destructively examined using metallographic and SEM fractography techniques to characterize any corrosion. In addition, an analysis of the OD and ID deposits, ID oxide films, and fracture face oxide films was performed using EDS, ESCA and AES tech-niques. In addition, ion chromatography and capillary electrophoresis were performed on soluble ID deposits obtained by water leaching.

5.2 NDE Results Table 5-1 presents a summary of the more important field and laboratory NDE results. The field eddy current data were conducted using + Point and I coil probes, while the laboratory inspections used + Point, CECCO and RPC probes. Field and laboratory eddy current inspections produced similar data. For the + Point probe, common to both the field and lab exams, the data produced the same signals, suggesting a 360'ircumferential indication in the HRLT of tubes R2C54 and R2C61, and a 300 to 360'ircumferential indication in the HRLT of tube R2C32. These signals were suggestive of deep, even throughwall degradation. The laboratory CECCO probe data produced similar conclusions with the exception that the circumferential indication in tube R2C32 appeared to be 360'ide, rather than 300 to 360 wide. In addition, the laboratory + Point and CECCO probes suggested the presence of a small indication in the hydraulic expansion lower transition (HELT) of tube R2C61 (the archive specimen). There was no suggestion by field or laboratory NDE of any corrosion degradation being present in the Alloy 690 sleeve.

DAPLARKVLERHE/EXAh(S.SEC 5-1 09/25/95

Westinghouse non-Proprietary Class 3 The radiographic laboratory examination detected a 270 to 360 circumferential band of short semi-continuous circumferential indications in the upper portion of the HRLT of the tube, just below the HR region in tube R2C32. These cracks were confined to a very narrow zone, less than 0.05" high, such that the individual cracks appeared to occur head-to-toe. In addition, a shorter (approximately 300 long) band of cracks was observed approximately 0.1" below the main band of cracks. tube R2C54 had two to three similar bands of short semi-continuous circumferential cracks that occurred over 350'rom the mid- to upper portion of the HRLT.

Tube R2C61 had one band of short semi-continuous circumferential cracks that occurred over 360'n the mid-portion of the HRLT.

The HRLT was approximately 0.25" long in the case of tube R2C32, and was approximately 0.5" long in the cases of tube R2C54 and R2C61. The HRLT apparently experienced noticeable rolldown'uring installation, especially for tubes R2C34 and R2C61. In contrast, the HRUTs for all three tubes were approximately 0.1 to 0.2" high. Dimensional characterization of the HE's showed that all three had similar hydraulic and hard roll expansion dimensions that were typical for qualified HEJ instaHations, e.g., see Figure 1-3.

The hardroll regions were expanded 0.009, 0.012 and 0.009" radially above the negligibly expanded hydraulic regions for tubes R2C32, R2C54, and R2C61, respectively.

5.3 Leak Testing The R2C54 HEJ was cut to 11" long with the hardroll region centered in the specimen. The bottom 1" of the specimen was then expanded to contact with the tube and the sleeve was then welded to the tube. This seal causes any leak through the hardroll region to occur bnly through the tube HRLT cracks. Elevated temperature leak testing was then performed on tube R2C54 at a variety of conditions that ranged from nominal operating conditions to simulated SLB conditions. No leaks were observed through the tube HRLT cracks at any of the test conditions. The maximum test differential pressure was 2534 psi with corresponding primary and secondary side temperatures of 618 and 611'F.

5.4 Tensile Testing Table 5-2 provides room temperature tensile properties obtained from a free span (FS) section of each tube. The tensile strengths for the FS section of tubes R2C34 and R2C61 are typical for Westinghouse tubing of this vintage. The tensile strength for tube R2C32 is noticeably higher than typical. Table 5-2 also provides tensile load separation data for the HEJs from tubes R2C32 and R2C54. The 11" long HEJ specimens, with their HR regions centered within the specimens, had the bottom 1" of their sleeves expanded into contact with the tubes.

The bottom end was then welded such that the sleeve and the tubing below the cracking in the HRLT would not move relative to each other during the tensile test. The top portion of the .

11" long specimens consisted only of tubing because the top of the sleeve ended approximately 3.3" below the top of the tubing. The HEJs were then pulled apart at 0.05" per minute with

'n order to remove the rolling tool from the installed sleeve, the direction of rolling is reversed to release the rollers from contact with the ID surface of the sleeve. Ifthe rollers do not immediately retract, additional rolling in the downward direction occurs, resulting in an elongation of the HRLT referred to as rolldown.

DM'LANT',EPLHEJEXAMS.SEC 5-2 N/25/9S

Westinghouse non-Proprietaxy Class 3 the separation load of the HRLT crack network being recorded. In additi th lidin of the HR region of the upper portion of the tubing being pulled over the HR region of the sleeve was also recorded. Both HEJs had high separation loads, 10,300 and 10,700 lb, respectively. The HR sliding loads decreased continuously over the remainin g HR region.

be R2C32, with the HRLT cracking located at the upper portion of the HRLT (at the bottom portion of the HR), had its sliding load start at 2800 lbs and decxease to 50 lbs at the toy portion of the sleeve HR. Tube R2C54, with the HRLT cracking located near the center of the HRLT, had a smaller diameter fracture opening that was required to pass over the s eeve HR region. Consequently, the initial sliding load was higher, 4000 lbs. The sliding oad continuously decreased to 200 lbs at the top portion of the sleeve HR.

5.5 Destructive Examination Results Post-tensile test visual inspection data showed that ID origin, circumferentially oriented, corrosion cracks were present continuously around the circumference of the tube fracture faces of both HEJs that were separated by tensile testing, Figure 5-1. The two HEJ specimens were subsequently given destructive examinations which included SEM fracto h f th ace openings, visual and SEM inspection of surface features and metallography of secondaxy corrosion within the HEJ region of the tubing.

The tensile fracture faces of the tubes from the two HEJ tensile specimens wexe examined by SEM. Table 5-3 presents the results of the fractographic data in the form of macrocrack length versus depth, microcrack length/average and maximum depth, and the number/location/

width of ductile or non-corroded ligaments found on the fracture face. The tube tensile

'h separations occurred in circumferentia1 macrocracks that were composed of numerous circumferentially oriented intergranular microcracks of ID o rigm a t wexe aligned ed in a single tight and narrow (< 0.05" high) band in the case of tube R2C32 an m a s lightly less tight and in narrow ( . g ) band in the case of tube R2C54 where the fracture face jumped from one circumferential crack network to a parallel one. (See radiogra hic data In S

..)

  • arge raction of the many ligaments separating the microcracks on botho specimens had ductile features. There were 21 ductile ligaments pxcsent in the case of tube R2C32 and 19 ductile ligaments present on the fracture face from tube RZC34. Many er li any oother ligaments aments had only intergranular features.

All intergranular e

'n corrosion was confined to and located in thee HRLT regions. In the case of e cracking was at the upper portion of the HRLT and in the case of tube R2C54 the cracking was located from the mid-portion of the HRLT to the upper portion of the HRLT. The fracture faces both had a maximum depth of 92% throu hwall ep s ranging rom 61% (tube R2C32) to 60% (R2C34) throughwall and with microcrack lengths that were 360 long. At some ID locations adjacent to the fracture faces, a few short circumferential microcracks were observed parallel to the fracture face. These microcracks appeared to be simple cracks, morphologically syeaking, in that the near absence o f o bli'que

~

g racks and bluntmg was noted. This morphology is more typical of PWSCC than of

~

~ ~ ~

secondary side corrosion that typically occurs in caustic crevices.

SEM examinations were conducted on the OD and ID surfaces of the balance of the tubing f

from, both tubes in the HEJ regions with the examination co ncen tratin g on m din g cracks at DAPLAPISV,EPQKJEXAMS.SEC 5-3

Westinghouse non-Proprietary Class 3 other, locations and on characterizing deposits. No cracks were observed. ID surface deposits were thin at all HEJ locations. Circumferential and oblique angled ID surface scratches from the honing operation used yrior to HEJ installation were clearly present below the HR. Above the HR, similar scratches were observed, but they were frequently obscured by slightly thicker, but still thin deposits. The ID deyosits on the tubes in the HR region, including those below the HR region, had the typical appearance of ID surface deposits that were located immediately above the HEJ sleeve. In the case of tube R2C32, local areas with unusual whisker-like deposits were observed just below the fracture face at the top of the HRLT and also at HRUT (hard roll upper transition). At no local crevice location (HR or HE transitions) were thicker or diffexently colored deposits observed, such as those typically concentrated by boiling.

No corrosion degradation was observed on the OD of the sleeves from both tubes when visual (30X) and SEM examinations were conducted. In comparison, similar examinations conducted on recent Doel 4 HEJs, that had been repaired by laser welding following a cycle of operation, showed some IGA type corrosion in the sleeve and tube. The IGA grain boundaries had very thick oxide layers in both the sleeve and tube at the bottom of a local crevice region.

Following SEM examination (and EDS analysis of deposits which will be presented shortly), a narrow axial metallographic section was cut from each tube through the HEJ region, primarily to obtain microhaxdness measurements from selected locations. Table 5-4 presents this data.

The microhardness at the fracture face location (HRLT) was similar to or slightly higher than other HE and HR transition locations; however, the ID-most microhardness next to 'the fracture face of both tubes did include two of the three highest hardness values, when appropriately ignoring hardness values taken next to tensile shear surfaces. In addition, no cracks were observed by metallography at locations other than the fracture face location in the HRLT. After smaH ESCA-AES specimens were cut from just below the lower fracture face of tube R2C32, the remaining portions of the tubes from both HEJ specimens were deformed to open any ID origin cracks such that they could be readily observed by visual inspection (30X). The tube sections were cut axially into to two 180'ide halves. The halves were flattened to open axial cracks. None were observed at any of the hydraulically or hard roll expanded regions. The halves were then bent to open any ID surface cixcumferential cracks.

Again, none were observed at any of the hydraulically or hard roll expanded regions.

Finally, metallographic axial sections were made through the HRLT to the fracture face to characterize the 1GSCC that was present in the HRLT. The cracks observed were simple appearing, more similar to that expected from PWSCC than from secondary side corrosion where caustic environments are typically concentrated. From the metallographic and SEM surface examinations conducted on the HRLT corrosion, it was concluded that the only corrosion morphology was ID origin, circumferentiaHy oriented intergranular stress corxosion cracking. The cracks were simple in morphology with only minor D/W ratios measuxed.

(IGSCC morphology can be characterized by D/W ratios where the extent of IGA associated with a given crack is measured by the ratio of the crack depth, D, to the width, W, of the crack at its mid-depth. D/W ratios greater the 20 are defined as minor.)

DAPLANTSV.ERHEJEXAh(S.SEC 5-4 09/2S/95

Westinghouse non-Proprietary Class 3 The microstructures of the removed tubes varied. Tube R2C32 had a moderate to high number of carbides while tubes R2C54 and R2C61 had few carbides. For all three tubes, most carbides were distributed transgranularly rather than intergranularly, the preferxcd microstructure for PWSCC resistance. The grain size for tube R2C54 was ASTM 8.5, typical of Westinghouse tubing of similar vintage. The grain sizes for tubes R2C32 and R2C61 were somewhat smaller, approximately ASTM 10 and 9.5, respectively, Based on laboratory testing data, these microstructures may have relatively low resistance to PWSCC.

5.6 Surface Chemistry ID and OD deposit data were obtained from the two destructively examined specimens using energy dispersive spectrometry (EDS). In addition, ID and OD deposit/oxide film and fracture face oxide film data from the fracture face of tube R2C32 was obtained using ABS and ESCA techniques. The following observations are considered the more important from the data obtained. EDS data conducted on the ID surfaces of the both tubes in the HEI regions provided minimal information since the deposits were thin and most of the EDS signal came from the base metal/oxide layer beneath the deposits. Other than the base metal elements of Ni, Cr, Fe and Tl, the only elements detected were 0, Al, S, and Si. On the OD, where deposits were thick, the deposits were rich, in Fe and 0 with some observations of Ni, Cu and Zn. The pH of many ID and OD surfaces was determined using deionized water moistened wide-range pH paper. At all locations, the pH readings were neutral.

From the ESCA mid ABS data obtained on tube R2C32:

1) high concentrations of B were observed on the ID surface below the fracture face below the HR region;
2) Cr was not significantly enriched or depleted on either the crack fracture face in the ID surface below the fracture face;
3) low levels of Zn, Na, Mg, SI and S were also detected in addition to the expected C, 0, Ni, Cr, and Fe.

Capillary electrophoresis and ion chromatography of water leached soluble ID deposits from a location just below the fracture face of tube R2C32 showed:

1) soluble cations at the following concentrations Na (0.97 mg/1), Mg (0.25 mg/1), K (0.21 mg/1), Ca (0.21 mg/1), and Li (0.10 mg/1);

2)

Ifit is assumed that the sleeve-tube gap is locally t'4>0 soluble anions at the following concentrations SO4 (1.71 mg/1), Cl (0.28 mg/1),

and at least 7 other anions, including organic acid anions.

then the measured concentrations obtained from the 0.15 ml of water are a factor of 100 lower than the actual crevice solution concentrations. That would make the Li concentration in the ERLT crevice 10 mg/l, higher than found in non-concentrated primary water.

D:LPLANTSiAEP6iEJEXAMS.SEC 5-5 09/25/95

Westinghouse non-Proprietary Class 3 Capillary electrophoresis and ion chromatography of water leached soluble ID deposits were also obtained for the hardroll upper transition region. This supplemental leachate test was performed subsequent to an NRC/AEP/W meeting at One White Flint North on August 10, 1995. The leachate test for the hardroll upper transition was performed identically to the leachate test for the hardroll lower transition region. The results of the test indicated that the same soluble cations were detected as for the hardroll lower transition, except they were found in significantly lower concentrations. Potassium, however, was not detected in the hardroll upper transition.

Crevice pH at operating temperature was estimated from the leachate solutions using EPRI's MULTEQ~ program. The results indicate that the operating temperature pH of the hardroll upper transition was 6.0 while the operating temperature pH of the hardroll lower transition was 8.3. For PWSCC, it is believed that a higher pH condition should be slightly more aggressive. However, in the pH range of interest (6 to 9) the impact of pH is considered to be negligible.

5.7 Conclusions The tubes in the HRLT of all three HEJs had corrosion present. Metallographic and SEM fractographic data showed that the HRLT region of the tubes had circumferentially oriented ID origin IGSCC. The individual circumferential microcracks associated with the macrocracks were simple cracks, that lacked the complexity usually associated with secondary side corrosion. While many of the microcracks were connected by ligaments with only intergranular features, a large number of ligaments had ductile features present. The maximum depth of corrosion for the 360 long macrocracks was 92% for both tubes R2C32 and R2C54 (tube R2C61 was set aside as an archive specimen) with average depths of 61%

and 60%, respectively. Dimensional data suggested that the tubes had experienced typical expansions radially. Two of the tubes (R2C54 and R2C61) did experience significant rolldown during the hardroll procedure, as the HRLT was 0.5" long. Microhardness traces conducted in the HEJ transition locations showed little variation in hardness and values that were similar to free span locations. One location with somewhat higher microhardness values was near the ID surface of the fracture faces of the two tubes and even there the increase was not great. The corrosion morphology observed was simple, typical of PWSCC environments rather than of secondary side crevice environments with a concentrated caustic environment.

The observed corrosion most likely resulted from an environment primarily derived from primary side water. The presence of Li and B on the tube ID surface below the HR region supports this hypothesis. The lack of significant Cr enrichment or depletion on ID surfaces below the HR and on the crack fracture face, and the relative balance of cations and anions indicate a somewhat neutral crevice environment. The fact that many cations and anions were found and that the estimated Li crevice concentration was higher than found in primary water also suggest that there was communication with the secondary side via a crack elsewhere in the tube. It is concluded that the observed corrosion could have been and probably was caused by a PWSCC type environment. The results of the chemistry evaluations of the ID surfaces for the hardroll lower and hardroll upper transition regions suggest the upper transition reqion was subjected to a slightly less aggressive solution than the hardroll lower transition, but it is not believed that this solution chemistry was the driving force for the DAPLANTS'NERHEJEXAMS.SEC 5-6 l0/OS/95

Westinghouse non-Pxoprietary Class 3 cracking. The driving force fox the cracking is believed to be attributed to a pure PWSCC effect, with the crevice chemistry representing a secondary effect.

Laboratory and field eddy current probe data correlated well with the corrosion that was destructively found. The + Point and CECCO probes produced very similar and accurate results. Even the RPC laboratory data showed the presence of the corrosion in the tubes despite the presence of the sleeve between the probe and the tube. The destructive examinations verified that there were no cracks in either tube at the HRUT or the HEUT.

Leak rate testing performed at elevated temperatures and pressures simulating normal operating and steam line break conditions pxoduced no leakage for the R2C54 specimen. The tensile separation loads for tubes R2C32 and R2C54 were 10,300 and 10,700 pounds, xespectively, and the sliding loads over the hard roll region started at 2800 and 4000 pounds, respectively. The tensile loads were well above any safety considerations.

DAPLANYSVLEPQiHEXAMS.SEC 5-7 10/0$ /95

Table 5-1: Comparison of NDE Indications Observed at Kewaunee on SG Tubes at HEJ Locations Tube/ Pield Eddy Current Laboratory Eddy Visual/Dimensional Laboratory Location Current Data X-Ray R2C32 + Point: 300-360'irc Ind in + Point: 300-360'irc Ind in HRLT starts 8.25" above bottom of One to one and one-half semi-HRLT, probably throughwall. HRLT, probably throughwall. pulled piece or 11.25" above TTS: continuous Circ networks of I Coil: (1994 data only) -270'irc CECCO: 360'irc Iud in HRLT, HRLT is 0.25" Iong; tube HR OD is short Inds at top of HRLT, Ind. probably throughwall. 0.907" & HRLT goes 0.009" lower observed over at least 270',

RPC: >270'irc Ind at top of (radially); all values include variable possibly 360'.

HRLT. OD deposits.

R2C54 + Point: 300-360'irc Ind in + Point: 360'irc Ind in HRLT, HRLT starts 6.8" above bottom of Two to three semi~ontinuous HRLT, probably throughwall. probably throughwall. pulled piece or 9.85" above TTS: Circ networks of short crack I Coil: No data. CECCO: 360'irc Ind in HRLT, HRLT is 0.50" Iong; tube HR OD is Inds in mid- to upper portion of probably throughwall. 0.903" 8c HRLT goes 0.012" lower HRLT, observed over 360'.

RPC: >270'irc Ind in HRLT. (radially); all values include variable OD deposits.

R2C61 + Point: 300-360'irc Ind in + Point: 360'irc Ind in HRLT, HRLT starts 6.7" above bottom of One semiwontinuous Circ net-HRLT, probably throughwall. probably throughwall, and small Ind pulled piece or 9.7" above TTS: work of short crack Inds in mid-I Coil: 1994 data only, at HELT. HRLT is 0.50" long; tube HR OD is portion of HRLT, observed over CECCO: 360'irc Ind in HRLT,

>270'irc indication. 0.905" & HRLT goes 0.009" lower 360', but less continuously than probably throughwall. and small Ind (radially); all values include variable for R2C32 Inds.

at HELT OD deposits.

RPC: >270'irc Ind in HRLT.

Legend of Abbreviations HR = HardroH HELT = HE lower transition RPC = Rotating pancake coil Ind = Indication HE = Hydraulic expansion HRLT = HR lower transition TTS = Top of tubesheet Circ = Circumferential D:LPLANTStA EPONA EP-EXAM.SEC 0912$ I95

Table 5-2: Tensile Data for Kewaunee SG Tube Sections Kewaunee Pxee Span Tensile Data Yield Strength Ultimate Tensile Strength Elongation Tube (psi) (psi) (%)

R2C32 72,200 123,300 22.0 R2C54 58,600 106,700 24.5 R2C61 55,400 104,000 23.1 Control (NX8161) 52,300 101,500 18.5 "

  • Broke outside of the gage length, probably reducing the elongation value.

Kewaunee HEJ Tensile Data Sliding Load over Practure Load HEJ Specimen Practure Location HR Region (Ibs)

(lbs)

R2C32 10,300 Top of HRLT 2800 decreasing to 50 R2C54 10,700 Middle of HRLT 4000 decreasing to 200 R2C61 NA (Archive) NA (Archive) NA (Archive)

DAPLANTSVLBPlABP-BXAM.SBC 5-9 09/25/95

Table 5-3: Kewaunee SG Tube Macrocrack Profiles for Tensile Fracture of HEJs Length vs. Depth and Ductile Ligament Width Tube, Location Ductile Ligament Location Comments (in.)

(degrees / % throughwall)

R2C32, HRLT 00/52 Twenty-one ligaments were Ligament 2 1 L21 = 0.004" wide 22/77 observed on the circumferential (32/92) ~ Maximum depth macrocrack located at the top of Ligament 20 L20 = 0.006" wide the HRLT. All intergranular 45/88 Ligament 19 L19 = 0.011" wide corrosion was of ID origin.

58/85 LIgament 18 L18 = 0.003" wide 9 p/8 8 112/88 Ligaments 16 & 17 L16, L17 = 0.006", 0.011" wide

~ Ligament 15 L15 = 0.008" wide 35/8 158/82

- Ligament 14 L14 = 0.004" wide

~ Ligaments 12 & 13 L12, L13 = 0.002", 0.003" wide 80/64 Ligament 11 L11 = 0.039" wide 202/76 Ligament 10 L10 = 0.027" wide 225/60

~ Ligament 9 L9 = 0.014" wide 248/52 27p/p8 Ligament 6, 7, &8 L6, L7, L8 = 0.002", 0.006",

0.012" wide 292/05 3 1 5/46 Ligament 4 & 5 L4, L5 = 0.015", 0.022" wide 338/ 9 Ligament 1, 2, & 3 Ll, L2, L3 = 0.015", 0.005",

0.012" wide (Average macrocrack depth =

61% over 360", maximum depth

= 92%)

DAPLANYSVLEPQEP-EXAM.SEC 5-10 09/25/95

Table 5-3 (Cont.): Kewaunee SG Tube Macrocrack ProCiles for Tensile Fracture of HEJs Length vs. Depth and Ductile Ligament Width Tube, Location Ductile Ligament Location Comments (in.)

(degrees / % throughwall)

R2C54, HRLT 00/04 22/67

- Ligament 17 & 18 L17, L18 = 0.015", 0.005" wide Nineteen ductile ligaments were observed on the circum-Ligaments I4, I5, I 6 L14, L15, L16 = 0.003", 0.008",

45 75 ferential macrocrack located in 0.007" wide 68/84 the middle of the HRLT. All (80/92) ~ Maximum depth intergranular corrosion was of Ligament I3 L13 = 0.017" wide ID origin.

9p/78 112/82 135/72 Ligament I2 L12 = 0.009" wide I5 8/74 80/74 Ligaments I 0 & I I LIO, LII = 0.017", 0.005" wide 202/56 Ligament 9 L9 = 0.011" wide Ligament 8 L8 = 0.050" wide 225/16 248/48

- Ligament 7 L7 = 0.002" wide Ligament 5 & 6 LS, L6 = 0.009", 0.007" wide 27p/64 292/78 315/70 L2, L3, L4 = 0.008", 0.013",

338/22 Ligament 2, 3, &4 0.013" wide

~ Ligament I & 19 LI, L19 = 0.013", 0.044" wide (Average macrocrack depth = 60%

over 360'; maximum depth =

92%)

DAPLANTSlABPLAEP-BXAM,SEC 5-11 09/25/95

Table 5-4: Microhardness Measurements (VHN, 500 gm load) on Kewaunee HEJ Sleeved Tubes Tube/Location Microhardness at Specified Depth from Tube ID Surface 0.001" 0.006" 0.016" 0.026" 0.036" 0.046"

~ ~

R2C32, HELT 196 193 183 181 191 HRLT 209 204 196'09'o

'09 193 204 HRLT next to FF 238 (IGSCC) 228 (IGSCC) 218 (IGSCC) 252 (shear) 268 (shear) data, necked HR 215 212 204 204 209 218 HRUT 186 193 186 186 191 198 HEUT 193 196 188 188 196 198 FS 4" above HEJ 198 1864 1794 1814 1864 188 R2C54, HELT 193 196 181 174 181 188 HRLT 196 196 181 172 183 188 HRLT 231 (IGSCC) 215 (IGSCC) 215 (IGSCC) 221 (shear) 234 (shear) no data, necked HR 241 228 221 212 215 HRUT 212 204 193 191 193 206~

HEUT 176 186 176 181 183 176 s FS 4" above HEJ 176 174 172 156 166 174 Notes: 1. Located 0.002" closer to the ID surface than indicated

2. Located 0.007" closer to the ID surface than indicated
3. Located 0.002" farther from the ID surface than indicated 4, Located 0.005" farther from the ID surface than indicated
5. Located 0.005" closer to the ID surface than indicated
6. Located 0.004" closer to the ID surface than indicated D LPLANTSLABPUNP-BXAhf.SBC 5- 12 09/2$ /9$

Location of Cracks in HHJ Sleeved Tubes Removed from Kewaunee No cracks found or detected on any of the tube specimens removed from Kewaunee Significant Nominal Hardroll Hardroll Rolldown Transition Circumferential cracking found Circumferential near/at the top cracking found of the transition near the center of the hardroll (Also typical of laboratoty specimens)

No cracks found in either of the two destructively examined tube specimens from Kewaunee Figure 5-1 D LPLANYSULEPQKJEXAMS.SEC 5-13 09/2$ /95

Westinghouse non-Proprietary Class 3 6.0 Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the tube indications on the operating performance of HEJs with PTIs, test and analysis programs were performed, References 8 and 9, aimed at:

1) characterizing the effect of the observed PTIs on the axial stxength of the joint, and
2) estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.

Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach 2 tubes (no indications have been determined to be present in the Cook 1 tubes at present) was explored via axial tensile testing and hydraulic proof testing. Additional analyses results were reported in References 11 and 12. A summary of the test and analysis pxograms is provided in the following sections. The results are applicable to the four U.S. plants with installed HEJs. Plant operating parameters relative to suxuctural integrity evaluations are presented in Table 6-1. The largest operating primaxy-to-secondary differential pressure, 1535 psi, occurs in the SGs at Kewaunee, although Cook 1 is approved to operate up to 1600 psi. The smallest differential pressure, 1225 psi, occurs at Point Beach 2. The current differential pressure at Cook 1 is 1453 psi. The axial end cap loads during normal operation, and the RG 1.121 3~ loads, are summarized in Table 6-2.

The maximum 3d P load is 2172 lbs (could be as high as 2264 lbs) and the minimum is 1734 lb,. Since each of the plants have 7/8" nominal diameter tubes with 0.050" thickness, the end cap load during a postulated SLB event is 1516 lbs regardless of the plant. Thus, the 3~ end cap load governs the analysis.

6.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9). Prototypic HEJ test specimens, see Figure 6-1, were fabricated using AOoy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were perfoxmed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations. For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e., 1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 3M end cap loading. For specimens where the tubes were completely removed by machining at the elevation corresponding to the approximate midspan of the hydraulically expanded region, i.e.,

-2.25" the bottom of the HRUT, the structural capability of the joints were -3.5 to 4 times the most limiting RG 1.121 3 end cap load.

The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign) was similar to that of Alloy 690 sleeves.

HE/STRUC.SEC 6-1 10/03/95

Westinghouse non-Proprietary Class 3 The structural proof tests were performed on specimens which had been fabricated for leak testing. Following the leak tests, the sleeved tubes were machined to simulate a throughwaH crack at the inflection point, i.e., middle, of the hard roll. AH of 360'ircumferential the samples were then pressurized to a differential pressure of 3657 psi. The pressure was then gradually increased until slipping of the joint was noted. Initial slippage of the tubes was genexaHy detected after an increase in the pressure of about 200 to 700 psi. The maximum pressures, i.e., those achieved when the tube was ejected from the sleeve, wexe not recorded, but did approach pressures on the order of three times normal operating pressure differentials.

6.2 Pulled Tube Structural Tests Section 5.0 of this report documented the results of leak and structural tests performed on the sleeved tube specimens removed from SG "B" at Kewaunee, see Table 5-2. The tensile test results fox both tubes are higher than that predicted by for the limit load. Tube R2C32 was found to have a high flow stress, -98 ksi, and an average depth of the cracking of 61%. The cxacking was near the top of the HRLT. The estimated limit load of the remaining ligament is 5980 lbs using a net section stress approach. The measured failure load for the specimen was 10300 lbs with a remaining sliy load immediately after the failure of 2800 lbs. Estimating the actual failure load of the remaining ligament as the total failure load minus the residual sliding load yields 7500 lbs. This is about 25% higher than the value predicted by analysis. The residual sliding load is about 60% largex than the maximum of two values obtained from tests reported in WCAP-14157 for 360'lits at the top of the HRLT. The sliding load following development of a 360 fracture is about four times, or 25%o higher than the RG 1.121 requirement, the end cap load that would be experienced during normal operation of the plant with the highest differential pressure. Moreover, the sliding load is almost three times, or twice the RG 1.121 requirement, the end cap load that would result during a postulated SLB event.

Tube R2C54 had a measured flow stress of -83 ksi, with an average depth of cracking of 60%o.

The cracking was at the approximate middle of the HRLT, which exhibited evidence of roHdown. The measured failure load was 10700 lbs with a residual sliding strength of 4000 lbs. Thus, the ligament failure load was on the order of 6700 lbs. This is about 30% higher than the calculated ligament limit load of 5170 lbs. The residual sliding load is about equal to the lower of two values obtained from tests reported in WCAP-14157 for a 360'lit at the bottom of the HRLT, and about equal to the average of three values reported in the Addendum to WCAP-14157. Thus, the residual sliding load for the field specimen with a 360'eparation at the inflection point is on the order of that obtained from test speciments with a 360 separation at the bottom of the HRLT. In addition, the sliding load is on the order of six times the end cay load due to normal operation and about four times the end cap load developed during a postulated SLB event.

6.3 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2 HHSTRUC.SEC 6-2 09/25/95

Westinghouse non-Proprietary Class 3 (Appendix A). The purpose of the analyses was to support the development of a repair boundary which included consideration of PTIs located at the top of the HRLT. Such indica-tions are not a subject of this report. The criterion supported by this report is that aO PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent. Thus, the structural integrity analyses consist of the evaluations of the test data reported in WCAP-14157 and its addendum, and of the test data obtained from the sleeve/tube joints removed from SG "B" at Kewaunee.

6.4 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the top, the midpoint and at the bottom of the HRLT. The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions. A summary of the leak rates from specimens with the tube removed or cut at an elevation corresponding to the top of the HRLT or at the repair boundary is provided in Table 6-3. The specimens with the tube removed at the midpoint of the HRLT'xhibited a maximum leak rate of 0.016 gpm at SLB conditions. The average leak rate for all of the specimens listed in Table 6-3 is about 0.004 gpm with a standard deviation of 0.008 gpm, thus, demonstrating a significant resistance to primary-to-secondary leakage.

These tests suggest that the presence of a "lip" of tube material below the top of the HRLT provides sufficient leakage restriction. The repair boundary determined from structural considerations, i.e., 1.1" below the bottom of the HRUT, would be expected to result in acceptable leak rates during a postulated SLB event.

6.5 Crack Growth Rate Considerations Since the HEJ has been demonstrated to meet the requirements of RG 1.121 for full circumference, i.e., 360', at the elevation of the middle of the HRLT, the strength relative to those requirements is independent of crack growth rates.

6.6 Additional Tube Integrity Considerations and Observations The repair boundary developed in this report does not assume any credit for the resistance to tube motion afforded by tube support plate denting. The presence of significant dents could preclude any tube integrity issues in HEJ sleeved tubes with PIIs. A review of pull forces required to remove tubes from Westinghouse Model 44 and 51 steam generators was discussed in WCAP-14157. For tubes with no significant interface loading within the tubesheet, pull forces for tubes without detectable denting ranged from 1000 to 3000 lbs, while for tubes with detectable dents, the forces rose to 2000 to 4000 lbs.

Based on the findings from the destructive and nondestructive examinations of the specimens removed from Kewaunee, Section 5.0, and from the results of accelerated corrosion tests per-Approximately 1.12 to 1.13 inch below the bottom of the HRUT.

HEISTRUC.SEC 6-3

Westinghouse non-Proprietary Class 3 formed by Westinghouse, the appearance of PTIs in joints experiencing significant rolldown may be likely to occur at a lower elevation than in joints without significant rolldown.

Approximately 90% of the PTIs at Kewaunee were found at distances R 1.3" from the bottom of the HRUT, thus implying the presence of significant rolldown. Hence, it is possible that transitions with significant rolldown are less resistant to PWSCC than transitions without significant rolldown.

6.7 Conclusions The specified repair boundary is supported by structural and leak test data obtained from surrogate specimens (WCAP-14157 w/addendum), and by structural data obtained from specimens removed from an operating SG. Tube rupture loads well in excess of those required by RG 1.121 have been demonstrated by both the surrogate and actual HET test programs. The repair boundary results in a radial overlap of the HRLT of approximately 0.1" in length. This is a geometric configuration for which neither significant tube axial displacement nor significant tube leakage would be expected to occur during a postulated SLB event.

EEJSTRUC.SEC 6-4 09/25/95

Westinghouse non-Proprietary Class 3 Table 6-1: Operating Parameters for U.S. Plants with Installed HEJs pp PE Thoc Tcold Plant SG Loops (psia) (psia) (psi) (6 Point Beach 2 44 2000 775 1225 596.7 541.7 Cook I 51 4 2100 1453 582.0 518.0 Kewaunee 51 2 2250 715 1535 591.2 531.8 Zion 1 51 4 2250 725 1525 592.2 532.2 Table 6-2: Tube Pressure Loading for U.S. Plants with Installed HEJs Normal 3~AP Load Normal cQ'oad Plant (lbs)

(psi) (lbs)

Point Beach 2 1225 578 1743 Cook 1 1453 685 2056 Kewaunee 1535 724

'172 Zion 1 1525 719 2158 Note: 1. The 3+dZ load at Cook 1 could be as high as 2264 lbs corresponding to an operating differential pressure of 1600 psi.

2. The end cap load during a postulated SLB event is 1516 lbs independent of plant.

HEJSTRUC.SEC 6-5 09/2S/9S

Westinghouse non-Proprietary Class 3 Table 6-3: Summary of Applicable HEJ Leak Rates from WCAP-14157 and Addendum Sleeve Cut Angle Distance from ~R te<>> Leak Rate"'t HRUT at 1600 psi 2560 psi Material (in ) (gpm) (gpm)

Alloy 690 240 1.08 0.0 0.0 Alloy 690 240 1.01 0.0 9 x 10~

Alloy 690 240 1.03 0.0084 0.0186 Alloy 690 240 1.0 + 0.0 4.5 x 10~

Alloy 690 360 1.1 0.0 2 x 10~

Alloy 690 360 1.1 0.0016 0.016 Alloy 600 360 0.0 1x 10' Alloy 600 360 1.1 0.0 x 10~

Notes: 1. Leak rates for specimens with 240'ut angles were increased by a factor of 1.5 to estimate the leak rate for a cut angle of 360'.

HBJSTRUC.SEC 6-6 10/03/95

i End Cap Plug or Tensile Gripper.

Tube Tube cut at elevations from the top of the transition to below the bottom of the transition, and at various arc lengths.

Hardroll I

Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.

Figure 6-1: HEJ specimen used for tensile testing.

D:KPLANTShhEPEHEJSTRUC.FlG 6-7 8/2/95

Westinghouse non-Proprietary Class 3 7.0 Leak Rate Based Repair Boundary 7.1 Introduction The purpose of this section of the report is to p resent en an alteternative method for establishing a repair boundary for HES e upper sleeve/tube joint region, but below the prim to-secondary pressure boundary at the sleeve/tube harclroH interface. The rev'n o sleeved tubes from Kewaunee, an evaluation of the structural y ocumented in References 8, 9, 11 and 12. The structural evaluations

'gin directly support the identification of a repair boundary for PTl b ed I

of the 'oint.. t is also possible to develop a repair boundary for PTIs in sleeve/tube oin which is not sensitive to the residual stren~~ of the oint rate dary a function of the instaHed geometry of the tubes an and the HEJs is developed in this section. Since re air boundary is based on geometry and total ince thee repair ge, it does not rely on the re siduali strength of the joint or on the extent of the indica-tions, or the growth rate of the indications, The repair b dary d cation of the PTI and the constraiiiing effects of outboard neighboring tubes location I The HEI consists

/2 b.low of a HE of the '

sleeve and tube over a length h..p'.f ".1-., f.How by.h~-H of 4" be r

w the top of the hydraulic expansion. The existing plant T hnical repairing/plugging criteria apply to the entire length of the sleeve, and to that portion of the parent tube above the bottom of the HB of the HEI. An exam le of the plugging criteria developed at the time of the installation of h This evaluation forms the basis for the development of a repair boun dary be o s eev tu e rom service due to the presence of PTls in the re extending downward from the upper part oof thee HRLT e.. see Pigure 7-1. The integrity of T, e.g.,

the tube bundl e with PXXs under normal op eratin g and postulated accident conditions is aad die ss ed.. Tlle results of the evaluation a pply to sleeved tubes in Westinghouse Model 44 aild 51 s. aspects of bundle integrity are ad-dressed:

1) maintenance maintenan of a fixed tube-to-sleeve *on in thee end condition limiting case of a circumferential m ~cation near the top of the lower transition of the hardroH indication limitation of rimaiy--to--secondary leakage consistent with acc

~ ~ ~

2

2) ccid en t an alysis assump-tions, and 7-1

Westinghouse non-Proprietary Class 3 g) maintenance of tube integrity under postulated limiting conditions of primary-to-secondary and secondary-to-primary differential pressure.

The result of the evaluation is the identification of a distance below the bottom of the HRUT for which PTls of any extent do not necessitate remedial action, e.g., plugging. The basis of the repair boundary is that the axial distance a postulated severed HEJ sleeved tube end can move is limited by the constraint afforded to the affected tube by it s outboard neighbor.

Thus, "hop off" of the upper portion of a severed parent tube will be precluded, and the leakage from such tubes during a postulated SLB will be within acceptable limits. For example, for the Kewaunee SGs the total allowable primary-to-secondary leak rate from all sources during a postulated SLB event was determined in Reference 30 to be 34.0 gallons per minute (gpm), without benefit of reducing primary coolant activity. Interim plugging criteria (IPC) have been approved for dispositioning tube indications at the elevation of the tube support plates in the D.C. Cook and Kewaunee SGs. The expected contribution to the total primary-to-secondary leakage from the IPC indications is likely on the order of 1 gpm or less.

Thus, approximately 33.0 gpm total leak rate from HEJ PIIs could be tolerated without exceeding the 10CFR100 limit for the Kewaunee plant.

Application of the leakage based repair boundary is expected to provide the same level of protection for PTIs in HEJ sleeved tubes as that afforded by Regulatory Guide (RG) 1.121 for degradation located outside the sleeve joint. Since the repair boundary does not rely on the residual strength of the joint, the calculation of margins against burst for the affected tube are not meaningful. For each affected tube, the repair boundary does rely on the structural capability of that tube's outboard neighbor. By restricting the application of the criteria to tubes with a structurally capable outboard neighbor.'.2 Sleeved Tube Dimensions A summary of the sleeve and tube dimensions pertinent to this evaluation were illustrated in Section 1 of this report. The tubing has a nominal outside diameter (OD) of 0.875" and a thickness of 0.050". The sleeves have an [

]". The region of the hardroH is denoted by the label interference'. The length of this region is governed by the length of the hardrolling tool used to create this section of the joint. For the D.C. Cook, Kewaunee, and Point Beach 2 SGs, the rollers had a flat length dimension of 1.0". Thus, the length cannot be less than 1.0" on the ID of the sleeve. In some cases the length of the hardroll is greater than 1.0" as a result of the reversal of the rolling process in order to release the roller from the inside of the sleeve. This reversal process is usually termed rolMown and the additional length of the hardroll is referred to as the rolldown length. It is not unusual for the rolldown to achieve a length of greater than

-0.5" during the reversal process.

The radii of the upper end of the rollers of the rolling tool were [

Limitations on the use of the leak rate based repair boundary are discussed in the evaluation section of this report.

HEJLEAKP.SEC 7-2

Westinghouse non-Proprietary Class 3

]*". Hence, a bounding lower limit on the radius at the OD of the sleeve in the transition is approximately 0.288". A true estimate of the radius of curvature in the axial direction is obtained by considering a hardroll transition length of 0.21" and a radial difference of 8 mils leads to the calculation of an effective radius of 1.4". The [

]'", thus, the effective length of the hardroll would be about 60 mils longer before the contact pressure between the sleeve and the hardroll would be lost. This would be somewhat offset by the potential contraction of the tube during the hydraulic expansion process. The expansion of the tube is about [

]*". Since the sleeves installed in the D.C.

Cook, Kewaunee, and Point Beach 2 SGs were fabricated of Alloy 690, their coefficient of thermal expansion is greater than that of the tubes. This would lead to a slight increase in the interference fit during operation as further increase the effective length of the hardron, however, the expected magnitude of such an increase would not be expected to be significant.

7.3 U-Bend Clearance The results of a study of SG fabrication practices, Reference 17, were evaluated in order to estimate the potential distance that a severed HEI sleeved tube end could displace in the vertical direction during normal operation or during a postulated SLB. The results of this evaluation are applicable to the development of a plugging repair boundary for PTIh in sleeved tubes. In SGs of the type installed at D.C. Cook, Kewaunee, Point Beach 2, i.e., Westing-house Model 44 and 51, the nominal vertical clearance between radially adjacent tubes at the apex of their U-bends is 0.406". The actual clearance will vary about the nominal due to tube installation tolerances during manufacture of the SGs. The potential contributing factors from the Model 44/51 SG manufacturing operations are:

1. The tube-to-tubesheet fit-up for welding.
2. The tube expansion process.
3. Tube dimensional tolerances on overall length, U-bend radius, tube diameter, etc.

The second operation does not significantly contribute to the manufacturing process tolerance since the tube-to-tubesheet joint process for the D.C. Cook, Kewaunee, and Point Beach 2 SGs involved partial depth rolling as opposed to full depth rolling.

The maximum tube-to-tube U-bend apex gap increase in the D.C. Cook, Kewaunee, and Point Beach 2 SGs as a result of the first and third operations was calculated to be [

]"'. The extremes of the total manufacturing tolerance are taken to be three standard deviations from the mean, hence, one standard deviation would be [ ]'"". Since the installation of one tube is independent of its inboard neighbor, the standard deviation of the manufacturing clearance, i.e., the difference between two radially adjacent tubes, may be HEJLEAKP.SEC 7-3 09/25/95

Westinghouse non-Proprietary Class 3 calculated as the square root of the sum of squares of the individual standard deviations.

Thus, the standard deviation of the U-bend apex gap between two radially adjacent tubes would be [ ]'".

An additional consideration in estimating the U-bend apex clearance between two radially adjacent tubes is due to the [

]'", assuming that a primary-to-second-ary pressure difference of 2560 psi is achieved during the event. Assuming the distribution of U-bend apex gaps to be normally distributed in the SG, an upper 95% confidence bound on the apex clearance is calculated to be [ ]SIC The U-bend apex gap can be used to estimate the maximum upward displacement of a tube end which is assumed to be severed within the HEJ. The driving force for such displacement will be the unbalanced pressure on the interior of the tube acting on the projection of the tube cross-section area at the tangent point between the U-bend and the straight length of the tube, i.e., the severed tube end is pulled up by the force at the U-bend. Once contact has occurred with an outboard neighbor, further displacement is prevented. The total vertical displacement may be estimated by calculating the distance that the affected tube's tangent point may traverse by considering that the inboard tube deforms into intimate contact with the outboard tube up to the apex of the U-bend. More extreme deformation would require lateral in-plane deformation which is opposed by the internal pressure. Moreover, the extent of intimate contact would likely be limited to the point of first contact, which would be expected to occur nearer to the midway point from the tangent point to the apex. Ifd is the tube-to-tube clearance at the apex of the U-bend, and R is the radius of the U-bend of the affected tube, the clearance at the tangent point, D, is D = (R+ d) sin 2R+d K d. (7.1) 2 Using the upper 95% confidence bounds of the U-bend apex clearance results in upper bounds on the tangent point displacement of [ ]*" respectively. The expected displacement would be between the two extremes. Taking the average of the apex and the maximum tangent point displacements results in expected displacement limits of

[

]*", with a limiting value of the expected displacement of 1.1". Since this result is based on a 95% confidence level, it would be expected that the occurrence of multiple tubes achieving this level of displacement would be very unlikely. I"urthermore, because the length of the sleeve above the bottom of the HR is on the order of 2.75", joint separation, i.e., hop-off, is precluded for tubes with PTIs below the top of the HRLT.

HE/LEAKP.SEC 7-4 09/25/95

Westinghouse non-Proprietary Class 3 Since, hop-off is precluded, the pertinent basis for the development of the leak rate repair boundary is the potential leakage from tubes with throughwall, 360, PTls which could displace upward either during normal operation or during a postulated SLB. The potential displacement during a postulated SLB is greater than that during normal operation, as is the primary-to-secondary differential pressure, hence, it is appropriate to develop the repair boundary based on the consideration of potential leakage during a postulated SLB. Verticany displaced severed tube conditions are illustrated on Figure 7-2. The expected displacement for a tube end severed at the top of the hardroll lower transition would be about midway along the length of the hardroll, with a 95% confidence bound on the displacement such that the location of the severed end would be about even with the top of the hardroll. Indications below the top of the hardroll would not be expected to lead to a configuration such that the severed end could achieve an elevation coincident with the top of the hardroll.

The effective length of the hardroll was estimated in the previous section to be 1.03" based on the radius of curvature in the axial direction and the elastic springback of the joint. This is about the same length as the 95% confidence level for the maximum displacement during a postulated SLB event. Since circumferential indications would not be expected above the top of the hardroll lower transition, the appearance of circumferential indications which could be postulated to lead to severing of the affected tube at elevation'n which could be exposed to the full primary-to-secondary pressure difference would be expected to be of low probability.

7.4 Leakage Potential Leak rates may be estimated from the tests that were performed, see References 8 and 9, and from calculations assuming various other geometry conditions, e.g., for a severed tube end which is elevated relative to the sleeve. It is to be noted that the maximum estimated primary-to-secondary differential pressure during a postulated SLB of 2560 psid assumes that the makeup system is capable of achieving that pressure regardless of primary-to-secondary leakage. Realistically, if one severed tube end displaced such that significant leakage occurred, the primary-to-secondary differential pressure would likely not increase further.

Thus, while conservative, the consideration of a significant number of leaking tubes during a postulated SLB is not realistic.

Ifthe postulated severed tube end is assumed to be displaced relative to the sleeve, the leak rates measured for full hardroll length engagement may be estimated by assuming the flow to be controlled by a friction factor. This is appropriate instead of estimating an annulus choke flow because of the interference fit between the sleeve and the tube in the hardroll region.

The relationship between the flow, Q, the length of engagement, L, the differential pressure, d,P, and the friction factor, f, would be, 0=- AP fL (7.2)

HElLPAKP.SEC 7-5 09/25/95

Westinghouse non-Proprietary Class 3 f

The value of could be estimated from the leak test for which the length of engagement was 1". However, this is not necessary since a comparison of leak rates for different engagement lengths leads to the relation, L,

@ =0,. (7.3)

L~

Thus, if the length of engagement is halved, the expected leak rate is doubled. This expres-sion may provide satisfactory estimates in the range of Q from 1.0 to 0.25 of L,, however, its use beyond that range would not be recommended since the Q,~oo as Q-4, and severed tube end effects would be expected to lead to increased radial deflection at the tube end accompa-nied by increased leakage.

7.4.1 Normal Operation During normal operation, the leakage from HEI sleeved tubes with throughwall degradation extending 360'round the tube and located at the elevation of the HR lower transition would be expected to be sufficient to be detected. If the tube end does not displace, the leakage from each such joint would likely be on the order of 1 gpd or less. Ifthe joint does displace, an increase in the leak rate would be experienced such that the plant could be shut down to address the source of the leakage.

7.4.2 Steam Line Break For the initial evaluation of potential leak rate in the event of severing of the tubes, calcula-tions were performed for assumed radial gaps if the tube displaced axially upward relative to the sleeve, For a radial gap of [ ]*", corresponding to elevating the hardroll length of the tube to correspond to the hydraulically expanded length of the sleeve, the projected leak rate was found to be -25 gpm, References 8 and 9. Ifthe tube displacement is limited to less than or equal to about 1.1", the -95% confidence value for tangent point contact, the lower end of the hardrolled region of the tube would still be in contact with the upper end of the hardrolled region of the sleeve. For leakage evaluation purposes, prior calculations assumed that a gap on the order of [

]"', and would thus be expected to leak at a rate of 2.5 gpm. In actuality, no gap would be expected to be present for displacements less than 1.03" and the expected leak rates would be substantially less than the estimated value of 2.5 gpm. Testing has been performed for tubes machined away at the top of the hardroll lower transition, References 8 and 9. Leak rate values under these circumstances were found to be relatively insignificant when compared to the makeup capacity of the plant hydraulic system. The maximum leakage from any single indication was estimated to be bounded between 0.01 and 0.033 gpm. These estimates may be considered to bound the leak rate if as little as -1/4" of sleeve-to-tube hardroll interference remains. Using the maximum value as an average for all such tubes results in a total leak rate from 1000 leaking HEJ sleeved tubes of 33.0 gpm. The total IPC leak rate which might be expected from the limiting D.C. Cook or Kewaunee SG is HElLEAKP.SEC 7-6 09/25/95

Westinghouse non-Proprietary Class 3

~

estimated.to be less than 1 gpm. Therefore, about 1000 or more HEJ sleeved tubes with PTIs

~ ~

~ ~ ~ ~ ~

ould remain in service, without expecting total leakage during a postulated SLB to exceed the 10CFR100 limit. Ifonly the results from the three valid tests are used, i.e., 0.0, 6+10,

~ ~ ~ ~

~ ~

~ and 0.0124 gpm, respectively, four times the maximum leak rate (assuming a displacement of

~ ~ ~

about 0.8") would be 0.05 gpm. Conservatively considering this maximum leak rate to apply to all sleeved tubes leads to a total leak rate for 665 HEJ sleeved tubes of 33.0 gpm. It is to be emphasized that the average total leak rate from the 665 sleeved tubes considered here would be expected to be significantly less than the 10CFR100 limiting leak rate.

I &

C&

More accurate estimates of the total leak rate could be developed using Monte Carlo simula-tion techniques, however, based on the conservatisrns utilized for the deterministic estimates, e.g., the probability of experiencing multiple severed tube conditions was considered to be unity, such results would be expected to be significantly less than those reported herein.

7.5 Tubes Interior to Stayrod Locations Tubes interior to stayrods have no immediate outboard neighbors. Therefore the clearance to the nearest restraint is significantly larger than for tubes with outboard neighbors, and would be expected to exceed the hop-off distance from the PTI to the top of the sleeve. Thus, the leak rate based repair boundary developed in this section is not applicable to tubes immediate-ly interior to the stayrods.

l 7.6 Distribution of Indications in the Kewaunee SGs Sleeved Tubes The distance from the bottom of the hardroll upper transition to the elevation of the indica-tions in the Kewaunee SG tubes was measured for each indication near the elevation of the hardroll. A summary of the measured distances for each SG and for the combined SGs is provided in Table 7-3. Histogram and cumulative frequency plots of the distribution of indications in SGs "A" and "B" are provided on Figure 7-3 and Figure 7-4 respectively. The combined distribution and cumulative frequency information for both SGs is provided on Figure 7-5.

A total of 630 indications were considered in this evaluation. The average distance was found to be 1.32" with a standard deviation of 0.10". The median distance was found to be 1.32".

The skew and kurtosis {normalized) were found to be 0.20 and 0.58 respectively. These last three values indicate the distribution to be relatively normal. An inspection of the plotted cumulative frequency curves indicates the distributions to be nearly symmetrical about the 50% value for the measured populations, thus supporting the judgment that the distributions are nearly normal. Hence, the probability of an indication being located within the 95%

confidence bound on the potential displacement is relatively small. To be located above the average value of the potential displacement, the indication would have to be located -4.5

~ ~ ~

~

~ ~ ~ ~

standard deviations away from the mean elevation. The distribution of indications in the

~ ~

Kewaunee SGs confirms the expectation that very few indications would be expected to occur

~ ~ ~

at elevations where significant leakage could occur during a postulated SLB.

EEJLPAKP.SEC 7-7 09/25/95

Westinghouse non-Proprietary Class 3 7.7 Phnt Operation Considerations Other factors which would be expected to have a beneficial effect on the total leak rate that could be experienced are:

1) Adoption of a normal operation leakage limit of 150 gpd.
2) Implementation of nitrogen 16 (N16) monitors for monitoring SG leakage.
3) Enhanced training of operators to respond to faulted events.

7.8 Summary and Conclusions Analyses have been performed which indicate that the total leakage that could reasonably be expected from the sleeved tubes with indications in the D.C. Cook, Kewaunee, and Point Beach 2 SGs during a postulated SLB would be small relative to the makeup capacity of the charging system. A comparison of the distance a severed tube end could be expected to move during normal operation or during a postulated SLB relative to the distance from the bottom of the HEJ hardroll upper transition to the indications in the D.C. Cook, Kewaunee, and Point Beach 2 sleeved tubes indicates that it is unlikely that any of the tubes could become disen-gaged from their respective sleeves if those tubes are constrained by the presence of a structurally capable outboard neighbor. For an outboard neighbor to be considered as structurally capable, it may not, if sleeved, have circumferential degradation evident above the bottom of the HEJ hardroll lower transition. Tubes which are plugged may not have been so removed from service on account of circumferential degradation. Axial degradation has no significant effect on the axial strength of active or inactive tubes, hence the presence of axial degradation alone is not considered. cause to consider an outboard neighbor as not structurally viable.

This section documented the development of a geometry based repair boundary for PIIs in HEJ sleeved tubes. The resulting repair boundary is independent of the repair boundary developed in previous sections based on the structural integrity of the joint. Since the result obtained, 1.1", is the same as the structural repair boundary, it essentially demonstrates a defense in depth against the occurrence of a tube separation. The application of the repair boundary results in expected leakage during normal operation and postulated steam line break (SLB) events within limits based on 10CFR (Code of Federal Regulations), Part 100 criteria.

The conclusion of the evaluation is that based on geometry considerations alone it is accept-able to leave HEJ sleeved tubes with PIIs in service that satisfy the following requirements:

1) The distance from the bottom of the HRUT to the PTI is greater than or equal to 1.1".
2) The tube is located on the interior of the tube bundle.
3) The tube is not located adjacent to and inboard of a stay rod.

HEJLEAKP.SEC

Westinghouse non-Pxoprietary Class 3

4) The outboaxd neighboring tube is stxucturally capable, i.e., it can be expected to provide restraint against upward motion of the affected tube ifthe affected tube is considered to be sevexed at or below 1.1" from the bottom of the hardxoll upper transition.

For example, a review of Kewaunee Nuclear Power Plant data indicates that the first three requirements are satisfied for all sleeved tubes in the SGs. Thus, only satisfaction of the last requirement would need to be specifically demonstrated if geometry was the only basis for the repair boundary. However, the development of the geometry based boundaxy is secondary to the structural based boundary, so requirements 2) through 4) would not be considered to be generally applicable.

7-9 09/25/95

Westinghouse non-Proprietary Class 3 Table 7-1: Tube U-Bend Apex Clearance Dimension Normal Steam Line Operation Break Nominal a.)c Pressure Difference Average Standard Error Table 7-2: Tangent Point Clearance Dimension Normal Steam Line Operation Break Q. C 50% Confidence 60% Confidence 90% Confidence 95% Confidence 99% Coilfidence 99.5% Confidence 99.9% Confidence HEJLEAKP.SEC 7- 10 09/26/95

Westinghouse non-Proprietaxy Class 3 Table 7-3: Distribution of the Distance of the Indications from the Bottom of the Kudroll Upper Transition Parameter SG "A" SG NBtl Both SGs Count 426 212 638 Average 1.32 1.31 1.32 Standard Deviation 0.092 0.106 0.100 Maximum 1.63 1.75 1.75 1VRnmum 1.04 1.00 1.00 1.32 1.30 1.32 Skew 0.01 0.52 0.20 Kurtosis 0.18 1.03 0.58 HEJLEAKP.SEC 7- ll

Westinghouse non-Proprietary Class 3 Repair Boundary illustration Alloy 600 Tube Alloy 690/600 Sleeve HRUT Hardroll and Critical Distance thermal Measurement of interference fit. 1.1" Location of PTls outside of the geometry based repair boundary Figure 7-1: Illustration of the leak based criterion for HEJ sleeved tubes.

7- 12

Westinghouse non-Proprietary Class 3 Displaced Tube End Leak Path Small Gap 1 mil Hardroll 0 mils and thermal gap expansion interference fit.

8mils gap Displacement Distance Expected Displacement Assumed severing of Distance the parent tube at the top of the hardroll lower transition.

Figure 7-2: Leak path for a moved tube segment relative to the sleeve.

7-13

Westinghouse non-Proprietary Class 3 SG "A" HE J Sleeved Tube Indications vs.

Distance Below the Bottom of the Hardroll Upper Transition 100 100%

EZ3SG "A" Indications 90 SG "A" Cumulative 90%

80 80%

O 70 70%

'a 6 60 80%

0 50 60%

O l4 40 40% O 8

30 30%

8 O

20 20%

10 10%

0%

CQ O

O W

CO W

O CC CO CC O

CQ CO Co O

W CO

'ICI O

IQ lQ IQ O

CO 0

CO O

C

. IQ C

H Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-3 SG "B" HE J Sleeved Tube Indications vs.

Distance Below the Bottom of the Hardroll Upper Transition 100 100%

90 EKI SG "B" Indications 90%

SG "B" Cumulative 80 80% CO O

70 70% 0$

C g 60 60%

IH 50 60%

O 40 40% e 8

30 30% 5 8

20 20%

10 10%

0%

O CO O CC CO OC O

M CO, Cc O

M CO M

O ID R

CA O

CD CO O CO C C

~W W I Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-4 7- 14

Westinghouse non-Proyrietaxy Class 3 SGs "A" 8s "B" HE J Sleeved Tube Indications vs.

Distance Below the Bottom of the Hardroll Upper Transition 130 i00%

K3 Both SG Indications 120 Both SG Cumulative 00%

110 80% ol 100 O ce 90 V0%

O 80 60% c' 0

70 60% Q 60 l4 40% o g 50 40 95% Conf. on 30%

8 30 SLB Criterion.

20%

20 l0%

10 0%

O Q O o O

~ lO m c4 H

oi rk cQ R

10 rl M co O

~ O lO lo A A A A A r<

Q M

O co lQ co O lO Upper Bin Distance Below Bottom of HR Upper Transition Figure 7-5 7-15 os12ass

Westinghouse non-Proprietary Class 3 S.O Repair Boundary for Parent Tube Indications 8.1 Compliance with draft RG I. 121 Tube Integrity Criteria To remain consistent with the licensing basis addressing structural integrity, the repair boundary must be located such that the sleeved tube meets the structural integrity (burst) requirements of RG 1.121. Por the case of the repair boundary established in this document for a HEJ sleeved tube, an RCS release rate equal to those for a postulated tube burst is only possible if a circumferential separation of the parent tube occurs and is followed by upward motion of the separated end by a distance on the order of 3". Separation of the tube can only occur if the pressure end cap loads exceed the residual holding strength of the joint. Testing of prototype and field specimens has demonstrated that the residual strength of the separated joint is on the order of greater than 4000 lbs. The maximum load applied during normal operation of the most limiting plant is 724 lbs. Thus, a margin of safety relative to normal operation is on the order of 5.5 versus the RG 1. 121 requirement of a margin of 3. The axial load applied during a postulated SLB is 1060 lbs. Thus, the margin of safety during postulated accident conditions is about 3.8 versus the RG 1.121 requirement of 1.43.

In order for the tube to experience leak rates on the order of those associated with a steam generator tube rupture described in the PSAR, the parent tube must experience axial motion of

-3" (for degradation in the HEX HRLT). At this point the tube and sleeve would no longer be in close proximity and an unrestrained leak path would be produced. Reactor coolant system leak rates approaching those assumed in the PSAR could be realized. The diameter restrictions of the sleeve itself will limit the flow through the sleeve to values less than assumed in the PSAR. The nominal tube ID flow area is approximately 36% greater than the flow area based on the sleeve ID. For tube axial displacements less than -3" and greater than

-1.5", the primary to secondary leakage is restricted by the close proximity of the tube hardrolled region and the sleeve hydraulically expanded region. For this condition, leak rates would be expected to be on the order of one third to one half of the normal makeup capacity.

For axial displacements of less than -1.5", intimate contact between the tube and sleeve is provided by the installed diameters in the rolled region. The attendant leak rate would be expected to be about an order of magnitude less than that for a displacement of 1.5" to 3". It must be stressed that the repair boundary of 1.1" below the bottom of the HRUT based on residual strength considerations would be expected to result in motion being precluded from occurring. Furthermore, the repair boundary of 1.1" below the bottom of the HRUT based on geometric constraint considerations results in there being a very low probability that such motions would occur in the unlikely event that the residual strength was not sufficient to preclude motion.

HE/ CRITR.SEC 8-1 09/2$ /9$

Westinghouse non-Proprietary Class 3 8.2 . Offsite Dose Evaluation For a Postulated Main steam Line Break Event Outside of Containment but Upstream of the Main Steamline Isolation Valve As stated in Section 3.0, the postulated SLB event is the most limiting faulted condition with regard to offsite dose potential. Following the SLB any primary-to-secondary leakage is assumed to be entirely released to the environment. Equilibrium primary and secondary side activities are calculated based on the Technical Specification limit.

NUREG-0800 is used to calculate the maximum allowable primary-to-secondarJJ leakage limit during the event such that offsite doses remain within the licensing basis. Similar calculations have shown that the accident initiated Iodine spiking case is usually limiting. Doses are limited to 10% of the 10 CFR 100 limit of 300 Rem thyroid dose. For example, the maximum faulted loop leakage for Point Beach Unit 2 is found to be 25 gpm in the faulted loop, assuming 150 gpd leakage in each steam generator prior to the event with a maximum RCS activity level of 1.0 micro Curies per gram dose equivalent Iodine-131. For Cook Unit 1, the value has been determined to be 12.6 gpm, and was approved by the NRC as part of the Voltage Based Interim Tube Support Plate Plugging Criteria for Cook Unit 1. Each tube permitted to remain in service due to application of the criteria will be assumed to contribute to the total leakage. If the total projected leakage exceeds the calculated maximum permissible value, tubes will be repaired or removed from service so that the, projected SLB leakage value is reduced below the maximum permissible limit. As an alternative th tube repair, the RCS technical specification activity level can be reduced. For Point Beach Unit 2, lowering the allowable activity level to 0.25 micro Curies per gram dose equivalent Iodine-131 supports a maximum leakage value of approximately 100 gpm.

8.3 Evaluation of Other Steam Loss Accidents The MSLB event outside of containment would be expected to represent the most severe static loading and dynamic response condition upon the steam generator. No U.S. plant has ever experienced a double ended guillotine rupture of a main steam pipe. Plants have experienced however, random instances where a steam line relief valve or safety valve have stuck open.

Of these two, the safety valve would have a greater dynamic response upon the system. This event, however, produces a limited response compared to the double ended SLB, and the plant response to this condition would be bounded by the SLB condition response.

In addition to a postulated SLB event or a spurious opening of a safety valve, the following moderate frequency accidents:

1) uncontrolled rod withdrawal from full power,
2) loss of reactor coolant fiow,
3) loss of load, and HEJCRITR.SEC 8-2

Westinghouse non-Proprietary Class 3

4) loss of normal feedwater would result in higher than normal primary too secondary pressure diff ressure differentials across the steam generator es. All of these events are rapidly occurrin or tubes. urring transients tran and lead to rapid of the steam linee iso ation v isolation valves and to a relatively rapid decrease of

'losure a event presents the most severe loading to an HEI sleeved tube with PTIs 8.4 HEJ Inspection Requirements A review of the currecurrent inspectMn criteria suggests that the HBJ parent tube be in su stanti axial and/or circumfemferential PTls in the region of the sleeve/tubee jomt.

joint. As a minimum, minimum the probes used should demonstrate ns e th e capability of detecting 40% to 60% deep EDM axial and circumferential notches.

To assist in establishin g a data b ase for continued evaluation, indications left in th

. air criteria should be inspected at thee subsequent refueling outage.

t spec sub e 'pec too inspectMn w be consistent from inspection in the convention of locating parent n tubee mdications relative to the bottom of HR o thee HRUT should be used defining the location of the PTIs.

HPJCRITR.SEC 8-3

Westinghouse non-Proprietary Class 3 9.0 Summary of Sleeve Degradation Limit Acceptance Criteria 9.1 Structural Considerations Based upon the information previously identified in this report, the foHowing structural considerations are considered to be validated:

9.1.1 Crack Indications Below the Upper HardroH Lower Transition Any crack indication, either circumferential or axial, is allowed to remain in service ifthe elevation of the uppermost portion of the crack is located below 1.1" below the bottom of the KRUT.

9.1.2 Sleeved Tube with Degradation Indications with Non-Dented Tube Support Plate Intersections For indications in the upper hardroH lower transition, circumferential crack extent is limited to 179't BOC. A 179'OC throughwaH crack is considered representative of a 224 EOC crack. The measured RPC angle should be assumed throughwaH over its entire indicated length. Circumferential indications to which this angle limit applies are limited to the lower transition region only, and do not apply to indications in the hardroH flat area or higher.

Any circumferential crack indication existing above the lower transition with a depth estimate of 40% or greater will be removed from service or repaired, consistent with current criteria.

Axial cracks are permitted to remain in service if the uppermost part of the crack is located no less than 1/2 inch below the bottom of the upper hardroH transition.

Any axially oriented crack existing less than 1/2 inch below the bottom of the upper hardroH transition will be removed from service or repaired, consistent with current criteria.

9.1.3 Dented Tubes The HEI repair boundary identified in this report does not rely on the resistive effects of dented tube support plate intersections to react any portion of the tube end cap load.

9.2 Leakage Assessment For PTIs located below the HRLT, SLB leakage would be expected to be negligible and can be excluded from SLB leak rate calculations. For circumferential indications below 1.1" HEJCRITR.SEC 9-1

Westinghouse non-Proprietary Class 3 below the bottom of the HRUT, but within the HRLT, SLB leakage would be expected to be limited to -0.02 gpm per indication.

9.3 Defense In Depth and Primary to Secondary Leakage Limits The repair boundary identified in this report results in margins which significantly exceed the burst criteria of RG 1.121 and leakage requirements relating to offsite dose evaluation. The Technical Specification normal operating primary-to-secondary leak rate limit will be lowered to 150 gpd per SG (0.1 gpm). The leak rate used in the evaluation for each plant will be selected to represent the expected leakage from an HEI which has experienced a complete circumferential separation at the elevation of the repair boundary. This level of leakage is readily detectable by plant leakage detection systems. The available axial translation limits of the tube and the relation of these limits to leakage limits are also addressed. Section 7.0 of this report has demonstrated that the maximum amount of axial motion that a postulated circumferentially separated tube could be expected to experience is 1.1". Based on the distribution of indication elevations observed at Kewaunee, a postulated movement of 1.1" would still result in a length of intimate tube/sleeve contact. If the tube were postulated to move an amount on the order of, say, 2", the maximum primary to secondary leakage would be limited to about 30 gpm at SLB pressure differentials, being limited by the thin gap created between the tube ID in the hardroll region and the sleeve OD in the hydraulically expanded region. This would be an extremely unlikely event since the sleeve/tube joint would have to have insufficient residual strength and the tube would have had to have been installed at a lower extreme deviation from its nominal U-bend elevation at the same time as its outboard neighbor having been installed at an upper extreme deviation from it nominal U-bend elevation. Such a situation would not be likely to have been overlooked during fabrication, and could be expected to have resulted in contact of the tubes in the V-bend, which would have been detected during the NDE of the tubes during prior inspection outages. I"inally, the prototype testing program demonstrated that the axial friction force between the postulated separated tube and sleeve increases as the amount of slippage increases further reducing the likelihood of a tube/sleeve separation.

HEJCRITR.SEC 9-2

Westinghouse non-Proprietary Class 3 10.0, Refer eaces

1. WCAP-9960 (Proprietary), "Point Beach Steam Generator Sleeving Report," Westing-house Electric Corporation (1981).
2. WCAP-9960 (Proprietary), Revision 1, "Point Beach Steam Generator Sleeving Report,"

Westinghouse Electric Corporation (1982).

3. WCAP-11573 (Proprietary), "Point Beach Unit 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).

WCAP-11643 (Proprietary), "Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).

5. WCAP-11643 (Proprietary), Revision 1, "Kewaunee Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation, November 1988.
6. WCAP-11669 (Proprietary), "Zion Units 1 and 2 Steam Generator Sleeving Report (Mechanical Sleeves)," Westinghouse Electric Corporation (1987).

I

7. WCAP-12623 (Proprietary), "American Electric Power D. C. Cook Unit 1 Steam Generator Sleeving Report (NIechanical Sleeves)," Westinghouse Electric Corporation (1990).

WCAP-14157 (Pxoprietary), "Technical Evaluation of Hybrid Expansion Joint (HH)

Sleeved Tubes With Indications Within the Upper Joint Zone," Westinghouse Electric Corporation, August, 1994.

9." WCAP-14157, Addendum (Proprietary), "Supplemental Leak and Tensile Test Results for Degraded HEJ Sleeved Tubes in Model 44I51 SIG's," Westinghouse Electric Corpora-tion, Septembex, 1994.

10. Regulatory Guide 1.121, "Bases For Plugging Degraded PWR Steam Generator Tubes,"

United States Nuclear Regulatory Commission, Issued for Comment (1976).

VPNPD-94-096 I NRC-94-068 (Proprietary), "Dockets 50-266 and 50-301, Response to Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 13, 1994.

10- 1 09/25/9S

i i

Westinghouse non-Proprietary Class 3

12. NPD-94-101 / NRC-94-069 (Proprietaxy), "Dockets 50-266 and 50-301, Response to .

Requests for Additional Information, Technical Specifications Change Request 175, Point Beach Nuclear Plant, Units 1 and 2," Wisconsin Electric Power Company, September 22, 1994.

13. USNRC SER, "Safety Evaluation by the Office of Nuclear Reactor Regulation RElated to Amendment Request CR-175 to Facility Operating Licenses DPR-24 and DPR-27, Wisconsin Electric Power Company Point Beach Nuclear Plant, Units 1 and 2, Dockets 50-266 and 50-301," United States Nuclear Regulatory Commission, January 11, 1995.
14. Wisconsin Public Service and Wisconsin Electric Power meeting with the United States Nuclear Regulatory Commission, discussion of the Point Beach SER and the responses to the RAIs, February 1, 1995.
15. Wisconsin Public Service meeting with the United States Nuclear Regulatory Commission, discussion of inspection results of Kewaunee SG tubes, April 13, 1995.
16. Hexnalsteen, P., "Belgian Experience with Cixcumferential Cracking, Part 1: Genexal Overview," EPRI Workshop on Circumferential Cracking, Charlotte, North Carolina, June, 1995.
17. WCAP-10949 (Proprietaxy), "Tubesheet Region Plugging Criteria for Full Depth HardroH Expanded Tubes," Westinghouse Electric Corporation (1985).
18. WCAP-12244, Revision 3 (Proprietary), "Steam Generator Tube Plug Integrity Summary Report," Westinghouse Electric Corporation (November, 1998).
19. Ducrile Fracture Handbook, Electric Power Research Institute, Palo Alto, California (October, 1990).
20. Flesch, B, et al., "Operating Stress and Stress Corrosion Cracking in Steam Generator Transition Zones (900-MWe PWR)," International Journal of Pressure Vessels and Piping, Vol. 56, pp. 213-228 (1993).
21. Bandy, R., and Van Rooyen, D., "Stress Corrosion Cracking of Inconel Alloy 600 in High Temperature Water - An Update," Corrosion, Vol. 40, No. 8, pp. 425-430 (August, 1984).

. Yonezawa, T., et al., "Effects of Metallurgical Factors on Stxess Corrosion Cracking of

¹AHoys in High Temperature Water," Proceedings of the 1988 JAIF International Conference on Water Chemistry in Nuclear Power Plants, Tokyo (April, 1988).

HEJREFS.SEC 10-2

Westinghouse non-Pxoprietaxy Class 3

23. Theus, G. J., "Summary of the Babcock and Wilcox Company's Stress Coxmsion

~ ~ ~

Cracking Tests of Alloy 600," EPRI WS-80-0136, EPRI Workshop on Cracking of Alloy

~

600 U-Bend Tubes in Steam Generators, Denver, Colorado (1980).

24. Kim, V. C., and Van Rooyen, D., "Strain Rate and Temperature Effect on the Stxess Corrosion Cracking of Inconel 600 Steam Generator Tubing in Primary Water Condi-tions," Proceedings of the Second International Symposium on Environmental Degrada-tion of Materials in Nuclear Power Systems Water Reactors, Monterey, California, pp.

448-455 (September, 1985).

25. Personal communication, Darol Haxxison of Entergy to Bob Keating of Westinghouse (September 15, 1994).
26. WCAP-12076 (Proprietaxy), "St. Lucie Unit 1 Steam Generator Sleeving Report (Me-chanical Sleeves)," Westinghouse Electric Corporation (November, 1988).
27. NUREG/CR-3464, "The Application of Fxacture Proof Design Methods Using Tearing Instability Theory to Nuclear Piping Postulating Through Wall Cracks," United States Nuclear Regulatory Commission (September, 1983).

~ ~ ~

28. NUREG/CR-0838, "Stability Analysis of Circumferential Cracks in Reactor Pi)ing

~

~ ~ ~

~ ~

Systems," United States Nuclear Regulatory Commission (Febxuaxy, 1979).

~

~

29. Tada, H., and Paris, P. C., "The Stress Analysis of Cracks Handbook," Second Edition, Paris Productions Incorporated, St. Louis, Missouri (1985).
30. WPS-94-587 (NTD-NSRLA-OPL-94-297), "Wisconsin Public Service Corporation, Kewaunee Nuclear Power Plant, Allowable Primary/Secondary Leak Rate During Steam Line Break for Kewaunee," Westinghouse Electric Corporation, September 30, 1994.

HEJREFS.SEC 10-3

Westinghouse non-Proprietary Class 3 Appendix A Review of Prior Amendment Requests for HEJ Sleeved Tubes 1.0 Discussion/Chronology of Prior Amendment Requests When HEJ sleeved tube PTIs were first detected at Kewaunee in the Spring of 1994, analyses and tests were performed to characterize the effect of the degradation on the strength of the joint. Since no tubes had been removed for destructive examination, it was assumed that the degradation was in the form of circumferential cracking. A meeting was held with the NRC on April 19, 1994, during the inspection outage, to discuss the non-destructive examination techniques, the results of the non-destructive examinations, the results of structural analyses and tests performed on HEJs with simulated circumferential degradation below the hardroll in the parent tube, and to propose and amendment request to allow selected HEJ sleeved tubes to remain in service. It was demonstrated HEJs with circumferential cracks below the HRLT of any extent, i.e., up to 360, met the structural xcquirements of draft RG 1.121, i.e., a margin of 3 relative to burst during normal operation and a margin of 1.43 relative to burst during a postulated SLB. Leak testing results were presented that indicated that a leak rate of < 1 gpm would be expected during a postulated SLB from all of the tubes with indications ifthey were allowed to remain in service. Thus, it was proposed that any indications below the HRLT be allowed to remain in service. Based on a structural analysis of circumferential cracks at the top of the HRLT, it was also recommended that tubes with projected crack lengths ( 240 at the end of the next cycle be allowed to remain in service. The NRC advised Wisconsin Public Service on April 20, 1994 that insufficient time was available to properly review the request for an amendment to the operating license. Therefore, the amendment request was not submitted to the NRC for approvaL In August, 1994, in preparation for a Fall outage, the Wisconsin Electric Power Company submitted an amendment request to the NRC to allow HEJ sleeved tubes to remain in service with PIIs below the hardroll. References 8 and 9 were included with that submittal in support of the request for an operating license amendment to allow selected HEJ sleeved tubes with PTIs to remain in service at Point Beach Unit 2. The technical bases of the submittal were similar to those developed for Kewaunee, i.e., RG 1.121 criteria would be met for any indications below the bottom of the HRLT, as would HEJs with indications with projected lengths of less than 226'n the HRLT. To support the angular extent criteria, additional existing data relative to the growth of crack in tubes were collated; these indicated that crack growth rates of 45 per cycle in the circumferential direction and 20% of the tube wall thickness per cycle in the radial direction could be considered as bounding. A series of re-quests for additional information (RAIs) were issued by the NRC which were responded to via References 11 and 12. The license amendment request was denied based on the conclusion documented in the safety evaluation report (SER), Reference 13, prepared by the office of Nuclear Reactor Regulation of the NRC.

DAPLANISVLEPiHEJPNDXA.SEC A-1 09/2$ /9S

Westinghouse non-Pxoprietaxy Class 3 A mepting with the NRC, initiated by W'isconsin Public Service (WPS, Kewaunee), Reference 14, was held on February 1, 1995, to verify a mutual understanding of the concerns expressed in the SER, and to discuss each of the Wisconsin Electric Power Company (WEP, Point Beach) responses to the RAIs. The conclusions reached at that meeting relative to unresolved NRC concerns were:

1. that the database employed for the potential growth calculations was insufficient for estimating the incubation time and growth rate of parent tube flaws (PTIs),
2. that the qualifications of the NDE probes used for the inspection of the parent tubes did not include a sufficient number of cracked tube specimens as opposed to the use of machined flaws in ASME NDE standards to calibrate the probes,
3. that the level of detection and the accuracy of sizing PTIs in the uppex transitions of the HEJs might not be sufficient to support the application of the criteria, and,
4. that the appearance of PTIs at the lower transition(s) is indicative of a tube that is prone to developing PIIs at the upper transitions.

Thus, taken as a whole, the NRC was concerned that undetected PTIs at the upper transitions of tubes with PTls in the lower transition(s) could grow during the operating cycle to the extent that the structural integrity of the tube would be less than that required by the RG 1.121 at the end of the operating cycle.

Another meeting between WPS and the NRC, Reference 15, was held on April 13, 1995, during the inspection outage at Kewaunee, to discuss PTIs detected using a + Point eddy current inspection probe (the previous inspection of the parent tubes was conducted using a Zetec I-coil eddy current inspection probe). Information was presented that the probe had been qualified to EPRI guidelines using both ASME standards and cracked HEJ sleeved tube specimens which had been fabricated by Westinghouse. Summaxy information was also presented to show that of over 930 total PIIs found at three plants, there were no instances of the simultaneous appearance of PTls at the lower and upper transitions. It was thus argued that PTIs in the lower transitions should not be cause to remove the sleeved tube from service.

However, since much of this information was developed during the outage, there was insuffi-cient time for the NRC to conduct a thorough review of the information and tubes with PTIs within the HEJ region were removed from service.

2.0 Summary of Structural Integrity and Leak Rate Evaluations In order to quantify the effect of the tube indications on the operating performance of HEJs with PTls, test and analysis programs were performed, References 8 and 9, aimed at:

1) characterizing the effect of the obsexved indications on the axial strength of the joint, and DAPLANTSM,EPQKJPNDXA.SEC A-2 09/25/9$

Westinghouse non-Proprietary Class 3

2) estimating the leak rate that could be expected during normal operation and under postulated SLB conditions for the case of a tube perforated below the hardroll.

Characterization of the axial strength of the joint in the event of tube degradation of the type indicated in the Kewaunee and Point Beach tubes (no indications have been determined to be present in the Cook 1 tubes at present) was explored via axial tensile (pull out) testing and hydraulic proof testing. Additional analyses results were reported in References 11 and 12.

A summary of the test and analysis programs is provided in the following sections. The results are applicable to the four U.S. plants with installed HEJs. Plant operating parameters relative to structural integrity evaluations are presented in Table A-1. The largest operating primary-to-secondary differential pressure (1535 psi) occurs in the SGs at Kewaunee. The smallest differential pressure (1225 psi) occurs at Point Beach 2. The differential pressure at Cook 1 is 1453 psi.

2.1 Structural Integrity Tests Two types of structural tests were performed, tensile strength tests and hydraulic proof tests (References 8 and 9). Prototypic HEJ test specimens, see Figure A-l, were fabricated using Alloy 600 tubing and both Alloy 600 and Alloy 690 sleeve material.'he initial tensile strength tests were performed on prototypic HEJ sleeved tube specimens with the lower portion of the tube completely machined away at various postulated crack elevations. For specimens where the tubes were completely removed by machining at the elevation corre-sponding to the bottom of the HRLT, i.e., 1.25 inches below the bottom of the HRUT, the structural capability of the joints were approximately twice the most limiting RG 1.121 cap loading. For specimens where the tubes were completely removed by machining at 3'nd the elevation corresponding to the approximate mid-span of the hydraulically expanded region, i.e., -2.25" the bottom of the HRUT, the structural capability of the joints were -3.5 to 4 times the most limiting RG 1.121 361? end cap load.

A second series of tests were conducted for HEJ sleeved tubes with simulated throughwall circumferential PTls of less than 360'rc. The results from these tests were documented in Reference 8. In these tests, the sleeves were installed in tube samples using prototypic techniques. The tubes were first slit 100% throughwall over varying arc lengths from 120'o 240 at axial locations as near to the top of the HRLT as practical. The structurally prototyp-ic specimens were installed in a tensile testing machine and axially loaded to failure at a temperature of 600'F with no internal pressure. The specimens were configured such that the tube end was attached to the movable crosshead of the machine and the sleeve end was attached to the stationary base. Upon loading, the bending moment caused by the centroid of the remaining ligament being non-coincident with the axis of the tube, the loading axis, caused a smaH lateral deflection of the tube and sleeve in the direction of the slit. This small deflecting resulted in additional locking of the tube to the sleeve such that, in most cases, even The tensile tests demonstrated that the performance of Alloy 600 thermally treated sleeves (utilized in the 1983 Point Beach 2 sleeving campaign) was similar to that of Alloy 690 sleeves.

DAPLANTSU.BF6KJPNDXA.SEC A-3 10/03/9S

i Westinghouse non-Proprietary Class 3 with a 240'hroughwall slit, the sleeve failed in tension at about ten times the normal operation end cap load. For the specimens that did fail in the tube ligament, the failure loads were approximately twice the ultimate tensile capacity of the ligament material. Thus, the additional friction force developed at the hardroll interface of the sleeve and the tube exceeded the most limiting RG 1.121 requirement. In summary, an HEJ sleeved tube with a PTI with a non-symmetric remaining ligament(s) of about 90'as a structural integrity in excess of the most limiting RG 1.121 requirements.

The structural proof tests were performed on specimens which had been fabricated for leak testing. Following the leak tests, the sleeved tubes were machined to simulate a throughwall crack at the inflection point of the hard roll. All of the samples 360'ircumferential were then pressurized to a differential pressure of 3657 psi. The pressure was then gradually increased until slipping of the joint was noted. Initial slippage of the tubes was generally detected after an increase in the pressure of about 200 to 700 psi. The maximum pressures, i.e., those achieved when the tube was ejected ftom the sleeve, were not recorded, but did ap-proach pressures on the order of three time normal operating pressure differentials.

2.2 Structural Integrity Analyses The structural analyses presented in References 8, 11, and 12 considered a model of the degraded tube cross-sectional area subjected to the applied loads as shown in Figure A-2. The purpose of the analyses was to support the application of an ARC which included consider-ation of PTls located at the top of the HBLT. Such indications axe not a subject of'this report. The criterion supported by this report is that all PTIs located below a distance of 1.1" below the bottom of the HRUT can be left in service regardless of depth or circumferential extent.

It is worth noting that the analyses demonstrated that tubes with LTL material properties would meet the RG 1.121 3iQ? structural requirement if they were cracked 224 throughwall.

The acceptable throughwall angle is reduced to 196 if the remaining ligament is also assumed to be cracked 50% throughwall from the ID of the tube. The model employed assumed that no friction force, e.g., due to magnetite packing or corrosion product buildup within the tube-to-tube support plate crevices, would add to the resistance to axial motion of the tube or to reduce the applied load transmitted to the tube-to-sleeve joint.

Reference 11 noted that in addition to a postulated SLB event or spurious opening of a safety valve, the following moderate frequency accidents:

1) uncontrolled rod withdrawal from full power,
2) loss of reactor coolant fiow,
3) loss of load, and
4) loss of normal feedwater would result in higher than normal primary to secondary pressure differentials across the steam generator tubes. The maximum pressure differential across the tubes that may be DAP~MEPQKJPNDXA.SEC A-4 10/03/95

Westinghouse non-Proprietary Class 3 experienced for steam generator loss of secondary side pressure events is 2560 psid. For items 1) through 4), the maximum pressure differential across the tubes would be expected to be less than 1800 psid. All of these events lead to closure of the steam line isolation valves and to a relatively rapid decrease of the differential pressure. Thus, the postulated SLB event presents the most severe loading to an HEJ sleeved tube with PTIs.

2.3 Leak Rate Tests and Analyses References 8 and 9 documented the results of elevated temperature leak tests that were performed using prototypic HEJ specimens which had the tube portion machined away at the midpoint and that the bottom of the HRLT. The specimens with the tube removed at the bottom of the HRLT exhibited leak rates on the order of 0.0012 gpm, with maximum of 0.008 gpm, at SLB conditions. The specimens with the tube removed at the midpoint of the a maximum leak rate of 0.016 gpm at SLB conditions, thus, also demonstrating a HRLT'xhibited significant resistance to primary-to-secondary leakage. These tests suggest that the presence of a "lip" of tube material below the top of the HRLT provides sufficient leakage restriction.

The proposed amendment would establish that any indications of tube degradation greater than 1.1" below the bottom of the HRUT would be acceptable for continued service, providing a "lip" of approximately 0.1", and would also provide the geometric configuration such that neither significant tube axial displacement nor significant tube leakage would be expected during a postulated SLB event.

Leak rate tests were also conducted using HEJ sleeved tube specimens with throughwall slits extending about 240 around the circumference of the tube. The slits were located at the top of the HRLT, i.e., approximately 1.0 to 1.03" below the bottom of the HRUT. The maximum leak rate at 600 F was found to be 0.015 gpm at a differential pressure of 2450 psi.

Based on the observation that one of the specimens may have exhibited leakage from one of the test fittings, a bounding SLB leak rate of 0.033 gpm per indication was established for 240 throughwall slits in the hardroH lower transition.

References 8 and 9 also documented the xesults of elevated temperature leak tests that were performed using specimens fabricated by sectioning and removing the tube section at the top of the HRLT. Since the acceptance of PTIs at the top of the HRLT is not a subject of this report, the results are not applicable and no discussion is necessary.

2.4 Crack Growth Rate Evaluations An assessment of the potential growth of the PIXs in both the circumferential and radial directions was provided in References 8, 11, and 12. The distribution of PTIs initially reported at Kewaunee was analyzed to determine if there was any apparent difference between the SGs. The average, miiiiinum, and maximum circumferential extents were similar, as were the standard deviations, and it was concluded that the distributions in each SG represented samples from the same parent population. Since the phenomena had not been previously Approximately 1.12 to 1.13 inch below the bottom of the HRUT.

DAPLANTSVEEPQKJPNDXA.SEC A-5

Westinghouse non-Proprietary Class 3 reposed, there was no historical database that could be used to estimate growth rates. For growth in the circumferential direction, an assumption was made regarding initiation and the average growth rate was estimated to be -35 per year. For analysis purposes, a rate of 45 per year was assumed. This was noted to be greater than a 95% confidence bound for ODSCC for observed growth at another plant that was operating at 614 F. In addition, the published data on crack growth rates of Alloy 600, of References 21, 22, 23 and 24, and Belgian data, were quoted to support the rate assumed of 45'er year as being conservatively bounding. It was also noted that the estimated rate was about three standard deviations above the mean of observed TI'S data.

There also was, and still is, no directly measured data for the radial growth rate of circum-ferential PTIs in HEI sleeved tubes. Reference 12 presented information radial growth information for tubes based on field observations at McGuire, Doel 4, Arkansas Nuclear One, and Maine Yankee in support of a bounding rate of 21% per year in 7/8" nominal diameter tubes. Information from PWSCC of mechanical plugs was evaluated which indicated radial growth rates on the order of -17% to -23% per year in 7/8" diameter tubes depending on the material activation energy. Using the tube developed rate, it was concluded that 360 PTIs with depths of 53% (Kewaunee) to 58% (Point Beach 2) at the BOC would not exceed the RG 1.121 32ZNO, structural limit at the end of a one year cycle. Using the mechanical plug growth rates, 360'TIs with depths of 51% (Kewaunee) to 56% (Point Beach 2) would not be expected to exceed the RG 1.121 limits at EOC. Although it has been demonstrated by field experience that the occurrence of a PTl at the HRLT or HELT does not imply the presence of another PTI at either the HRUT or the HEUT, undetected PTIs at such'ocations would not be likely to violate the RG 1.121 requirements at the EOC.

3.0 Summary Prior submittals for license amendments requested approval for the implementation of multiple criteria to deal with the occurrence of PTls as a function of the location of the PIIs in the HEJ. These are summarized in the following paragraphs.

1. For indications below the bottom of the HRLT, it was demonstrated that PTls of any extent did not result in degradation of the joint such that the requirements of RG 1 121 would not be met at the end of an, or any, operating cycle. This was also

~

demonstrated for indication up to the middle of the HRLT. It was further demon-strated by test that the total leak rate from all such indications would not lead to a violation of the radiological release limits during a postulated SLB event.

2. For indications at the top of the HRLT it was demonstrated that indications on the order of 2/3 of the circumference of the tube, with the remaining ligament degraded to the detection level of the NDE, could be tolerated without exceeding the require-ments of RG 1.121 at the end of the operating cycle. The acceptance criteria for the beginning of the cycle length and depth of such indications were based on assumed conservative growth rates in the circumferential and radial directions. It was demon-strated by test and analysis that a significant number of throughwall PTIs could be DAPLANTSQ.EPQiE/PNDXA.SEC A-6 10/03/9S

Westinghouse non-Proprietary Class 3 allowed to remain in service without expecting leak rate limits to be exceeded.

The information presented in the main section of this report resulting from the destructive examination of the Kewaunee tubes continues to support the application of a criterion based on item 1. The results from the destructive examination of the Kewaunee tubes do not support the implementation of criteria based on item 2, even though the indications were not thxough wall and had a residual strength in excess of RG 1.121 requirements. Since the indications extended 360'round the tube, effective circumferential growth rates of at least 50'er year were experienced as a result of the presence multiple initiation sites. However, the informa-tion obtained does not contradict the radial growth rate developed in support of item 2.

Finally, the information obtained does support the detection thresholds previously considered for both the + Point and CECCO 3 probes.

D LPLANTSQ.EPQKlPNDXA.SEC A-7

Westinghouse non-Proprietaxy Class 3 Table A-1: Operating Parameters for V.S. Plants with Installed HEJs PP Ps Thot Tcotd Plant SG Loops (psia) (psia) (psi) ('6 ('8 Point Beach 2 44 2000 775 1225 596.7 541.7 Cook 1 51 2100 1453 582.0 518.0 Kewaunee 51 2250 715 1535 591.2 531.8 Zion 1 51 2250 725 1525 592.2 532.2 DM'LANYSlAEPalEJPNDXA.SEC A-8

End Cap Plug or Tensile Gripper.

Tube cut at elevations from the top of the transition to below the

~ Tube

~

bottom of the transition, and at various arc lengths.

Hardroll Hydraulic Expansion Sleeve End Cap Plug or Tensile Gripper.

Figure A-I: HEJ specimen used for tensile testing.

D:EPLhRKEAEPKHEJPNDXhSlG A-9 7/29/95

Circumferential Crack Structural Model

.; Assumed:

depth I

I I

/

/

/ I

/

I I

I I

I I

I I

I I

Throu ghwall Circumferential Neutral Axis Crack Figure A-2: Structural model for a tube with a circumferential throughwall crack.

D:KPLANTSKAEP4 EKJPNDXAPIG A- 10 7/29(95

Critical Axial Load vs. Through-Wall Crack Angle 7/8" x 0.050", Alloy 600 MA SG Tubes w/LTL Material Properties 4.5 4.0

--- Critical Angle for LTL Material 40% Through-Walt Ligament Note: Hardroll capacity of 300 l&assumed based on

.- RG 1.121 NOp Limit lower bound of test data.

~ . RG 1.121 SLB Limit 3.5 P) 3.0

'0 o 2.5

~ 2.0 1.8 79 KLS

~ 1.5 1.4 27 KLEk

'1.0 0.5 0.0 0 200 224'50 256'50 Crack Angular Extant (Degrees)

Figure A-3 D:EPLARIS'tAEPtHEJPNDXJLZIG A- 11 7/2%95

'60'W Circumferential tW Axial cracking does cracking degrades the not degrade the axial axial strength of the joint strength of the tube/joint.

, to less than the require- The leak resistance is

! ments of RG1.121. degraded.

.,'Leak resistance is

'ignificantly reduced.

360'W Circumferential cracking at this location, or below, does not degrade the axial strength of the joint to less than the require

-ments of RG 1.121.

Leak resistance is HEJ Joint Critical slightly reduced.

Tube Crack Locations Figure A-4: Critical tube crack locations in a HEJ.

D:REPLANTS hhEPKHEJPNDXhSIG A-12 7/29/95

4 ATTACHMENT 2 TO AEP:NRC:10820 Donald C. Cook Nuclear Plant Individual Plant Examination Human Reliability Analysis Summary of Methodology Changes and Example Calculations

ThIs attachment includes a summary of the changes made in the human reliability analysis methodology and example calculatIons.

SUMMARY

OF METHODOLOGY CHANGES After a complete comparison of the original (Revision 0) AEPSC human reliability methods to the THERP [Reference 1] methods was performed, the AEPSC methods were updated to be more consistent with the THERP method and to reflect newer information. Below is a summary of the major inconsistencIes identified and their resolution in the revised (Revision 1) human reliability analysis:

Human reliabilit action s eciflc to se uences:

Revision 0: A simplifying assumption was utilized that an operator action, such as establishing primary feed and bleed, was independent of the accident sequence.

Revision 1: Sequence specific human error probabilities were calculated based on differences in timing, stress, dependence, and possible recoveries, using THERP.

De endence Modelin:

Revision 0: Dependence modeling was used infrequently.

Revision 1: Prior human action failures were assessed for modeling of dependent failures of subsequent actions, both within a modeled action and between different modeled actions.

Performance sha in factors in dia nosis:

Revision 0: Training and stress performance shaping factors were utilized for the diagnosis error frequencies.

Revision 1: The EPRI methodology [Reference 2] was used for diagnosis, which is consistent with THERP.

Ex licit consideration of timin:

Revision 0: For most cases, timing was only considered in a qualitative manner, with the diagnosis error rate being frequently based on the time needed to complete the action.

Revision I: Timing was used to check ifthere was adequate time available to perform the action and any recovery actions. Workload was also considered as influencing the stress level.

Consistent use of second erson checkin:

Revision 0: Credit was generally taken for checking, to the extent needed to determine an acceptably accurate final result (i,e., once a human error failure path was found to be not the dominant path, further credits were not taken). Thus, known actions such as second person checking were inconsistently used.

Revision 1: These credits were only used when the checking actions were clearly proceduralized (e.g.,

checker initials required), or on a case by case basis when it could be shown that the person actually makes a habit of reviewing what the operator was doing.

Trainin erformance sha in factors:

Revision 0: Training performance shaping factors were included for execution type errors to address the impact of improved training and procedures.

Revision 1: These generic training shaping factors were not used. Training was only considered on a case by case basis. Section 3.3 (attached) is an example of how operator training and practices were credited.

References "Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plant Applications," A. D. Swain and H. E. Guttmann, NUREG/CR-1278, 1983.

2. "An Approach to the Analysis of Operator Actions in Probabillstlc Risk Assessment," EPRI TR-100259, EPRI Project 2847%1, Final Report, June, 1992.

II. EXAMPLE CALCULATIONS The following portions from the Donald C. Cook Nuclear Plant's Human Reliability Analysis, Revision 1, are included with this attachment:

Section 3,3 High Pressure Cold Leg Recirculation'HPR) Event Tree Level HEP Calculation Section 3.5 Depressurizatlon to Allow Low Pressure Iqjectlon (OLI) Event Tree Level HEP Calculation Attachment HPR Marked up procedure pages for Section 3.3 Attachment OLI Marked up procedure pages for Section 3.5 Figures E-8 HPR fault trees HPR1, HPR2, HPR3 and HPR4 (only more complex fault through F 11 trees, i.e,, those with AND gates, are included)

Both HPR and OLI are good examples of how dependencies were treated in the analysis. The different types considered were dependencies between personnel, steps within a human failure event, and steps in different human failure events. Both cognitive and execution error dependence were considered.

The HPR fault trees are much more detailed than the majority of the HRA fault trees due to dependence with switchover to containment spray recirculation (CSR), which is performed at the same time. These switchover actions had common cognitive errors (i.e., totally dependent), and some common execution errors. These common cognitive and execution errors were quantified as totally dependent by using the same identiTiers in the corresponding fault trees.

As described in Section 3.5.6, for a Medium LOCA event, OLI is required about the same time as switchover to recirculation. As many factors influence which comes first, it was conservatively assumed that OLI precedes switchover and switchover was considered totally dependent on OLI.

For more information on the assumptions used in the analysis, see Section 3.3.3 of Attachment 1 of this submittal. Results are summarized in Tables 3.3-2 and 3.3-3 of Attachment 1 of this submittal.

33 HPR - HIGH PRESSURE COLD LEG RECIRCULATION 3.3.1 ~Atication Small LOCA (SLO) with success of auxiliary feedwater (AF4) - HPRA (JMR)

SLO with failure of auxiliary feedwater (AF4) - HPRB (JMR)

Medium LOCA (MLO) with success of auxiliary feedwater (AF4) - HPRC (JMR)

Transient with Steam Conversion Systems Available (TRA) - HPRD (JAJ)

Transient without Steam Conversion Systems Available (TRS) - HPRE (JAJ)

Large Steam Line/Feedline Break (SLB) - HPRF (JAJ)

Loss of Offsite Power (LSP) - HPRG (JAJ)

Steam Generator Tube Rupture (SGR) - HPRH (JAJ)

Station Blackout (SBO) with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI - HPRS (JMR)

SBO with success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, failure of AF1, success of PBB, and success or failure of CSI - HPRT (JMR)

SBO with success of AFT, success or failure of RCC, failure of AFC, success of XHR, CNU and PBB, and success or failure of CSI - HPRU (JMR)

SBO with failure of AFT, success of XHR, CNU, and PBB, and success or failure of CSI

- HPRV (JMR)

Loss of CCW or ESW with success of RCP and RR2 - HPRW (JMR) 3.3.2 ~Dcacrt tion High pressure cold leg recirculation is required for several top events following successful ECCS high pressure injection when RWST reaches the low level setpoint of 32%. The transfer to recirculation is required to ensure a continued source of flow is available to the RCS so that core cooling is maintained following depletion of the RWST inventory. In the HPR phase, the water that is spilled from the break collects in the lower containment, flows through course and fine mesh strainers into the recirculation sump. The CCPs and SI pumps then take suction from the recirculation sump via the residual heat removal system. During the manual switchover from the injection phase to the recirculation phase, both the RHR and SI pumps discharge line cross-tie valves are shut. This provides two separate trains of injection during the recirculation phase.

3.3.3 Success Criteria and Timin Anal sis Success of this event requires one of two SI pumps and one of two CCPs to inject to one of three intact cold legs with the pump suction supplied by one of two RHR trains operating in the recirculation mode. If this top event fails, late core damage with the RCS at high pressure is postulated to occur.

3.3-1

The Event Tree Notebook provides justification for the time to switchover from accident initiation and the amount of time the operator has to complete the switchover based on useable volume of the RWST for each application of this top event. A summary of these success criteria times is presented below. Refer to the Event Tree Notebook for additional information.

For medium LOCA (MLO) and small LOCA (SLO), the time from accident initiation until switchover is required would be approximately 30 minutes, assuming all safeguards pumps initially operating. This assumes containment spray is actuated early in the accident. The time to switchover would be longer if there are equipment failures or if spray actuation is delayed. Once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment (Reference 1).

For steam generator tube rupture (SGR) events, containment spray actuation would be expected about 30 minutes following initiation of primary bleed (See Success Criteria Notebook, Table 28). Switchover to high pressure cold leg recirculation would then be required about 30 minutes after. this. This relative timing would also be expected for transient events in which bleed and feed recovery is used due to unavailability of feedwater for decay heat removal. Once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment. This time is the same as that for MLO and SLO since containment spray actuation is expected following initiation of bleed and feed.

This timing analysis is also applicable to TRA, TRS and LSP events in which bleed and feed recovery is used due to the unavailability of feedwater for decay heat removal.

For SLB events, the time from accident initiation for a large secondary break inside containment until switchover is conservatively assumed to be approximately 30 minutes. This assumes containment spray is actuated early in the accident if the break is located inside containment. Similar to MLO and SLO, once RWST level reaches 32% and switchover is initiated, the operators will have 17 minutes to complete the switchover to high pressure recirculation before any of the safeguards pumps cavitate due to air entrainment.

For SBO events, depending on the amount of RCP seal leakage and the resulting need for containment spray injection, the time at which switchover to cold leg recirculation would be required could be as short as 30 minutes after spray and high pressure injection are actuated to several hours if spray actuation is not required. The timing requirements for completing the switchover to cold leg recirculation is 17 minutes, similar to MLO and SLO, since high pressure injection may also be actuated.

For SSW and CCW events, the timing analysis is the same as that of SBO, recirculation may be required within 30 minutes of event initiation and completion of the switchover actions within 17 minutes.

Procedures Upon a small LOCA causing a reactor trip and SI actuation, the operators will enter E-0. At step 25, they will transfer to E-1, and at step 14 of E-1, they will transfer to ES-1.2.

The Emergency Operating Procedure used to perform switchover to cold leg recirculation is 3.3-2

~ 4 ES-1.3, TRANSFER TO COLD LEG RECIRCULATION, Rev. 2 ES-1.3 is entered from:

a) E-1, LOSS OF REACTOR OR SECONDARY COOLANT, Rev. 5, Step 15, on low RWST level.

b) ECA-2.1, UNCONTROLLED DEPRESSURIZATION OF ALLSTEAM GENERATORS, Rev. 4, Step 9, on low RWST level.

c) Other procedures whenever RWST level reaches the switchover setpoint.

For a small LOCA with success of AFW, entry into ES-1.3 will occur from the caution statement at the beginning of ES-1.2, and the RWST low level alarm provides cognitive recovery. This transition could also be from the foldout page for E-1 and ES-1.2, but this is conservatively not credited. Although the check for RWST level is performed in different procedures, depending on the initiating event, the action is the same for all cases. The Cue Table is applicable to all listed applications.

3.3.5 Critical and Recove Actions The following are the primary tasks which must be completed for satisfying the success criteria of the HPR actions:

1. Monitor for low RWST level and the need for establishing cold leg recirculation (Caution statement before ES-1.2) (cognitive)
2. Reset SI (Step 1 of ES-1.3)
3. Align West RHR for recirculation (Step 4 of ES-1.3)
4. Align CCPs and SI pumps for recirculation (Step 5 of ES-1.3)
5. Align east RHR pump for recirculation (Step 6 of ES-1.3)

See Table 3.3-1, Cue Table for HPR for identification of symptoms for establishing high pressure cold leg recirculation.

See Table 3.3-2, Subtask Analysis for HPR for identification of critical or relevant recovery actions associated with cold leg recirculation.

3.3.6 ~Assum tiuus See sections 3.3.8, 3.3.9 and 3.3.10.

3.3.7 Si nificant 0 erator Interview Findin s

1. Switchover to recirculation takes top priority above all other actions. Whenever the RWST level reaches 32%, they will stop what they are doing and immediately go to ES-1.3. The unit supervisor and RxO will not be interrupted with other tasks, and 3.3-3

others in the control room know to not get in the way.

2. The unit supervisor, who is reading the procedure, will watch each step performed by the RxO, and wait until completion of the step (i.e., until valves have transferred to correct position) before going on to the next step.
3. There will be at least two others in the control room who will be going through the procedure and ensuring that the steps are carried out completely (i.e., the extra US and the STA). The SS, ASS and BOPO may also be watching.
4. Whenever the operators start a pump or close a suction valve, they will watch the pump amps and discharge flow. This is second nature to the operators.

Most unit supervisors will actually start switchover before the RWST has reached 32%, so they have do not have to hurry, and will not have to deal with the confusion of the RHR pumps tripping on low-low RWST level. They are encouraged to start early.

3.3.8 Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21). Tables 3.3-3 and 3.3-4 contain the calculation of the cognitive human error probability, pc, that the operators fail to recognize the need for switchover to high pressure recirculation. Pc was calculated in Table 3.3-3 to be 3.1E-03, without recovery. The recovered value of pc was calculated in Table 3.34 to be 1.5E-04.

3.3.9 Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.

(T20-x refers to Table 20-x of Reference 2.) The critical actions identified in Table 3.3-2 were reviewed to determine the dominant critical actions to be quantified. Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability. Attachment HPR is a copy of the relevant portion of ES-1.3, with dominant critical steps circled. The reasons why the other critical steps (identified in Table 3.3-2) are not dominant are also included.

3.3.9.1 Ste 4 Ali n West RHR Pum for Recirculation:

4a Sto 8c lockout W RHR PP Errors of Omission:

Omit step/page:

1.3E-03 (T20-7 03, Assumption G)

Step 4 of procedure Errors of Commission:

3.3-4

Select wrong control when it is dissimilar to adjacent controls:

negligible (Table 20-12, ¹1A gtem 1A has been added by Swain since NUREG/CR-1278))

The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the West RHR panel.

4c o en recirc sum to W RHR/CTS um valve Errors of Omission:

Omit step/page:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 4 of procedure Errors of Commission:

Select wrong control when it is dissimilar to adjacent controls:

negligible (Table 20-12, ¹1A /tern 1A has been added by Swain since NUREG/CR-1278))

This control is different from adjacent controls because it is metal and has a key in it.

Total error robabilit for Ste s 4a & c:

1.3E-03 + 1.3E-03 = 2.6E-03 4d Start W RHR PP Errors of Omission:

Omit step:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 4 of procedure Errors of Commission:

negligible, see Errors of Commission for Step 4a 3.3-5

Ste 5 Ali n SI Pum s and CCPs for Recirculation Si o en SI um suction from west RHR HX valve and

~5' en SI um suction crosstie to CCP valves These two steps were considered as one perceptual unit. These are adjacent procedure steps and the valve controls are all right next to each other (i.e., these actions are not separated by time or location).

Errors of Omission:

Omit step/page:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 5 of procedure Errors of Commission:

Select wrong control on panel from array of similar appearing controls:

1.3E-03 (T20-12 ¹3)

All safety injection suction and discharge valves are in one area on SI control panel.

Total error robabilit for Ste 5:

2.6E-03 Ste 6 Ali n East RHR Pum for Recirculation:

6b Sto & lockout East RHR PP Errors of Omission:

Omit step/page:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 6 of procedure Errors of Commission:

Select wrong control when it is dissimilar to adjacent controls:

negligible (Table 20-12, ¹1A (item 1A has been added by Swain since NUREG/CR-1278))

The RHR trains are delineated, the ammeter is directly above the control, and no similar ammeters are on the East RHR panel.

3.3-6

6d o en recirc sum to East RHR/CTS um valve Errors of Omission:

Omit step:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 6 of procedure Errors of Commission:

Select wrong control when it is dissimilar to adjacent controls:

negligible (Table 20-12, ¹1A (1tem 1A has been added by Swain since NUREG/CR-1278))

This control is different from adjacent controls because it is metal and has a key in it.

Total error robabilit for Ste s 6b & d:

1.3E-03 + 1.3E-03 = 2.6E-03 6e Start East RHR PP Errors of Omission:

Omit step:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 6 of procedure Errors of Commission:

negligible, see Errors of Commission for Step 6b 6f 0 en CCP suction from East RHR HX valve Errors of Omission:

Omit step:

1.3E-03 (T20-7 ¹3, Assumption G)

Step 6 of procedure Errors of Commission:

Select wrong control on panel from array of similar appearing controls:

3.3-7

ll '

II

1.3E-03 (T20-12 P3)

It is clearly labeled on the boric acid charging and letdown panel. It is at the bottom left of the panel.

3.3.10 Calculation of Total Human Error Probabilit for Failure to Switchover to HPR The cognitive and execution error probabilities were calculated in sections 3.3.8 and 3.3.9 to be:

pc'(HPRA) = 1.5E-04 pe(steps 4a&c) = 2.6E-03 (without stress, dependence or recovery) pe(step 4d) = 1.3E-03 (without stress, dependence or recovery) pe(step 5) = 2.6E-03 (without stress, dependence or recovery) pe(steps 6b&d) = 2.6E-03 (without stress, dependence or recovery) pe(step 6e) = 1.3E-03 (without stress, dependence or recovery) pe(step 6f) = 2.6E-03 (without stress, dependence or recovery)

In order for alignment of the east RHR train (step 6) to recover for an error in aligning the west train (step 4), the operators must recognize that there is not adequate flow from the west RHR pump train before aligning the high head pumps (step 5). The high head pumps are expected to fail quickly without a suction source (per operator interviews). A high level of dependence is assumed, therefore, for the operators recognizing that there is a problem with the east RHR train before they align the high head pumps in step 5. This was modelled by a high dependence failure of noticing failed step 4, so performing step 6 before step 5 (i.e.,

human error probability = 0.5). A high level of dependence is conservative, however, as the operator and unit supervisor will be watching pump amperes when suction sources are closed (e.g., for the high head pumps) and when the RHR pumps are started (per operator interviews). The ammeters are right above the pump controls in the control room. Also, the unit supervisor watches what the operator is doing, and waits for completion of one step before moving on to another (which can be significant, as it takes about 30 seconds for the RWST suction valves to close).

A moderate level of dependence was assumed between failure of step 4 and the initial tasks in step 6. Although steps 4 and 6 are similar, they are different procedure steps, on different pages, and unless the operators realize they failed step 4, step 5 will be performed between them. An extremely high level of stress is assigned to all step 6 actions, though, as these actions are only critical if the operators failed in step 4.

Per operator interviews, a minimum of two people will be watching the unit supervisor and operator go through the switchover using a copy of the procedure. Whenever switchover is occurring, it is top priority, and almost everything else has come to a stop. The STA does not want to get in the way, so he will be going through the procedure and watching what is going on, as well as the extra unit supervisor. The unit supervisor is not interrupted during switchover, therefore, the extra unit supervisor will be free to watch the switchover. Several more people may also be watching, but this is conservatively not credited. If it is under an hour after event initiation, the shift supervisor may still be busy with his E-plan duties. The assistant shift supervisor may be busy in his role as contingency director, and the BOPO may not be paying close enough attention to catch a mistake.

3.3-8

Only one recovery was given to the extra unit supervisor and STA. A low level of dependence was assumed between them and the unit supervisor and RxO because they are not interacting at all with the US and RxO; they are standing back and fulfillinga supervisory type role. This combined effort was equated to that of the shift supervisor in Table 204, Reference 2.

Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks. Per Table 20-17, if the basic error probability (BHEP) is greater than .01, the equations to use for low, moderate, 'uman and high dependence are: (1+19N)/20, (1+6N)/7, and (1+N)/2, respectively. Per Table 20-21, if the BHEP is less than or equal to .01, HEPs of .05, .15 and .5 should be used for low, moderate, and high dependence, respectively.

Recovery due to extra unit supervisor and STA following procedure and actions = 0.05 These parameters and assumptions are used below to determine the total human error probability for failure to switchover for high pressure recirculation under different conditions.

HPRA: Switchover to hi h ressure recirculation u on a small LOCA and successful AFW

~AF4 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)

A moderately high level of stress was assumed for steps 4 and 5. This is a procedure that is well known and practiced by the operators, and they are not concentrating on doing anything else during this procedure, as it takes top priority.

pc'(HPRA) = 1.5E-04 (HPRA-LPR-CSRHE) pe'(steps 4a&c) = 2.6E-03

  • 2 = 5.2E-03 (REC 4A&C-MHHE) pe'(step 4d) = 1.3E-03
  • 2 = 2.6E-03 (REC- 4D-MH HE) pe'(step 5) = 2.6E-03
  • 2 = 5.2E-03 (REC---5-MHHE) pe'(steps 6b&d) = 2.6E-03
  • 5 with MD (REC-6B&D-EHHE-M)

= (1 + 6*1.3E-02)/7 = 1.5E-01 pe'(step 6e) = 1.3E-03 ~ 5 = 6.5E-03 (REC--6E-EHHE) pe'(step 6f) = 2.6E-03

  • 5 = 1.3E-02 (REC 6F-EHHE) pe'(recognize to do step 6 before step 5) = HD = 0.5 (REC-6TH EN5 HE-H)

Recovery, execution errors (extra US and STA) = 0.05 (REC-US-STA HE-L)

The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a small LOCA and successful AFW (AFW) is calculated as shown in fault tree HPR1:

THEP(HPRA) = pc' fpe'(step 4)

  • pe'(step 6) + pe'(step 5)]
  • recovery(extra US or STA) 3.3-9

THEP(HPRA) = 1.5E-04 + [(5.2E-03 + 2.6E-03) * (0.5 + 1.4E-01 + 6.5E-03 + 1.3E-02)

+ 5.2E-03]

  • 5.0E-02 THEP(HPRA) = 6.7E-04 HPRB: Switchover to hi h ressure recirculation u on a small LOCA failure of AFW AF4 and success of rima bleed and feed BF1 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)

For this scenario, the operators will transition from Step 18 of E-0 to FR-H.1 to complete PBF. Due to adverse containment conditions, the operators will immediately go to step 18 of FR-H.1. They should still be in FR-H.l when RWST level reaches 32%. The caution statement after step 25 of FR-H.1 will be their cue to monitor the RWST level, with cognitive recovery provided by the alarm. It is assumed that the RxO monitoring the RWST level will have a high work load, as they will be busy with PBF and subsequent actions in FR-H.1.

The only change in pc'rom pc'(HPRA) will be to tree b. The new end path will be 1 due to the high work load, which is not recovered.

pc'(HPRB) = 7.5E-04 + 3.0E-07 pc'(HPRB) = 7.5E-04 (HPRB-LPR-CSRHE)

The extremely high level of stress from primary bleed and feed is conservatively assumed to still exist. Otherwise, the actions have the same failure probabilities as HPRA.

pe'(steps 4a&c) = 2.6E-03 ~ 5 = 1.3E-02 (REC-4A&C-EHHE) pe'(step 4d) = 1.3E-03

  • 5 = 6.5E-03 (REC--4D-EH HE) pe'(step 5) = 2.6E-03
  • 5 = 1.3E-02 (REC EH HE) pe'(steps 6b&d) = 2.6E-03
  • 5 with MD (REC 6B&D-EHHE-M)

= (1 + 6~1.3E-02)/7 = 1.5E-01 pe'(step 6e) = 1.3E-03 ~ 5 = 6.5E-03 (REC 6E-EHHE) pe'(step 6f) = 2.6E-03

  • 5 = 1.3E-02 (REC 6F-EHHE) pe'(recognize to do step 6 before step 5) = HD = 0.5 (REC-6TH ENS-HE-H)

Recovery, execution errors (extra US and STA) = 0.05 (REC-US-STA-HE-L)

The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a small LOCA, failure of AFW (AF4), and success of PBF is calculated as shown in fault tree HPR2:

THEP(HPRB) = pc' [pe'(step 4) ~ pe'(step 6) + pe'(step 5)]

  • recovery(extra US or STA)

THEP(HPRB) = 7.5E-04 + [(1.3E-02 + 6.5E-03) * (0.5 + 1.4E-01 + 6.5E-03 + 1.3E-02)

+ 1.3E-02]

  • 5.0E-02 THEP(HPRB) = 2.0E-03 3.3-10

S 8

't

HPRC: Switchover to hi h ressure recirculation u on a medium LOCA and successful

~AFW AF4 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)

This is the exact same scenario as HPRA, except for the size of the LOCA. For this event, however, this difference in LOCA size is irrelevant, as the timing and flow through the procedures should be the same.

The total human error probability (THEP) for failing to switchover to high pressure recirculation upon a medium LOCA and successful AFW (AFW) is the same as HPRA:

THEP(HPRC) = THEP(HPRA) = 6.7E-04 HPRD: Switchover to high pressure recirculation after a transient with steam conversion systems available (TRA), followed by loss of auxiliary feedwater (AF1), a loss of alternate secondary cooling sources (AFW from the other Unit and main feedwater-MF1, and SG depressurization combined with condensate-OA5), and success of primary feed and bleed (PBT). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRD equals HPRA, and fault tree HPR1 is used.

For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRD is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.

HPRE: Switchover to high pressure recirculation after a transient with failure of steam conversion systems (TRS), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBT). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRE equals HPRA, and fault tree HPR1 is used.

For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRE is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.

3.3-11

HPRF: Switchover to high pressure recirculation after a large steam/feedwater line break (SLB), followed by successful high pressure injection (HP3) and successful isolation of the faulted SG (MS1) but loss of auxiliary feedwater (AFS), countered by success of primary feed and bleed (PBS). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, equation HPRF equals HPRA, and fault tree HPR1 is used.

For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRF is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.

HPRG: Switchover to high pressure recirculation after a transient loss of offsite power (LSP), followed by loss of auxiliary feedwater (AF1), and success of primary feed and bleed (PBL). In this scenario, the operator initiates a LOCA when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. However, there may be one train equipment unavailable depending on the diesel generator (DG) response. If two diesel generators succeed, then HPR equals HPRA. If only one diesel generator succeeds, then HPR equals HPRA (in timing) but with only one train available. Although the case for the two DG success is more likely (-95%),

the case of success of only one DG (-5%) leads to more restrictive modeling and has conservatively been applied. Thus, equation HPRG equals HPRA Steps 4 and 5, as calculated in fault tree HPR4.

For the branch where primary bleed and feed succeeds, but containment spray injection fails, HPRG is also assigned because the development is similar to that described above, only the containment spray injection fails to actuate extending the timing.

HPRH: Switchover to high pressure recirculation after a steam generator tube rupture (SGR),

followed by loss of all auxiliary feedwater (AF2 and AF3), and success of primary feed and bleed (PBG). In this scenario, the operator initiates a LOCA inside of containment when primary feed and bleed is started. Because of this, switchover to recirculation will occur approximately 30 minutes after Containment Spray Injection actuates. Containment Spray Injection actuates a short time after the rupture disk on the primary pressure relief tank blows out. This timing is similar to the development in the small LOCA event tree (SLO) on the path where high pressure injection (HP2) succeeds and auxiliary feedwater (AF4) succeeds, leading to high pressure recirculation about a half hour later. Thus, HPRH equals HPRA, and fault tree HPR1 is used.

3.3-12

HPRS: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU RRI and AF1 and success or failure of CSI Dependency upon CSI failure is not evaluated, because THEP for CSI is mostly due to errors of omission, which are independent for steps on different pages, with the remainder due to cognitive failures. If the operators failed to actuate CSI, switchover to recirculation is not necessary for 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after this CSI failure. In this time, there are no other system failures.

This amount of time, with no other major operator tasks, negates any cognitive dependency.

Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause'a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.

Per the Event Tree Notebook (Reference 1), with the containment spray and high head ECCS pumps injecting, there is 17 minutes available for switchover, and switchover will not be required until at least 30 minutes following completion RRI and CSI.

For this scenario, everything has been successful following power restoration, and at least 30 minutes have elapsed since operators finished RRI and CSI. Power has been back for an hour, and things are under control. The operators will transfer to E-1 (LOSS OF REACTOR OR SECONDARY COOLANT) at the end of ECA-0.2 (i.e., step 14).

The cue for the operators to monitor RWST level will be Step 15 of E-1. A low work load can be assumed at this time and recovery with the alarm can also be credited. This results in a value for pc'qual to that for HPRA. (The end state for tree e is all that changes (from b to c), but the value remains the same (3.0E-03).)

pc'(HPRS) = pc'(HPRA)

As things are under control, recovery due to the extra US/STA can be credited.

Therefore, the total human error probability for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, RRI, and AF1, and success or failure of CSI is the same as that from HPRA.

THEP(HPRS) = THEP(HPRA)

Fault tree HPR1 is used.

HPRT: Switchover to hi h ressure recirculation u on a SBO and success of AFT success or failure of RCC success of AFC XHR CNU and RRI failure of AF1 success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF). Therefore, as these paths include success of PBF, there is no dependence to consider.

3.3-13

Failure of the containment spray system is not addressed separately. If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following power recovery). The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.

Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.

For this scenario, the operators will transition to FR-H.1 following completion of Step 10 of ECA-0.2. For hydrogen control, the operators may transfer to FR-Z.1 (per caution statement before step 27 of FR-H. 1) and then return to FR-H.1. Eventually, the operators will leave FR-H.1 to transfer E-1 or to switchover to recirculation (ES-1.3). The caution statement in FR-H.1 (before step 26) should be their cue to monitor RWST level, with cognitive recovery provided by the alarm. It is assumed that the operator monitoring RWST level will have a high work load, as they will be busy with FR-H.1 and FR-Z.1. This results in a pc'qual to that for HPRB:

pc'(HPRT) = pc'(HPRB)

The extremely high level of stress from primary bleed and feed is conservatively assumed to still exist.

Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO and success of AFT, success or failure of RCC, success of AFC, XHR, CNU, and RRI, and failure of AF1, success of PBB, and success or failure of CSI is the same as HPRB.

THEP(HPRT) = THEP(HPRB)

Fault tree HPR2 is used.

HPRU: Switchover to hi h ressure recirculation u on a'SBO success'of AFT success or failure of RCC failure of AFC success of XHR and CNU success of PBB and success or failure of CSI See writeup for HPRT. Fault tree HPR2 is used.

This is the same scenario as described in HPRT. AFW has been lost (worse case scenario) for a couple hours before power recovery, and PBB must be initiated right after completion of CSI (i.e., step 10 of ECA-0.2).

Early failure of RCS cooldown (RCC) is not addressed separately, as this action was performed several hours earlier (long before power restoration), errors of commission were due to the AEO (who will not be involved in HPR), and there have been numerous successes since this time. This early failure should not cause a higher level of stress at this time. RCC failure just mandated earlier power restoration, which was successful.

3.3-14

HPRV: Switchover to hi h ressure recirculation u on a SBO failure of AFT success of XHR and CNU success of PBB and success or failure of CSI Although the event tree displays PBB occurring before CSI, the operators must complete CSI before they transfer to any FRPs (i.e., PBF). Therefore, as this path includes success of PBF, there is no dependence to consider.

Failure of the containment spray system is not addressed separately. If CTS failed, operators would have even more time to perform HPR, and it would not be required until much later into the event (i.e., 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following power recovery). The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CTS has failed.

An extemely high level of stress is assumed, as a blackout with failure of the TDAFP is a severe incident for the operators, and switchover is required fairly early in the accident (about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> from loss of power). (This level of stress is also assumed because it follows PBB.)

As described in HPRT, a high work load is assumed for the RxO for calculation of pc'.

Therefore, the THEP for failing to switchover to high pressure recirculation upon a SBO, failure of AFT, success of XHR and CNU, success of PBB, and success or failure of CSI is the same as HPRT.

THEP(HPRV) = THEP(HPRT) = THEP(HPRB)

Fault tree HPR2 is used.

HPRW: Switchover to hi h ressure recirculation u on a loss of CCW or ESW and success of RCP and RR2 (CSI status is not addressed. If CSI failed, operators would have even more time to perform HPR, and it would not be required until much later into the event. The corresponding decrease in stress would be negated by the added stress the operators experience if they notice CSI has failed.)

HPR will not be required until very late into the event. Since the RCPs were tripped, seal failure is not actually expected until an hour or two into the event (see RCP, Section 3.25.2),

at which time the containment sprays will be actuated. With both containment spray pumps operating, it takes at least 35 more minutes to reach the RWST low level. A charging pump is started (i.e., RR2A) within 30 minutes of the restoration of CCW/ESW. As a result, HPR is expected after a charging pump has been started in RR2A.

At this point, things are well under control. The small LOCA through the seals is under control and CCW/ESW has been restored. A low work load is considered for the operators by the time HPR is needed. The operators will probably still be in OHP 4022.016.004 when HPR is required, since they will not leave it until after the RCS is cooled and depressurized enough to start RHR. There is not a procedure step to warn the operators to monitor RWST level, but the operators know to monitor this. Only cognitive tree b applies (data not attended to) to this situation. End path I from tree b results in a cognitive value of 7.5E-04. No recovery is applied to this value. (Note: the path for high work load was conservatively followed, so this cognitive failure probability can be used for other scenarios.)

3.3-15

pc(HPRW) = 7.5E-04 (HPRW-CSR-COGHE)

It is assumed that only one train of CCW/ESW has been restored, so HPR recovery with the second train is not credible. The operators will go to Attachment A or B of ES-1.3 via step 2 or 3, since both trains of RHR/CCW are not available. The steps in these attachments are similar to the main procedure, except they will align the high head pumps to the one available train of RHR. The critical actions are still the same, with only the step numbers being different. Therefore, for simplicity, the same identifiers are used as before. (Steps 2 and 3 do not need to be evaluated because the operators would be well aware that both trains are not available, and an EOM of step 2 would be recovered by step 3 (as they are on different pages).) Due to the low work load and since things are under control, recovery with the extra US or STA is warranted.

pc(HPRW) = 7.5E-04 (HPRW-CSR-COGHE) pe'(steps 4a&c) = 2.6E-03

  • 2 = 5.2E-03 (REC-4A&C-MHHE) pe'(step 4d) = 1.3E-03
  • 2 = 5.2E-03 (REC- MH HE)

Recovery, execution errors (extra US and STA) = 0.05 (REC-US-STA-HE-L)

The total human error probability for failing to switchover to high pressure recirculation upon a loss of CCW or ESW and success of RCP and RR2 is calculated as shown in fault tree HPR3:

THEP(HPRW) = pc' fpe'(step 4) + pe'(step 5)] ~ recovery(extra US or STA)

THEP(HPRW) = 7.5E-04 + [(5.2E-03 + 2.6E-03) + 5.2E-03] ~ 5.0E-02 THEP(HPRW) = 1.4E-03 3.3.11 HPR Fault Trees Summa The basic events and cutsets (with support system failures (i.e., SUBs) set equal to 1.0E-03) for the HPR fault trees are listed below.

3.3-16

Fault tree HPR1 (used for HPRA, HPRC, HPRD, HPRE, HPRF, HPRH, HPRS)

VER 1.6 hprl.cut Ver. 1.71 7/25/95 9:07:40 10 11 1.670E-03 O.OOOE+00 1.000E-09 HPRA-LPR-CSRHE 1 '000E-04 0.0000E+00 2 REC-US-STA.-HE.L 5 ~ 0000E.02 0 '000E+00 3 REC--4A&C.MHHE 5 '000E-03 0 ~ 0000E+00 4 REC--.-4D.MHHE 2.6000E-03 0 '000E+00 5 REC-----5.MHHE 5.2000E-03 0.0000E+00 6 REC-6THENS--HE-H 5.0000E-01 0.0000E+00 7 REC--6B&D-EHHE-M 1.5000E-01 0.0000E+00 8 REC----6E-EHHE 6.5000E-03 0.0000E+00 9 REC----6F-EHHE 1.3000E-02 0.0000E+00 10 SUB-HPR 1.0000E-03 0 ~ OOOOE+00 1 ~ 1.00E-03 1 SUB-HPR

2. 2.60E-04 2 REC-US-STA--HE-L REC-----5-MHHE
3. 1 ~ 50E-04 1 HPRA-LPR-CSRHE
4. 1.30E-04 3 REC-US-STA--HE-L REC--4A&C-MHHE REC-6THEN5--HE-H
5. 6.50E-OS 3 REC-US-STA--HE-L REC----4D-MHHE REC-6THEN5--HE-H
6. 3.90E-05 3 REC-US-STA--HE-L REC--4A&C-MHHE REC--6B&D-EHHE-M
7. 1.95E.05 3 REC-US-STA--HE-L REC----4D-MHHE REC--6B&D.EHHE-M
8. 3.38E-06 3 REC-US-STA--HE-L REC--4A&C-MHHE REC----6F-EHHE
9. '1.69E-06 3 REC-US-STA--HE-L REC--"40 MHHE REC--"6F.EHHE
10. 1.69E-06 3 REC-US-STA--HE-L REC--4A&C-MHHE REC----6E-EHHE

'l1. 8.45E-07 3 REC-US-STA--HE-L REC----4D-MHHE REC----6E-EHHE Fault tree HPR2 used for HPRB, HPRT, HPRU, HPRV VER 1.6 hpr2.cut Ver. 1.71 7/25/95 9:07:41 10 3.04 9E-03 O.OBOE+00 1.000E-09 1 HPRB-LPR-CSRHE 7.5000E-04 0.0000E+00 2 REC-US-STA--HE-L 5.0000E-02 0.0000E+00 3 REC--4A&C-EHHE 1.3000E-02 0.0000E+00 4 REC----4D-EHHE 6.5000E-03 0.0000E+00 5 REC-----5-EHHE '1.3000E-02 0.0000E+00 6 REC-6THEN5--HE-H 5.0000E-01 0.0000E+00 7 REC--6B&D-EHHE-M 1.5000E-01 0.0000E+00 8 REC----6E-EHHE 6.5000E-03 0.0000E+00 9 REC----6F-EHHE 1.3000E-02 0.0000E+00 10 SUB-HPR 1.0000E-03 0.0000E+00

1. 1 ~ OOE-03 1 SUB-HPR 2~ 7.50E-04 1 HPRB-LPR-CSRHE 3~ 6.50E-04 2 REC-US-STA--HE-L REC-----5-EHHE
4. 3.25E-04 3 REC-US-STA--HE-L REC--4A&C-EHHE REC-6THEN5--HE-H
5. 1.63E-04 3 REC-US-STA--HE-L REC----4D-EHHE REC-6THENS--HE-H
6. 9.75E-05 3 REC-US-STA--HE-L REC--4A&C-EHHE REC--6B&D-EHHE-M
7. 4.88E-05 3 REC-US-STA--HE-L REC----4D-EHHE REC--6B&D-EHHE-M
8. 8.45E-06 3 REC-US-STA--HE-L REC--4A&C-EHHE REC----6F-EHHE
9. 4 '3E-06 3 REC-US-STA--HE-L REC----40-EHHE REC----6F-EHHE
10. 4.23E-06 3 REC-US-STA--HE-L REC--4A&C-EHHE REC----6E-EHHE
11. 2 '1E-06 3 REC-US-STA--HE-L REC----4D-EHHE REC----6E-EHHE 3.3-17

Fault tree HPR3 used for HPRW VER 1.6 hpr3.cut Ver. 1.71 7/25/95 9:07:41 6 5 2.39BE-03 O.OOOE+00 1.000E-09 1 SUB-HPR 1.0000E-03 0.0000E+00 2 HPRM-CSR-CDGHE 7.5000E-04 0.0000E+00 3 REC-US-STA--HE-L 5.0000E-02 0.0000E+00 4 REC--4ASC-MHHE 5.2000E-03 0.0000E+00 5 REC----4D-MHHE 2.6000E-03 0.0000E+00 6 REC-----5-MHHE 5.2000E-03 0.0000E+00

1. 1 'OE-03 1 SUB-HPR
2. 7.50E-04 HPRW-CSR-COGHE
3. 2.60E.04 2 REC-US-STA--HE-L REC-----5-MHHE
4. 2.60E-04 2 REC-US-STA--HE-L REC--4AKC.MHHE
5. 1.30E-04 2 REC-US-STA--HE-L REC----4D-MHHE Fault tree HPR4 used for HPRG VER 1.6 hpr4.cut Ver. 1 '1 7/25/95 9:07:42 6 5 1.799E-03 O.OOOE+00 1.000E-09 1 SUB-HPR 1 ~ OOOOE-03 0.0000E+00 2 HPRA-LPR-CSRHE 1.5000E-04 0.0000E+00 3 REC-US-STA--HE-L 5.0000E-02 0.0000E+00 4 REC--4A&C.MHHE 5 '000E-03 0.0000E+00 5 REC----4D.MHHE 2.6000E-03 0.0000E+00 6 REC-----5-MHHE 5.2000E-03 0.0000E+00 1 ~ 1.00E-03 1 SUB-HPR
2. 2.60E-04 2 REC.US-STA--HE-L REC-----5-MHHE 3~ 2.60E-04 2 REC-US-STA--HE-L REC--4ASC-MHHE 4~ 1.50E-04 1 HPRA-LPR-CSRHE 5~ 1.30E-04 2 REC-US-STA--HE-L REC----4D-MHHE 3.3-18

Respond to RWST low Alarm annunciator light Respond to 1 of 1 Control level alarm alarm

  • room - SPY panel Monitor RWST level RWST level < 32% Recognize Control symptoms room - SPY requiring panel and transfer to cold BA panel 3.3-19

EOP Reset SI SI status Control Omit action ES-13, room Rev. 2 Select wrong control for SI reset button EOP 4a Stop 1 of 1 west RHR pump Pump status Control Omit action ES-19, room Rev. 2 Select wrong controls for west RHR pump EOP 4b Close 1 of 1 west RHR pump suction valve Valve position Control Omit actions ES-13, (1-IMO-320) room Rev. 2 Close 1 of 1 west RHR pump discharge Select wrong valve crosstie valve (1-IMO-324) controls EOP 4c Open 1 of 1 recirc sump valve to west Valve position Control Omit action ES-12, RHR pump room Rev. 2 Select wrong controls for recirc sump valve 3.3-20

EOP 4d Start 1 of 1 west RHR pump Pump status Control Omit action ES-13, room Rev. 2 Select wrong controls for west RHR pump EOP 5a, c Reset and close 2 of 2 CCP miniflow Valve switches Control Omit actions ES-19, valves room Rev. 2 Select wrong controls for CCP miniflow valves EOP 5d Verify 2 of 2 North SI pump isolation Valve switches Control Omit actions ES-13, valves open (1-ICM-260, 1-IM(h316) room Rev. 2 Check wrong status lights EOP 5e Verify 2 of 2 south SI pump isolation Valve switches Control Omit actions ES-13, valves open (1-ICM-265, 1-IMO-326) room Rev. 2 Check wrong status lights EOP 5f Close 2 of 2 SI pump discharge crosstie Pump status Control Omit action ES-13, valves (1-IMO-270, I-IMO-275) room Rev. 2 Select wrong controls for crosstie valves 3.3-21

I' EOP 5h Close 2 of 2 SI pump recirculation valves Valve switches Control Omit actions ES-1.3, to RWST (1-1MO-262, 1-IMO-263) room Rev. 2 Select wrong controls for SI pump recirc valves EOP 5i Open 1 of 1 SI pump suction valve from Valve switches Control Omit actions ES-1.3, west RHR Hx (I-IMO-350) room Rev. 2 Select wrong controls for SI pump suction valve EOP 5j Open 2 of 2 SI pump suction crosstie Valve switches Control Omit actions ES-19, valves to CCP (1-IMO-361, 1-IMO-362) room Rev. 2 Select wrong controls for SI pump suction valves EOP 51 Close 1 of 1 SI pump suction valve from Valve switch Control Omit action ES-13, RWST (1-IMO-261) room Rev. 2 Select wrong controls for SI pump suction valve 3.3-22

EOP -5m Close 2 of 2 CCP suction valves from Valve switches Control Omit 1 of 2 actions ES-19, RWST (1-IMO-910, I-IMO-911) room Rev. 2 Select wrong controls for CCP suction valves EOP 5n Verify 1 of 2 CCPs running in recirc mode Pump status Control Omit 2 of 2 actions ES-13, room Rev. 2 Select wrong controls for CCPs EOP 5o Verify 1 of 2 SI pumps running in recirc Pump status Control Omit 2 of 2 actions ES-13, mode room Rev. 2 Select wrong controls for SI pump EOP 6b Stop 1 of 1 east RHR pump Pump status Control Omit action ES-19, room Rev. 2 Select wrong controls for east RHR pump 3.3-23

,"-;:NUMBER'.,':,

EOP 6c Close 1 of 1 east RHR pump suction valve Valve position Control Omit actions ES-13, (1-IM0-310) room Rev. 2 Select wrong valve Close 1 of 1 east RHR pump discharge controls crosstie valve (1-IMO-314)

EOP 6d Open 1 of 1 recirc sump valve to east Valve position Control Omit action ES-13, RHB/CTS pump (1-ICM-305) room Rev. 2 Select wrong controls for recirc sump valve EOP 6e Start 1 of 1 east RHR pump Pump status Control Omit action ES-13, room Rev. 2 Select wrong controls for east RHR pump EOP 6f Open 1 of 1 CCP suction valve from east Valve position Control Omit action ES-19, RHR Hx (1-IMO-340) room Rev. 2 Select wrong controls for CCP suction valve 3.3-24

TABLE 3.3-3 VORKSHEET FOR CALCULATION OF pc Scenario: Small LOCA with success of ECCS hi h ressure in'ection HP2 success of RCS cooldown usin AFW AF4 and success of containment s ra in ection CSI HI: HPR - Switchover to hi h ressure cold le recirculation Cue(s): RWST at low level alarm Duration of time window available for action (TW): 340 Seconds.

17 min - 680 sec 340 sec (per Reference 26, actions take 680 sec)

Approximate start time for TW 30 Procedure and step governing HI: Caution statement at be innin of ES-1 2 A. Initial Estimate of pc pc Failure Mechanism Branch HEP pca: Availability of information ~a ~ne pcb: Failure of attention d 1 5E-4 The ExO should not have much distracting him ac this point following a small LOCA (per operator interviews).

pcc'isread/miscommunicate data ~na ~na no data communicated - just instruction to watch level pcd: Information misleading ~ne pce: Skip a step in procedure 3 OE-3 Caution statement is italicized and in all CAPS.

pcf: Misinterpret instruction ~ne pcg: Misinterpret decision logic n~e pch: Deliberate violation n~e um of pca through pch I i i l pc 3 1E-3 Total reduction in TW min.

Effective TW min.

Check here if recovery credit claimed on page 2: xx Notes:

There are two RWST level indicators for the o erators to use a chart recorder and an indicator that is ver eas to read 3.3-25

TABLE 3.3-4 WORKSHEET FOR CALCULATION OF pc RECOVERY FACTORS Scenario: Small LOCA with success of ECCS hi h ressure in ection HP2 success of RCS cooldown usin AFW AF4 and success of containment s ra in ection CSI HI: HPR - Switchover to hi h ressure cold le recirculation B. Recover Facto s Identif ed Alarm at low RWST level did not credit this for b because credit for alarm alread in tree C. Recovery Factors Applied to pc pc Failure Initial Multiply Final Mechanism HEP Recover Factor ~b Value pca pcb 1 5E-4 1 5E-4 pcc pce 3.0E-03 alarm T20-23 1 0001 3 OE-7 This is probably the only alarm going off, and at time much later than the initial alarms, so it will get more attention. Also, this red dot alarm is trained on as a high priority alarm.

pcf pcg pch Eum of recovered pca through pch - Recovered pc 1 5E-4 Time at which all recovery factors effective ~t 30 mi 3.3-26

OLI - DEPRESSURIZATION TO ALLOW LOW PRESSURE INJECTION

~Attention Medium LOCA (MLO) with failure of high pressure injection (HP2) - OLIA (JMR)

~Desert tion Following the occurrence of a medium LOCA, if the high head pumps fail to start or fail to provide adequate cooling (HP2), the operators, by following emergency operating procedures, would be directed to depressurize the primary system to below the shutoff head of the RHR pumps to allow the RHR pumps to inject water to the core. The most effective means to perform this action is a rapid secondary depressurization (Reference 4a). If the RCPs are not all running, other actions include starting RCPs to provide forced two-phase flow through the core and/or opening the pressurizer PORVs to depressurize the RCS.

Success Criteria and Timin Anal sis Success of this event requires 450 gpm (240x10'PH per EOPs) of AFW flow for the duration of the accident. Success criteria of improved core cooling and increasing vessel inventory is achieved by actions of dumping steam from at least two of four steam generators and/or at least two of three pressurizer PORVs. These actions will allow for the start (or verify running) of at least one of two RHR pumps.

The MLO Event Tree description in the Event Tree Notebook provides a detailed description of the timing analysis assumed for meeting the success criteria of this event. The success criteria is based on the identification of inadequate core cooling (ICC) symptoms (high core exit TC indication) at around 30 minutes following MLO event initiation (Reference 25, MLO-35 example). Upon identification of ICC symptoms, the operators should be ready to perform the rapid cooldown with little time delay and then perform the remaining actions.

Operator actions are provided in EOP FR-C.1.

Procedures The Emergency Operating Procedure used to perform this task is FR-C.1, RESPONSE TO INADEQUATE CORE COOLING, Rev. 4.

FR-C.1 is entered from F-0.2, Core COOLING Critical Safety Function Status Tree on a RED condition.

For this event, entry into FR-C.1 will occur from the STA recognizing the red path from F-0.2. Operators will review the red path summary from the foldout pages when they transfer to E-1 from step 25 of E-0 and when they transfer to ES-1.2 from step 14 of E-1, but this is conservatively not credited.

Critical And Recove Actions The following are the primary tasks which must be completed for success of the MLO event tree OLI top event:

1. Recognize core exit TC indications greater than 1200'F on the F-0.2, CORE 3.5-1

I

~,

J I

COOLING Critical Safety Function Status Tree or on the red path summary (item 2b on foldout) (cognitive)

2. Start RHR pumps (Step 5 of FR-C.1) (Per operator interviews, the RHR pumps will probably still be running, but starting them is conservatively modelled.)
3. Initiate RCS cooldown at maximum rate using SG steam relief valves (conservatively not taking credit for condenser steam dump) (Step 13 of FR-C.1)

See Table 3.5-1, Cue Table for OLI for identification of symptoms for OLI actions, See Table 3.5-2, Subtask Analysis For OLI for identification of critical or relevant recovery actions for OLI.

3.5.6 ~Assum tions This action will be required at about the same time that switchover to recirculation will be required. Many factors influence which will come first, therefore, it is conservatively assumed that OLI precedes LPR and CSR. (This is conservative because OLI has a much higher THEP than LPR or CSR.)

3.5.7 Si nificant 0 erator Interview Findin s

1. The STA will monitor the core exit thermocouple temperatures using the plant process computer, unless conditions are abnormal, upon which they will also monitor indication on the control room back panels.

The RCPs would be running when the operators reach step 12 of FR-C.1. (They will only stop the RCPs upon a medium LOCA if RCS pressure is less than 1250 psig and high head injection is available.) Since the pumps are already running when they reach this step ("Check if RCPs Should Be Started" ), they will go on to step 13.

Therefore, they will not open the pressurizer PORVs (RNO column for step 12).

3. The RHR pumps will probably still be running when the operators enter FR-C.1.

3.5.8 Calculation of Co nitive Error A cognitive model was used to address diagnosis type errors (Reference 21). Table 3.5-3 contains the calculation of the cognitive human error probability, pc, that the STA fails to recognize the red path core cooling conditions. Pc was calculated in Table 3.5-3 to be 6.0E-

03. Recovery was not applied to this value.

3.5.9 Calculation of Execution Error For the calculation of execution errors, the tables from Chapter 20 of Reference 2 were used.

(T20-x refers to Table 20-x of Reference 2.) The critical actions identified in Table 3.5-2 were reviewed to determine the dominant critical actions to be quantified. Critical actions are not dominant if they are recovered by other procedure steps or if they follow a mechanical failure because the human error probability would be multiplied by another human error probability or a mechanical failure probability. Attachment OLI is a copy of the relevant portion of FR-H.1, with dominant critical steps circled. The reasons why the other critical steps (identified in Table 3.5-2) are not dominant are also included.

3.5-2

I:

1

'\

Ste 13 Initiate RCS Cooldown to 200'F:

13b Manuall dum steam from intact SG s usin steam relief valves Errors of Omission:

Omit step/page:

4.2E-03 (T20-7 ¹4, Assumption G)

Step 13 of procedure Errors of Commission:

Select wrong control when it is dissimilar to adjacent controls:

1.3E-03 (Table 20-12, ¹3)

The level and relief valve controls for the steam generators are well marked and different from adjacent controls on the steam generator panels. The only truly credible failure would be selecting the level control rather than the relief control.

3.5.10 Calculation of Total Human Error Probabilit for Failure to De ressurize OLI The cognitive and execution error probabilities were calculated in sections 3.5.8 and 3.5.9 to be:

pc'(OLIA) = 6.0E-03 pe(OLI) = 5.5E-03 (without stress or dependence)

OLIA: De ressurize and Start RHR followin a medium LOCA An extremely high level of stress is assumed for red path recoveries. Per table 20-16, HEPs should be multiplied by two for moderately high stress for step-by-step tasks, and by 5 for extremely high stress for step-by-step tasks.

pc'(OLIA) = 6.0E-03 pe'(OLIA) = 5.5E-03 ~ 5 = 2.8E-02 (OLI COG-HE)

(OLI-13B-EHHE)

The total human error probability (THEP) for failing to depressurize following a medium LOCA and failure of high pressure injection is:

THEP(OLIA) = pc'

6.0E-03 + 2.8E-02

pe'HEP(OLIA) 3.4E-02'he corresponding fault tree is OLI1.

3.5-3

3.5.11 OLI Fault Trees Summa 0 The basic events and cutsets (with support system failures (i.e., SUBs) set equal to 1.0E-03) for the OLI fault tree are listed below.

Fault Tree OLI1 used for OLIA VER 1.6 ot11.cut Ver. 1.71 7/25/95 9:07:00 2 2 3.383E-02 0 OOOE+00 1.000E-08

~

1 OLI-----COG-HE 6.0000E-03 0.0000E+00 2 OLI---13B-EHHE 2.8000E-02 0.0000E+00

1. 2.80E-02 1 OLI---138-EHHE
2. 6.00E-03 1 OLI-----COG-HE 3.5-4

Identify symptoms of Core exit temperature > 1200'F- Recognize red Control room inadequate core cooling RED path path for core exit on foldout page or on F- temperature >

0.2, Core Cooling Status 1200'F, and Tree transfer to FR-C.1 3.5-5

~ c ~

I;.:;~NUMBER:.'::

EOP sa Start RHR pumps pump status Control Omit action FR-C.1, (RNO) room Rev. 4 Select wrong controls for RHR pumps EOP 13b Dump steam at maximum rate using SG steam relief Control Omit actions FR-C.1, (RNO) steam relief valves valve position room Rev. 4 indication Select wrong controls for steam relief valves 3.5-6

TABLE 3.5-3 WORKSHEET FOR CALCULATION OF pc Scenario: Medium LOCA with success of accumulators and failure of hi h ressure in'ection HI: OLI - De ressurization to allow low ressure in ection Cue(s): Red ath conditions - foldout a e or status tree Duration of time window available for action (TW):

Seconds'pproximate start time for TW.

Procedure and step governing HI: F-0.2 Status Tree Red Path i.e. STA A. Initial Estimate of pc pc Failure Mechanism Branch HEP pca: Availability of information ~na ~na pcb: Failure of attention e 3 OE-3 (assume low workload for STA)

(per interview, STA will be watching computer screen for core exit thermocouple temperatures until things look abnormal, then they will check indicator on back panel -- per G. Parry, use front panel path for this tree) pcc: Misread/miscommunicate data ~na ~na pcd: Information misleading ~na ~na pce Skip a step in procedure b 3.0E-3 (Status trees are monitored in particular order, and paths are graphically distinct using different colors and line types.)

pcf: Misinterpret instruction n~e pcg: Misinterpret decision logic n~e pch: Deliberate violation n~e Sum of pca through pc I i i l pc 6.0E-03 Total reduction in TW min.

Effective TW min.

Check here if recovery credit claimed on page 2:

Notes:

Due to inconsistent usea e of the foldout a es er o erator interviews credit is conservativel not iven to the US reco nizin the red ath from the foldout a es 3.5-7

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Title Number 01-OHP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

3. Check CCW Pumps - BOTH OPERABLE IF East CCW pump is INOPERABLE, THEN:
a. Stop the East RHR pump and place in PULL-TO-LOCK.
b. Go to Attachment A.

IF Mest CCW pump is INOPERABLE, THEN'.

Stop the West RHR pump and place in PULL-TO-LOCK.

b. Go to Attachment B.

CAUTION: VHEN CONTROL POh'ER IS RESTORED FOR VALVE OPERATION, THE CONTROL POWER HUST BE LEFT ON SO ASSOCIATED INTERLOCKS 4'ILL BE OPERABLE.

4. Align West RHR And CTS Pumps For Recirculation:

Qa. Stop the following pumps and place in PULL-TO-LOCKOUT position:

QWest RHR pump

~

~ ,Mest CTS pump

b. Close the following valves concurrently:

g,. 1-1H0-320, West suction valve RHR pump Q IC.-~W tat~CL!C .

~ I-IH0-225, West CTS pump suction valve from RWST

~ I-IM0-324, West RHR pump C.

discharge crosstie valve This Step continued on the next page.

Page 3 of 35 Rev. 2

Title Humber 01-OHP 4023.

TRANSFER TO COLQ LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTEQ RESPONSE RESPONSE NOT OBTAINEQ o

c. Restore control power and open 1-ICM-306, Recirc sump to West RHR/CTS pump valve
c. Perform the following:
1) Open 1-IM0-225, West CTS pump suction valve from RWST.
2) IF West CTS pump was previously running, THEN restart the West CTS pump.

IF NOT, THEN place the West CTS pump in NEUTRAL.

3) Go to Attachment B.
d. IF the West RHR pump .can NOT be started, THEN:
1) IF West CTS pump was previously running, restart the West CTS pump.

IF NOT, ~TH N place West CTS pump in NEUTRAL.

2) Go to Attachment B.
e. Check West CTS pump status e. Place West CTS pump in NEUTRAL PREVIOUSLY RUNNING
1) Restart the West CTS pump
2) Verify ESW to/from West CTS heat exchanger valves-OPEN:

~ I-WMO-715

~ 1-WMO-717 Page 4 of 35 Rev. 2

Title 01-OHP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: ~ IF THE SI PUHP HINIFLOh'ALVES ARE CLOSED, THEN THE SI PUHPS SHOULD BE STOPPED WHENEVER RCS PRESSURE APPROACHES THEIR SHUTOFF HEAD.

~ IF RCS PRESSURE INCREASES TO 2000 PSIG, THEN A PR2 PORV SHOULD BE OPENED, AS NECESSARY, TO REDUCE RCS PRESSURE AND HAINTAIN HINIHUH CCP FLOP.

NOTE: Hinimum total BIT flow for CCP cooling is:

~ for I CCP - 150 gpm (160 gpm for adverse containment)

~ for 2 CCPs - 275 gpm (2SO gpm for adverse containment)

'.. Align SI Pumps Recirculation:

And CCPs For

a. Reset both CCP miniflow valves:

~ 1-QMO-225

~ 1-QMO-226

b. Check total BIT flow GREATER b. Perform the following:

THAN MINIMUM NEEDED FOR CCP COOLING 1) Stop all but one CCP.

2) IF total BIT flow is greater than 150 gpm (160 gpm for adverse containment), THEN go to step Sc.

IF NOT, THEN, open the associated CCP miniflow valve and go to step 5d.

WHEN RCS pressure is less than 1700 psig, THEN close all miniflow valves.

~ ~ ~ilCS CCP

c. Close both CCP miniflow valves:

~ i-q~o-225 C

~

'-gMQ-226 ~J cI8 z,(~- ~~ ~wwd This Step continued on the next page.

,Page 5 of 35 Rev. 2

Title Number 01-OHP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

d. Check the following valves for d. Manually open valves.

the North SI pump - OPEN

~ 1-ICM-260

~ l-ICM-260, North SI pump 1-IMO-316 discharge to old le s 1 8, 4 I VQk~ IF either valve remains

~

-AND- closed, THEN stop the North SI pump.

~ 1-IM0-316, RHR and SI to RCS cold 1 valve Go to step Sg.

CP4

e. Check the follow ng valves for e. Manually open valves.

the South SI pump OPEN

~ 1-ICM-265

~ 1-ICM-265, South SI pump ~ 1-IMO-326 discharge t cold legs 2 3 IF either valve remains

-AND- closed, THEN stop the South SI pump.

~ 1-IM0-326, RHR and SI to RCS cold le valv Go to step 5g.

~

Close SI dischar valves:

~ 1- IMO-270

'-IMO-275 e

~

crosstie ykLv80

~dlpVLA . P

@~~~ $ y a Check each SI pump flow - g. Stop affected SI pump(s).

GREATER THAN 70 GPM:

~ 1-IFI-260 WHEN RCS pressure is less than

~ 1- I F I-266 1425 psig (1150 psig for adverse containment), THEN start SI pump(s).

Restore control power and close SI valves:

~ 1-IMO-262 pumps recirc to RWST

~+ c

~ 1-IMO-263 i Open l-IM0-350, SI pump i. Locally open 1-IM0-350.

suction from West RHR HX valve DO NOT PROCEED UNTIL 1-IMO-350 IS OPEN.

This Step continued on the next page.

Page 6 of 35 Rev. 2

l' Number 01-OHP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 0j. Open Sl pump to

~

CCP valves:

1-IMO-361 suction crosstie

/

~ 1-IMO-362

k. Verify I-IM0-360, SI pump suction crosst'e CCPs - OP
l. 'lose Restore control power 1-IM0-261, SI and pump

~~~ Qkk/QQL e

suction from RWST

m. Close valves:

~

CCP 1-IMO-910 t

suction from. RWST ~~ quxb~

~l~4I V~~

~ 1-IMO-911

/

n. Check CCP's BOTH RUNNING n. IF CCPs were stopped because of RWST low-low level, THEN perform the following:
1) Start one CCP.
2) Check total BIT flow-greater than 150 gpm (160 gpm for adverse containment)

IF NOT, THEN open associated mini.flow valve and go to step 5o.

') Check RCS pressure than 1700 psig less IF NOT, THEN go to step 5o.

WHEN RCS pressure is less than 1700 psig, THEN restart all CCPs.

4) Start second CCP.

This Step continued on the next page.

Page 7 of 35.

Rev. 2

Hurrher Ol-OHP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED

o. Check SI pumps BOTH RUNNING o. IF SI pumps were stopped because of, RWST low-low level, THEN perform the following:
1) Check RCS pressure - less than 1425 psig (1150 psig for adverse containment)

.IF NOT, ~TH N go to step 6.

WHEN RCS pressure is less than 1425 psig (1150 psig for adverse containment, THEN do step 5o.

2) Check SI pump discharge crosstie valves - closed:

~ I- IHO-270

-OR-

~ I-IMO-275

3) IF SI pump discharge crosstie is isolated, THEN start both SI pumps.

IF NOT, THEN start only one SI pump.

Page 8 of 35 Rev. 2

Humber 01-.0HP 4023.

TRANSFER TO COLD LEG RECIRCULATION ES-1.3 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED 6 Align fast RHR And CTS Pumps For Reer rcul ati on:

a. Check RWST Level - LESS THAN a. Continue with step 7..

101m WHEN RWST level drops to IOX, TKH do steps 6b through 6h.

b Stop the following pumps and place in PULL-TO-LOCKOUT position:

@East RHR pump

~ East CTS pump c.'lose the following valves concurrently:

~ 1-IM0-310, East RHR pump suction valve

~ l-IM0-215, East CTS pump suction from RWST valve

~ l-IM0-314, East RHR pump '~Imr discharge crosstie valve

. Restore control power and open d. Restore control power and 1-ICM-305, Recirc sump to East close 1-IMQ-390 RHR pumps RHR/CTS pump valve suction from RW5T.

Go to step 7.

Qe./Start the East RHR pump e. Go to step 6g.

f. Open 1-IMO-340 CCP suction from East RHR (IX valve
g. Check East CTS pump- g. Place East CTS pump in NEUTRAL PREVIOUSLY RUNNING
1) Restart the East CTS pump
2) Verify ESW to/from East CTS heat exchanger valves - OPEN

~ 1-WMO-711

~ 1-WMO-713

h. Restore control power and close 1-IMO-390 RHR pumps suction from RW)T Page 9 of 35 Rev. 2

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i 01-OHP 4023.

RESPONSE Tp INAOEqUATE CpRE CppLING FR-C.1 STEP ACTION/EXPECTED RESppNSE

~~

RESPONSE NOT OBTAINEO NOTE: Normal conditions are desired but not requir d for starting the RCns. is&.~

12. Check if RCPs Should Be Started:
a. Core exit TCs GREATER THAN a. C6 to Step 13.

1200'F.

b. Check if an idle RCS cooling h. Perform the following:

loop is available:

1) Open all PR2 PORVs and

~ Narrow range SG level block valves.

GREATER THAN 6X (22X FOR AOVERSE CONTAINMENT) 2) +F core exit TCs remain greater than 1200'F, ~TH N

~ RCP in associated loop- open other RCS vent paths AVAILABLE AND NOT OPERATING to containment:

a) PRZ vent path valves:

~ 1-NSO-61 and 1-NSO-62

-OR-

~ 1-NSO-63 and 1-NSO-64 b) Reactor head vent path valves:

~ 1-NSO-21 and 1-NSO-22

-OR-

~ 1-NSO-23 and 1-NSO-24

3) Go to Step 13.
c. Start RCP in one idle RCS cooling loop.
d. Return to Step 12a.

Page 9 of 16 Rev. 4; CS-1

Title Hurber 01-OHP 4023.

RESPONSE TO INADEQUATE CORE COOLING FR-C.1 STEP ACTION/EXPECTED RESPONSE RESPONSE NOT OBTAINED CAUTION: DURING COOLDOVN, STEAN FLOP OF GREATER THAN 1.42x106 PPH ON TMO OR NORE SGs VILL RESULT IN A STEAPILINE ISOLATION.

NOTE: ~ Partial uncovering of SG tubes is acceptable in the following steps.

~ Both steam dump control selector switches should be momentarily placed in BYPASS INTERLOCK when Tavg decreases to 541'F.

13.~ Initiate

~

RCS Cooldown To 200'F: ~ ~

a. Transfer condenser steam dump to steam pressure mode
b. ump steam to condenser from b. Hanually or locally dump steam intact SG(s) at maximum rate from intact SG(s) at maximum rate using steam relief valves.
c. Check RCS hot leg temperatures c. Cooldown using faulted or

- DECREASING ruptured SG(s).

Page 10 of 16 Rev. 4, CS-1

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16166 11012 %45.516.4K-l 666--.S-MIE K--6S MIE REC 611M 4E

}R favell 1rcc Rll CO 8%2MI2 STA-fE-l R--.S.Bff 45.5TA.+4

FIGURE E-10 HPR3 FAULT TREE HPA3 Fault Tree HPR30OOI HPR30004 SU9-HPA HPRW-CSR-COGHE HPR30005 AEC.US-STA--HE-L REC--(ALC-LONE AEC-- ~ ~ ID-ISE REC- - - - INHE

FIGURE E-11 HPR4 FAVLT TREE HPA( Fault Tree HPA(0001 HPR40004 SUB-HPA HPRA.LPA.CSRHE HPR40005 REC-US-STA--%-L REC----<D.NHE REC-----54fSE

ATTACHMENT 1 TO AEP'NRC'10820 Donald C. Cook Nuclear Plant Individual Plant Examination Individual Plant Examination Revision 1

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CQOK NUCLEAR PLANT Bridgman, Michigan

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An+ * w "+f,, '+gty+ pj 'PlQe'. M I~ 1~~~ 0 W INDIVIDUALPLANT: EXAIMZNATION =:

-.: REVISION!=1"-'=";.-."':='."-',-';-"-;,.'.,',.

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