ML072540254

Additional Information - Technical Specification Change Request No. 331: Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity

ML072540254
Person / Time
Site:	Three Mile Island
Issue date:	09/04/2007
From:	Cowan P AmerGen Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
5928-07-20194, TAC MD1807
Download: ML072540254 (43)

Text

AmeTGen Energy Company, LLC www.exeloncorp.com AmerGenm An Exelon Company 200 Exelon Way Kennett Square, PA 19348 10 CFR 50.90 September 4, 2007 5928-07-20194 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:

Additional Information - Technical Specification Change Request No. 331:

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

References:

1) 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."

2) AmerGen Energy Company, LLC letter to NRC dated July 25, 2007 (5928 20168), "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 as discussed in a conference call with the NRC on August 27, 2007, regarding TMI Unit 1 Technical Specification Change Request No. 331, submitted to NRC for review on May 15, 2006 (Reference 1).

Proposed TMI Unit 1 Technical Specification (TS) sections 6.19.c.2 and 6.19.d are being revised to clarify the scope of the associated inspection and repair criteria. These are the only changes to the proposed TS page markups previously submitted in Reference 2.

Additionally, TMI Unit 1 commits to revise the Updated Final Safety Analysis Report (UFSAR) in the next required periodic update to identify that the technical basis for the adequacy of the original steam generator tube sleeve installation will be submitted to the NRC if the existing TMI Unit 1 steam generators are not replaced in the 1 R18 refueling outage (currently planned for Fall 2009).

U.S. Nuclear Regulatory Commission September 4, 2007 Page 2 An additional editorial change is being made to the TS page 3-12, Section 3.1.6.3 markup previously submitted to remove the duplicate wording "the reactor shall be placed" since these words are included in the markup insert and to ensure consistent wording with other TS action statements.

These changes have no impact on the conclusions of the original safety analysis or no significant hazards consideration evaluation provided in Reference 1. The revised proposed Technical Specification pages are provided in Enclosure 1. Enclosure 1 provides a complete replacement set of the proposed Technical Specification pages previously submitted in Reference 2.

Regulatory commitments established by this submittal are identified in Enclosure 2. If any additional information is needed, please contact David J. Distel at (610) 765-5517.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 4 th day of September, 2007.

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

Enclosures:

1) Revised TS Page Markups

2) List of Commitments cc: S. J. Collins, USNRC Administrator, Region I P. J. Bamford, USNRC Project Manager, TMI Unit 1 D. M. Kern, USNRC Senior Resident Inspector, TMI Unit 1 File No. 06007

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

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

CONTROLLED C-PY (8) Repaired Steam Generators In order to confirm the leak-tight integrity of the Reactor Coolant System, includin the steam generators, operation of the facility shall be in accordance with the following:

1. Prior to initial criticality, the licensee shall submit to NRC the results ofhe steam generator hot test program and a summary of its management revi

2. he licensee shall confirm baseline primary-to-secondary lea ge rate e blished during the steam generator hot test program. If eakage exceeds the seline leakage rate by more than 0.1 gpm*, the fac iy shall be shut down and le tested. If any increased leakage above base' e is due to defects in the tube e span, the leaking tube(s) shall be rem ed from service. The baseline le age shall be re-established, provide hat the leakage limit of Technical Sp ification 3.1.6.3 is not exceede

3. The licensee shall omplete its post-cntica est program at each power range (0-5%, 5%-50% 509 100%) in confo ce with the program described in Topical Report 008, Re 3, and shall ave available the results of that test program and a summary i ts man ement review, prior to ascension from each power range and prior n al power operation.

4. The licensee shall conduct dy- rrent examinations, consistent with the extended inservice inspe on plan fined in Table 3.3-1 of NUREG-1019, either 90 calendar day fer reachin ull power, or 120 calendar days after exceeding 50% pow operation, which er comes first. In the event of plant operation for an e ended period at less th 50% power, the licensee shall provide an asse ment at the end of 180 da of operation at power levels between 5%/ d 50%, such assessment to con in recommendations and supporting formation as to the necessity of a sp ial eddy-current testing (ECT) s, down before the end of the refueling cycl (The NRC staff will evalu that assessment and determine the time of th next eddy-current exa ination, consistent with the other provisions of the Ii nse conditions.) In t absence of such an assessment, a special ECT shutdo shall take place efore an additional 30 days of operation at power above 5%.

• If lea ge exceeds the baseline leakage rate by more than 0.1 gpm during the rem 'nder of the cle 8 operation, the facility shall be shutdown and leak tested. Operation at lea ge ra s of up to 0.2 gpm above the baseline leakage rate shall be acceptable during the mainder of Cycle 8 operation. After the 9R refueling outage, the leakage limit and accompanying shutdown requirements revert to 0.1 gpm above the baseline leakage rate.

Amendment No. 103,163 Amendment Na-.Znw-yý_

CONTROLLEO COPY (9) Lon Ranaqe Planning Program - Deleted Sale and License Transfer Conditions (10) Deleted (11) Deleted (12) Deleted (13) Deleted Amendment No. 1-9, 2 2+8, EN6, 249,-06 1

COnTROLLEO COPY TABLE OF CONTENTS Section Page 4.8 DELETED 4-51 4.9 DECAY HEAT REMOVAL (DHR) 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 4.11 REACTOR COOLANT SYSTEM VENTS 4-54 4.12 AIR TREATMENT SYSTEMS 4-55 4.12.1 EMERGENCY CONTROL ROOM AIR TREATMENT SYSTEM 4-55 4.12.2 REACTOR BUILDING PURGE AIR TREATMENT SYSTEM (DELETED) 4-55b 4.12.3 AUXILIARY AND FUEL HANDLING BUILDING AIR TREATMENT 4-55d SYSTEM (DELETED) 4.12.4 FUEL HANDLING BUILDING ESF AIR TREATMENT SYSTEM 4-55f I 4.13 RADIOACTIVE MATERIALS SOURCES SURVEILLANCE 4-56 4.14 DELETED 4-56 4.15 MAIN STEAM SYSTEM INSERVICE INSPECTION 4-58 4.16 REACTOR INTERNALS VENT VALVES SURVEILLANCE 4-59 4.17 SHOCK SUPPRESSORS (SNUBBERS) 4-60 4.18 FIRE PROTECTION SYSTEMS (DELETED) 4-72

!-1T *' .T";mr .r';1 i.P*.'..':._..* *.:*._ 4,?V 4.19

• 4.91l STE-AMG* GENE*RATOR OSAAAPE SLEr'Cr-TION ANDINSPECTION A -4 f% elr-*lARA f--QhlflAI-Dr* -r1-1 ir- r iA1Ir'll Ir' nr'- i,-t-rI &l ARiA l, -

4.10.3 I9.aECTIO, FREQUENSIES 4 4. 119.4 ACCEPTANCE CRITERIA 4 03 4.11.. REPORTS 4 81 4.20 REACTOR BUILDING AIR TEMPERATURE 4-86 4.21 RADIOACTIVE EFFLUENT INSTRUMENTATION (DELETED) 4-87 4.21.1 RADIOACTIVE LIQUID 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 INTERLABORATORY COMPARISON PROGRAM (DELETED) 4-87 H sThThj1 CjEA/egAToZ (56$~) ~flis~6 ~ q-7,7 I I

iv Amendment No. 11,22, , , , 55 72, 78, 06, 07, 119,12,12,

!137, 1*6, 1 7, 242, 245, 246,6-248->

CON TROL L. (^.O0Y TABLE OF CONTENTS Section Paae 5 DESIGN FEATURES 5-1 5.1 SITE 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 RESPONSIBILITY 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 REVIEW AND CONTROL 6-4 6.5.2 INDEPENDENT SAFETY REVIEW 6-5 6.5.3 AUDITS 6-7 6.5.4 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 6.9.5 CORE OPERATING LIMITS REPORT 6-19 6.10 RECORD RETENTION 6-20 6.11 RADIATION PROTECTION PROGRAM 6-22 6.12 HIGH RADIATION AREA 6-22 6.13 PROCESS CONTROL PROGRAM 6-23 6.14 OFFSITE DOSE CALCULATION MANUAL (ODCM) 6-24 6.15 DELETED 6-24 6.16 DELETED 6-24 6.17 MAJOR CHANGES TO RADIOACTIVE WASTE TREATMENT SYSTEMS 6-25 6.18 TECHNICAL SPECIFICATION (T) BASES CONTROL PROGRAM 6-25 Amendment No. 11, 47, 72, 77, 129, 150, 173, 2 1 62

, 2 ,--S 71a&- lovsf"cno-J1e7rW I,

CCU4 [OLLE-D CCPY LIST OF TABLES TABLE TITLE PAG, E 1.2 Frequency Notation I-8 2.3-1 Reactor Protection System Trip Setting Limits 2-9 3.1.6.1 Pressure Isolation Check Valves Between the 3-15.1 Primary Coolant System and LPIS 3.5-I Instruments Operating Conditions 3-29 3.5-1A DELETED 3.5-2 Accident Monitoring Instruments 3-40c 3.5-3 Post Accident Monitoring Instinmentation 3-40dl 3.5-4 Remote Shutdown System Instrumentation and Control 3-411i 3.21-I DELETED 3.21-2 DELETED 3.23-I DELETED 3.23-2 DELETED 4.1-1 Instrument Surveillance Requirements 4-3

4. 1-2 Minimum Equipment Test Frequency 4-8 4.1-3 Minimum Sampling Frequency 4-9 4.1-4 Post Accident Monitoring Instrumentation 4-10at 4.19-1 a4--

anspectIod During [ngronei. !nspeeti-nn 4.19-2 .....m- . r Tube

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4.21-1 DELETED 4.21-2 DELETED 4.22-1 DELETED 4.22-2 DELETED 4.23-1 DELETED vi Amendment No.. 92, 4144406, 11, !-7, 112, 11, -

CONTROYED COPY REACTOR COOLANT SYSTE*M 3.1 I 3.1.1 OPERATIONAL COMPONENTS Acol-icabilitv Aoplies to the operating status of reactor coolant system components.

Objective To specify those limiting conditions for operation of reactor coolant system components wnich must be met to ensure safe reactor operations.

Soecification 3.1.1.1 Reactor Ccolant Pumps

a. Pump combinations permissible for given power levels small ce as shown in Specification Table 2.3.1.

b. Power coeration with one idle reactor coolant pump in each loop shall be restricted to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the reactor is not returnea to an acceptable RC pump operating combination at the end of the 24-hour pericc, the reactor shall be in a hot shutdown condition within 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 concentration in the reactor coolant .system shal2 not be reouced unless at least one reactor coolant pump or one tecay heat removal pump is circulating reactor coolant.

3.1.1.2 Steam Generator

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IN5CAT a. seem steamgeeatr shaLL -al cc ocrci:~rcer- vne reaetar eoolant eycre ee tcrouciz oboe 2§GaF-r 3.1.1.3 Pressurizer Safety Valves

a. The reactor shall not remain critical unless both pressurizer code safety valves are operable with a lift setting of 2500 psig - 1%.

b. When the reactor is subcritical, at least one pressurizer code safety valve snail be operacle if all reactor coolant system openings are closed, except for hydrostatic tests in accordance with ASME 9oiler and Pressure Vessel Ccoe, Section Iii.

3-la I Amendment No. 12. 77, U0, 77,X

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

a. Whenever the reactor coolant average temperature is above 2000 F, the following conditions are required:

(1.) SG tube integrity shall be maintained.

AND (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 6.19.)

ACTIONS:

---

N-NOTE------------------------------

Entry into Sections 3.1.1.2.a.(3.) and (4.), below, is allowed for each SG tube.

(3.) If the requirements of Section 3.1.1.2.a.(2.) are not met for one or more tubes then perform the following:

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(s) is maintained until the next refueling outage or SG tube inspection, AND

b. Plug the affected tube(s) 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.) IfAction 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 />.

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CONTROLLED COPY Bases The limitation on power operation with 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 allowed for operation with one idle RC pump in each loop toeffect 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 expected to have considerable margin for the peak cladding temperature limit and since the likelihood of a LOCA within the 24-hour period is considered vet- remote.

A reactor coolant pump or decay heat removal pump is required to be in operation before the boron concentration is reduced by dilution with makeup water. Either pump will provide mixing which

%%illprevent sudden positive reactivity changes caused by dilute coolant reaching the reactor. One decay heat removal pump %%ill 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 system can remove decay heat when the reactor coolant system is belowv this temperature (References 1, 2, and 3).

Both steam generators musti before heatup of the Reactor Coolant System to 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 at 2500 psig +1% allowance for error. Surveillance requirements are specified in the Inservice Testing Program. Pressurizer code safety valve setpoint drift of up to 3% is acceptable in accordance with ASME Section XI (Reference 5) and the assumptions of TMI-I safety analysis.

Rfrn ce rio a( - -cmmAr e -ft t /-l-t (I) UFSAR, Tables 9.5-1 andg9.5-2 A4 e.K ýjri (2) UFSAR, 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) UFSAR, Section 4.3.7 - 'Overpressure Protection" 3-2 Amendment No. 4-7 (12/22/78),-4 CONTROLLED COPY 3.1.6 LEAKAGE Applicability Applies to reactor coolant leakage from the reactor coolant system and the makeup and purification system.

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

Specification 3.1.6.1 Ifthe 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 one plac gpm or~ifsuin dwitho any reactor w coolant leakage 2hour is evaluated as*f)/

of detection. unsafe, the reactor shall be .. ***,p pla ht douwn within 24 h 3.1.6.3 If primary- o-secondary leakage,*-,eF- ,r-1r -hee exceeds-I-JA ttalafe;I bh*ý 3 .... n g Fra.t- m, thez ;z ekt9&&alll plIpod in- cold shutdgwn within

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d- r AI eý(cel ,,4ot5,44 fown 3.1.6.4 If any reactor coolant leakage exists through a noniso able fault in an RCS strength 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 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.

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, 429, 480,- 246/

(12-22-78)

(OTrROLL:ED COPY Bases (Continued)

The unidentified eakage limit of I gpm is established as a quantity which can be accurately measured while sufficiently low to ensure 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 allowance tefr for a limited amount of leakage from known sources whose presence w lction of unidentifie-d leak ,.t qI* /P.b

'1 p rii~a /.(-*oo dya kpg et *een ra** il~et fr~~~~~tkg 7 t/nteeo tmnn is/

If reactor coolant leakage is to the auxiliary building, it may be identified by one or more of the following methods:

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.

b. Water inventories around the auxiliary building sump.

c. Periodic equipment inspections.

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

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

3-15a Amendment No. 444, OFreo dtd. 4A"2'1 ,-_R4

INSERT TO TS PAGE 3-15a (BASES FOR SECTION 3.1.6)

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 a leakage volume or rate of primary to secondary leakage from all steam generators (SGs) depending on the specific accident analyses.

The leakage rate may increase (over that observed during normal operation) as a result of accident-induced conditions. The TS requirement to limit the sum of the primary to secondary leakage from 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 on the sum of the primary to secondary leakage from both SGs of 144 gallons per day is less than 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.

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CONTrROLLED COPY 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 EFW Pump or both EFW 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 EFW System must be in communication with the control room and stationed in the immediate vicinity of the affected EFW 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 EFW 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 EFW 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 EFW components to operable status. TS 3.0.1 is not applicable, as it could force the unit into a less safe condition.

The EFW 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 power. According to Specification 3.1.1.2a, both OTSGs shall4whenever the reactor coolant average temperature is above0266-degrees F. his assures that all four (4)

MSSVs are available for redundancy. Dudn( power operation at 5% full power or above, if MSSVs are inoperable, the power level mu* be reduced, as sa ted in Specification 3.4.1.2.3 such that the remaining MSSVs can preve toerpressure on turbine tri 3-26c Amendment No. 78, 119, 125, 133, 1,57, 220,-24,-

J

TROLLED Copy CON Bases (Cont'd- Tables 4.1-2, a safe specified in and sampling frequencies the equipment systems in testing and systemadequate to maintain 4.1-3,equipment The and 4.1-5 are considered operational status.

REFERENCE 7 .1.2.3(d) - "Periodic Testing and Reliability" UFSAR, Section 5, 1988.

(1) Supplement 1, December (2) NRC SER for BAW-10167A, 1986.

(3) BAW-10167 May 4-2b Amendment No.

INSERT TO TS PAGE 4-2b (BASES FOR SECTION 4.1)

The primary to secondary leakage surveillance in TS Table 4.1-2, Item 12, verifies that the sum of the primary to secondary leakage from both SGs is less than or equal to 144 gallons per day. 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 3.1.1.2, "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 the sum of the leakage through both SGs.

The TS Table 4.1-2 primary 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 operation.

The TS Table 4.1-2 primary to secondary leakage surveillance frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 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 EPRI guidelines (Ref. 5).

1 of 1

CO%)NTROLLED COPY TABLE 4.1-2 MINIMUM EQUIPMENT TEST FREQUENCY Item Test 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 Inservice Testing Program

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

5. Refueling System Functional Start of each Interlocks refueling period

6. (Deleted) I

7. Reactor Coolant Evaluate Daily, when reactor System Leakage coolant system temperature is greater than 525 die ree s ro

8. (Deleted)

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

10. Intake Pump (a) Silt Accumulation - Not to exceed 24 months 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

• _.* ~full trave...l. -------

a. P No.rj lb Sondc. Evm,.&e.2-1-1-,-

-7X 4.4o, 78, Ev, -8 Amendment No. W,68, 78, -44Q, 4146, 4-98, 24-1,-ie467

CI ?hC'L LEDT( iCOPY f~t 4.19 licabilit T Technical Sppcification applies to the inservice inspection o the SG tube portion of the reactor coolant pressure boundary.

Ob ecti The object of this inservice inspection program is to ovide assurance of utinued integrity of the tube portion of e Once-Through Steam rators, while at the same time Ing radiation exposure to pers el in the performance of the map tion.

Specification Each steam generator sh 1 be demonstrated OP LE by performance of the following augmente inservice inspec on program and the requirements of Specificati 3.1.6.3.

4.19.1 Steam Generator Sample electi and Inspection Methods

a. Each steam generator shall determined OPERABLE during shutdown by selecting and ecting at least the minimum number of steam generat s sp ified in Table 4.19.1 at the frequency specified i 4.19.3.

b. Inservice inspecti of steam gene tor tubing shall include nondestructive tion by eddy-c ent testing or other equivalent tec iques. The inspection quipment shall be calibrated to rovide a sensitivity that 11 detect defects with a pane ation of 20 percent or morel the minimu allowable manufactured tube wall thickne 4.19.2 Steam orator Tube Sample Selection and Inspe tion Th steam generator tubeminlmum sample size, insp tion result c sification, and the corresponding action require shall e as specified in Table 4.19.2. The inservice inspec on of steam generator tubes shall be performed at the frequ cies tubes ie specified in Specification 4.19.3 and the inspected shall be verified acceptable per the acceptance criteria of Specification 4.19.4. The tubes selected for 4-77 Amendment No AOL (12-22-78)

each inservice inspectio".t ) $lfd*'yit) t 1h tRtal..if tubes n a steam enerators; the tubes selected * -.,,J.orAIspedions these a = , **,*. ,.:*. ,:,, be, *ectd tu e in basis

.,. V. one af random except al steam e*/ r

a. The first sample of tubes selected for each inservice inspection (subsequent to the reservice inspection) of each steam generator shall include:

1. All nonplugged tubes that previously had detectable wall penetrations (>20%).

2. t least 50% of the tubes inspected shall be in those areas where ex rience has in "cated potential problems.

3. A tub inspection (pursuant to Specification 4.19.4.a.8) shall e performed on each sel ted tube. If any selected tube does not permit th assage of the eddy current pr e for a tube inspection, this shall be recorde and an adjacent tube shall be sele d and subjected to a tube inspection.

4. Tubes in the foil ing groups may be excluded fr m the first random sample if all tubes in a group both steam generators ar nspected. No credit will be taken for these tubes i meeting minimum sa plie size requirements.

(1) Group A-1: Tubes rows 73 thro h 79 adjacent to the open inspection lane, and tubes betwe iand on 1 es drawn from tube 66-1 to tube 75-15 and from 86-1 to 77-15.

(2) Group A-2: Tubes having 'lied opening in the 15th support plate.

b. The tubes selected as the second an ird sa les (if required by Table 4.19.2) during each inservice inspection may be d to a rtial tube inspection provided:

1. The tubes selected for ese second and third mples include the tubes from those areas of the tu sheet array where tubes 'th imperfections were previously found.

2. The inspectio nd,ncludes previously/ . ~those portions of the tubes w re imperfections were

c. Implementation f the repair criteria for Inside Diameter (ID) Inter- anular Attack (IGA) requir 100% bobbin coil inspection of all non-plugged tubes r accordance with AmerGen gineering Report, ECR No. TM 01-00328, during all subse ent steam generato nspection intervals pursuant to Section 4.19.3. ID TGA indicatio detected by the bo in coil probe shall be characterized using rotating coil probes, as de fed in that irepo ."

The res s of each sample inspection shall be classified into one of the following three categories:

Categoy Inspection Results C-I 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, 1-3, -423, (12-22-78)

19.2 Specification (Continued)

C-2 One or more tubes, but not more than I%of the total tubes inspected in a stea generator are defective, or between 5% and 10% of the total tubes inspected re degraded tubes. darg/a C-3 More than 10% of the total tubes inspected in a steam generator are d raded tubes or more than I%of the inspected tubes are defective.

NOTES: (1 In all inspections, previously degraded tubes whose degr ation has not een spanned by a sleeve must exhibit significant incr se in the applicable d ran size measurement (> 0.24 volt bobbin c i amplitude increase fort side diameter IGA indications or > 10% flirt r wall penetration for all ot degradation) to be included in the above p centage calculations.

(2) Where specia inspections are performed rsuant to 4.19.2.a.4, defective or degraded tubes und as a result of the i pection shall be included in determining the In ection Results C gory for that special inspection but need not be included in de rmining the spection Results Category for the general steam generator inspec n.

4.19.3 Inspection Frequencies The required inservice inspections of st m gen ator tubes shall be performed at the following frequencies:

a. The first (baseline) inspection as performed after ffective full power months but within 24 calendar months of initial riticality. The subseque inservice inspections shall be performed not more tha calendar months after the prious inspection. If the results of two consecutive ispect!' ns for a given group of tubes' en mpassing not less than 18 calendar months all f5Winto the C-I category or demonstrate t previously observed degradation has not ontinued and no additional degradation as ccurred, the inspection interval for that goup may be extended to a maximum of once per 0 months.

b. If the results f the inservice inspection of a steam generator conducte *n accordance with Table 4.19 at 40 month intervals for a given group of tubes* fall into egory C-3 the inspecti frequency for that group shall be increased to at least once per 2 months. The increa in inspection frequency shall apply until the subsequent inspections isfy the crit a of Specification 4.19.3.a; the interval may then be extended to a maxim of once p 0months.

A u of tubes means:

(a) All tubes inspected pursuant to 4.19.2.a.4, or (b) All tubes in a steam generator less those inspected pursuant to 4.19.2.a.4 4-79 Amendment No. 47, 153, 2O ,--*09-

I

4. 1 ns ection ,rei L L U k kr

c. Additional, unscheduled inservice inspections shall be performed on each steam genera r il accordance with the first sample inspection specified in Table 4.19-2 during the shut %-n subsequent to any of the following conditions:

1. A seismic occurrence greater than the Operating Basis Earthquake.

A loss of coolant accident requiring actuation of engineering safe ards, or

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

d. After prima -to-secondarv tube leakage (not including leaks o g nating from tube-to-tube sheet welds) excess of the limits of Specification 3.1.6.3, spection of the affected steam generator will erformed in accordance with the followl criteria:

1. If the leak is bove the 14th tube support plate* a Group as defined in Section 4.19.2.a.4(1)a of the tubes in this Group eaffected steam generator will be inspected above 14th tube support pla . If the results of this inspection fall into the C-3 catego

• additional inspec i ns will be performed in the same Group in the other steam gen r.

2. If the leaking tube is not as efin in 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 Acceptance Criteria

a. As used in this Specification:

I. Imperfection me s an exception to the dim sions. finish, or contour of a tube from that requ, d by fabrication drawing or s cifications. Eddy current testing indications I s than degraded tube criteria speci d in a.3 below may be consider mperfections.

2. Dee tion means a service-induced cracking, wastage. ear or general corrosion occ ng on either inside or outside of a tube.

egraded Tube means a tube containing:

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

/ oooexen,or .....

_>0.2 volt or a 0.13 inches axial extent or _ 0.26 inches circu rential (b) imperfections 2!20% of the nominal wall thickness caused by degrada on.

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

4-80 Amendment No. 116, 1,19, 153, 206, 209" -Ht-

4.19.4 Acceptance Uritera Onlu? $. - Y.

5. Defect means an imperfection of such severity that it exceeds the repair limit. A tube containing a defect is defective.

6. Repair Limit means the extent of degradation at or beyond whi the tube shall be repaired or removed from service because it may be me unserviceable prior to the next inspection.

is limit is equal to 40% of the nominal tube wall ickness. Inside dia ter IGA indications shall be repaired or re ved from service if they excee n axial extent of 0.25 inches, or a cir inferential extent of 0.52 inc or a through wall degradation mensions of> 40% if assigned.

7. Unserviceable des ibes the condi

• n of a tube if it leaks or contains a defect large enough affect it tructural integrity in the event of an Operating Basis Earthq ke loss of coolant accident, or a steam line or feedwater line break ass 'fled in 4.19.3.c., above.

8. Tube Inspection m s an inspe *on of the steam generator tube from the bottom tubesheet,of the u r tubesheet con tely to the top of the lower ex/tas permitted by 4.1 .. , above.

9. Inside ' meter Inter- Granular Attack (IG Indication means an indic ion initiating on the inside diameter su e and confirmed by di nostic ECT to have a volumetric morphology aracteristic of IGA.

b. The meam c 'espondinggenerator shall be determined OPERABLE after co atos(removal eting the from service by plugging, or repahi ykiec expansion, sleeving, or other methods, of all tubes exceeding the rep *limit and all tubes containing throughwall cracks) required by Table 4.19-2.

19 Reports

/" a. DELETED 4-81 Amendment No. 147, 83, 91, 103, 129, 19, 153, 157, 206, 209. 43

• ,1): Kcporis I unli U`k" CO D~LL~ Y

b. The complete results of the steam generator tube inservice inspection shall be iporied to the NRC within 90 day s following completion of the inspection and rep rs (main generator breaker closure). The report shall include:

1. Number and extent of tubes inspected.

. L tion and percent of wall-thickness penetratio r each indication of an imper ction.

3. Location, bo in coil depth estimate (if ermined), bobbin coil amplitude (if determined). d axial and circum rential extent for each inside diameter IGA indic on, and

4. Identification of tubes repa or removed from service.

5. The number of tubes paired or r oved from service in each steam generator,

6. An assess nt of growth of inside diameter A degradation in accordance with th olumetric ID IGA management progr contained in AmerGen En eering Report., ECR No. TM 0 1-00-328, and

7. esults of in-situ pressure testing, if performed.

C. esults of steam generator tube inspections which fall into Category C-3 quire notification in accordance with 10 CFR 50.72 prior to resumption of pl~ant operation. The written follow-up of this report shall provide a description of investigations conducted to determine the cause of the tube degradation and corrective measures taken to prevent recurrence in accordance with 10 CFR 50.73).

4-82 Amendment No. 47, 86, 116, 119, !53, _-g6-.0-9, "f'l

Bases -*",*' '-" *'"* nue / :~

e Surveillance Requirements for inspection o' the steam generator tubes ensure that the st tural integrity of this portion of the RCS will be maintained.

The pro am for inservice inspection of steam generator tubes is based on modificatio o Regulato Guide 1.83, Revision I. In-service inspection of steam generator tubingA essential in order to mai in surveillance of the conditions of the tubes in the event that there s evidence of mechanical da ge or progressive degradation due to design, manufacturing e rs, or inservice conditions. Inse ce inspection of steam generator tubing also provides am s of characterizing the n re and cause of any tube degradation so that correct* e measures can be taken.

The Unit is expected to be erated in a manner such that the prim and secondary coolant will be maintained within those ch istry limits found to result in ne gible corrosion of the steam generator tubes. If the primary secondary coolant chemistry no maintained within these chemistry limits, localized corrosi may likely result.

The extent of steam generator tube le e due to cracki would be limited by the secondary coolant activity, Specification 3.1.6.3.

The extent of cracking during plant operation o be limited by the limitation of total steam generator tube leakage between the primary coo t system and the secondary coolant system (primary-to-secondary leakage = 1 gpm). Le agei, excess of this limit will require plant shutdown and an unscheduled inspection, ing whi the leaking tubes will be located and repaired or removed from service.

Wastage-type defects are unlikely w` proper chemistry trea ent of the primary or the secondary coolant. However, eve f a defect would develop in ervice, it will be found during scheduled inservice steam gener or tube examinations. For tube ith ID IGA indications, additional conservatism is bei applied to evaluate circumferential d axial dimensions for determining final dispositio of the tube. For ID IGA indications thro wall dimension will continue to be assigned t ose indications where amplitude response pe its measuring through wall dimension. Stea enerator tube inspections of operating plants have monstrated the capability to reliably etect degradation that has penetrated 20% of the origin tubewall thickness.

Removal fro ervice by plugging, or repair by kinetic expansion, sleeving, or other ethods, will be requ ed for degradation equal to or in excess of 40% of the tube nominal wall ckness.

Tubes wi .D. initiated intergranular degradation may remain in service without % T.W. .zing the d adation morphology has been characterized as not crack-like by diagnostic eddy curre inspection and the degradation is of limited circumferential and axial length to ensure tub structural integrity. Additionally, serviceability for accident leakage under the limiting stulated Main Steam Line Break (MSLB) accident will be evaluated by determining that this

.D. initiated degradation mechanism is inactive (e.g. comparison of the outage examination 4-83 Amendment No. 17, 129, 206, 29-,3ha

ases (Continued) COR 1;1% 4((L~

results h the results from past outages meets the requirements of AmerGen Enginee g Report, EC No. TM 01-00328) and by successful in-situ pressure testing of a sa e of these degraded tubes t aluate their accident leakage potential when in-situ press tests are performed.

Where experiencein similar pla with similar water chemist , as documented by USNRC Bulletins/Notices, indicate critical ar to be inspected, a ast 50% of the tubes inspected should be from these critical areas. First le ins ions sample size may be modified subject to NRC review and approval.

Whenever the results of any steam gen tor tubing inse e inspection fall into Category C-3 on the first sample inspection (See T e 4.19.2), these results wI e reported to NRC pursuant to the requirements of Specific n 4. 19.5.c. Such cases will be con ered by the NRC on a case-by-case basis and may r t in a requirement for analysis, laborator ex inations, tests, additional eddy cur inspection, and revision of the Technical Specificati if necessary.

NOTE: eddy current examination voltages referred to in this section (section 4. 1 re based on a alization procedure that sets the bobbin coil prime fr-equency peak-to-peAk respon the four 720% through-wall holes of an ASMIE calibration standard to 4 volts.

4-83a Amendment No. 47, 129, 206,- 2*9,

C~iCLIFHCL'd-D CQPY TABLE 4.19-1 ESII4L" MERtlOF GS*BRTLv24 Ofl*AS T DOBE DISPECTD DURIIG INS.EVCE INS=EC. r0n Pc nspection No. of Steh Generators per Unit First InservicInspection 1%

Il TAPLZ NOT.AT_I  :

X. The Inservice Inspecti may be limited to one team generator on a C rotating schedule conpassine 6% of the tubes in steam generator It the results f the first and subsequent Inspecticnsz dicute that both steam gen ators are performing in a like anner. Note tha der some circ ances, the operating conditions In one steam generator be found t more severe than those In the other steam generator. Under su iercumstances the sanple sequence shafl be modified to Inspect the most severe conditions.

Amendment No.-47 (12-22-78)

S-dry

,q TABLE 4.19-2 STEAM GENERATION TUBE INSPECTION( 2 )

i 'I. . _ _ _ _ _ _

I i lill~m~L INSPECTION ISample Size I ReOJft I Action Required i I 2ND SAMPLE INSPECTION Result I Action Required 3RD SAMPLE IN I eS- IIc-nRqie TION I

• m**l I ~ II 1A winimim of I C- INk None N/A I NI/A N/A ' N/A

_ * .... ne IS.Tul"j per II 1-z Z.

I P or repair I C-1 INone " su conne is G. def Ive tubes I (t-2 I Plug or repair I I and in ct I defective tubes and I

I I

I additiona iS tubes in th, S.G.

I iI C C-3 I inspect additional4S II Perform this S.G.

tubes in action I C-3 result of fgr" rst I

I I I 7C-2 C-3 I Plug or repair defective

-T Perform action tubes.

I Q

I for C-3 result I I IOtGl e I i -sample. o I I_ _ of first sample.

I C-3 I I II Inspect all tubes in this I

I Is. G. "1 1 . ,. neI I I S.G., plug or I N/A I N/A I "N I

I I repair defect- I lye tubes and I IOther IS.G. iJ I form actiofo sJC-2"*r sult of second I

I N/A 1 N/A

/A I 0

I I inspect 2S tubesl

_-C.-2 ! L .sample"* .. .

I in other S.G. I I ut~e Provide notifi- I I-,Tv1i s inspec t 6 each S.G. a LuDCs in I I plug or I I iN/A N/A I r cation to NRC I 4'C-3 repair defect I I pursuant to tubes. Provide I I iOCFR50.72.b I notification to NRC I I and submi I pursuant to IOCFR5O.7* I report rsuant I b.2.i and submit a I to 1 R50.73.- I report pursuant to i I a... i.1t. 1 IOCFR5O.73.a.2.1t. I I Notes: (1) S = 3 wWhere N is the number of steam generators in the unit. and n is number of steam S* 3N generators inspected during an Inspection.

(2) or tubes inspected pursuant to 4.19.2.a.4: No action is required for C-1 results. or C-2 results in one or both steam generators plug or repair defective tubes. For C-3 resu in one or both steam generators, plug or repair defective tubes and provide notification to NRC pursuant to 10 CFR 50.72.b.2.i followed by a written report pursuant to 10 CFR 50.73.a.2.i I

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

Each steam generator shall be determined to have tube integrity 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 system's 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. The SG heat removal function is addressed by TS Section 3.4.

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 6.19, "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 of 7

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.1 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(c)(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. A portion of the parent tube length has been 4-78 2 of 7

BASES LCO (continued) removed from service in the sleeved tubes, so examination requirements for sleeved and unsleeved tubing lengths are described in the Specification.

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 burst/collapse 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 III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, 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 3 of 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 the sum of the primary to secondary leakage from both 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 2000F.

RCS conditions are far less challenging when average temperature is at or below 2000 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. Inorder 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.

4-80 4 of 7

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.a.(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.

3.1.1.2.a.(4.)

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. 1), and its referenced EPRI 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 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 6.19 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, 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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Steam generator tube repairs are described in TS Section 6.19.f. All in-service tubes were repaired by kinetic expansion in the early 1980's, and approximately 250 tubes in each SG were sleeved in the early 1990's.

Installation of additional kinetic expansions, sleeves, or other type of tube repair requires prior NRC approval. ECR 02-01121 prescribes examination requirements and flaw dispositioning criteria for the kinetic expansions and sleeves. NRC approval of ECR 02-01121 was provided under Reference 7.

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. 10CFR100.

4. ASME Boiler and Pressure Vessel Code,Section III, 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".

7. U.S.N.R.C. Letter, 'Three Mile Island Nuclear Station, Unit 1 - Steam Generator Tube Kinetic Expansion Inspection and Repair Criteria (TAC No.MC7001)", November 8, 2005.

4-83 (Pages 4-84 through 4-85 deleted) 7 of 7

CONTROLLED COPY 6.9.5 CORE OPERATING LIMITS REPORT 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 Methodology for Acceptable Cycle Reload Analyses." The current revision level shall be specified in the COLR.

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

(3) TR-087-A, "TMI-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-1",

Revision 0. NRC SER dated 2/21/96.

(5) TR-092P-A, "TIMI-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.

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 transient/accident 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 upon issuance for each reload cycle to the NRC Document Control Desk with copies to the Regional Administrator and Resident Inspector.

6-19 Amendment No.72,-77, 129, 43711, . * , .144.4 l ,*v!

.v! 10, V~l 1:73, 478,

• vI 168, , , v 29021

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

j. 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.

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

I. The number and percentage of inservice tubes repaired by each method existing in the SGs.

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CONTROLLED COPY

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.1 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.-056-/

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-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure 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 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage volume or rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage volume or rate in the accident analysis in terms of total leakage volume or rate for all SGs and leakage volume or rate for an individual SG. Leakage from all sources excluding the leakage attributed to the degradation described in TS Section 6.19.c.1.b is also not to exceed 1 gpm per SG.

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. The non-sleeved regions of 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. (ECR No. TM 01-00328 is not applicable to tube sleeves nor the parent tubing spanned by the sleeves.) ID IGA indication means an indication initiating on the inside diameter surface and confirmed by diagnostic ECT to have a volumetric morphology characteristic of IGA. ID IGA indications shall be 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 > 40% if assigned.

b. Upper tubesheet kinetic expansion indications may be dispositioned in accordance with ECR No. TM 02-01121, Rev. 2.

2. Tubes found by inservice inspection to contain a flaw in a sleeve, or in a sleeve's parent tube adjacent to the sleeve between the lower sleeve end and the top of the middle sleeve roll, shall be "plugged-on-detection."

3. Sleeved tubes found by inservice inspection to contain any of the following attributes in the parent tubing adjacent to the sleeve upper tubesheet roll expansion shall be removed from service:

a) The parent tubing is not present.

b) There is a change in the number of indications present.

c) There is a change in the orientation/morphology of the indications.

d) There is a significant change in the circumferential extents of the circumferential and volumetric flaws.

e) There is a significant change in the axial extents of the axial and volumetric flaws.

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 tubes repaired by sleeving, the portion of the parent tube between the top of the middle sleeve roll to the bottom of the uppermost sleeve roll (upper tubesheet roll) is not an area requiring inspection. 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 2 of 3

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.

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). Ifdefinitive 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-plugged tubes using inspection methods and probes in accordance with 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 using inspection methods and probes in accordance with ECR No. TM 02-01121, Rev.2.

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-1's kinetic expansion repairs installed in the 1980's, and without flaws exceeding the criteria of 6.19.c. 1.b, may remain in service subject to the requirements of TS Sections 3.1.1.2, 4.19, and 6.19.

TMI-1's 80" Inconel-690 rolled sleeves installed in 1991 and 1993, and without flaws exceeding the repair criteria of 6.19.c.2 or 6.19.c.3, may remain in service subject to the requirements of TS Sections 3.1.1.2, 4.19, and 6.19.

Installation of new repair methods, additional kinetic expansions, or additional sleeves, requires prior NRC approval.

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

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ENCLOSURE 2 TMI Unit 1 Technical Specification Change Request No. 331 List of Commitments

5928-07-20194 Enclosure 2 Page 1 of 1

SUMMARY

OF AMERGEN COMMITMENTS The following table identifies regulatory commitments made in this document by AmerGen. (Any other actions discussed in the submittal represent intended or planned actions by AmerGen. They are described to the NRC for the NRC's information and are not regulatory commitments.)

COMMITMENT TYPE COMMITMENT COMMITTED DATE ONE-TIME OR "OUTAGE" ACTION PROGRAMMATIC (Yes/No) (Yes/No)

The TMI Unit 1 Updated Final Safety Analysis Report (UFSAR) will be UFSAR Update 19 Yes No revised in the next required periodic Spring 2008 update to identify that the technical basis for the adequacy of the original steam generator tube sleeve installation will be submitted to the NRC if the existing TMI Unit 1 steam generators are not replaced in the 1R18 refueling outage (currently planned for Fall 2009).