ML051780328

Supplemental Technical Specification Revisions for the Steam Generator Replacement Project

ML051780328
Person / Time
Site:	Callaway
Issue date:	06/17/2005
From:	Keith Young AmerenUE, Union Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
ULNRC-05 157
Download: ML051780328 (71)

Text

Union Electric Callaway Plant PO Box 620 Fulton, MIO 65251 June 17, 2005 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Station P 1-137 Washington, D.C. 20555 ULNRC-05 157 Ladies and Gentlemen:

wAmeren UE DOCKET NUMBER 50-483 UNION ELECTRIC COMPANY CALLAWAY PLANT SUPPLEMENTAL TECHNICAL SPECIFICATION REVISIONS FOR THE STEAM GENERATOR REPLACEMENT PROJECT

References:

1. ULNRC-05056 dated September 17,2004

2. ULNRC-05117 dated February 11, 2005

3. ULNRC-05145 dated May 26,2005

4. NRC Notice of Availability of Model Application Concerning Technical Specification Improvement to Modify Requirements Regarding Steam Generator Tube Integrity Using the CLIIP, 70 FR 24126 dated May 6, 2005 (TSTF-449 Revision 4)

AmerenUE herewith transmits a supplement to the application for amendment to Facility Operating License Number NPF-30 for the Callaway Plant that was originally submitted via Reference I above in support of the replacement steam generators to be installed during Refuel 14 (fall 2005). The required supplements to the Technical Specification (TS) changes requested in Reference I are categorized as follows:

• The LEAKAGE definition in TS 1.1 is revised to reflect Reference 4 (NRC-approved TSTF-449 Revision 4).

• TS Tables 3.3.1-1 and 3.3.2-1 are revised to reflect the RTS and ESFAS setpoint restoration footnotes submitted in Reference 3.

• TS Table 3.3.2-1, Functions L.e and 4.e.(1), is revised to reflect the correction of the Allowable Value round-off error on the low steamline pressure trip functions submitted in Reference 3.

• TS 3.4.13 is revised to reflect the NRC-requested addition of "steam generator" to LCO 3.4.13.d to explain the "SG" acronym for its first use within a TS.

• New TS 3.4.17 is revised to reflect the change to Required Action A.1 per NRC-approved TSTF-449 Revision 4.

• Administrative Control 5.5.16 is revised to reflect the NRC-requested change to the Insert such that the ILRT exception applies only for Refuel 14 during the fall of 2005.

AQD l a subsidiary of Ameren Corporation

ULNRC-05 157 June 17, 2005 Page 2 Attachments 1 through 4 provide the revised Evaluation (revisions to the Reference 1 Evaluation are indicated by revision bars), Markup of Technical Specifications, Retyped Technical Specifications, and Proposed Technical Specification Bases Changes, respectively, in support of this amendment request. Attachment 4 is provided for information only. Final Bases changes will be implemented pursuant to TS 5.5.14, Technical Specifications Bases Control Program, at the time the amendment is implemented. There are no new commitments contained herein.

It has been determined that the nature of the minor TS changes contained in this supplement does not invalidate the findings of the licensing evaluations contained in Attachment I of Reference 1. The amendment application, as supplemented, does not involve a significant hazard consideration as determined per IOCFR50.92 nor is there a requirement to prepare an environmental impact statement or environmental assessment.

The Callaway Onsite Review Committee and Nuclear Safety Review Board have reviewed and approved the submittal of this supplement. The requested approval date and implementation plans for this amendment application remain unchanged from Reference 1. In accordance with 10CFR50.91, a copy of this amendment application supplement is being provided to the designated Missouri State official.

If you have any questions on this amendment application, please contact us.

Very truly yours, Keith D. Young Manager-Regulatory Affairs GGY/

Attachments:

1 Revised Evaluation 2

Markup of Technical Specifications 3

Retyped Technical Specifications 4

Proposed Technical Specification Bases Changes (for information only)

I I

Z ULNRC-05157 June 17, 2005 Page 3 cc:

U.S. Nuclear Regulatory Commission (Original and I copy)

Attn: Document Control Desk Mail Stop P1-137 Washington, DC 20555-0001 Mr. Bruce S. Mallett Regional Administrator U.S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-4005 Senior Resident Inspector Callaway Resident Office U.S. Nuclear Regulatory Commission 8201 NRC Road Steedman, MO 65077 Mr. Jack N. Donohew (2 copies)

Licensing Project Manager, Callaway Plant Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Mail Stop 7E1 Washington, DC 20555-2738 Missouri Public Service Commission Governor Office Building 200 Madison Street PO Box 360 Jefferson City, MO 65102-0360 Deputy Director Department of Natural Resources P.O. Box 176 Jefferson City, MO 65102

STATE OF MISSOURI

))

SS COUNTY OF CALLAWAY)

Keith D. Young, of lawful age, being first duly sworn upon oath says that he is Manager, Regulatory Affairs, for Union Electric Company; that he has read the foregoing document and knows the content thereof; that he has executed the same for and on behalf of said company with full power and authority to do so; and that the facts therein stated are true and correct to the best of his knowledge, information and belief.

By 4f0& ov0 Ke( D. Yo1Wg u

Manager, Regulatory Affairs SUBSCRIBED and sworn to before me this day of Jl IC.

20Qy.5 SMA NOTEA RY, V ¶BU

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.LL*ate O. A\\E-W

Attachment I Page 1 of l REVISED EVALUATION

1. DESCRIPTION Page 2

2. PROPOSED CHANGES Page 2

3. BACKGROUND Page 6

4. TECHNICAL ANALYSIS Page 11

5. REGULATORY SAFETY ANALYSIS Page 39 5.1 NO SIGNIFICANT HAZARDS CONSIDERATION Page 39 5.2 APPLICABLE REGULATORY REQUIREMENTS/CRITERIA Page 47

6. ENVIRONMENTAL CONSIDERATION Page 49

7. REFERENCES Page 49 Only pages with revision bars are included with ULNRC-05157 dated 6-17-05.

I

Attachment I

Attachment I Page 2 of 51 REVISED EVALUATION

1.0 DESCRIPTION

The proposed amendment would revise the following Technical Specifications (TS) in support of replacement steam generators to be installed during Refuel 14 (fall 2005):

• TS 1., "Definitions",l

• TS 2.1.1, "Reactor Core Safety Limits";

• TS 3.3.1, "Reactor Trip System (RTS) Instrumentation";

• TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation";

• TS 3.4.1, "RCS Pressure, Temperature, and Flow DNB Limits";

• TS 3.4.5, "RCS Loops - MODE 3";

• TS 3.4.6, "RCS Loops - MODE 4";

• TS 3.4.7, "RCS Loops - MODE 5, Loops Filled";

• TS 3.4.13, "RCS Operational Leakage";

• TS 3.7.1, "Main Steam Safety Valves";

• TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program";

• TS 5.5.16, "Containment Leakage Rate Testing Program"; and

• TS 5.6.10, "Steam Generator Tube Inspection Report."

In addition, the proposed amendment would add new TS 3.4.17, "Steam Generator Tube Integrity," pursuant to Reference 7.1, Technical Specification Task Force (TSTF)

Improved Standard Technical Specifications Change Traveler TSTF-449 Revision 4.

l Section 7.0 of this Evaluation provides a listing of references cited herein.

2.0 PROPOSED CHANGE

S The following changes to the TS are included in this amendment application:

la.

An editorial change is made to the definition of LEAKA.GE. The definition uses the term "SG LEAKAGE" but that term is never used or defined in the Technical Specifications or Bases. The term used in the Technical Specifications and Bases is 'prinary to secondary LEAKAGE." Therefore, the definition of LEAKAGE is revised to use the term 'rimary to secondary LEAKAGE" instead of "SG LEAKAGE." This change reflects Revision 4 of TSTF-449.

1.

Figure 2.1.1-1, "Reactor Core Safety Limits," will be replaced with a new figure to reflect the replacement steam generators and associated safety analyses.

2.

Condition W in LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation," will no longer be used. RTS Function 14.c in TS Table 3.3.1-1 will be deleted. The Trip Time Delay (TTD) portion of the Steam Generator (SG) Water Level Low-Low Page 4 of 51

b.

TS Table 3.3.2-1, ESFAS Function 5.e.(1), SG Water Level Low-Low (Adverse Containment Environment); and

c.

TS Table 3.3.2-1, ESFAS Function 6.d.(1), SG Water Level Low-Low (Adverse Containment Environment).

7.

The Allowable Values for the following trip functions are decreased from

> 19.8% of Narrow Range Instrument Span to > 16.6% of Narrow Range Instrument Span to reflect the replacement steam generators and associated setpoint calculations:

a.

TS Table 3.3.1-1, RTS Function 14.b, SG Water Level Low-Low (Normal Containment Environment);

b.

TS Table 3.3.2-1, ESFAS Function 5.e.(2), SG Water Level Low-Low (Normal Containment Environment); and

c.

TS Table 3.3.2-1, ESFAS Function 6.d.(2), SG Water Level Low-Low (Normal Containment Environment).

8.

The Allowable Value for Safety Injection on Steam Line Pressure -Low (ESFAS Function L.e in TS Table 3.3.2-1) will be increased from > 571 psig (with the "c" footnote) to > 609 610 psig (with the "c" footnote) to reflect the replacement steam generators and associated setpoint calculations.

9.

The Allowable Value for Steamline Isolation on Steam Line Pressure - Low (ESFAS Function 4.e.(1) in TS Table 3.3.2-1) will be increased from > 571 psig (with the "c" footnote) to > 609 610 psig (with the "c" footnote) to reflect the replacement steam generators and associated setpoint calculations.

10.

The Allowable Value for Turbine Trip and Feedwater Isolation on SG Water Level High-High (ESFAS Function 5.c in TS Table 3.3.2-1) will be increased from < 79.8% of Narrow Range Instrument Span to < 91.4% of Narrow Range Instrument Span to reflect the replacement steam generators and associated setpoint calculations.

11.

The pressurizer pressure limit and RCS average temperature limit in TS 3.4.1, "RCS Pressure, Temperature, and Flow DNB Limits," are changed from > 2220 psig to > 2223 psig and from < 592.60F to < 590.10 F, respectively. These changes reflect the revised safety analysis limits for the replacement steam generators while maintaining allowances for measurement uncertainty for instrument loop indications that are unaffected by the proposed changes.

Attachment I Page 5 of 51

12.

Water levels used in the following LCOs will be revised to reflect the replacement steam generators and the associated indication instrument readings corresponding to the top of the SG tubes:

a. SR 3.4.5.2 in TS 3.4.5, "RCS Loops - MODE 3," will be changed from a SG secondary side narrow range water level reading of > 4% to > 7%.

b. SR 3.4.6.2 in TS 3.4.6, "RCS Loops - MODE 4," will be changed from a SG secondary side narrow range water level reading of> 4% to > 7%.

c. LCO 3.4.7.b and SR 3.4.7.2 in TS 3.4.7, "RCS Loops - MODE 5, Loops Filled," will be changed from a SG secondary side wide range water level reading of> 66% to> 86%.

13.

TS 3.4.13, "RCS Operational Leakage," is revised to reflect Revision 42 of TSTF-449.

14.

New TS 3.4.17, "SG Tube Integrity," is added to reflect Revision 42 of TSTF-449.

15.

Table 3.7.1-1 of TS 3.7.1, "Main Steam Safety Valves (MSSVs)," is revised to decrease the Maximum Allowable Power for 3 OPERABLE MSSVs per SG from

< 49% of Rated Thermal Power (RTP) to < 45% of RTP to reflect the replacement steam generators and associated safety analyses. A revised Loss of Load / Turbine Trip analysis covering operation with inoperable MSSVs was performed by Westinghouse for the RSG project. From the results of that analysis it was determined that operation with 3 OPERABLE MSSVs per steam generator could not be supported above 45% RTP.

16.

TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program," is retitled to "Steam Generator (SG) Program" and revised to reflect Revision 42 of TSTF-449.

17.

TS 5.5.16, "Containment Leakage Rate Testing Program," is revised to take exception to the requirement to perform an integrated leak rate test after installation of the replacement steam generators.

18.

TS 5.6.10, "Steam Generator Tube Inspection Report," is revised to reflect Revision 42 of TSTF-449.

Attachments 2 and 3 provide the TS markups reflecting the above changes and the retyped TS. Attachment 4 provides an information-only copy of the associated TS Bases changes, including the revised nominal trip setpoints associated with changes 6, 7, and 10 above in mark-ups to TS Bases Tables B 3.3.1-1 and B 3.3.2-1.

Attachment I Page 9 of 51 wastage, it is generally considered to be conservative for other mechanisms of SG tube degradation. The repair criterion does not allow licensees the flexibility to manage different types of SG tube degradation. Licensees must either use the through wall criterion for all forms of degradation or obtain approval for use of more appropriate repair criteria that consider the structural integrity implications of the given mechanism.

For the last several years, the industry, through the Electric Power Research Institute (EPRI) Steam Generator Management Program (SGMP), has developed a generic approach to improving SG performance referred to as "Steam Generator Degradation Specific Management" (SGDSM). Under this approach, different methods of inspection and different repair criteria may be developed for different types of degradation. A degradation specific approach to managing SG tube integrity has several important benefits. These include:

• improved scope and methods for SG inspection;

• industry incentive to continue to improve inspection methods; and

• development of plugging and repair criteria based on appropriate NDE parameters.

As a result, the assurance of SG tube integrity is improved and unnecessary conservatism is eliminated. Over the course of this effort, the SGMP has developed a series of EPRI guidelines that define the elements of a successful SG Program. These guidelines include:

• TR-107569, "Steam Generator Examination Guideline" (Reference 7.6),

• TR-1 07621, "Steam Generator Integrity Assessment Guideline" (Reference 7.7),

• TR-1 07620, "Steam Generator In-situ Pressure Testing Guideline" (Reference 7.8),

• TR-104788, "PWR Primary-to-Secondary Leak Guideline" (Reference 7.9),

• TR-105714, "Primary Water Chemistry Guideline" (Reference 7.10), and

• TR-102134, "Secondary Water Chemistry Guideline" (Reference 7.11).

These EPRI Guidelines, along with NEI 97-06 (Reference 7.12), tie the entire Steam Generator Program together, while defining a comprehensive, performance based approach to managing SG performance.

In parallel with the industry efforts, the NRC pursued resolution of SG performance issues. In December of 1998, the NRC Staff acknowledged that the Steam Generator Program described by NEI 97-06 and its referenced EPRI Guidelines provides an acceptable starting point to use in the resolution of differences between it and the staff's -

proposed Generic Letter and draft Regulatory Guide (DG-1074). Since then the industry and the NRC have participated in a series of meetings to resolve the differences and develop the regulatory framework necessary to implement a comprehensive Steam Generator Program.

Attachment I Page 10 of 51 Revising the existing regulatory framework to accommodate degradation specific management is the most appropriate way to address the issues of regulatory stability, resource expenditure, use of state-of-the-art inservice inspection techniques, repair criteria, and enforceability. The NRC Staff has stated that an integrated approach for addressing SG tube integrity is essential and that materials, systems, and radiological issues that pertain to tube integrity need to be considered in the development of the new regulatory framework.

TSTF-449 supports changes la, 13, 14, 16, and 18 in Section 2.0 above.

3.4 Post-Modification ILRT The Callaway Plant containment consists of the concrete reactor building, its steel liner, and the penetrations through this structure. The structure is designed to contain radioactive material that may be released from the reactor core following a design basis loss of coolant accident. Additionally, this structure provides shielding from the fission products that may be present in the containment atmosphere following accident conditions.

The containment is a pre-stressed reinforced concrete structure with a cylindrical wall, a flat foundation mat with a reactor cavity pit projection, and a hemispherical dome roof.

The inside surface of the containment is lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions.

The vertical cylinder wall is provided with a system of vertical and horizontal (hoop) tendons. Vertical tendons are continuous to form inverted U's that extend over the dome.

The configuration of the tendons in the dome is based on a three-way system consisting of two groups of vertical tendons oriented at 90 degrees with respect to each other and a horizontal (hoop) group extending from the spring line to approximately 45 degrees from the horizontal. Hoop tendons in both the wall and the dome are placed in a 240 degree system in which three tendons form two complete rings using three buttresses for anchoring the tendons.

During a design basis loss of coolant accident (LOCA) portions of the steam generators and lines emanating from their shells are relied upon to act as a barrier against the uncontrolled release of radioactivity to the environment. As such, the outer shell of the steam generators, the inside containment portions of lines emanating from the steam generator shells (the main steam lines, the main feedwater lines, the steam generator blowdown and sample lines), and the inside surface of the steam generator tubes are all considered part of the containment boundary. All of these components will be impacted by the steam generator replacement activities. Thus, replacing the steam generators will constitute a modification to the containment boundary.

Attachment I Page 19 of 51 Radiological Consequence Conclusions The replacement steam generators have a minimal impact on the doses calculated for the accidents listed above (i.e., where minimal is defined as an increase that is less than 10%

of the margin between the regulatory limit and the currently reported dose). In all cases, the doses associated with this project are less than the applicable regulatory limits.

Containment Pressure / Temperature Response Associated with SG Replacement The original Callaway containment evaluation model was based on the CONTEMPT code. A new Callaway containment evaluation model, based on the NRC approved containment evaluation model for Kewaunee, was built using the GOTHIC code. Most of the input data for the Callaway GOTHIC containment evaluation model was taken from the CONTEMPT LOCA and MSLB containment model input decks. The GOTHIC LOCA containment evaluation model contains input for service water cooled fan coolers, the containment spray, the major heat sinks, and recirculation cooling. The GOTHIC MSLB containment evaluation model does not require the recirculation cooling input.

The GOTHIC code and evaluation model input were compared with the CONTEMPT code and evaluation model input. Differences were identified in modeling condensation heat and mass transfer to the heat sinks, flashing of the liquid break flow, and condensation on the spray droplets. The heat and mass transfer correlations can be changed in GOTHIC to match the CONTEMPT models; however, GOTHIC does not have the same flashing or spray condensation models as CONTEMPT. To determine the effect of these differences, the GOTHIC Callaway containment evaluation model was modified for benchmark comparisons with the original CONTEMPT LOCA and MSLB containment evaluation models. In addition to various input changes required to add the mass and energy releases and change the heat transfer correlations, a circular flow path with drop de-entrainment was used to simulate the temperature flash option in CONTEMPT and the containment spray drop diameter input value was reduced by a factor of 1 0 to simulate the 1 00% spray efficiency in CONTEMPT. With these benchmarking changes, the GOTHIC model results were reasonably close to those predicted by CONTEMPT. For the LOCA event, GOTHIC predicted a 2.9 psi higher peak pressure and a slightly lower (1.00F) peak temperature. For the MSLB event, GOTHIC predicted a 4.36 psi higher peak pressure for the peak MSLB pressure case and a slightly lower (2.950F) peak temperature for the peak MSLB temperature case.

The GOTHIC Callaway containment evaluation model was used to produce sample results for the LOCA and MSLB transients using conservative mass and energy release data that is representative of Callaway.

A double-ended hot leg LOCA was assumed to be initiated from full power. A loss of offsite power and failure of an emergency diesel generator was assumed. In this analysis containment spray starts to inject at 44.74 43.7 seconds and the containment fan coolers start to remove heat at 61 seconds.

Page 20 of 51 The calculated peak containment pressure was 46.25 psig at 24 22 seconds. This is less than the containment design pressure of 60 psig and less than the peak pressure currently listed in FSAR Table 6.2.1-8 for LOCA Case 1 (47.3 psig) which will continue to be reported in the FSAR and used in all future operability determinations and 10 CFR 50.59 evaluations. The difference between 47.3 psig and 46.25 psig will be treated as available margin. The peak containment temperature was 271.87Ffor this LOCA casefefflained less than 2700 F for the entire transient. This is less than the peak temperature currently listed in FSAR Table 6.2.1-8 for LOCA Case 2 (308.60F) which will continue to be reported in the FSAR and used in all future operability determinations and 10 CFR 50.59 evaluations. The difference between 308.60F and 270271.8 0F will be treated as available margin.

The limiting MSLB event in terms of containment pressure is a split break at 0% power.

A loss of one containment spray pump and two containment fan coolers (one train of containment cooling) was assumed. In this analysis the fan coolers start to remove heat at 74.2 seconds and containment spray starts to inject at 227.9 seconds. The peak containment pressure for this case was 44.8 psig at 605 seconds. This is less than the containment design pressure of 60 psig and less than the peak pressure currently listed in FSAR Table 6.2.1-58 for MSLB Case 12 (48.1 psig) which will continue to be reported in the FSAR and used in all future operability determinations and 10 CFR 50.59 evaluations. The difference between 48.1 psig and 44.8 psig will be treated as available margin. The limiting MSLB event in terms of containment temperature is a double ended rupture at 102% power. An MSIV failure was assumed for this case. In this analysis the fan coolers start to remove heat at 63.1 seconds and containment spray starts to inject at 65.9 seconds. The peak temperature for this case was 352.8° F at.4920 seconds. This is less than the peak temperature currently listed in FSAR Table 6.2.1-58 for MSLB LOCA Case 6 (384.90F) which will continue to be reported in the FSAR and used in all future operability determinations and 10 CFR 50.59 evaluations. The difference between 384.90F and 352.80F will be treated as available margin.

Therefore, there will be no adverse impact on containment design or the qualification of equipment required to operate inside containment.

4.2 TTD Elimination This evaluation will address the impact of the trip time delay elimination in the following areas.

Instrumentation and Control The 7300 Process Protection System cabinets will be modified to eliminate the trip time delay function. The 7300 Process Protection System is part of the reactor protection system. The plant commitments in FSAR Section 7.1 to IEEE-279-1971 will continue to be met after the trip time delay function is eliminated from the 7300 Process Protection System.

Attachment I Page 24 of 51 The accident analysis acceptance criteria for the licensing basis as documented in the FSAR, and updated for RSG conditions in Appendix A of this amendment application, will be unaffected by the TTD elimination.

4.3 TSTF-449 Generic Licensing Change Package The proposed changes in TSTF-449 do not affect the method of operation of the steam generators nor the primary or secondary coolant chemistry controls. The primary coolant activity limit and its assumptions are not affected by the proposed TS changes. The proposed changes are an improvement to the existing SG inspection requirements and provide additional assurance that the plant licensing basis will be maintained between SG inspections.

A steam generator tube rupture (SGTR) event is one of the design basis accidents that are analyzed as part of a plant's licensing basis. The analysis of SGTR cases for Callaway assumes a bounding primary to secondary LEAKAGE rate of 1 gpm in the unaffected steam generators, in excess of the RCS Operational LEAKAGE rate limit in TS 3.4.13, plus the leakage rate associated with a double-ended rupture of a single tube in the ruptured SG.

For design basis accidents such as main steam line break (MSLB), rod ejection, and reactor coolant pump locked rotor, the SG tubes are assumed to retain their structural integrity (i.e., they are assumed not to rupture). These analyses assume that primary to secondary LEAKAGE for all SGs is 1 gallon per minute. For accidents that do not involve fuel damage, the reactor coolant activity levels are at the TS values. For accidents that do involve fuel damage, the primary coolant activity values are a function of the amount of activity released from the damaged fuel. The consequences of these design basis accidents are, in part, functions of the radioactivity levels in the primary coolant and the accident primary to secondary LEAKAGE rates. As a result, limits are included in the TS for RCS Operational LEAKAGE and for DOSE EQUIVALENT I-13 1 in the primary coolant to ensure the plant is operated within its analyzed condition. The current TS limit of 150 gallons per day of primary to secondary LEAKAGE through any one SG is based on operating experience as an indication of one or more tube leaks. 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. This LEAKAGE limit pro] ides assurance that leaking flaws w ill not propagate to burst prior to plant shutdown. The TS changes proposed in this amendment application are, in general, a significant improvement over the existing TS requirements. They replace an outdated prescriptive technical specification with one that references Steam Generator Program requirements that incorporate the latest knowledge of SG tube degradation morphologies and the techniques developed to manage them.

The requirements being proposed are more effective in detecting SG degradation and prescribing corrective actions than those required by existing TS. As a result, the proposed changes will result in added assurance of the function and integrity of SG tubes.

Page 25 of 51 RCS Operational LEAKAGE The primary to secondary LEAKAGE limit was previously reduced to 150 gallons per day through any one SG in Callaway Amendment 116 dated October 1, 1996. 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. This leakagc rate limit provides assurancc against tube rupture at normal operating and faulted conditions. This together with the allowable accident induced leakage limit helps to ensure that the dose contribution from tube leakage will be limited to less than the licensing basis limits for postulated faulted events.

This limit also contributes to meeting the GDC-14 requirement that the reactor coolant pressure boundary "have an extremely low probability of abnormal leakage, of rapidly propagating to failure, and of gross rupture." The revised Bases change for SR 3.4.13.2 references the Steam Generator Program. The Steam Generator Program uses the EPRI Primary-to-Secondary Leak Guideline (Reference 7.9) to establish sampling requirements for determining primary to secondary LEAKAGE and plant shutdown requirements if leakage limits are exceeded. The guidelines ensure leakage is effectively monitored and timely action is taken before a leaking tube exceeds the performance criteria. The Frequency for determining primary to secondary LEAKAGE is unchanged (i.e., 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishing steady state operating conditions).

The existing TS requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is physically more conservative than the analysis limit of 1 gpm total primary to secondary LEAKAGE through all SGs, used as initial condition in the radiological consequence analyses. From a dose consequence perspective, use of the 1 gpm leak rate is conservative.

RCS Operational LEAKAGE Actions If primary to secondary LEAKAGE exceeds 150 gallons per day through any one SG, a plant shutdown must be commenced. MODE 3 must be achieved in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The existing TS allow 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to reduce primary to secondary LEAKAGE to less than the limit. The proposed TS 3.4.13 change removes this allowance.

The removal of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period during which primary to secondary LEAKAGE can be reduced to avoid a plant shutdown results in a TS that is significantly more conservative than the existing RCS Operational LEAKAGE specification. This change is consistent with the Steam Generator Program that also does not allow 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> before commencing a plant shutdown.

RCS Operational LEAKAGE Determined by Water Inventory Balance The proposed change adds a second Note to SR 3.4.13.1 that makes the water inventory balance method not applicable to determining primary to secondary LEAKAGE. This change is proposed because primary to secondary LEAKAGE as low as 150 gallons per Page 26 of 51 day through any one SG cannot be measured accurately by an RCS water inventory balance.

SG Tube Integrity Verification The current SR 3.4.13.2 requires verification of tube integrity in accordance with the SG Tube Surveillance Program. This surveillance is no longer appropriate since tube integrity is addressed through the addition of new TS 3.4.17, SG Tube Integrity.

Specification 3.4.13 now applies specifically to primary to secondary LEAKAGE. SR 3.4.13.2 has been changed to verify the LCO requirement on primary to secondary LEAKAGE only. Steam generator tube integrity is verified in accordance with SR 3.4.17.1 in new TS 3.4.17.

The Steam Generator Program and the EPRI "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines" (Reference 7.9) provide guidance on leak rate monitoring.

During normal operation the program depends upon continuous process radiation monitors and/or radiochemical grab sampling in accordance witth the methodology of the EPRI guidelines. The monitoring and sampling frequency increases as the amount of detected LEAKAGE increases or if there are no continuous radiation monitors available.

Primary to secondary LEAKAGE is determined through the analysis of secondary coolant aetivity lerves. At low pew pm.

nd secondafy coclant activity is be difficult. immediately after-shutdown, seme f the short lived isetFpAs afc usually at sufficient levels to monitor for LEAKAGE by normal poewcr operational means as long as other plant conditions allow the measuremcnt. During startup, especially after a long outage, there arc no short lived isotopes in either the primary or secondary system. This limits measuremcet of the LEAKAGE to chemical or-long lie ed r-adieehemieal means-.

Beeause of these effects, an accurate pr-imar-y to secondar-y leakage measur-ment is highly dependent upon plant conditions and may not be obtainable pr-ior to reactor criticality (e.g., MODES 1 and 2). if SG water sampils arc less than the minimum detectable activity for-each pr-incipal gamma emitter-, primary to secondar-y LEAKAXGE may be assumed to be less than or cqual to 150 gallons per day through any one SG.

Determination of the primary to secondary LEAKAGE is required every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Revised SR 3.4.13.2 is modified by a Note stating the SR 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 operating conditions. As stated above, additional monitoring of primary to secondary LEAKAGE is also required by the Steam

'r,--

rm r3 _-

a A, 7

Page 28 of 51 length of time that the SGs can be operated and still provide reasonable assurance that the performance criteria will be met at the next inspection. The actual interval is the shorter of the evaluation results and the requirements in Reference 7.7. Allowing plants to use the proposed inspection intervals maximizes the potential that plants will use improved techniques and knowledge since better knowledge of SG conditions supports longer intervals.

SG Tube Sample Selection The existing TS base tube selection on SG conditions and industry and plant experience.

The minimum sample size is 3% of the tubes times the number of SGs in the plant. The proposed change refers to the Steam Generator Program degradation assessment guidance for sampling requirements. The minimum sample size is 20% of all the tubes in the four steam generators.

The Steam Generator Program requires the preparation of a degradation assessment.

before evefry SG inspection. The degradation assessment is the key document used for planning a SG inspection, where inspection plans and related actions are determined, documented, and communicated

. The degradation assessment addresses the various reactor coolant pressure boundary components within the SG (e.g.,

plugs, tubes, and components that support the pressure boundary). In a degradation assessment, tube sample selection is performance based and is dependent upon actual SG conditions and plant operational experience and of the industry in general. Existing and potential degradation mechanisms and their locations are evaluated to determine which tubes will be inspected. Tube sample selection is adjusted to minimize the possibility that tube integrity might degrade during an operating cycle beyond the limits defined by the performance criteria. The EPRI Steam Generator Examination Guidelines (Reference 7.6) and EPRI Steam Generator Integrity Assessment Guidelines (Reference 7.7) provide guidance on degradation assessment.

In general, the sample selection considerations required by the existing TS and the requirements in the Steam Generator Program as proposed herein are consistent, but the Steam Generator Program provides more guidance on selection methodologies and incorporation of industry experience and requires more extensive documentation of the results. Therefore the sample selection method proposed herein is more conservative than the existing TS requirements. In addition, the minimum sample size in the proposed requirements is larger.

SG Inspection Techniques The Surveillance Requirements proposed in new TS 3.4.17 require that tube integrity be verified in accordance with the requirements of the Steam Generator Program. The Steam Generator Program uses the EPRI Steam Generator Examination Guidelines (Reference 7.6) to establish requirements for qualifying NDE techniques and maintains a list of qualified techniques and their capabilities.

Attachment I Page 29 of 51 The Steam Generator Program requires the performance of a degradation assessment before c] cvr SG inspection and refers utilities to EPRI Steam Generator Examination Guidelines (Reference 7.6) and EPRI Steam Generator Integrity Assessment Guidelines (Reference 7.7) for guidance on its performance. The degradation assessment will identify current and potential new degradation locations and mechanisms and NDE techniques that are effective in detecting their existence. Tube inspection techniques are chosen to reliably detect flaws that might progress during an operating cycle beyond the limits defined by the performance criteria.

SG Inspection Scone The existing TS include a definition of inspection that specifies the end points of the eddy current examination of each tube. Typically an inspection is required from the point of entry of the tube on the hot leg side to some point on the cold leg side of the tube, usually at the first tube support plate after the U-bend. This definition is overly prescriptive and simplistic and has led to interpretation questions in the past.

The Steam Generator Program states:

"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, and d.3 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."

The Steam Generator Program provides extensive guidance and a defined process, the degradation assessment, for determining the extent of a tube inspection. This guidance takes into account industry and plant specific history to determine potential degradation mechanisms and the location that they might occur within the SG. This information is used to define a performance based inspection scope targeted on plant specific conditions and SG design.

The proposed change is an improvement over the existing TS because it focuses the inspection effort on the areas of concern, thereby minimizing the unnecessary data that the NDE analyst must review to identify indication of tube degradation.

Page 30 of 51 SG Performance Criteria The proposed change adds TS 5.5.9, a performance-based Steam Generator Program. A performance-based approach has the following attributes:

• measurable parameters;

• objective criteria to assess performance based on risk-insights;

• deterministic analysis and/or performance history; and

• licensee flexibility to determine how to meet established performance criteria.

The performance criteria used for SGs are based on tube structural integrity, accident induced leakage, and operational LEAKAGE. The structural integrity and accident induced leakage criteria were developed deterministically and are consistent with the plant's licensing basis. The operational LEAKAGE criterion was based on providing an effective meastire for minimizing the frequency of tube ruptures added assuranc-against 4bbe iuptufe-at normal operating and faulted conditions. The proposed structural integrity and accident induced leakage performance criteria are new requirements. The performance criteria are specified in revised TS 5.5.9. The requirements and methodologies established to meet the performance criteria are documented in the Steam Generator Program. The existing TS contain only the operational LEAKAGE criterion; therefore the proposed change is more conservative than the current requirements.

The SG performance criteria identify the standards against which performance is to be measured. Meeting the performance criteria provides reasonable assurance that the SG tubing will remain capable of fulfilling its specific safety function of maintaining RCPB integrity throughout each operating cycle.

The structural integrity performance criterion is:

"All inservice 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 cooldown, and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 (3AP) 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."

The structural integrity performance criterion is based on providing reasonable assurance that a SG tube will not burst during normal operation or postulated accident conditions.

Adjustments to include contributing loads are addressed in the applicable EPRI

Page 32 of 51 orders of magnitude. The NRC has concluded (Item Number 3.4 in Attachment 1 to Reference 7.17) that additional research is needed to develop an adequate methodology for fully predicting the effects of leakage on the outcome of some accident sequences.

Therefore, a separate performance criterion was established for accident induced leakage.

The limit for accident induced leakage at Callaway is 1 gpm.

The operational LEAKAGE performance criterion is:

"The RCS Operational primary to secondary LEAKAGE through any one steam generator shall be limited to 150 gallons per day."

Plant shutdown will commence if primary to secondary LEAKAGE exceeds 150 gallons per day at room temperature conditions from any one SG. The operational LEAKAGE performance criterion is documented in the Steam Generator Program and implemented in TS 3.4.13, "RCS Operational LEAKAGE." Changes proposed to TS 5.5.9 contain the performance criteria and is more conservative than the existing TS. The existing TS do not address the structural integrity and accident induced leakage criteria.

SG Repair Criteria Repair criteria are those NDE measured parameters at or beyond which the tube must, for the Callaway RSGs, be removed from service by plugging.

Tube repair criteria are established for each active degradation mechanism. Tube repair criteria are either the standard through-wall depth-based criterion (e.g., 40% through-wall for Callaway) or through-wall depth based criteria for repair techniques approved by the NRC, or other Alternate Repair Criteria (ARC) approved by the NRC such as a voltage-based repair limit per Generic Letter 95-05 (Reference 7.18). A SG degradation-specific management strategy is followed to develop and implement an ARC. Previously approved tube sleeving techniques have not been approved by NRC as applicable to the RSGs and, therefore, have been deleted in revised TS 5.5.9.

The surveillance requirements of the proposed Steam Generator Tube Integrity TS 3.4.17 require that tubes that satisfy the tube repair criteria be plugged since Callaway has not licensed an ARC for the replacement steam generators yet to be installed. SG tubes experiencing a damage form or mechanism for which no depth sizing capability exists are "repaired/plugged-on-detection" and their integrity assessed. It cannot be guaranteed that every flaw will be detected with a given eddy current technique and, therefore, it is possible that some flaws will not be detected during an inspection. If a flaw is discovered and it is determined that this flaw would have satisfied the repair criteria at the time of the last inspection of the affected tube, this does not mean that the Steam Generator Program was violated. However, it may be an indication of a shortcoming in the inspection program.

Page 34 of 51 If performance or repair criteria are exceeded while shutdown, the affected tubes must be plugged at Callaway. If the number of degraded tubes exceeds 1% of those inspected in any SG, a report will be submitted to the NRC in accordance with revised TS 5.6.10. The changes in the required reports are discussed below.

SG Repair Methods Repair methods are those means used to reestablish the RCS pressure boundary integrity of SG tubes without removing the tube from service. Plugging a SG tube is not a repair.

The purpose of a repair is typically to reestablish or replace the RCPB. The proposed Steam Generator Tube Integrity surveillance requirements in new TS 3.4.17 require that tubes that satisfy the tube repair criteria be plugged at Callaway in accordance with the Steam Generator Program. There are no repair methods listed in revised TS 5.5.9 for the replacement steam generators yet to be installed at Callaway.

Steam generator tubes experiencing a damage form or mechanism for which no depth sizing capability exists are "fepaiked'plugged-on-detection" and their integrity is assessed. This requirement is unchanged by the proposed TS revisions.

Note that SG plug designs do not require NRC review and, therefore, plugging is not considered a repair in the context of this requirement. The proposed approach is not a change to the existing TS.

Reporting Requirements The existing TS require the following reports:

• A report listing the number of tubes plugged or repaired in each SG submitted within 15 days of the end of the inspection.

• A SG inspection results report submitted within 12 months after the inspection.

• Reports required pursuant to 10 CFR 50.73.

The proposed changes to TS 5.6.10 replace the 15 day and the SG inspection reports with one report required within 180 days. if greater than one percent of the tubes inspected in any one SG exezed a repair criterion. The proposed report also contains more information than the current SG inspection report. This provision expands limits-the reports to submitted to the NRC to those documenting more extensi;'e degradation, requires that the reports that are submitted provide more substantive information and will be sent earlier (180 days versus 12 months). This allows the NRC to focus its attention on the more significant conditions.

The guidance in NUREG-1022, Rev. 2, "Event Reporting Guidelines 10 CFR 50.72 and 50.73," identifies serious SG tube degradation as an example of an event or condition that results in the condition of the nuclear power plant, including its principal safety barriers, Page 35 of 51 being seriously degraded. Steam generator tube degradation is considered serious if the tubing fails to meet the structural integrity or and-accident induced leakage performance criteria. Serious SG tube degradation would be reportable in accordance with 10 CFR 50.72(b)(3)(ii)(A) and 50.73(a)(2)(ii)(A) requiring NRC notification and the submittal of a report containing the cause and corrective actions to prevent recurrence.

The proposed reporting requirements are an improvement as compared to those required by the existing TS. The proposed reporting requirements are more useful in identifying the degradation mechanisms and determining their effects. In the unlikely event that a performance criterion is not met, NEI 97-06 (Reference 7.12) directs the licensee to

-submit additional information on the root cause of the condition and the basis for the next operating cycle.

The changes to the reporting requirements are performance based. The new requirements remove the burden of unnecessary reports from both the NRC and the licensee, while ensuring that critical information related to problems and significant tube degradation is reported more completely and, when required, more expeditiously than under the existing TS.

SG Terminology The proposed Bases for new TS 3.4.17, "Steam Generator Tube Integrity," explain a number of terms that are important to the function of a Steam Generator Program. The terms are described below.

1.

Accident induced leakage rate means the primary to secondary LEAKAGE rate occurring during postulated accidents other than a steam generator tube rupture.

This includes the primary to secondary LEAKAGE rate existing immediately prior to the accident plus additional primary to secondary LEAKAGE induced during the accident.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a limiting design basis accident. The potential primary to secondary leak rate during postulated design basis accidents must not cause radiological dose consequences in excess of approved licensing basis limits.

2.

The LCO section of the bases for new TS 3.4.17 defines the term "burst" 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."

Since a burst definition is required for condition monitoring, a definition that can be analytically defined and is capable of being assessed via in pitu and laboratory testing is necessary. Furthermore, the definition must be consistent with ASME

Attachment I Page 36 of 51 Code requirements, and apply to most forms of tube degradation.

The definition developed for tube burst is consistent with the testimony of James Knight (Reference 7.19), and the historical guidance of draft Regulatory Guide 1.121 (Reference 7.20). The definition of burst per these documents is in relation to gross failure of the pressure boundary; e.g., "the degree of loading required to burst or collapse a tube wall is consistent with the design margins in Section III of the ASME B&PV Code (Reference 7.21)." Burst, or gross failure, according to the Code would be interpreted as a catastrophic failure of the pressure boundary.

The above definition of burst was chosen for a number of reasons:

• The burst definition supports field application of the condition monitoring process. For example, verification of structural integrity during condition monitoring may be accomplished via in situ testing. Since these tests do not have the capability to provide an unlimited water supply, or the*

capability to maintain pressure under certain leakage scenarios, opening area may be more a function of fluid reservoir rather than tube strength.

Additionally, in situ designs with bladders may not be reinforced. In certain cases, the bladder may rupture when tearing or extension of the defect has not occurred. This condition may simply mean the opening of the flanks of the defect was sufficient to permit extrusion of the bladder, and that the actual, or true, burst pressure was not achieved during the test.

The burst definition addresses this issue.

• The definition does not characterize local instability or "ligament pop-through", as a burst. The onset of ligament tearing need not coincide with the onset of a full burst. For example, an axial crack about 0.5" long with a uniform depth at 98% of the tube wall would be expected to fail the remaining ligament (i.e., extend the crack tip in the radial direction) due to deformation during pressurization at a pressure below that required to cause extension at the tips in the axial direction. Thus, this would represent a leakage situation as opposed to a burst situation and a factor of safety of three against crack extension in the axial direction may still be demonstrated. Similar conditions have been observed for localized deep wear indications.

3.

The LCO section of the new TS 3.4.17 Bases defines a SG tube as, "the entire length of the tube, including the tube wall, 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."

This definition ensures that all portions of SG tubes that are part of the RCPB, with the exception of the tube-to-tubesheet weld, are subject to Steam Generator Program requirements. The definition is also intended to exclude tube ends that

Attachment I Page 37 of 51 can not be NDE inspected by eddy current. If there are concerns in the area of the tube end, they will be addressed by NDE techniques if possible or by using other methods if necessary.

For the purposes of SG tube integrity inspection, any weld metal in the area of the tube end is not considered part of the tube. This is necessary since the acceptance requirements for tubing and weld metals are different.

4.

The LCO section of the new TS 3.4.17 Bases defines the term "collapse" 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."

In dealing with pure pressure loadings, burst is the only failure mechanism of interest. If bending loads are introduced in combination with pressure loading, the definition of failure must be broadened to encompass both burst and bending collapse. Which failure mode applies depends on the relative magnitude of the pressure and bending loads and also on the nature of any flaws that may be present in the tube. Guidance on assessing applicable failure modes is provided in the EPRI steam generator guidelines.

5.

The LCO section of the new TS 3.4.17 Bases defines the term "significant" as used in the structural integrity performance criterion 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."

6.

The LCO section of the new TS 3.4.17 Bases describes how to determine whether thermal loads are primary or secondary loads. The description is based on the

-ASMAE definition in which secondary loads are self limiting and will not cause failure under single load application. For steam generator 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.

Conclusion The proposed changes will provide greater assurance of SG tube integrity than that offered by the existing TS. The proposed requirements are performance-based and provide the flexibility to adopt new technology as it matures. These changes are consistent with the guidance in NEI 97-06, "Steam Generator Program Guidelines,"

(Reference 7.12). Adopting the proposed changes will provide added assurance that SG tubing will remain capable of fulfilling its specific safety function of maintaining RCPB integrity.

Page 39 of 51 would be to eliminate the post-modification containment leakage rate (Type A) testing required after the modification to the containment boundary, specifically associated with the steam generator replacement.

4.5 Balance of Plant Evaluations A review of systems, structures, and components that could be affected by steam generator replacement activities has been performed. For example, the following systems and analyses were reviewed by SGT, a contractor for the RSG project:

Main Steam Line Differential Pressure; Containment Cooling and HVAC; Containment Spray System; Sump pH verification; Time to Boil; Natural Circulation; Essential Service Water; Secondary Chemical Addition System; Secondary Sample System; Steam Generator Blowdown System; High Energy Line Breaks at Callaway; and Callaway RSG Radiological Consequences.

The above areas, as well as other plant calculations and documents, were evaluated for the RSG conditions. Any changes needed to support systems can be accomplished without a Technical Specification change or prior NRC approval.

5.0 REGULATORY SAFETY ANALYSIS This section addresses the standards of I0CFR50.92 as well as the applicable regulatory requirements and acceptance criteria.

5.1 NO SIGNIFICANT HAZARDS CONSIDERATION (NSHC)

The proposed amendment would revise the following Technical Specifications (TS) in support of replacement steam generators to be installed during Refuel 14 (fall 2005):

• TS 1.1, "Definitions";

• TS 2.1.1, "Reactor Core Safety Limits";

• TS 3.3.1, "Reactor Trip System (RTS) Instrumentation";

• TS 3.3.2, "Engineered Safety Feature Actuation System (ESFAS)

Instrumentation";

• TS 3.4.1, "RCS Pressure, Temperature, and Flow DNB Limits";

Page 40 of 51

• TS 3.4.5, "RCS Loops - MODE 3";

• TS 3.4.6, "RCS Loops - MODE 4";

• TS 3.4.7, "RCS Loops - MODE 5, Loops Filled";

• TS 3.4.13, "RCS Operational Leakage";

• TS 3.7.1, "Main Steam Safety Valves";

• TS 5.5.9, "Steam Generator (SG) Tube Surveillance Program";

• TS 5.5.16, "Containment Leakage Rate Testing Program"; and

• TS 5.6.10, "Steam Generator Tube Inspection Report."

In addition, the proposed amendment would add new TS 3.4.17, "Steam Generator Tube Integrity," pursuant to Technical Specification Task Force (TSTF) Improved Standard Technical Specifications Change Traveler TSTF-449 Revision 42a.

The proposed changes do not involve a significant hazards consideration for Callaway Plant based on the three standards set forth in IOCFR50.92(c) as discussed below:

(1)

Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No Nuclear Steam Supply System Evaluations for Replacement Steam Generators As discussed in the NSSS Licensing Report (Appendix A to this amendment application),

all acceptance criteria continue to be met. All major NSSS components (e.g., Reactor Vessel, Pressurizer, RCPs, Steam Generators, etc.) have been assessed with respect to bounding conditions expected for replacement steam generator (RSG) conditions. In all cases operation has been found to be acceptable. Major systems and subsystems (e.g.,

safety injection, RHR, etc.) have been reviewed and acceptable performance has been verified for their normal operation and, as applicable, for their safety-related functions.

All reactor trip and ESFAS actuation setpoints have been assessed, and the proposed setpoint modifications will assure adequate protection is afforded for all design basis events.

The reactor core safety limits have been revised based on the RSG project parameters.

All of the acceptance criteria for the accident analyses (e.g., DNBR limits, fuel centerline temperatures, etc.) continue to be met with the revised safety limit lines. Therefore, the revised core safety limit line changes are acceptable. The proposed changes to the reactor core safety limits will not initiate any accidents; therefore, they do not increase the probability of an accident previously evaluated in the FSAR. The comprehensive analytical efforts performed to support the proposed RSG conditions include a reanalysis or evaluation of all accident analyses that are impacted by the revised reactor core safety limits.

Page 49 of 51 protection systems that they automatically initiate appropriate protective action whenever a condition monitored by the system reaches a preset level, i.e., the nominal Trip Setpoint.

NRC Regulatory Guide (RG) 1.105 discusses accepted practices for the treatment of instrument setpoints. Callaway's compliance with RG 1.105 is described in FSAR Appendix 3A.

There are no changes being proposed such that compliance with any of the regulatory requirements and commitments above would come into question. The evaluations documented above and attached hereto confirm that Callaway Plant will continue to comply with all applicable regulatory requirements.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

AmerenUE has determined that the proposed amendment would change requirements with respect to the installation or use of a facility component located within the restricted area, as defined in IOCFR20, or would change an inspection or surveillance requirement.

However, AmerenUE has evaluated the proposed amendment and has determined that the amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amount of effluent that may be released offsite, or (iii) a significant increase in the individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 1 OCFR51.22 (c)(9). Therefore, pursuant to 1 OCFR51.22 (b), an environmental assessment of the proposed amendment is not required.

7.0 REFERENCES

7.1 Technical Specification Task Force (TSTF) Improved Standard Technical Specifications Change Traveler TSTF-449, Revision 42, "SG Tube Integrity."

7.2 ULNRC-04592 dated June 27,2003 and ULNRC-04928 dated December 12, 2003.

7.3 Callaway License Amendment Number 159 dated March 11, 2004.

ATTACHMENT 2 MARKUP OF TECHNICAL SPECIFICATIONS

Definitions 1.1 1.1 Definitions (continued)

ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water leakoff), that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or seeo<44y

)

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator4($e to the Secondary System

b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except-s,LEAKAGE) through a nonisolable fault in an RCS comp1 ent body, pipe wall, or vessel wall.

f r-7114 7 recaol ay (continued)

CALLAWAY PLANT 1.1-3 Amendment No. 133

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE'a>

9.

Pressurizer Water Level - High 3

M SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 M

SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16

10.

Reactor Coolant Flow-Low 11g) 3 per loop s 93.8% of instrument span

Ž 88.8%la JZ T/,d ca--4 /O~f

-rA/r0S~1 "

11.

Not Used

12.

Undervoltage RCPs

13.

Underfrequency RCPs 1(9)

I (9) 21bus 2/bus M

SR 3.3.1.9 SR 3.3. 1.10 SR 3.3.1.16 M

SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.16 2 10105Vac 2 57.1 Hz

14.

Steam Generator (SG) Water Level Low-Lowv

a.

Steam Generator Water Level Low-Low (Adverse Containment Environment)

b.

Steam Generator Water Level Low-Low (Normal Containment Environment) 1,2 4perSG 1°,2" 4 per SG E

SR 3.3.1.1 SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 E

SR 3.3.1.1 Sft 3.3.1.7 SR 3.3.1.10 SR 3.3.1.16 4zo. (0 %

Narrow Range Instrument Span

/ 6. 6 0/

2 4of Narrow Range Instrument Span (I

I

') I I

iZ cc (continued)

(a)

(g)

(I)

(m)

(p)

(e)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Above the P-7 (Low Power Reactor Trips Block) interlock.

The applicable MODES for these channels in Table 3.3.2-1 are more restrnicve.

OS 0f loop minimum m flow (MPMF - 9',C60 gpm)

A/VeL urtea Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

-CNXERT I I

CALLAWAY PLANT 3.3-1 9 Amendment No. 157

INSERT I If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(")

1.

Safety Injection

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays (SSPS)

c.

Containment Pressure -

. High 1

d.

Pressurizer Pressure -

Low 1,2.3,4 1.2,3,4 1.2,3 1,2,3(b) 2 2 trains 3

4 B

SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 SR 3.3.2.13 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA s4.5psig 2 1834 psig

e.

Steam Line Pressure -

Low 1,2.3()

3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 2 &,Psig'

) CS) 10

(

2.

Containment Spray

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation

• Relays (SSPS)

c.

Containment Pressure High - 3 1,2,3.4 1.2,3,4 1.2,3 2 per train.

2 trains 2 trains 4

B SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA S 28.3 psig (continued)

(a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(b) Above the P-11 (Pressurizer Pressure) interlock and below P-11 unless the Function is blocked.

(c) Tlime constants used in the leadAag controller are rX Ž 50 seconds and 12 S 5 seconds.

(s) rErRV

/.

I CALLAWAY PLANT 3.3-38 Amendment No. 165 l

INSERT 1 If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE'a)

4. Steam Line Isolation

a. Manual Initiation

b. Automatic Actuation Logic and Actuation Relays (SSPS)

c. Automatic Actuation Logic and Actuation Relays (MSFIS)

d. Containment Pressure - High 2 1 24, 3Y 1,2') 3Y)

1. 2i' 30) 1.2r' 3(i' 2

2 trains 2 trains(c) 3 F

SR 3.3.2.8 G

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 S

SR 3.3.2.3 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA NA s 18.3 psig I

e. Steam Line Pressure (1)

Low 1,2 n, 3cX' 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 2t 91psig(c) es) 6o/0 I

(2) Negative Rate - High 3(9)X 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 s 124 psi>'

(continued)

(a)

(b)

(c)

(9)

(h)

(i)

(o)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Above the P-1I (Pressurizer Pressure) Interlock and below P-11 unless the Function is blocked.

Time constants used in the lead/lag controller are 't, Ž 50 seconds and t.z 5 5 seconds.

Below the P-1l(Pressurizer Pressure) Interlock; however, may be blocked below P-1I when safety injection on low steam line pressure is not blocked.

Time constant utilized in the rate/lag controller is 2 50 seconds.

Except when all MSIVs are closed.

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

s-) RxAMSE-I I

CALLAWAY PI-ANT 3.3-40 Amendment No. 165

INSERT 1 If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

ESFAS Instrumentation 3.3.2 Thhlp ' 'A ?-l Innnp 4 nf Ra

INSERT 1 If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE"')

5. Turbine Trip and Feedwater Isolation

e. Steam Generator Water Level Low-Low"q)

(continued)

(2)

Steam Generator Water Level Low-Low (Normal Containment Environment) 1"i) 2'¢') 3°J')

4per SG D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

% (S) 2t 409-4 ~of Narrow Range Instrument Span (3) eeV T-NVo4-IAr e.l

.m..-

T Tri 4

f r 1elar

-(Powei cr1 -GR 3.3.?-

cn 9.3.2.5 sR 3.3.2..

-Ni-

-SR B.B2+I GRc.3.2.5 GR 3.3.2.9 SR3 3.2.1E qui. n lo-44ewe 4Ptere (4) Containment Pressure -

Environmental Allowance Modifier 1, 2. 3 4

N SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 s 2.0 psig (continued)

(a) a)

(k)

(I)

(q)

(r)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Except when all MFIVs are dosed.

WAih a timc delay 240 soends J"A/4L £tgj-&

Witlh time daoi' c 130 coconds. NVo-I-Iurea{.

Feedwater isolation only.

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

(S)

I/CAAETRT /

I CALLAWAY PLANT 3.3-42 Amendment No. 165 l

INSERT 1 If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 6 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION SPECIFIED CHANNELS CONDITIONS REQUIREMENTS VALUE'a)

CONDITIONS

6. Auxiliary Feedwater

a. Manual Initiation

b. Automatic Actuation Logic and Actuation Relays (SSPS)

c. Automatic Actuation Logic and Actuation Relays (BOP ESFAS) 1, 2.3 1.2.3 1,2.3 lpump 2 trains 2 trains P

SR 3.3.2.8 G

SR 3.3.2.2

• SR 3.3.2.4 SR 3.3.2.6 Q

SR 3.3.2.3 NA NA NA

d. SG Water Level Low-Low (1)

Steam Generator Water Level Low-Low (Adverse Containment Environment)

(2) Steam Generator Water Level Low-Low (Normal Containment Environment)

1. 2,3 4 per SG D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 Narrow Range Instrument Span

/D,; /0/a) 2 4O of Narrow Range Instrument Span I

I". 2". 3"f) 4 per SG (continued)

(a)

(r)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

Cs).CNffeR4

/

I CALLAWAY PLANT 3.3-43 Amendment No. 165 l

INSERT 1 If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE:.

b.

I gpm unidentified LEAKAGE;

c.

10 gpm identified LEAKAGE; Onog

-+-*

000 gllOM nc par d 0,'

oI-primty to tcowndwy' 66AKAGC tlhrewghl C(, 150 allons per day primary to secondary LEAKAGE through any oneS,69 I

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS COMPLETION CONDITION REQUIRED ACTION TIME 0frA,4vDr^i A. RCSVLEAKAGE not wittin A1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limits for reasons other within limits.

than pressure boundary L{EAKAG[;,0rj-,rro r

ec B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

OR Pressure boundary B.2 Be in MODE 5.

36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

_AEAKAGE exists.

CA rLLA -W L AN coTw y 3.A CALLAWAY PLANT 3.,.4-30 Amendment No. 133

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS k SITI

-[ML I to-Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of 7 days satisfying the tube the affected tube(s) is repair criteria and not maintained until the next plugged in accordance refueling outage or with the Steam inspection.

Generator Program.

AND A.2 Plug the affected tube(s)

Prior to entering in accordance with the MODE 4 following Steam Generator the next refueling Program.

outage or SG tube inspection B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A AND not met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.

CALLAWAY PLANT 3.4-44 Amendment No.

Programs and Manuals 5.5 5.5 Pro-rams and Manuals i

5.5.16 Containment Leakaae Rate Testinr Program (continued)

2.

The visual examination of the steel liner plate Inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J.

Option B testing, will be performed in accordance with the requirements of and frequency specified byASME Section Xl Code, Subsection IWE, except where relief has been authorized by the NRC.

The peak calculated containment internal pressure for the design basis loss of coolant accident, P., is 48.1 psig.

7VX:4E-rb

,57.6. /I*

b.

(-re re v;[re/

{',4e rL4 )

c The maximum allowable containment leakage rate, L, at P,, shall be 0.20% of the containment air weight per day.

d.

Leakage rate acceptance criteria are:

1 Containment leakage rate acceptance criterion is

• 1.0 L.. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 L. for the Type B and C tests and

• 0.75 L, for Type A tests;

2.

Air lock testing acceptance criteria are:

a)

Overall air lock leakage rate is *0.05 L. when tested at

ŽPs:

(

b)

For each door, leakage rate is s 0.005 L. when pressurized to 2 10 psig.

e.

The provisions or Technical Specification SR 3.0.2 do not apply to the test frequencies in the Containment Leakage Rate Testing Program.

f.

The provisions of Technical Specification SR 3.0.3 are applicable'to the Containment Leakage Rate Testing Program.

CALLAWAY PLANT 5.0-27 Amendment No. 160

INSERT 5.5.16

3.

The unit is excepted from post-modification integrated leakage rate testing requirements associated with steam generator replacement during the Refuel 14 l

outage (fall of 2005).

I

ATTACHMENT 3 RETYPED TECHNICAL SPECIFICATIONS

Definitions 1.1 1.1 Definitions (continued)

ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water leakoff), that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE);

b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

I (continued)

CALLAWAY PLANT 1.1-3 Amendment No. ###

RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(')

9.

Pressurizer Water 1(9) 3 M

SR 3.3.1.1 s 93.8% of Level - High SR 3.3.1.7 instrument SR 3.3.1.10 span

10.

Reactor Coolant 1(9) 3 per loop M

SR 3.3.1.1 2 88.8% of Flow-Low SR 3.3.1.7 indicated loop SR 3.3.1.10 flow SR 3.3.1.16

11.

Not Used

12.

Undervoltage 1(9l 2/bus M

SR 3.3.1.9 2 10105 Vac RCPs SR 3.3.1.10 SR 3.3.1.16

13.

Underfrequency 1(g) 2/bus M

SR 3.3.1.9 2 57.1 Hz RCPs SR 3.3.1.10 SR 3.3.1.16

14.

Steam Generator (SG) Water Level Low-Low")

a. Steam 1, 2 4 per SG E

SR 3.3.1.1 2 20.6%q) of Generator SR 3.3.1.7 Narrow Range Water Level SR 3.3.1.10 Instrument Low-Low SR 3.3.1.16 Span (Adverse Containment Environment)

b. Steam 1°"P,2°P 4 per SG E

SR 3.3.1.1 2 16.6%(q) of Generator SR 3.3.1.7 Narrow Range Water Level SR 3.3.1.10 Instrument Low-Low SR 3.3.1.16 Span (Normal Containment Environment)

(continued)

I I

I (a) The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

(g) Above the P-7 (Low Power Reactor Trips Block) interlock.

(I)

The applicable MODES for these channels in Table 3.3.2-1 are more restrictive.

(m)

Not used.

I (p) Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

(q) If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

CALLAWAY PLANT 3.3-1 9 Amendment No. ::::::

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(')

1.

Safety Injection

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays (SSPS)

c.

Containment Pressure -

High 1

d.

Pressurizer Pressure -

Low 1,2,3,4 1.2,3,4 1,2,3 1,203) 2 2 trains 3

4 B

SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 SR 3.3.2.13 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA

• 4.5 psig 2 1834 psig

e.

Steam Line Pressure -

Low 1,2,3° 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 2 610 psig(C) Cs)

I

2.

Containment Spray

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays (SSPS)

c.

Containment Pressure High - 3 1,2,3,4 1,2,3.4 1,2,3 2 per train, 2 trains 2 trains 4

B SR 3.3.2.8 C

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 E

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA

• 28.3 psig (continued)

(a)

(b)

(c)

(s)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Above the P-1I (Pressurizer Pressure) interlock and below P-11 unless the Function is blocked.

Time constants used in the lead/ag controller are Ar 2 50 seconds and z2 *5 seconds.

If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

CALLAWAY PLANT 3.3-38 Amendment No. #

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a)

FUNCTION

4. Steam Line Isolation

a. Manual Initiation

b. Automatic Actuation Logic and Actuation Relays (SS PS)

c. Automatic Actuation Logic and Actuation Relays (MSFIS)

d. Containment Pressure - High 2 1,201, 3c) 1,2(l, 3a) 1, 2fi),

1,2n', 30° 2

2 trains 2 trains(O) 3 F

SR 3.3.2.8 G

SR 3.3.2.2 SR 3.3.2.4 SR 3.3.2.6 S

SR 3.3.2.3 D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 NA NA NA

• 18.3 psig

e. Steam Line Pressure (1) Low 1,2 °, 3°°)01 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10 2 610 psig(c) (S)

I (2) Negative Rate - High 3(g)(0 3 per steam line D

SR 3.3.2.1 SR 3.3.2.5 SR 3.3.2.9 SR 3.3.2.10

• 124 psi(t)

(continued)

(a)

(b)

(c)

(9)

(h)

(i)

(o)

(s)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Above the P-1I (Pressurizer Pressure) Interlock and below P-1I unless the Function is blocked.

Time constants used in the lead/lag controller are sr 2 50 seconds and T2 5 seconds.

Below the P-11 (Pressurizer Pressure) Interlock; however. may be blocked below P-11 when safety injection on low steam line pressure is not blocked.

Time constant utilized in the rate/lag controller is 2 50 seconds.

Except when all MSIVs are closed.

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

CALLAWAY PLANT 3.3-40 Amendment No. ###

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE(a)

5. Turbine Trip and Feedwater Isolation

a. Automatic 1,2a) 30) 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

SR 3.3.2.14

b. Automatic 1, 20), 30 2 trains(o)

S SR 3.3.2.3 NA Actuation Logic and Actuation Relays (MSFIS)

c. SG Water Level -

1,2° 4 per SG I

SR 3.3.2.1 s 91.4%ts) of High High (P-14)

SR 3.3.2.5 Narrow Range SR 3.3.2.9 Instrument SR 3.3.2.10 Span

d. Safety Injection Refer to Function I (Safety Injection) for all initiation functions and requirements.

e. Steam Generator Water Level Low-Lowv)

(1) Steam 1 20),3) 4 perSG D

SR 3.3.2.1

Ž 20.6%) of Generator SR 3.3.2.5 Narrow Range Water Level SR 3.3.2.9 Instrument Low-Low SR 3.3.2.10 Span (Adverse Containment Environment)

(continued)

I I

(a) a)

(o)

(q)

(S)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpbints.

Except when all MFIVs are closed.

Each train requires a minimum of two programmable logic controllers to be OPERABLE.

Feedwater isolation only.

If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

CALLAWAY PLANT 3.3-41 Amendment No. ###

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 5 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE~s)

5. Turbine Trip and Feedwater Isolation

e. Steam Generator Water Level Low-Lowvq)

(continued)

(2) Steam Generator 1(r), 20), 30 4 per SG D

SR 3.3.2.1 216.6%(') of Water Level SR 3.3.2.5 Narrow Range Low-Low (Normal SR 3.3.2.9 Instrument Containment SR 3.3.2.10 Span Environment)

(3) Not used.

(4) Containment 1, 2°, 3) 4 N

SR 3.3.2.1

• 2.0 psig Pressure -

SR 3.3.2.5 Environmental SR 3.3.2.9 Allowance Modifier SR 3.3.2.10 (continued)

I I

(a) a)

(k)

(I)

(q)

(r)

(s)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Except when all MFIVs are closed.

Not used.

Not used.

Feedwater isolation only.

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

I CALLAWAY PLANT 3.3-42 Amendment No. ###

ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 6 of 8)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION SPECIFIED CHANNELS CONDITIONS REQUIREMENTS VALUE(a)

CONDITIONS

6. Auxiliary Feedwater

a. Manual Initiation 1.2, 3 1/pump P

SR 3.3.2.8 NA

b. Automatic 1,2,3 2 trains G

SR 3.3.2.2 NA Actuation Logic SR 3.3.2.4 and Actuation SR 3.3.2.6 Relays (SSPS)

c. Automatic 1,2,3 2 trains Q

SR 3.3.2.3 NA Actuation Logic and Actuation Relays (BOP ESFAS)

d. SG Water Level Low-Low (1) Steam 1,2,3 4perSG D

SR3.3.2.1 220.6%(" of Generator SR 3.3.2.5 Narrow Range Water Level SR 3.3.2.9 Instrument Low-Low SR 3.3.2.10 Span (Adverse Containment Environment)

(2) Steam 1(r 2"' 3' 4 per SG D

SR 3.3.2.1 216.6%(s) of Generator SR 3.3.2.5 Narrow Range Water Level SR 3.3.2.9 Instrument Low-Low SR 3.3.2.10 Span (Normal Containment Environment)

(continued)

I I

(a)

(r)

(s)

The Allowable Value defines the limiting safety system setting. See the Bases for the Trip Setpoints.

Except when the Containment Pressure - Environmental Allowance Modifier channels in the same protection sets are tripped.

If a channel is found with an actual trip setpoint value outside its two-sided calibration tolerance band, the channel's trip setpoint shall be restored to within the as-left calibration tolerance band on either side of the Nominal Trip Setpoint established in accordance with the plant setpoint methodology to protect the safety analysis limit.

CALLAWAY PLANT 3.3-43 Amendment No. ###

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a.

No pressure boundary LEAKAGE;

b.

1 gpm unidentified LEAKAGE;

c.

10 gpm identified LEAKAGE; and

d.

150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

I I

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION TIME A. RCS operational A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within limits within limits.

for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

CALLAWAY PLANT 3.4-30 Amendment No. ###

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity I

I LCO 3.4.17 SG tube integrity shall be maintained.

I AND I

All SG tubes satisfying the tube repair criteria shall be plugged in accordance with Steam Generator Program.

I I

APPLICABILITY:

MODES 1 2, 3, and 4.

I ACTIONS

-N-NOTE Separate Condition entry is allowed for each SG tut CONDITION REQUIRED ACTION COMPLETION A. One or more SG tubes A.1 Verify tube integrity of 7 days satisfying the tube repair the affected tube(s) is criteria and not plugged in maintained until the next accordance with the Steam refueling outage or Generator Program.

inspection.

AND A.2 Plug the affected tube(s)

Prior to entering in accordance with the MODE 4 following Steam Generator the next refueling Program.

outage or SG tube inspection (continued) I CALLAWAY PLANT 3.4-44 Amendment No. ###

SG Tube Integrity 3.4.17 ACTIONS (continued)

CONDITION REQUIRED ACTION TIME B. Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.

I CALLAWAY PLANT 3.4-45 Amendment No. ###

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the Steam In accordance with Generator Program.

the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following Steam Generator Program.

a SG tube inspection I

CALLAWAY PLANT 3.4-46 Amendment No. ###

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Containment Leakage Rate Testinq Program (continued)

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified byASME Section Xl Code, Subsection IWE, except where relief has been authorized by the NRC.

3.

The unit is excepted from post-modification integrated leakage rate testing requirements associated with steam generator replacement during the Refuel 14 outage (fall of 2005).

b.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 48.1 psig.

c.

The maximum allowable containment leakage rate, La, at Pa, shall be 0.20% of the containment air weight per day.

d.

Leakage rate acceptance criteria are:

1.

Containment leakage rate acceptance criterion is < 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type B and C tests and < 0.75 La for Type A tests;

2.

Air lock testing acceptance criteria are:

a)

Overall air lock leakage rate is < 0.05 La when tested at 2 Pa; b)

For each door, leakage rate is

• 0.005 La when pressurized to 2 10 psig.

e.

The provisions or Technical Specification SR 3.0.2 do not apply to the test frequencies in the Containment Leakage Rate Testing Program.

f.

The provisions of Technical Specification SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

CALLAWAY PLANT 5.0-27 Amendment No. ###

ATTACHMENT 4 PROPOSED TECHNICAL SPECIFICATION BASES CHANGES (for information only)

RTS Instrumentation B 3.3.1 BASES (continued)

BACKGROUND Reactor Trip Switchcear (continued) output voltage signal is removed, the undervoltage coils are de-energized, the breaker trip lever is actuated by the de-energized undervoltage coil, and the RTBs and bypass breakers are tripped open. This allows the shutdown rods and control rods to fall into the core. In addition to the de-energization of the undervoltage coils, each reactor trip breaker is also equipped with an automatic shunt trip device that is energized to trip the breaker open upon receipt of a reactor trip signal from the SSPS. Either the undervoltage coil or the shunt trip mechanism is sufficient by itself, thus providing a diverse trip mechanism.

The decision logic matrix Functions are described in the functional diagrams included in Reference 1. In addition to the reactor trip or ESF, these diagrams also describe the various "permissive interlocks" that are associated with unit conditions.

Each train has a built in testing device that can test the decision logic matrix Functions and the actuation devices while the unit is at power.

When any one train is taken out of service for testing, the other train is capable of providing unit monitoring and protection until the testing has been completed. The testing device is semiautomatic to minimize testing time.

APPLICABLE The RTS functions to maintain the applicable Safety Limits during all SAFETY AOOs and mitigates the consequences of DBAs in all MODES in which

ANALYSES, the Rod Control System is capable of rod withdrawal or one or more rods LCO, AND are not fully inserted.

APPLICABILITY Each of the analyzed accidents and transients can be detected by one or more RTS Functions. The accident analysis described in Reference 2 takes credit for most RTS trip Functions. RTS trip Functions not specifically credited in the accident analysis are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These RTS trip Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. They may also serve as backups to RTS trip Functions that were credited in the accident analysis.

The LCO requires all instrumentation performing an RTS Function, listed in Table 3.3.1-1 in the accompanying LCO, to be OPERABLE. Failure of any instrument renders the affected channel(s) inoperable and reduces the reliability of the affected Functions/,

oentrnsud/-6 (continued)

CALLAWAY PLANT B 3;3.1-6 Revision 5

INSERT B 3.3.1-6 The Allowable Value column for Trip Functions 14.a, Steam Generator Water Level Low-Low (Adverse Containment Environment), and 14.b, Steam Generator Water Level Low-Low (Nommal Containment Environment) in TS Table 3.3.1-1 is modified by a Note that requires the as-left condition for a channel in those Trip Functions to be within the established calibration tolerance band for that channel on either side of the Nominal Trip Setpoint. This assures that the assumptions in the plant setpoint methodology (Reference 17) are satisfied in order to protect the safety analysis limit. As-found and as-left setpoint data for these specific Trip Functions obtained during CHANNEL OPERATIONAL TESTS are trended to demonstrate that the rack drift assumptions used in the plant setpoint methodology are valid. If the trending evaluation determines that a channel is performing inconsistent with the uncertainty allowances applicable to the periodic surveillance test being performed (e.g., whether it be a COT, CHANNEL CALIBRATION, etc.), the channel will be evaluated under the corrective action program.

If the channel is not capable of performing its specified safety function, it shall be declared inoperable.

ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued)

Balance of Plant (BOP) ESFAS The BOP ESFAS processes signals from SSPS, signal processing equipment (e.g., LSELS), and plant radiation monitors to actuate certain ESF equipment. There are two redundant trains of BOP ESFAS (separation groups 1 and 4), and a third separation group (separation group 2) to actuate the Turbine Driven Auxiliary Feedwater pump and reposition automatic valves (turbine steam supply valves, turbine trip and throttle valve) as required. The separation group 2 BOP-ESFAS cabinet is considered to be part of the end device (the Turbine Driven Auxiliary Feedwater pump) and its OPERABILITY is addressed under LCO 3.7.5, "Auxiliary Feedwater (AFW) System." The redundant trains provide actuation for the Motor Driven Auxiliary Feedwater pumps (and reposition automatic valves as required, i.e., steam generator blowdown and sample line isolation valves, ESW supply valves, CST supply valves),

Containment Purge Isolation, Control Room Emergency Ventilation, and Emergency Exhaust Actuation functions.

The BOP ESFAS has a built-in automatic test insertion (ATI) feature which continuously tests the system logic. Any fault detected during the testing causes an alarm on the main control room overhead annunciator system to alert operators to the problem. Local indication shows the test step where the fault was detected.

APPLICABLE Each of the analyzed accidents can be detected by one or more ESFAS SAFETY Functions. One of the ESFAS Functions is the primary actuation signal

ANALYSES, for that accident. An ESFAS Function may be the primary actuation LCO, AND signal for more than one type of accident. An ESFAS Function may also APPLICABILITY be a secondary, or backup, actuation signal for one or more other accidents. For example, Pressurizer Pressure - Low is a primary actuation signal for small loss of coolant accidents (LOCAs) and a backup actuation signal for steam line breaks (SLBs) outside containment.

Functions such as manual initiation, not specifically credited in the accident safety analysis, are qualitatively credited. These Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. These Functions may also serve as backups to Functions that were credited in the accident analysis (Ref. 3).

• ZK,/r63 2-5 The LCO requires all instrumentation performing an ESFAS Functi n to be OPERABLE. Failure of any instrument renders the affected c nnel(s)

Nnoperable and reduces the reliability of the affected Functions.

The LCO generally requires OPERABILITY of three or four channels in each instrumentation function and two channels in each logic and manual

(;4.~..

111\\

Adinitiation function. The two-out-of-three and the two-out-of-four g0 rAp Uf (continued)

CALLAWAY PLANT B 3.3.2-5 Revision 5

INSERT B 3.3.2-5 The Allowable Value column for Trip Functions I.e (Safety Injection on Steam Line Pressure - Low), 4.e. I (Steam Line Isolation on Steam Line Pressure - Low), 5.c (Turbine Trip and Feedwater Isolation on Steam Generator Water Level High-High),

5.e. I (Feedwater Isolation on Steam Generator Water Level Low-Low - Adverse Containment Environment), 5.e.2 (Feedwater Isolation on Steam Generator Water Level Low-Low - Normal Containment Environment), 6.d. 1 (Auxiliary Feedwater Actuation on Steam Generator Water Level Low-Low-Adverse Containment Environment), and 6.d.2 (Auxiliary Feedwater Actuation on Steam Generator Water Level Low-Low - Normal Containment Environment) in TS Table 3.3.2-1 is modified by a Note that requires the as-left condition for a channel in those Trip Functions to be within the established calibration tolerance band for that channel on either side of the Nominal Trip Setpoint.

This assures that the assumptions in the plant setpoint methodology (Reference 18) are satisfied in order to protect the safety analysis limit. As-found and as-left setpoint data for these specific Trip Functions obtained during CHANNEL OPERATIONAL TESTS are trended to demonstrate that the rack drift assumptions used in the plant setpoint methodology are valid. If the trending evaluation determines that a channel is performing inconsistent with the uncertainty allowances applicable to the periodic surveillance test being performed (e.g., whether it be a COT, CHANNEL CALIBRATION, etc.), the channel will be evaluated under the corrective action program. If the channel is not capable of performing its specified safety function, it shall be declared inoperable.

-RCS-Operational LEAKAGE B 3.4.13 ACJ

,BASES (continued)L R CS S

fe w

APPLICABLE Except r rimary to secondary LEAKGJ the sajety analyses do not SAFETY addres perational LEAKAGE. However, eherfperational LEAKAGE-ANALYSES are related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analyses for events resulting in steam discharge to the atmosphere assumem to r, L 3

z rj 8

.4+/3A I

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. Other accidents or transients involving secondary steam release to the atmosphere include the steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is released vi-trn"Oetr A~"'

S/

4%/44 v~Ato s,/'*t C'.C)v-/v A r//

4 e tn The safety analysis for the SLB accident assumes I gpm primary to 1

secondary LEAKAG ~g enerator as an initia condition. The dose V/.

m}

consequences resulte fro the SLB and SGTR ccidents are well within the limit F 100 (Ref. 5) (i.e., a s all fraction of these limits)§sgsUAt<)L7eo v The saf y

r RCS main loop piping for GDC4 (Ref. 1) assumes I gpm unidentified leakage and monitoring per RG 1.45 (Ref. 2) are maintained (Ref. 4).

The RCS operational LEAKAGE satisfies Criterion 2 of 1 OCFR50.36(c)(2)(ii).

LCO RCS operational LEAKAGE shall be limited to:

a.

Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak Itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals, gaskets, and instrumentation lines is not pressure boundary LEAKAGE.

Instrumentation lines are 3/8 inch tubing for instrument connections to ASME Class 1 fluid piping downstream of the root valves and 1/8 inch core exit thermocouple sheaths. These instrument lines are not part of the reactor coolant pressure boundary (RCPB) nor do they provide a pressure retaining barrier.

.(continued-CALLAWAY PLANT B 3.4.13-2 Revision 0(

INSERT 2 The 1 gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential for SGTR given the magnitude of the postulated break flow rate.

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS B.1 and B.2 (continued)

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

In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

SURVEILLANCE REQUIREMENTS SR 3.4.13.1 Verifying RCStEAKAGE to be within the LCO limits ensures the Integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals, gaskets, and instrumentation lines is not pressure boundary LEAKAGE. Unidentified LEAKAGE and Identified LEAKAGE are determined by performance of an RCS water inventory balance.

ry to r

LEAKA8E i mo~cuod b eFrfomrRono ofA kne R

W819F iAYontoc cGQnqWn1Qi0A Ypih OCZe.ZFdJoy Qkt saamping said me. 04_44%%"ig.

Sp.S.4.f./ / F4'*OW J1 4, A

The RCS water inventory balan must be met with the reactor at steady state operating conditions (stab RCS pressure, temperature, power level, pressurizer and makeup nk levels, makeup and letdown, and RCP seal injection and return flows).

W N

i eat this SR 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 establi ng steady state operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance provides suff time to collect and process all necessary data after stable plant copltions are established.

/ For Steady state operation is preferred to perform a proper inventory balance since calculations during non-steady state conditions must account for the changing parameters. -fer Rl8 p nl LEAKAGe dotomimnfition by

?watar Invantory batlnco, Getady-a; ot;is defined taq letz RCC PFG6rOe.r tg-MpgrF-Iit0r.

_-Vwor-104.10o. Drocou&0Fo MCI malee~tinh Make

~up

-endow r.

c in 2nd r_

flo'..,o.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmospher ioactivity and the containment sump level. It should be noted that L' GE past seals, gaskets, and instrumentation lines is not pressure boeary LEAKAGE. These leakage detection systems are specified 0 3.4.

"RCS Leakage Detection Instrumentation."

(

i I,

CALLAWAY PLANT B 3.4,13-5 Revision 0

-RCS Operatib--aI LEAKAGE.--

B 3.4.13 JZ Z:Ar-le-t-B :3. 4. 130-BASES SURVEILLANCE (SR 3.4.13.1 (continued)

REQUIREMENTS The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

REFERENCES 1

10 CFR 50, Appendix A, GDC 4 and 30.

2.

Regulatory Guide 1.45, May 1973.

(

3.

FSAR, Section 15.6.3.

4.

NUREG-1061, Volume 3, November 1984.

5.

10CFR100.

6.

Amendment No. 116 dated October 1. 1996.

XNX4RT

£6 i

CALLAWAY PLANT B 3.4,13 6 Revision 0

INSERT B 3.4.13 C Note 2 states that SR 3.4.13.1 is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance.

INSERT B 3.4.13 D This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day through any one SG Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.17, uSteam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 8. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG SR 3.4.13.2 is modified by a Note which states that the 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. 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 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. During normal operation tThe primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the methodology of Reference 8. In MODES 3 and 1, the primary system radioactivity level may be ver' low, making it difficult to meacure primary to econldary LEAKAGE. If Sa pe ate r.mUnlare re c than the minimum detectable, activity for each principal gamma emitter, primary to secondary LEAKAGE may be ar.c6umned to be lese than 150 gallone per day through any one SG (Ref. 8). Leakage verification is provided by chemistry procedures that provide alternate means of calculating and confirming primary to secondary leakage is less than or equal to 150 gallons per day through any one SG.

INSERT B 3.4.13 E

7.

NEI 97-06, 'Steam Generator Program Guidelines."

8.

EPRI TR-1 04788, 'Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

SG Tube Integrity B 3.4.17 BASES (continued)

APPLICABLE SAFETY ANALYSES' The steam generator tube rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a primary to secondary LEAKAGE rate of 1 gpm to the unaffected steam generators, in exess ef -exceeding the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is released to the atmosphere via a postulated stuck-open atmospheric steam dump (ASD) valve or via a partially stuck-open main steam safety valve (see Ref. 2).

I 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. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific 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. 3), 10 CFR 100 (Ref. 4) 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 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, 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.

CALLAWAY PLANT B 3.4.17-2 Revision

SG Tube Integrity B 3.4.17 BASES LCO (continued)

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.9, "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 follows: 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 significanty eaffect on burst or collapse. In that context, the term significant is defined as follows:

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. Theo determinatioR of whether thermal lbade are primar' or secondar' lade iE bayed on the ASME definition in wyhic-h ecrondary leade alr selo limiting and will not causo faitilr under single load application. For steam generator 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 1II, 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 CALLAWAY PLANT B 3.4.17-3 Revision

SG Tube Integrity B 3.4.17 BASES A.1 and A.2 (continued)

Program as required by SR 3.4.17.2. 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 criter-ia 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 orSG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situa-tion 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, Condition B applies.

I 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 A.2 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 entering MODE 4 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.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 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 REQUIREMENTS SR 3.4.17.1 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 CALLAWAY PLANT B 3.4.17-5 Revision

SG Tube Integrity B 3.4.17 BASES SR 3.4.17.1 Guidelines, establish the content of the Steam Generator (continued)

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 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 3.4.17.1. The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 7). 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 5.5.9.contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.17.2 During a 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 5.5.9 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 I and Reforonco 7 provides guidance for performing operational assessments to verify that the tubes CALLAWAY PLANT B 3.4.17-6 Revision