ML063480459

(TMI Unit 1), Response to Request for Additional Information - Technical Specification Change Request No. 331: Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

ML063480459
Person / Time
Site:	Three Mile Island
Issue date:	12/12/2006
From:	Cowan P AmerGen Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
5928-06-20559, TAC MD1807
Download: ML063480459 (49)

Text

Ame;Cen Energy Company, i i C www.exeioncorp.corn An Exelon Company 2 0 0 Exeion Way Kennett Square, PP, 19348 10 CFR 50.90 December 12,2006 5928-06-20559 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Three Mile Island, Unit 1 (TMI Unit 1)

Facility Operating License No. DPR-50 NRC Docket No. 50-289

Subject:

Response To Request For Additional Information -

Technical Specification Change Request No. 331: Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity (TAC No. MD1807)

References:

1) USNRC Letter dated November 9, 2006, Request for Additional Information Regarding the Steam Generator Tube Integrity Technical Specification Amendment (TAC No. MD1807)

2) USNRC Letter dated August 14, 2006, Three Mile Island, Unit 1 - Request for Additional Information Regarding the Steam Generator Tube Integrity Technical Specification Amendment (TAC No. MD1807)

3) AmerGen Energy Company, LLC letter to NRC dated May 15,2006 (5928-06-20390), Technical Specification Change Request No. 331 - Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

4) AmerGen Energy Company, LLC letter to NRC dated October 6,2006 (5928-06-20492), Response To Request For Additional Information - Technical Specification Change Request No. 331: Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity (TAC No. MD1807)

This letter provides additional information in response to: (1) NRC request for additional information (RAI), dated November 9,2006 regarding sleeve repairs (Reference I ) , and (2)

NRC RAI questions regarding sleeve repairs contained in Reference 2, regarding TMI Unit 1 Technical Specification Change Request No. 331, submitted to NRC for review on May 15, 2006 (Reference 3). The additional information is provided in Enclosure 1.

As described in the Enclosure 1 responses, the proposed Technical Specification page 6-26 Insert markup has been revised from our submittal of October 6, 2006 (Reference 4) to incorporate additional requirements and clarifications regarding sleeve repairs, consistent with the NRC approved TSTF-449, Revision 1.

U.S. Nuclear Regulatory Commission December 12,2006 Page 2 Additionally, the previously proposed markups for Technical Specification page 4-8 and the associated Bases page 4-2b Insert markup are revised from our submittal of October 6, 2006 (Reference 4) to clarify that primary-to-secondary leakage surveillance is not required until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of Power Operation, which ensures sufficient xenon buildup in the reactor coolant system to support accurate leakage measurement. The previous proposed markup inadvertently required primary-to-secondary leak rate quantification at all plant operating modes. The revised TS markups are consistent with the intent of the TSTF-449, Revision 4, which only requires primary-to-secondary leak rate quantification when stable power operation is achieved.

The previously proposed markup for TS Bases page 3-15a is also revised to delete the statement describing the contribution of the primary-to-secondary leak rate to 10 CFR Part 100 dose limits. This contribution has been adequately described in the additional Bases paragraphs being incorporated into TS page 3-15a, as previously proposed, and the TS 4.1 9 Bases (Applicable Safety Analyses) previously proposed, both of which are fully consistent with the TSTF-449, Revision 4 Bases.

These changes have no impact on the conclusions of the original safety analysis or no significant hazards consideration evaluation provided in Reference 3. The revised proposed Technical Specification pages are provided in Enclosure 2. Enclosure 2 provides a complete replacement set of the proposed Technical Specification pages previously submitted in References 3 and 4.

No new regulatory commitments are established by this submittal. If any additional information is needed, please contact David J. Distel at (610) 765-5517.

iL26 I declare under penalty of perjury that the foregoing is true and correct. Executed on the __

day of December, 2006.

Respectfully, Pamela B. Cowan Director - Licensing & Regulatory Affairs AmerGen Energy Company, LLC

Enclosures:

1) Response to Request for Additional Information

2) Revised TS Page Markups cc: S. J. Collins, USNRC Administrator, Region I F. E. Saba, USNRC Project Manager, TMI Unit 1 D. M. Kern, USNRC Senior Resident Inspector, TMI Unit 1 File No. 06007

ENCLOSURE 1 TMI UNIT 1 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION TECHNICAL SPECIFICATION CHANGE REQUEST No. 331 APPLICATION FOR TECHNICAL SPECIFICATION IMPROVEMENT REGARDING STEAM GENERATOR TUBE INTEGRITY 5928-06-20559 Page 1 of 7 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION TMI UNIT 1 TECHNICAL SPECIFICATION CHANGE REQUEST No. 331 APPLICATION FOR TECHNICAL SPECIFICATION IMPROVEMENT REGARDING STEAM GENERATOR TUBE INTEGRITY NRC Reauest For Additional Information Letter dated November 9,2006:

1. NRC Question You proposed to delete reference to sleeving as a repair method in the TMI-1 TSs. You indicated that TMI-1 will not install additional sleeves without prior NRC approval.

However, there are sleeves currently installed at TMI-1. Please provide the inspection and repair criteria, including technical bases, for the existing sleeved tubes. Please discuss how your proposed TS 6.1 9, Steam Generator (SG) Program, ensures that sleeved tube integrity is maintained. Also, clarify whether you are planning to add the above described criteria in the TMI-1 TSs. If not, explain.

Response

Marked-up, proposed Technical Specification (TS) pages have been provided in Enclosure 2. Inspection and repair criteria for the sleeves have been incorporated to ensure maintenance of sleeved tube integrity. Note that, as discussed with the staff, the proposed TSs have been revised to incorporate the existing sleeves; since no new sleeve installations are planned at TMI-1 without NRC prior approval, the proposed TSs reflect the presence of the existing sleeve population and do not cover the installation of new sleeves.

The following are the technical bases for the proposed TS pages:

TMI Unit 1 Sleeve Desian The design analyses and testing of the TMI Unit 1 Alloy 690 rolled sleeves were performed by the B&W Nuclear Services Company and were based on previous qualifications performed for Alloy 600 sleeves. Reference 1, below, was the qualification for the TMI-1 Alloy 690 sleeves. This report was submitted by the B&W Nuclear Services Company to the NRC for review and approval on March 26, 1991 (Reference 2). The NRC approved this qualification report ...for referencing in license applications in Reference 3.

All of the TMI Unit 1 sleeves are installed in the steam generators upper tubesheets and are 8 0 long, extending from the upper tubesheet down through the 15th tube support plate.

The upper sleeve roll-expanded joint is captured within the upper tubesheet; the lower roll expansion is a freespan joint. The sleeves were designed, fabricated, and installed as safety-related ASME Class I components.

All of the TMI Unit 1 sleeves are manufactured from Alloy 690, a corrosion-resistant material that is used for new steam generator tubes. While plants with Alloy 600 sleeves have detected sleeve degradation; plants with Alloy 690 sleeves have not detected significant corrosion to date. In addition to being corrosion-resistant, the TMI Unit 1 sleeves are stronger than the plants original steam generator tubing. (The steam generator tubing has a 0.034 minimum wall thickness: the sleeves have a 0.045 minimum wall thickness.

5928-06-20559 Page 2 of 7 The design sleeve loads assumed a 360-degree severance was present in the parent tubing behind the sleeve.)

The TMI Unit 1 upper sleeve rolled expansion joints are captured within kinetic expanded tubing in the upper tubesheets. At this location they are protected from secondary side loose parts and tube bending loads. These joints are also in compression since the sleeves were expanded into the parent tubing and tubesheets. The compressive loads, along with the corrosion-resistant material of construction, minimize the joints subsequent susceptibility to stress corrosion cracking.

The qualification reports for the sleeves were extensive and addressed the following areas:

- Leakage tests

- Joint strength tests

- Light expansion tests

- Corrosion tests

- Flow-induced vibration analysis

- Strain tests

- Adjacent tube tests

- ThermaVhydraulic effects of sleeving

- Structural and functional integrity of the sleeves TMI Sleeve Powlation TMI Unit 1 installed 125 sleeves in each of its two steam generators during 1991 Outage 9R. (This work was reported to the NRC in Reference 4.) TMI Unit 1 installed 124 sleeves in its A steam generator, and 128 sleeves in its B steam generator, during 1993 Outage 10R. (The work was reported to the NRC in Reference 5.)

One of the sleeved tubes in the Asteam generator, A66-1, was plugged during 1995 Outage 11R due to an indication between the 4hand !jth tube support plate (which is outside the installed sleeve area).

One of the sleeved tubes in the Asteam generator, A68-7, was plugged in 2003 Outage 1R15 due to an indication at the lower tube end (which is outside the installed sleeve area).

One of the sleeved tubes in the B steam generator, 868-4, was plugged in 2003 Outage 1R15 due to an indication at the lower tube end (which is outside the installed sleeve area).

The plugging of these sleeved tubes was reported to the NRC in the respective outage reports. The result is that TMI Unit 1 has 247 sleeved tubes currently in service in the A steam generator and 252 sleeved tubes in service in the B steam generator.

5928-06-20559 Page 3 of 7 Reasons for Sleeve Installation TMI Unit 1, along with all of the other operating Once-Through Steam Generator (OTSG) plants, installed sleeves in order to prevent high-cycle fatigue cracks in tubes in the lane-wedge areas of the steam generator tube bundles. An untubed lane for future tube bundle visual inspections was a design feature of the original OTSGs; however this design feature resulted in excessive vibration of the tubes located adjacenthearby the untubed lane, in the lane-wedge area. Tubes in this area were prone to vibration-induced failures near the Upper Tube Sheet (UTS) faces. A large number of primary-to-secondary leaks and leaker outages occurred at the OTSG plants as a result of fatigue cracks at the upper lengths of these tubes, so 8 0 long sleeves were installed to stabilize them. These sleeves were, and continue to be, very effective in preventing the lane-wedge tube cracking - prior to installing the sleeves about 77% (40 of 52) of the OTSG tube leaks were from tubes within the preventive sleeving zone. Since 1994 there have been no tube leaks from tubes within the preventive sleeving zones. (Approximately 3600 of these 8 0 long sleeves, of both Alloy 600 and Alloy 690, were installed in the various U.S. OTSGs. The original OTSGs at 4 of the 7 B&W-designed operating plants have been recently replaced, and their sleeves have been removed from service. Rancho Seco plant OTSG tubing was also sleeved, but that plant has been shutdown since 1989.) The only steam generator tube leaker outage at TMI Unit 1 occurred as a result of a high-cycle fatigue failure in a tube in the area of the steam generator tube bundles that has since been preventively sleeved. In summary, there is sufficient technical data and operating experience to indicate that the TMI Unit 1 installed sleeves have been very effective in preventing tube leaks, and thus supporting the position that the TMI Unit 1 sleeves should remain in service to continue to prevent tube leaks.

Some small parent tube eddy current imperfections located below the UTS kinetic expansions were covered (Le., removed from service) by the TMI Unit 1 sleeves.

However, of the 502 sleeves that were originally installed in the TMI Unit 1 steam generators, only one (1) sleeve was installed to repair a tube with a repairable indication (-

as opposed to being installed for the preventive reasons described above.) This tube, A74-30, had an ID-initiated indication >40% throughwall (TW) in the upper tubesheet portion of the tube and was sleeved in 1993 Outage 10R as reported to the NRC in Reference 5.

Additional Sleeve Qualification Testina for TMI Unit 1 The TMI Unit 1 sleeves were installed consistent with their qualification report. However, the TMI Unit 1 upper sleeve roll joints differed slightly from those of the sleeves installed at the other OTSG plants. The tubing in the TMI Unit 1 upper tubesheet joints was damaged in the early 1980s and repaired by a kinetic expansion process. (This kinetic expansion process was another effective repair and was approved by the NRC Safety Evaluation Report documented under NUREG 1019. Kinetic expansion examination and repair criteria, including treatment of the sleeves, were recently approved by the NRC in Reference 6.)

All of the TMI Unit 1 sleeves were installed in parent tubing that had previously been degraded within the upper tubesheet and had been repaired by kinetic expansion. The sleeves were originally qualified for typical OTSG 1 nominal rolled expansions into tubing with existing flaws up to 20% TW. (These were the qualifications pre-sleeving eddy current acceptance criteria for the upper tubesheet sleeve expansions.)

5928-06-20559 Page 4 of 7 Additional testing was performed for the TMI Unit 1 sleeve installation into kinetic expanded tubing. To provide additional evaluation of the acceptability of the sleeves for the TMI Unit 1 upper tubesheet parent tubing prior to their installation, additional testing was performed on roll joints with degraded parent tubing.

In addition, the sleeves at the other OTSG plants were installed over their original 1 nominal parent tube roll expansions. Approximately 2/3 of the sleeve roll expansion length was placed,over the original rolled joints, and 1/3 of the new sleeve expansions were placed over unexpanded parent tubing. This differed from the TMI Unit 1 sleeve upper joints, where the full length of the sleeve upper expansion would be into kinetic expanded tubing. Analysis and testing showed that when a sleeve was installed into a fully expanded tube, as in the TMI Unit 1 case, the entire delivered energy from the roll expander was used to achieve wall thinning of the sleeve (vice some fraction of the expander energy used to expand the length of unexpanded parent tube). The result was a tighter sleeve-to-tube joint for the TMI Unit 1 upper sleeve joint configuration.

Sleeve Examinations Parent tube examinations were performed prior to TMI Unit 1 sleeve installations. In addition, post-installation examinations were conducted on each of the sleeves when they were installed in 1991 and 1993.

Since sleeve installation, TMI Unit 1 has continued to perform an extensive eddy current examination scope on its in-service sleeves, considering that they are manufactured from corrosion-resistant Alloy 690 material. During the plants most recent outage in the Fall of 2005, 33% of the sleeve upper expansions and 100% of the sleeve lower expansions were examined with MRPC/PlusPoint probes, and 33% of the sleeve unexpanded lengths were examined with bobbin probes. This scope is also currently planned for the plants forthcoming Fall 2007 outage, and is reflected in the attached proposed TS page markups.

In addition, TMI Unit 1 has committed to a stringent repair criterion for these examinations (i.e., plug on detection) that was approved by the NRC staff in Reference 6. The original sleeve qualification work demonstrated that a 40% through-wall (TW) sleeve defect could be tolerated and justified a sleeve plugging criteria of 40% TW. Therefore, the TMI Unit 1 sleeve plugging criterion is more stringent than the original qualification/analysis.

Examinations are not performed on the parent tubing behind the TMI Unit 1 upper sleeve roll expansions, which is known to be degraded and was the reason for kinetic expansion tube repairs and the additional qualification work described above. The probability of further parent tube degradation at this location is small for the reasons described above (e.g., corrosion-resistant sleeve material covers the parent tubing, compressive loads, etc.)

The condition of the TMI Unit 1 parent tubing behind the upper sleeve roll expansions is analogous to the condition of parent tubing behind the thousands of Alloy 690 rolled tube plugs in the industry. Rolled plug-to-tubesheet joints have been successfully utilized in these installations without subsequent inspection of the parent tubing behind the plugs; further structural or leakage-significant degradation of the parent tubing is not anticipated, and this area is not typically inspected and is often known to be degraded prior to plug installation.

5928-06-20559 Page 5 of 7 Proiected Sleeve Leakaae The projected leakage from the TMI Unit 1 sleeves during a hypothetical Main Steam Line Break is low. Based on its review of the qualification report, the NRC staff (in Reference 3) found that the sleeve-to-tube joints had acceptable leak tightness. The qualification report (Reference 3, Page 6-23) gives the tested leakage as: The combined leak rate during the maximum accident load, from 2500 installed sleeves into tubes with through wall defects, would be 2.34 gaVhr.. . Given that TMI Unit 1 has 252 in-service sleeves in its most-sleeved steam generator, this equates to approximately a tenth (i.e. 252/2500) of that value. Therefore, the projected leakage from the TMI Unit 1 installed sleeves is bounded by the leakage addressed in BAW-2120P.

Since their installation in 1991 and 1993, TMI Unit 1 sleeve leakage has been monitored during the plants operation by the plants primary-to-secondary leak monitoring program, including radiation monitors and periodic sampling of the primary and secondary systems.

Primary-to-secondary leakage from the plants steam generators has been very low during recent plant operating cycles (typically less than 1 or 2 gallons per day.) Sleeve leakage has not been encountered at TMI Unit 1 since their 1991 and 1993 installations.

Summarv Given the above, the TMI Unit 1 sleeves were installed consistent with the appropriate requirements and criteria contained in the NRC approved Topical Report BAW-2120P. The subject sleeves, to date, have effectively prevented tube leaks at TMI Unit 1 and at other OTSG plants. Therefore, the proposed TMI Unit 1 Technical Specification (TS) changes incorporating TSTF-449 requirements have included the existing installed sleeves and their associated inspection and repair criteria, described above. Since no new sleeve installations are planned at TMI Unit 1 without NRC prior site specific approval, the proposed TS changes reflect the presence of the existing sleeve population and do not cover the installation of new sleeves.

References

1. BAW-2120P, Revision 0, OTSG 8 0 Mechanical Sleeve Qualification (Alloy 690), B&W Nuclear Services Company, January 1991.

2. B&W Nuclear Technologies Letter, J.H. Taylor to U.S.N.R.C., BWNS Topical Report BAW-212OP, March 26, 1991.

3. U.S.N.R.C. Letter to B&W Nuclear Services Company, J. E. Richardson to J.H. Taylor, Acceptance for Referencing of Topical Report BAW-2120P, Rev. 0, OTSG 80 Inch Mechanical Sleeve Qualification (Alloy 690), August 1, 1991.

4. GPU Nuclear Letter C311-92-2130, T. G. Broughton to U.S.N.R.C., Refueling Interval 9R Once Through Steam Generator (OTSG) Tube Inspection Report, October 4, 1992.

5. GPU Nuclear Letter C311-94-2127, T.G. Broughton to U.S.N.R.C., Refueling Interval 10R Once Through Steam Generator (OTSG) Tube Inspection Report, October 4, 1994.

5928-06-20559 Page 6 of 7

6. U.S.N.R.C. Letter to AmerGen Energy Company, P.S.Tam to C. M. Crane, Three Mile Island Nuclear Station, Unit 1 - Steam Generator Tube Kinetic Expansion and Repair Criteria (TAC No. MC7001), November 8, 2005.

NRC Request For Additional Information Letter dated Auqust 14,2006:

9. NRC Question On Page 4-78, the proposed Limiting Condition of Operation (LCO) for TS Section 3.1.1.2.b, third paragraph states that ...a SG tube is defined as the entire length of the tube, including the tube wall and any repairs made to it,... Please discuss your plans to modify the proposed LCO to remove and any repairs made to it given that TMI-1 does not have approved SG tube repair methods.

TMI Unit 1 installed tube sleeves in the past as a repair method and these sleeves remain in service. Therefore, the phrase and any repairs made to it should be retained in the definition of a SG tube. It is noted (in the response to Question 1, above) that any future installation of sleeve repairs would require site specific NRC approval.

14. NRC Question Given that TMI-1 does not have approved SG tube repair methods, discuss your plans to remove TS Section 6.9.6.i. In addition, for the same reason, discuss your plans to modify TS Section 6.19 by deleting Section 6.19.f.

Response

The previously proposed TS Section 6.9.6.i is consistent with the TSTF-449, Revision 1, and contains the qualifying phrase, if any to accommodate plants that may not have approved SG tube repair methods. As described in the response to Question 1, above, TMI Unit 1 installed tube sleeves in the past as a repair method and these sleeves remain in service. Accordingly, the proposed TS Section 6.19.f has been modified to clarify that 80-inch sleeves installed in 1991 and 1993 may remain in service, and that future installation of new sleeves or other new repair methods requires site specific NRC approval prior to installation. The revised TS page markup is provided in Enclosure 2.

5928-06-20559 Page 7 of 7

16. NRC Question In addition, discuss your plans to remove reference to and tube repairs in proposed TS Section 6.9.6.h.

(Refer to the response to Question 1, above.) The phrase and tube repairs was retained in proposed TS Section 6.9.6.h since TMI Unit 1 has approximately 500 sleeves in service and these sleeves influence the effective plugging percentage reported under that TS section.

17. NRC Question The NRC staff is aware that sleeves were installed in the TMI-1 SGs to stiffen the tubes and not as a SG tube repair method. Please confirm that the tube repair criteria (240-percent through-wall) is being applied to the parent tube behind the sleeves including the sleeve-to-tubejoint. If the repair criteria is not being implemented for the required length of defect free joint, discuss your plans for submitting the sleeving method for approval as a repair technique.

ResDonse The current TMI Unit 1 TS Section 4.19.4(b) refers to sleeving as a repair method. TMI Unit 1 sleeves were installed in 1991 and 1993 and remain in service. The 40% through-wall criterion is not applied to the parent tube at the sleeve-to-tube joint in the upper tubesheet. TMI Unit 1 ECR # 02-01121, Inspection Acceptance Criteria and Leakage Assessment Methodology for TMI OTSG Kinetic Expansion Examinations, Revision 2, Section 2.7, approved by the NRC in an SER dated November 8,2005, describes the installed sleeves, the scope of associated examinations for sleeved tubes, and the repair criterion used to disposition degradation detected in sleeved tubes. (Refer also to the response to Question 1, above.)

ENCLOSURE 2 TMI Unit 1 Technical Specification Change Request No. 331 Revised Markup of Proposed License, Technical Specifications, and Bases Page Changes Revised License Paues 6

7 Revised Technical Specifications & Bases Paues Table of Contents Page iv Table of Contents Page v Table of Contents Page vi 3-1a 3-2 3-12 3-15a 3-26~

4-2b 4-8 4-77 4-78 4-79 4-80 4-81 4-82 4-83 4-83a 4-84 4-85 6-19 6-26

(8) Repaired Steam Generators a- DELETED generator hot test program and a summary of its management r ensee shall confirm baseline primary-to-secondary I shed during the steam generator hot test program.

sted. If any increased leakage above due to defects in shall be re-established, pr the leakage limit of (O-S%, 5%-50°/6, 50 with the program described in Topical Report 008, program and a summary ent review, prior to ascension from each power range and p 4, The licensee shall condu nt examinations, consistent with the extended inservice ins either 90 calendar d power, or 120 calendar days after power, the licensee shall 09'0,such assessment to wn before the end of the refueling c he NRC staff will ation, consistent with the other provisions of t fore an additional 30 days of operation at power above 5 exceeds the baseline leakage rate by more than 0.1 gpm during the r Amendment No. +f33+i3 Amendment No*,

verse corrosion test resu (9) -

Lona Ranae Plannina Proaram Deleted Sale and License Transfer Conditions (10) Deleted (11) Deleted (12) Deleted (13) Deleted Amendment No. W, M, pfe, W ,itif9,-

I 1

TABLE OF CONTENTS Section Paae 4.8 DELETED 4-51 4.9 DECAY HEAT REMOVAL (DHRI CAPABILITY - PERIODIC TESTING 4-52 4.9.1 REACTOR COOLANT SYSTEM

- (RCS) TEMPERATURE GREATER

~

THAN 250 DEGREES F 4-52 4.9.2 RCS TEMPERATURE LESS THAN OR EQUAL TO 250 DEGREES F 4-52a 4.10 REACTIVITY ANOMALIES 4-53 4.1 1 REACTOR COOLANT SYSTEM VENTS 4-54 4.1 2 AIR TREATMENT SYSTEMS 4-55 4.12.1 EMERGENCY CONTROL ROOM AIR TREATMENT SYSTEM 4-55 4.1 2.2 REACTOR BUILDING PURGE AIR TREATMENT SYSTEM (DELETED) 4-55b 4.12.3 AUXILIARY AND FUEL HANDLING BUILDING AIR TREATMENT 4-55d 4.12.4 4.13 SYSTEM (DELETED)

FUEL HANDLING BUILDING ESF AIR TREATMENT SYSTEM RADIOACTIVE MATERIALS SOURCES SURVEILLANCE 4-55f 4-56 1

4.14 DELETED 4-56 4.15 MAIN STEAM SYSTEM INSERVICE INSPECTION 4-58 4.16 REACTOR INTERNALS VENT VALVES SURVEILLANCE 4-59 4.1 7 SHOCK SUPPRESSORS SNUBBERS) 4-60 4.18 FIRE PROTECTION SYSTEMS (DELETED) 4-72 4.,19 I .$:$4: i 4- r?-

4.20 REACTOR BUILDING AIR TEMPERATURE 4-86 4.21 RADIOACTIVE EFFLUENT INSTRUMENTATION (DELETED) 4-87 4.21.1 RADIOACTIVELIQUID EFFLUENT INSTRUMENTATION(DELETED) 4-87 4.21.2 RADIOACTIVE GASEOUS PROCESS AND EFFLUENT MONITORING 4-87 INSTRUMENTATION(DELETED) 4.22 RADIOACTIVE EFFLUENTS (DELETED) 4-87 4.22.1 LIQUID EFFLUENTS (DELETED) 4-87 4.22.2 GASEOUS EFFLUENTS (DELETED) 4-87 4.22.3 SOLID RADIOACTIVE WASTE (DELETED) 4-87 4.22.4 TOTAL DOSE (DELETED) 4-87 4.23.1 MONITORING PROGRAM (DELETED) 4-87 4.23.2 LAND USE CENSUS (DELETED) 4-87 4.23.3 INTERLABORATORYCOMPARISONPROGRAM (DELETED) 4-87 I r iv

TABLE OF CONTENTS Section 5 DESIGN FEATURES 5-1 5.1 5-1 5.2 CONTAINMENT 5-2 5.2.1 REACTOR BUILDING 5-2 5.2.2 REACTOR BUILDING ISOLATION SYSTEM 5-3 5.3 REACTOR 5-4 5.3.1 REACTOR CORE 5-4 5.3.2 REACTOR COOLANT SYSTEM 5-4 5.4 NEW AND SPENT FUEL STORAGE FACILITIES 5-6 5.4.1 NEW FUEL STORAGE 5-6 5.4.2 SPENT FUEL STORAGE 5-6 5.5 AIR INTAKE TUNNEL FIRE PROTECTION SYSTEMS 5-8 6 ADMINISTRATIVE CONTROLS 6-1 6.1 RESPONSIBtLlTY 6-1 6.2 ORGANIZATION 6-1 6.2.1 CORPORATE 6-1 6.2.2 UNIT STAFF 6-1 6.3 UNIT STAFF QUALIFICATIONS 6-3 6.4 TRAINING 6-3 6.5 REVIEW AND AUDIT 6-3 6.5.1 TECHNICAL REVlNV AND CONTROL 6-4 6.5.2 INDEPENDENT SAFETY REVIEW 6-5 6.5.3 AUDITS 6-7 8.5.4 DELETED 6-8 6.6 REPORTABLE EVENT ACTION 6-10 6.7 SAFETY LIMIT VIOLATION 6-10 6.8 PROCEDURES AND PROGRAMS 6-11 6.9 REPORTING REQUIREMENTS 6-12 6.9.1 ROUTINE REPORTS 6-12 6.9.2 DELETED 6-14 6.9.3 ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT 6-17 6.9.4 ANNUAL RADIOACTIVE EFFLUENT RELEASE REPORT 6-18 CORE OPERATING LIMITS REPORT 6-19 RECORD RETENTION 6-20 RADIATION PROTECTIONPROGRAM 6-22 6.12 HIGH RADIATION AREA 6-22 6.13 PROCESS CONTROL PROGRAM 6-23 6.14 OFFSITE DOSE CALCULATION MANUAL (ODCMl 6-24 6.15 DELETED 6-24 6.16 DELETED 6-24 6.17 MAJOR CHANGES TO RADIOACTIVE WASTE TREATMENT SYSTEMS 6-25 L SPECIFICATION(TSI BASES CONTROL PROGRAM 6-25 I c

-v-

m B LE 1.2 Frcqucncy Notation 2.3- 1 Rcilctor Protection System Trip Sctting Limits 3.1.6.1 Prcssurc Isolation Check Valves Bctwccn the 3- I Sil Primitry Coolant Systcni iind LPIS 3.5- 1 Instruments Operating Cotiditions 3-29 3.5-1 A DELETED 3.5-2 Accidcnt Monitoring Instruniciits 3-4oc 3.5-3 Post Accidcnt Monitoring Instruiiictitatioti 3-4Otl 3.s-4 Rcmo te Sliii t dow n System I nst nr m et i t it t ion ;in tl Control 3.21-1 3-4Oi I

DELETED 3.21-2 DELETED 3.23- 1 DELETED 3.23-2 DELETED 4.1-1 lnstnimcnt Suncillancc Requircrnents 4-3 4.1-2 Rlinirnuni E quipmcn t Test Frcqtre tic? 4-8 4.1-3 Mininiurn Sampling Freyuenc?. 4-9 4.1-4 Past Ace i tlcn t Mo riit ori n): In st ru nient a t ion 4-1 O i l 4.19-1 44t-4.19-2 4.21-1 DELETED 4.21-2 DELETED 4.22-1 DELETED 4.22-2 DELETED 4.23- I DELETED

3.1 REACTOR CUCLANT SYSTEM I 3.1.1 OPD?AfIONAt COMPONENTj P c o l l c a b i l it v Aoolits t o the w e r a t i n g s t a t u s of r e a c t o r ccolant system components.

Ob iective To specify those Limiting conditions f o r operation of r e a c t o r coolant system components wnich must be met t o ensure safe reactor operations.

Soecifica t i c n 3.1.1.1 Reactor CGzlant Pmos

a. Pump combinations permissible f o r given power l e v e l s shall be a s shown i n S n e c i f i c a t i o n Table 2.3.1.

b. Power CDeratfon with one i d l e reactor coolant pump i n each lcop s h a l l b e restricred t o 2b nours. If the c reactor is not r e t u n e d t o an acceptable RC pmp operating combination a t the end of the 24-hour pericc, the r e a c t o r s h a l l be i n a hot shutcown condition witain the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

c. The boron concsntration in the r e a c t c r c c a l a n t , s y s t m snail not be reauced u n k s s a t l s a s t one L'eaCtJr ccolant Pump or one Cecay heat removal ~ c m pi s c i r c u l a t i n g 3.1.1.3 Prsssurizer Safety Valves

a. The r e a c t o r shall not remain c r i t i c a l u n l s s s both p r e s s u r i z e r code s a f e t y valves are operable with a l i 7 t s e t t i n g of 2500 p s i g U. -

b. When :he r e a c t o r is s u b c r i t i c a l , a t l e a s t one pr2ssurizcr code ssfety valve m a l l be eperaole i f a l l r e a c t o r coolant system openings are closed, exce9t for hydrostatic tests i n accumancs w i t h ASME Soil2r anc Pressure Vessel Ccce, Sectlcn 111.

3-la I Amendpent No* 12. 17, ZB, P7, # , - -

INSERT TO TS PAGE 3-1a (REVISED TS 3.1.1.2)

a. Whenever the reactor coolant average temperature is above 200"F, the following conditions are required:

(1.) SG tube integrity shall be maintained.

(2.) All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program. (The Steam Generator Program is described in Section 6.1 9.)

ACTIONS:

NOTE-----------------------------------------------------------

Entry into Sections 3.1.1.2.a.(3.) and (4.), below, is allowed for each SG tube. If the requirements of Sections 3.1.1.2.a.(1.) or 3.1.1.2.a.(2.) were not met for one or more tubes then perform the following.

(3.) With one or more SG tubes satisfying the tube repair criteria and not plugged in accordance with the Steam Generator Program:

a. Verify within 7 days that tube integrity of the affected tube@) is maintained until the next refueling outage or SG tube inspection,

b. Plug the affected tube@) in accordance with the Steam Generator Program prior to exceeding a reactor coolant average temperature of 200°F following the next refueling outage or SG tube inspection.

(4.) If Action 3., above, is not completed within the specified completion times, or SG tube integrity is not maintained, be in HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and be in COLD SHUTDOWN within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The limitation on po\ver operation ivith one idle RC pump in each loop has been imposed since the ECCS cooling performance has not been calculated in accordance with the Final Acceptance Criteria requirements specifically for this mode of reactor operation. A time period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is alloLved for operation with one idle RC pump in each loop to-effect repairs of the idle pump(s) and to return the reactor to an acceptable combination of operating RC pumps. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for this mode of operation is acceptable since this mode is espected to have considerable margin for the peak cladding temperature limit and since the likelihood of a LOCA within the 24-hour period is considered very remote.

A reactor coolant pump or decay heat removal pump is required to be in opsration before the boron concentration is reduced by dilution with makeup water. Either pump nd1 provide mising \vhich ivill prevent sudden positive reactivity changes caused by dilute coolant reaching the reactor. One decay heat removal pump will circulate the equivalent of the reactor coolant system volume in one-half hour or less.

The decay heat removal system suction piping is designed for 300°F and 370 psig; thus, the s)stem can remove decay heat when the reactor coolant system is below this temperature (References I , 2, and 3).

Both steam generators must of the Reactor Coolant S5,stet-nto insure system integrity against leakage under normal and transient conditions. Only one steam generator is required for decay heat removal purposes. ~

One pressurizer code safety valve is capable of preventing overpressurization when the reactor is not critical since its relieving capacity is greater than that required by the sum of the available heat sources which are pump energy, pressurizer heaters, and reactor decay heat. Both pressurizer code safety valves are required to be in service prior to criticality to conform to the system design relief capabilities. The code safety valves prevent.overpressure for a rod withdrawal or feedwater line break accidents (Reference 4). The pressurizer code safety valve lift set point shall be set a t 2500 psig t l % allowance for error. Surveillance requirements are specified in the Insenice Testing Program. Pressurizer code safety valve setpoint drift of up to 3% is acceptable in accordance with ASME Section XI (Re References (1) U F S a Tables 9.5 (2) U F S a Sections 4.2.5.1 and 9.5 - Decay Heat Removal (3) UFSAR, Section 4.2.5.4 - Secondary System (4) UFSAR. Section 4.3.10.4 - System Minimum Operational Components (5) U FSm Section 4.3.7 - Overpressure Protection 3-2 Amendment No. 47 (12/22/78),W 222 1

3.1.6 LEAKAGE Applicability Applies to reactor coolant leakage from the reactor coolant system and the makeup and purification system.

0biective To assure that any reactor coolant leakage does not compromise the safe operation of the facility.

Specification 3.1.6.1 If the total reactor coolant leakage rate exceeds 10 gpm, the reactor shall be placed in hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection.

3.1.6.2 If unidentified reactor coolant leakage (excluding normal evaporative losses) exceeds 3.1.6.3 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />,eM&s+km A

3.1.6.4 boundary (such as the reactor vessel, piping, valve body, etc., except the steam generator tubes), the reactor shall be shutdown, and a cooldown to the cold I shutdown condition shall be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection.

3.1.6.5 If reactor shutdown is required by Specification 3.1.6.1 , 3.1.6.2, 3.1.6.3, or 3.1.6.4, the rate of shutdown and the conditions of shutdown shall be determined by the safety evaluation for each case.

3.1.6.6 Action to evaluate the safety implication of reactor coolant leakage shall be initiated within four hours of detection. The nature, as well as the magnitude, of the leak shall be considered in this evaluation. The safety evaluation shall assure that the exposure of offsite personnel to radiation is within the dose rate limits of the ODCM. I 3.1.6.7 If reactor shutdown is required per Specification 3.1.6.1 , 3.1.6.2, 3.1.6.3 or 3.1.6.4, the reactor shall not be restarted until the leak is repaired or until the problem is otherwise corrected.

3.1.6.8 When the reactor is critical and above 2 percent power, two reactor coolant leak detection systems of different operating principles shall be in operation for the Reactor Building with one of the two systems sensitive to radioactivity. The systems sensitive to radioactivity may be out-of-service for no more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided a sample is taken of the Reactor Building atmosphere every eight hours and analyzed for radioactivity and two other means are available to detect leakage.

3-12 Amendment No. 47, MIW I T (12-22-78)

Bases (Continued)

The is established as a quantity which can be accurately early detection of leakage. Leakage of this magnitude can be reasonably detected within a matter of hours, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

Total reactor coolant leakage is limited by this specification to 10 gpm. This limitation provides

a. The auxiliary and fuel handling building vent radioactive gas monitor is sensitive to very low activity levels and would show an increase in activity level shortly after a reactor coolant leak developed within the auxiliary building. \

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b. Water inventories around the auxiliary building sump.

I c.

d.

Periodic equipment inspections, In the event of gross leakage, in excess of 13 gpm, the individual cubicle leak I detectors in the makeup and decay heat pump cubicles, will alarm in the control room to backup "a", "b", and "c" above.

When the source and location of leakage has been identified, the situation can be evaluated to determine ifoperation can safely continue. This evaluation will be performed by TMI-1 Plant Operations.

3-15a Amendment No. 4-44, *I,

INSERT TO TS PAGE 3-15a (BASES FOR SECTION 3.1.61 Except for primary to secondary leakage, the safety analyses do not address operational leakage. However, other operational leakage is related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary leakage from all steam generators (SGs) is one gallon per minute or is assumed to increase to the leakage rates described in TS 6.19.c.2 as a result of accident-induced conditions.

The TS requirement to limit primary to secondary leakage through both SGs to less than or equal to 144 gallons per day is significantly less than the conditions assumed in the safety analysis.

The limit of 144 gallons per day total for both SGs bounds the TSTF-449, Rev. 4 limit of 150 gallons per day per SG, which is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 1). The Steam Generator Program operational leakage performance criterion in NEI 97-06 states, The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day. The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

1 of 1

3.4 DECAY HEAT REMOVAL (DHR) CAPABILITY (Continued)

Bases (Continued)

If EFW were required during surveillance testing, minor operator action (e.g., opening a local isolation valve or manipulating a control switch from the control room) may be needed to restore operability of the required pumps or flowpaths. An exception to permit more than one ERN Pump or both E R N flowpaths to a single OTSG to be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> during surveillance testing requires 1) at least one motor-driven EFW Pump operable, and 2) an individual involved in the task of testing the E R N System must be in communication with the control room and stationed in the immediate vicinity of the affected ERN flowpath valves. Thus the individual is permitted to be involved in the test activities by taking test data and his movement is restricted to the area of the EFW Pump and valve rooms where the testing is being conducted.

The allowed action times are reasonable, based on operating experience, to reach the required plant operating conditions from full power in an orderly manner and without challenging plant systems. Without at least two ERN Pumps and one EFW flowpath to each OTSG operable, the required action is to immediately restore EFW components to operable status, and all actions requiring shutdown or changes in Reactor Operating Condition are suspended. With less than two ERN pumps or no flowpath to either OTSG operable, the unit is in a seriously degraded condition with no safety related means for conducting a cooldown. In such a condition, the unit should not be perturbed by any action, including a power change, which might result in a trip.

The seriousness of this condition requires that action be started immediately to restore E M I components to operable status. TS 3.0.1 is not applicable, as it could force the unit into a less safe condition.

The ERN system actuates on: 1) loss of all four Reactor Coolant Pumps, 2) loss of both Main Feedwater Pumps, 3) low OTSG water level, or 4) high Reactor Building pressure. A single active failure in the HSPS will neither inadvertently initiate the EFW system nor isolate the Main Feedwater system. OTSG water level is controlled automatically by the HSPS system or can be controlled manually, if necessary.

The MSSVs will be able to relieve to atmosphere the total steam flow if necessary. Below 5%

power, only a minimum number of MSSVs need to be operable as stated in Specifications 3.4.1.2.1 and 3.4.1.2.2. This is to provide OTSG overpressure protection during hot functional testing and low power physics testing. Additionally, when the Reactor is between hot shutdown and 5% full power operation, the overpower trip setpoint in the RPS shall be set to less than 5%

as is specified in Specification 3.4.1.2.2. The minimum number of MSSVs required to be operable allows margin for testing without jeopardizing plant safety. Plant specific analysis shows that one MSSV is sufficient to relieve reactor coolant pump heat and stored energy when the reactor has been subcritical by 1% delta K/K for at least one hour. Other plant analyses show that two (2) MSSVs on either OTSG are more than sufficient to relieve reactor coolant pump heat and stored energy when the reactor is below 5% full power operation but had been subcritical by 1% delta K/K for at least one hour subsequent to power operation above 5% full MSSVs are inoperable, the power level must be reduced, as stated in Specification 3.4.1.2.3 such that the remaining MSSVs can prevent overpressure on a turbine trip.

3-26~

Amendment No. W , !25, ! S W , 229

Bases Cont'd)

The equipment testing and system sampling frequencies specified in Tables 4.1-2, 4.1-3, and 4.1-5 are considered adequate to maintain the equipment and systems in a safe operational status.

1, I -

I 4-2b Amendment No. 484+245,*,

The primary to secondary leakage surveillance in TS Table 4.1-2, Item 12, verifies that primary to secondary leakage is less than or equal to 144 gallons per day total through both SGs. Satisfying the primary to secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If this surveillance is not met, compliance with TS 3.1.I .2,Steam Generator (SG) Tube Integrity, and TS 3.1.6.3, should be evaluated. The 144 gallons per day limit is measured at room temperature. The operational leakage rate limit applies to leakage through both SGs.

The TS Table 4.1-2primary to secondary leakage surveillance is modified by a Note, which states that the initial surveillance is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state POWER OPERATION. For RCS primary to secondary leakage determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The TS Table 4.1-2primary to secondary leakage surveillance frequency of Daily is a reasonable interval to trend primary to secondary leakage and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary leakage is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRl guidelines (Ref. 5).

I of 1

TABLE 4.1-2 MINIMUM EQUIPMENT TEST FREQUENCY Item Frequency

1. Control Rods Rod drop times of all Each Refueling shutdown full length rods

2. Control Rod Movement of each rod Every 92 days, when Movement reactor is critical

3. Pressurizer Setpoint In accordance with the Safety Valves Insetvice Testing Program

4. Main Steam Setpoint In accordance with the Safety Valves lnsewice Testing Program

5. Refueling System Functional Start of each Interlocks refueling period

6. (Deleted) -- --

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7. Reactor Coolant Evaluate Daily, when reactor System Leakage coolant system temperature is greater than 525 degrees F

8. (Deleted) -- --

9. Spent Fuel Functional Each refueling period Cooling System prior to fuel handling

10. Intake Pump (a) Silt Accumulati,.i - Not to exceed 24 monl 1s House Floor Visual inspection (Elevation of Intake Pump 262 ft. 6 in.) House Floor (b) Silt Accumulation Quarterly Measurement of Pump House Flow

11. Pressurizer Block Functional* Quarterly Valve (RC-V2)

• Function shall be demonstrated by operating the valve through one complete cycle of Amendment No. 6,643,a, W,~,4-@ W,-e46.

8, J

licabFu Technical Sppcffication applies to the inservice lerrprctiou o portion of the reactor coolant pteraure bouadary. J 4

Ob cctiv ineervice inspection program integrity o f the tube Once-while a t the same the performance of SpecificatIan by performance a, Each nteam generator aha determined OPERABLE during .

shutdown by selecting an ccting a t least the minhum nondestnrc t i v e tartla8 or other equivalent tec pment a N l be ll detect defect6 4-77 h e n b e n t ,+.ON (12-22-78)

erators; the tubes sele a random basis except eservice inspection) of each steam generator shall include:

east 50% of the tubes inspected shall be in those areas where

e. If any selected tube does not per a tube inspection, this shall be reco and subjected to a tube inspection.

oups may be exclude the first random sample if adjacent to the open inspection lane, and tubes bet and from 86-1 to 77-1 (2) Group A-2: Tubes havi led opening in the 15th support plate.

b.

each inservice inspection may b those areas of the t c.

each sample inspection shall be classified into one of the following three Category Inspection Results Less than 5% of the total tubes inspected in a steam generator are degraded tubes and none of the inspected tubes are defective, 4-78 Amendment No. 47+3,251-,

( 12-22-78)

\ 19.2 Specification (Continued)

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spanned by a sleeve must exhibit significant in e diameter IGA indications or > 10% h ections are performe uant to 4.19.2.a.4,defective or steam generator in 4.19 3 InsDection Frequencies The required insewice inspections o fiequencies:

a The first (baseline) insp ctive full power months but within 24 calendar months of in1 calendar months all interval for that the inservice inspection of a steam generator conduc i \

p 40 months.

4-79 Amendment No.47+3+% 9-t

Additional. unscheduled insenice inspections shall be performed on each steam gen accordance vith the first sample inspection specified in Table J 19-2 dunng the shut subsequent to any of the following conditions:

A seismic occurrence greater than the Operating Basis Earthquake.

\

A loss of coolant accident requiring actuation of

3. A major main steam line or feedwater line break.

d a y tube leakage (not including from tube-to-tube ss of the limits of Specification of the affected stear rmed in accordance ivith the

1. in Section steam generator will be of this inspection fall in the same Group

2. If the leaking tube is not n Section 4.19.3.d. 1, then an inspection will be performed on the affected am generator(s) in accordance with Table 4.19-2.

4.19.4 .4cceptance Criteria

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a. As used in this Specification:

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1. or contour of a tube Eddy current testing

2. tion means a service-induced cracking, general corrosion ns on either inside or outside of a tube.

epraded Tube means a tube containing:

(a) an inside diameter (I.D.) IGA indication with a bobbin

\

2 0.2 volt or 1 0.13 inches axial extent or 2 0.26 inches extent, or (b) imperfections 2 20%of the nominal wall thickness caused by

4.  % Deeradation means the percentage of the tube wall thickness affected or by degradation.

4-80 Amendment- .oN *,*,

5. Defect means an imperfection of such s limit. A tube containing a defect is defective.

. Repair Limit means the extent of degrada shall be repaired or removed from servic unserviceable prior to the next inspection.

limit is equal to 40% of the nomina IGA indications shall be repair axial extent of 0.25 inches, o or a through wall degradati Unserviceable d

/ of a tube if it leaks or contains a ural integrity in the event of an s of coolant accident, or a steam line or the steam generator tube from the to the top of the lower I

I tubes containing throughwail cracks) required by Table 4.1 4-8 1 Amendment No. 43;-83,3!, -ee,zes* * ,

. The complete results of the sream senerator tube i to the NRC within 90 da: s folloxving completion enerator breaker closure). The report shall include:

Number and extent of tubes inspected.

2. n and percenr of wall-thickness pe 3

3. mined). bobbin coil amplitude 1 extent for each inside

4. Identification of tubes re r removed from service.

5. m service in each steam 6.

generator,

/ of growth of inside

\ in accordance ID IGA ECR No. TM 0 1-00328, and esults of in-situ pressure testing, if performed.

f steam generator tube inspections which fall into Cate notification in accordance with 10 CFR 50.72 prior to resumpti operation. The written follow-up of this report shall provide a description of investigations conducted 10 determine the cause of the tube degradation and corrective measures taken to urevent recurrence in accordance with 10 CFR 50.73.

4-82 Amendment No. I ,aJfaJ%*4

irements for inspection of tine steam generator tubes ensure that tho is portion of the RCS will be maintained.

ce inspection of s t e m generator tubes is based on Revision 1. In-service inspection of steam gener llance of the conditions of the tubes in the event rogressive decgradation due to design, manufact pection of steam generator tubing also provide and cause of any tube degradation so that corr taken.

/

d secondary coolant will ry limits found to result generator tubes. If the pri chemistry limits, localized corr ould be limited by the secondary The extent of cracking during plant operatio e limited by the limitation of total steam generator tube leakage between the prim stem and the secondary coolant system (primary-to-secondary leakage = 1 gpm). cess of this limit will require plant shutdown and an unscheduled inspection, repaired or removed from service.

secondary coolant. However, ev continue to be assigned

. initiated intergranular degradation may remain in service without %

Main Steam Line Break (MSLB) accident will be evaluated by determining that this ed degradation mechanism is inactive (e.g. comparison of the outage examination 4-83 Amendment NO.^?, 129, 2egizes,*,

e results from past outages meets the requirements of-AmerGen En '

0 1-00328) and by successhi in-situ pressure testing of Where experience in similar p Bulletins/Notices. indicate criti to NRC review and approval.

spection, and revision of the Technical Specific r 20% through-wall holes of an ASME calibration standard to 4 volts.

4-83a Amendment No. 47, 1 - w -T

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r. may be l i m i t e d t o ssinc 6%of the tubes in steam generator t and subsequent m i n g in i like circF ancet, t h e opereting conditions I n me s t e m 8enaetar&be more #evere than those In t h e other steam generator. Under su found circumstlnccr the sample sequence s h a l l be modif5ed to inspect t h e most

/ severe confitions.

\ TABLE 4.19-2 STEAM GENERATION TUBE IN SPEC TI^^)

/

LE INSPECTION ZWD SAMPLE INSPECTION I Perform action I C-3 I f o r C-3 result I I of f i r s t sarple. 1 I i n other S.G.

I Provide n o t i f i -

I cation t o NRC Notes: (1) S = Uhere N i s the number o f steam generators i n the unit, and n i mber of steam generators inspected duri ng an inapection.

INSERT TO TS PAGE 4-77 (REVISED TS 4.19) 4.19 STEAM GENERATOR (SG) TUBE INTEGRITY Armlicabilitv: Whenever the reactor coolant average temperature is above 200°F Surveillance Reauirements (SR):

Each steam generator shall be determined to be OPERABLE by performance of the following:

4.19.1 Verify SG tube integrity in accordance with the Steam Generator Program.

4.19.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged in accordance with the Steam Generator Program prior to exceeding an average reactor coolant temperature of 200°F following an SG tube inspection.

BASES:

BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary systems pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG.

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 6.1 9, Steam Generator (SG) Program, requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.19, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and 4-77 1 nf7

BASES BACKGROUND (continued) operational leakage. The SG performance criteria are described in Specification 6.19. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a bounding primary to secondary leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i-e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary leakage from all SGs of 1 gallon per minute or is assumed to increase to the leakage rates described in TS 6.19.c.2 as a result of accident-induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is conservatively assumed to be equal to, or greater than, the TS 3.1.4, Reactor Coolant System Activity, limits.

For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref.

2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(~)(2)(ii).

LCO TS 3.1.1.2.a The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

During a SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

4-78 2 of 7

BASES LCO (continued)

A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 6.19, Steam Generator Program, and describe acceptable SG tube performance.

The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational leakage. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation. Tube collapse is defined as, For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero. The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term significant is defined as An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting bursthollapse condition to be established. For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section Ill, Service Level A (normal operating conditions) and Service Level 6 (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code, Section Ill, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary leakage caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG, except for specific types of degradation at specific locations 4-79 2 nf 7

BASES LCO (continued) where the NRC has approved greater accident induced leakage. (Refer to TS 6.19.c for specific types of degradation and approved repair criteria.)

The accident induced leakage rate includes any primary to secondary leakage existing prior to the accident in addition to primary to secondary leakage induced during the accident.

The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational leakage is contained in TS 3.1.6.3, LEAKAGE, and limits primary to secondary leakage through the SGs to 144 gallons per day.

This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced when the reactor coolant system average temperature is above 200°F.

RCS conditions are far less challenging when average temperature is at or below 200°F; primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for leakage.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

3.1.1.2.a.(3.)a. and 3.1.1.2.a.(3.)b.

3.1.1.2.a.(3.) applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by Surveillance Requirement 4.19.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, 3.1.1.2.a.(4.) applies.

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BASES ACTIONS (continued)

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action 3.1.1 .2.am(3.)b. allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to exceeding a reactor coolant average temperature of 200°F following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

If the Required Actions and associated Completion Times of Condition 3.1.1.2.a.(3.) are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT SHUTDOWN within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and COLD SHUTDOWN within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

The allowed Completion Times are reasonable, based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENT SR 4.19.1:

During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. l ) , and its referenced EPRl Guidelines, establish the content of the Steam Generator Program. Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the as found condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also 4-81 5 of 7

BASES

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SURVEILLANCE REQUIREMENTS (continued) specifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the frequency of SR 4.19.1. The frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 6.1 9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SURVEILLANCE REQUIREMENT SR 4.19.2:

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging.

The tube repair criteria delineated in Specification 6.19 are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s). Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

Tubes with inside diameter (ID) initiated intergranular degradation may remain in service without percent throughwall sizing if the degradation has been characterized as not crack-like by diagnostic eddy current inspection and if the degradation is of limited circumferential and axial length to ensure tube structural integrity. Additionally, serviceability for accident leakage under the limiting postulated Main Steam Line Break (MSLB) accident will be evaluated by determining that this ID initiated degradation mechanism is inactive (e.g., comparison of the outage examination results with the results from past outages meets the requirements of AmerGen Engineering Report ECR No. TM 01-00328) and by successful in-situ pressure testing of a sample of these degraded tubes to evaluate their accident leakage potential when in-situ pressure tests are performed.

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The frequency of prior to exceeding an average reactor coolant temperature of 200°F following an SG tube inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

REFERENCES

1. NEI 97-06, Steam Generator Program Guidelines.

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code, Section Ill, Subsection NB.

5. Draft Regulatory Guide 1.121, Basis for Plugging Degraded Steam Generator Tubes, August 1976.

6. EPRI, Pressurized Water Reactor Steam Generator Examination Guidelines.

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6.9.5 CORE OPERATING LIMITS REPORT

\

i 6.9.5.1 The core operating limits addressed by the individual Technical Specifications shall be established and documented in the CORE OPERATING LIMITS REPORT prior to each reload cycle or prior to any remaining part of a reload cycle.

6.9.5.2 The analytical methods used to determine the core operating limits addressed by the individual Technical Specifications shall be those previously reviewed and approved by the NRC for use at TMI-1, specifically:

(1) BAW-10179 P-A, Safety and Methodologyfor Acceptable Cycle Reload Analyses. The current revision level shaU be specified in the COLR.

(2) TR-078-A, YMI-1 Transient Analyses Using the RETRAN Computer Code, Revision 0. NRC SER dated 2/10/97.

(3) TR-087-A, YMI-1 Core Thermal-Hydraulic Methodology Using the VIPRE-01 Computer Code, Revision 0. NRC SER dated 12/19/96.

(4) TR-091-A, Steady State Reactor Physics Methodology for TMI-I, Revision 0. NRC SER dated 2/21/96.

(5) TR-092P-A, YMI- 1 Reload Design and Setpoint Methodology, Revision 0. NRC SER dated 4/22/97.

(6) BAW-10227P-A, Evaluation of Advanced Cladding and Structural Material (M5) in PWR Reactor Fuel, NRC SER dated February 4,2000. I 6.9.5.3 The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as shutdown margin, and transienVaccident analysis limits) of the safety analysis are met.

6.9.5.4 The CORE OPERATING LIMITS REPORT, including any mid-cycle revisions or supplements thereto, shall be provided uponJssuance for each reload cycle to the NRC Document Control Desk with copies to the Regional Administrator and Resident Inspector.

c C I 6-19

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Amendment No.72, 77, --!

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INSERT TO TS PAGE 6-19 6.9.6 STEAM GENERATOR TUBE INSPECTION REPORT A report shall be submitted within 90 days after the average reactor coolant temperature exceeds 200°F following completion of an inspection performed in accordance with Section 6.19, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found, C. Nondestructive examination techniques utilized for each degradation mechanism,

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e. Number of tubes plugged during the inspection outage for each active degradation mechanism,

f. Total number and percentage of tubes plugged to date, g- The results of condition monitoring, including the results of tube pulls and in-situ testing,

h. The effective plugging percentage for all plugging and tube repairs in each SG,

i. Repair method utilized and the number of tubes repaired by each repair method, if any,

j. Location, bobbin coil depth estimate (if determined), bobbin coil amplitude (if determined), and axial and circumferential extent for each inside diameter (ID) IGA indication.

k. An assessment of growth of inside diameter IGA degradation in accordance with the volumetric ID IGA management program contained in AmerGen Engineering Report, ECR No. TM 01-00328.

I. The information specified for reporting in ECR No. 02-01121, Rev.2.

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b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. A change in the TS incorporated in the license or

2. A change to the updated FSAR (UFSAR) or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the UFSAR.

d. Proposed changes that meet the criteria of Specification 6.18.b.l or 6.18.b.2 above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71 (e).

6-26 Amendment No.-E&-

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INSERT TO TS PAGE 6-26 6.19 STEAM GENERATOR (SG) PROGRAM A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the as found condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The as found condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational leakage.

1. Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondarypressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondarypressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.O on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Leakaae is not to exceed 1 apm per SG, except for specific tvpes of dearadation at sDecific locations as described in paraaraph c of the Steam Generator Proaram below.

3. The operational leakage performance criterion is specified in TS 3.1.6, LEAKAGE.

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c. Provisions for SG tube repair criteria.

1. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth based criteria:

a. Volumetric Inside Diameter (ID) Inter-Granular Attack (IGA) indications may be dispositioned in accordance with ECR No. TM 01-00328. MSLB accident-induced leakage rates are limited to less than 1 gpm under the report. (ECR No. TM 01-00328 is not applicable to tube sleeves nor the parent tubing spanned by the sleeves.) ID IGA indications shall be repaired or removed from service if they exceed an axial extent of 0.25 inches, or a circumferential extent of 0.52 inches, or a through wall degradation dimension of 140% if assigned.

b. Upper tubesheet kinetic expansion indications may be dispositioned in accordance with ECR No. TM 02-01121, Rev. 2. MSLB accident-induced leakage is limited to less than 3228 gallons for the initial 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and 9960 gallons over the MSLB duration, under this report.

2. Tubes found by inservice inspection to contain a flaw in a sleeve, or in a sleeves parent tube adjacent to the sleeve between the lower sleeve end and the parent tube kinetic expansion transition, shall be plugged-on-detectionin accordance with ECR No. TM 02-01121, Rev. 2.

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, d.3, d.4, and d.5 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.

2. Inspect 100% of the tubes at sequential periods of 60 effective full power months.

The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one refueling outage (whichever is less) without being inspected.

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3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

4. Implementation of the repair criteria for ID IGA requires 100°/~bobbin coil inspection of all non-pluggedtubes in accordance with AmerGen Engineering Report, ECR No.

TM 01-00328. ID IGA indications detected by the bobbin coil probe shall be characterized using rotating coil probes, as defined in that report.

5. Implementation of the repair criteria for kinetic expansion indications requires 100%

rotating probe inspection of the required lengths of the kinetic expansions in all non-plugged, non-sleeved, tubes in accordance with AmerGen Engineering Report, ECR No. TM 02-01121, Rev.2.

6. During each scheduled refueling outage steam generator inspection, the following sleeve examinations shall be conducted:

-a minimum of 33% of the inservice sleeves unexpanded lengths shall be examined with bobbin coil probes.

- a minimum of 33% of the inservice sleeves upper tubesheet roll expansions, and 100% of the inservice sleeves lower roll expansions, shall be examined with PlusPoint probes.

e. Provisions for monitoring operational primary to secondary leakage.

f. Provisions for SG tube repair methods. Steam generator tube repair methods shall provide the means to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. For the purposes of these Specifications, tube plugging is not a repair. All acceptable tube repair methods are listed below.

TMI-1s 80 Inconel-690 rolled sleeves installed in 1991 and 1993, and without flaws exceeding the repair criteria of 6.1 9.c.2, may remain in service. Installation of new sleeves or other new repair methods requires prior NRC approval.

NOTE: Refer to Section 6.9.6 for reporting requirements for periodic SG tube inspections.

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