Text

License Amendment Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity
	ML061560134
Person / Time
Site:	Davis Besse
Issue date:	05/30/2006
From:	Bezilla M; FirstEnergy Nuclear Operating Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	3231, LAR 05-0009
	Download: ML061560134 (101)
	v • d • e

FENOC FE O 5501 North State Route 2 FirstEnergy Nuclear Operating Company Oak Harbor, Ohio 43449 Mark B. Bezilla 419-321-7676 Vice President - Nuclear Fax: 419-321-7582 Docket Number 50-346 10 CFR 50.90 License Number NPF-3 Serial Number 3231 May 30, 2006 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001

Subject:

Davis-Besse Nuclear Power Station License Amendment Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity (License Amendment Request No. 05-0009)

Ladies and Gentlemen:

Pursuant to 10 CFR 50.90, a license amendment is requested for the Davis-Besse Nuclear Power Station, Unit 1 (DBNPS). The proposed amendment would revise the Technical Specification (TS) requirements related to steam generator tube integrity. This change is consistent with NRC-approved Revision 4 to Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity." The availability of this TS improvement was announced in the Federal Register on May 6, 2005 (70 FR 24126) as part of the consolidated line item improvement process (CLIIP).

Approval of the proposed amendment is requested by May 31, 2007. Once approved, the amendment shall be implemented within 120 days.

The proposed changes have been reviewed by the DBNPS Plant Operations Review Committee and Company Nuclear Review Board. Enclosure 1 provides a description of the proposed change and confirmation of applicability. A list of regulatory commitments made in this letter is included in Enclosure 2.

AoLX~

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 2 If there are any questions or if additional information is required, please contact Mr. Gregory A. Dunn, Manager - Fleet Licensing, at (330) 315-7243.

The statements contained in this submittal, including its associated enclosures and attachments, are true and correct to the best of my knowledge and belief. I am authorized by the FirstEnergy Nuclear Operating Company to make this submittal. I declare under penalty of perjury that the foregoing is true and correct.

Executed on: (1*L 3 0 By:

M/lark B. Bezilla, Vice-Tsident-Nuclear MKL Enclosures cc:

Regional Administrator, NRC Region III NRC/NRR Project Manager Executive Director, Ohio Emergency Management Agency, State of Ohio (NRC Liaison)

DB-1 Senior Resident Inspector, NRC Region III Utility Radiological Safety Board

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 1 DAVIS-BESSE NUCLEAR POWER STATION DESCRIPTION AND ASSESSMENT FOR LICENSE AMENDMENT REQUEST NUMBER 05-0009

Subject:

Technical Specification Improvement Regarding Steam Generator Tube Integrity

1.0 INTRODUCTION

2.0 DESCRIPTION

OF PROPOSED AMENDMENT

3.0 BACKGROUND

4.0 REGULATORY REQUIREMENTS AND GUIDANCE

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

6.1 Verification and Commitments 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION 8.0 ENVIRONMENTAL EVALUATION 9.0 PRECEDENT

10.0 REFERENCES

11.0 ATTACHMENTS

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 2

1.0 INTRODUCTION

The proposed license amendment revises the Technical Specification (TS) requirements related to steam generator tube integrity. The changes are consistent with NRC approved Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-449, "Steam Generator Tube Integrity," Revision 4. The availability of this technical specification improvement was announced in the Federal Register on May 6, 2005, as part of the consolidated line item improvement process (CLIIP).

2.0 DESCRIPTION

OF PROPOSED AMENDMENT The proposed TS changes described below are shown in Attachments 1 and 2.

Consistent with the NRC-approved Revision 4 of TSTF-449, the proposed TS changes include:

" Revised TS definition LEAKAGE (specifically, TS Definition 1.14, "IDENTIFIED LEAKAGE" and TS Definition 1.16, "PRESSURE BOUNDARY LEAKAGE")

Revised TS 3/4.6.2, "Reactor Coolant System Operational Leakage"

" New TS 3/4.4.5, "Steam Generator (SG) Tube Integrity"

New TS 6.8.4.g, "Steam Generator (SG) Program"

" New TS 6.9.1.12, "Steam Generator Tube Inspection Report" Associated with the above, the proposed TS changes also include the following administrative and editorial changes:

Relocation of SG level requirements previously provided in TS 3/4.4.5 to New TS 3/4.7.9, "Steam Generator Level," and corresponding revision of a reference to LCO 3.4.5 in TS 3/4.1.1.1, "Boration Control - Shutdown Margin"

" Deletion of mention of the steam generator tube inservice inspection annual report in TS Section 6.9.1.5.b, since new TS 6.9.1.12 will now list reporting requirements associated with steam generator tube inspections

" Revisions to the TS Index

" Consolidation and repagination of TS Section 6.0, "Administrative Controls" Proposed revisions to the TS Bases are also included in this application for information (Attachment 3). As discussed in the NRC's model safety evaluation, adoption of the revised TS Bases associated with TSTF-449, Revision 4 is an integral part of implementing this TS improvement. The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 3 The Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS) TS are currently based on NUREG-0103, "Standard Technical Specifications for Babcock and Wilcox Pressurized Water Reactors," whereas TSTF-449 is based on NUREG-1430, "Standard Technical Specifications Babcock and Wilcox Plants." Attachment 4 provides a matrix correlating changes proposed by the TSTF with those proposed for the DBNPS by this license amendment application.

3.0 BACKGROUND

The background for this application is adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

4.0 REGULATORY REQUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

5.0 TECHNICAL ANALYSIS

The FirstEnergy Nuclear Operating Company (FENOC) has reviewed the safety evaluation (SE) published on March 2, 2005 (70 FR 10298) as part of the CLIIP Notice for Comment. This included the NRC staff s SE, the supporting information provided to support TSTF-449, and the changes associated with Revision 4 to TSTF-449. FENOC has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to the DBNPS and justify this amendment for the incorporation of the changes to the DBNPS TS.

6.0 REGULATORY ANALYSIS

A description of this proposed change and its relationship to applicable regulatory requirements and guidance was provided in the NRC Notice of Availability published on May 6, 2005 (70 FR 24126), the NRC Notice for Comment published on March 2, 2005 (70 FR 10298), and TSTF-449, Revision 4.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 4 6.1 Verification and Commitments The following information is provided to support the NRC staffs review of this amendment application:

Plant Name, Unit No.

Davis-Besse Nuclear Power Station, Unit 1 Steam Generator Model(s)

B&W Model 177FA Once-Through Steam Generators (OTSG)

Effective Full Power Years 17.6 EFPY (approx.) as of the end of Cycle 14 (March 2006).

(EFPY) of service for currently installed SGs Tubing Material Mill Annealed Alloy 600 (ASTM SB 163)

Number of tubes per SG 15,457 Number and percentage of 579 (3.7%) tubes plugged in the 2-A OTSG tubes plugged in each SG 244 (1.6%) plugged tubes in the 1-B OTSG Number of in-service tubes OTSG 2-A 1-B repaired in each SG Sleeved 199 212 Factory re-rolls 3

3 Repair rolls 117 23 Degradation mechanism(s) 9 Upper Tube End Primary Water Stress Corrosion Cracking identified (PWSCC)

Volumetric Degradation in Freespan and Adjacent Tube Support Plates (TSPs)

" Volumetric Degradation in Upper and Lower Tubesheet and Tube Support Crevices

" Wear at Tube Support Plates

" Freespan Axial Outside Diameter Stress Corrosion Cracking/Intergranular Attack (ODSCC/IGA) at Upper Bundle Denting From Auxiliary Feedwater Stabilization

" Axial Freespan ODSCC/IGA (Groove IGA)

Upper Roll Transition PWSCC

Lower Tube End and Lower Tube End Expansion Transition PWSCC Current primary-to-secondary Per SG: 150 gallons per day leakage limits Total: Combined leakage of 150 gallons per day Leakage is evaluated at approximately room temperature Approved Alternate Tube None Repair Criteria (ARC)

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Enclosure I Page 5 Plant Name, Unit No.

Davis-Besse Nuclear Power Station, Unit 1 Approved SG Tube Repair Sleeves Methods Amendment number: 171 dated 07/28/92 Limits: As defined in BAW-2120P (upper span location)

Repair criteria: 40% of the nominal tube wall thickness Repair Rolls Amendment number: 252 dated 02/20/02 Limits: As defined in BAW-2303 Rev 4 (exclusion zones, installation and acceptance limits)

Repair criteria: the new roll area must be free of degradation in order for the repair to be considered acceptable Performance criteria for Per SG: 1 gpm maximum accident leakage Total: Combined leakage of 1 gpm A primary to secondary leak rate of I gpm is assumed in the Main Steam Line Break (MSLB) and Steam Generator Tube Rupture (SGTR) analyses. Leakage is evaluated at room temperature for a MSLB at full power. Leakage is evaluated at RCS conditions for a MSLB at Mode 3 conditions and for a SGTR.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION FENOC has reviewed the proposed no significant hazards consideration determination published on March 2, 2005 (70 FR 10298) as part of the CLIIP. FENOC has concluded that the proposed determination presented in the notice is applicable to the DBNPS and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

8.0 ENVIRONMENTAL EVALUATION FENOC has reviewed the environmental evaluation included in the model SE published on March 2, 2005 (70 FR 10298) as part of the CLIIP. FENOC has concluded that the staffs findings presented in that evaluation are applicable to the DBNPS and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. FENOC is not proposing any significant variations or deviations from the TS changes described in TSTF-449, Revision 4, or the NRC staff's model SE published on March 2, 2005 (70 FR 10298). However, as stated in Section 2.0 above, the DBNPS TS are currently based on NUREG-01 03, whereas TSTF-449 is

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 6 based on NUREG-1430. Therefore, adaptation of TSTF-449 was required. The following variations are of note:

Consistent with NUREG-1430, a footnote is proposed to be added to Surveillance Requirement (SR) 4.4.6.2.1.d to clarify that performance of the Reactor Coolant System water inventory balance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

" In proposed TS 6.8.4.g.4, plant-specific exclusions to SG tube inspection provisions have been added for tubes that have undergone repair rolling or sleeving repairs.

A special interest tube inspection requirement associated with the repair roll process is included in proposed TS 6.8.4.g.7. This is a plant-specific requirement included in the applicable portions of current SR 4.4.5.9. Administrative changes are made in transferring the current SR to the SG Program requirements described in the proposed TS 6.8.4.g.

" A special visual inspection requirement associated with the secured internal auxiliary feedwater header is included in proposed TS 6.8.4.g.8. This is a plant-specific requirement included in current SR 4.4.5.8. Only administrative changes are made in transferring the current SR to the SG Program requirements described in the proposed TS 6.8.4.g.

" A special interest tube inspection requirement associated with peripheral tubes in the vicinity of the secured internal auxiliary feedwater header is included in proposed TS 6.8.4.g.9. This is a plant-specific requirement included in current SR 4.4.5.7. A provision included in current SR 4.4.5.7 regarding limiting the required testing to only the SG selected for inspection is not carried over into TS 6.8.4.g.9 since each scheduled SG tube inspection includes both SGs each outage. Other administrative changes are made in transferring the current SR to the SG Program requirements described in the proposed TS 6.8.4.g.

" In that the DBNPS has not yet converted to the improved Standard TS, the content of the current TS Bases is not as extensive as that of the NUREG-1430 Bases. However, FENOC intends to incorporate the key changes in the Bases portion of the TSTF package. A markup of the proposed changes is provided for information in.

FENOC believes that these variations meet the intent of TSTF-449 and do not affect the no significant hazards consideration determination and environmental evaluation included in the aforementioned model SE.

10.0 REFERENCES

Federal Register Notices:

Notice for Comment published on March 2, 2005 (70 FR 10298)

Notice of Availability published on May 6, 2005 (70 FR 24126)

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 7 11.0 ATTACHMENTS

1.

Proposed Mark-Up Of Technical Specification Pages

2.

Proposed Retyped Technical Specification Pages

3.

Technical Specification Bases Pages

4.

Correlation of TSTF-449 Changes versus the Proposed DBNPS License Amendment Changes

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Enclosure I PROPOSED MARK-UP OF TECHNICAL SPECIFICATION PAGES (32 pages follow)

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4.4 PRESSURIZER.............................................

3/4 4-5 3/4.4.5 STEAM GENERATORS (SG) TUBE INTEGRITY.................

3/4 4-6 [

3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems....................................

3/4 4-13 Operational Leakage..........................................

3/4 4-15 3/4.4.7 D eleted....................................................

3/4 4-17 3/4.4.8 SPECIFIC ACTIVITY........................................

3/4 4-20 3/4.4.9 PRESSURE/TEMPERATURE LIMITS Reactor Coolant System.......................................

3/4 4-24 D eleted....................................................

3/4 4-29 3/4.4.10 STRUCTURAL INTEGRITY.................................

3/4 4-30 3/4.4.11 D eleted...................................................

3/4 4-32 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3/4.5.1 CORE FLOODING TANKS....................................

3/4 5-1 3/4.5.2 ECCS SUBSYSTEMS - Tavg >280°F.............................

3/4 5-3 3/4.5.3 ECCS SUBSYSTEMS - Tayg < 280OF............................

3/4 5-6 3/4.5.4 BORATED WATER STORAGE TANK.........................

3/4 5-7 DAVIS-BESSE, UNIT 1 V

Amendment No. 135, 201, 234,

245,

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE Safety V alves...............................................

3/4 7-1 Auxiliary Feedwater System...................................

3/4 7-4 Condensate Storage Tanks....................................

3/4 7-6 A ctivity...........

3/4 7-7 Main Steam Line Isolation Valves..............................

3/4 7-9 Motor Driven Feedwater Pump System..........................

3/4 7-12a Main Feedwater Control Valves and Startup Feedwater Control Valves.

3/4 7-12d Turbine Stop Valves.........................................

3/4 7-12e 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION.

3/4 7-13 3/4.7.3 COMPONENT COOLING WATER SYSTEM....................

3/4 7-14 3/4.7.4 SERVICE WATER SYSTEM.................................

3/4 7-15 3/4.7.5 ULTIMATE HEAT SINK.....................................

3/4 7-16 3/4.7.6 CONTROL ROOM EMERGENCY VENTILATION SYSTEM.......

3/4 7-17 3/4.7.7 SNUBBERS...............................................

3/4 7-20 3/4.7.8 SEALED SOURCE CONTAMINATION........................

3/4 7-36 3/4.7.9 Delet dSTEAM GENERATOR LEVEL........................

3/4 7-38 3/4.7.10 Deleted 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES O perating..................................................

3/4 8-1 Shutdown..............................

3/4 8-5 3/4.8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. Distribution - Operating..................................

3/4 8-6 A.C. Distribution - Shutdown..................................

3/4 8-7 D.C. Distribution - Operating..................................

3/4 8-8 D.C. Distribution - Shutdown..................................

3/4 8-11 DAVIS-BESSE, UNIT 1 VII Amendment No. 38, 103, 106, 135, 164, 174, 246,

INDEX BASES SECTION 3/4.0 APPLICABILITY...........................................

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL....................................

3/4.1.2 BORATION SYSTEM S.....................................

3/4.1.3 MOVABLE CONTROL ASSEMBLIES........................

3/4.2 POWER DISTRIBUTION LIMITS.............................

PAGE B 3/4 0-1 B 3/4 1-1 B 3/4 1-2 B 3/4 1-3 B 3/4 2-1 3/4.3 INSTRUMENTATION 3/4.3.1 and 3/4.3.2 REACTOR PROTECTION SYSTEM AND SAFETY SYSTEMS INSTRUMENTATION............................

3/4.3.3 MONITORING INSTRUMENTATION........................

3/4.4 REACTOR COOLANT SYSTEM B 3/4 3-1 B 3/4 3-2 3/4.4.1 REACTOR COOLANT LOOPS..............................

3/4.4.2 and 3/4.4.3 SAFETY VALVES...............................

3/4.4.4 PRESSURIZER......................................

3/4.4.5 STEAM GENERATORS TUBE INTEGRITY................

3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE...................

3/4.4.7 D eleted..................................................

3/4.4.8 SPECIFIC ACTIVITY......................................

3/4.4.9 PRESSURE/TEMPERATURE LIMITS........................

3/4.4.10 STRUCTURAL INTEGRITY................................

3/4.4.11 D eleted..................................................

B 3/44-1 B 3/44-1 B 3/4 4-2 B 3/4 4-2 B 3/4 4-4 B 3/4 4-5 B 3/4 4-5 B 3/4 4-6 B 3/4 4-13 B 3/4 4-13 DAVIS-BESSE, UNIT I IX Amendment No. 135,201,234,

INDEX BASES SECTION PAGE 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE.........................................

3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION 3/4.7.3 COMPONENT COOLING WATER SYSTEM...................

3/4.7.4 SERVICE WATER SYSTEM.................................

3/4.7.5 ULTIMATE HEAT SINK....................................

3/4.7.6 CONTROL ROOM EMERGENCY VENTILATION SYSTEM......

3/4.7.7 SNUBBERS...............................................

3/4.7.8 SEALED SOURCE CONTAMINATION........................

3/4.7.9 DetetedSTEAM GENERATOR LEVEL.........................

3/4.7.10 Deleted 3/4.8 ELECTRICAL POWER SYSTEMS.............................

B 3/4 7-1 B 3/4 7-4 B 3/4 7-4 B 3/4 7-4 B 3/4 7-4a B 3/4 7-4a B 3/4 7-5 B 3/4 7-6 B 3/4 7-6 B 3/4 8-1 3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION................................

3/4.9.2 INSTRUMENTATION......................................

3/4.9.3 DECAY TIM E.............................................

3/4.9.4 CONTAINMENT PENETRATIONS...........................

3/4.9.5 DELETED B 3/49-1 B 3/4 9-1 B 3/4 9-1 B 3/4 9-1 DAVIS-BESSE, UNIT 1 XII Amendment No. 38, 106, 135, 174, 224, 246,

INDEX ADMiNISTRATIVE CONTROLS SECTION PAGE 6.1 RESPON SIBILITY.................................................

6-1 6.2 ORGANIZATION Offsite and Onsite Organizations......

6-1 Facility Staff..................................................

6-1e Facility Staff Overtime...........................................

6-4a2 6.3 FACILITY STAFF QUALIFICATIONS.........................

6-5_

6.4 DELETED........................................................

6-53 6.5 REVIEW AND AUDIT 6.5.1 Deleted 6.5.2 Deleted 6.5.3 Technical Review and Control......................................

6-4 4_

6.6 DELETED.....................................................

6-4-2a5 6.7 DELETED.....................................................

6-4-35 68i PROCEDI)IRES AND PROCGRAMS.................................

6-445 6.9 REPORTING REQUIREMENTS 6.9.1 Routine Reports.................................................

6.9.2 Special Reports..................................................

6.10 RECORD RETENTION......................................

6.11 DELETED 6.12 HIGH RADIATION AREA...................................

6.13 ENVIRONMENTAL QUALIFICATION.........................

6-44e.-fl 64-91-g 64-9M8 6-24016 6-419 6.14 DELETED 6.15 OFFSITE DOSE CALCULATION MANUAL (ODCM).................

6.16 CONTAINMENT LEAKAGE TESTING PROGRAM...................

6.17 TECHNICAL SPECIFICATIONS (TS) BASES CONTROL PROGRAM...

6-212I 6-N202 6-2-21 6-2422 DAVIS-BESSE, UNIT 1 XV Amendment No. 38,135,170,189,231, 235, 236,240,244, 248, 249, 272,

DEFINITIONS CHANNEL FUNCTIONAL TEST FOR INFORMATION ONLY 1.11 A CHANNEL FUNCTIONAL TEST shall be:.

a.

Analog channels - the injection of a simulated signal into the channel as close to the primary sensor as practicable to verify OPERABILITY including alarm and/or trip functions.

b.

Bistable channels -

the injection of a simulated signal into the channel sensor to verify OPERABILITY including alarm and/or trip functions.

CORE ALTERATION 1.12 CORE ALTERATION shall be the movement of any fuel, sources, or reactivity control components, within the reactor vessel with the vessel head removed and fuel in the vessel.

Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position.

SHUTDOWN MARGIN 1.13 SHUTDOWN MARGIN shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

a.

No change in axial power shaping rod position, and

b.

All control rod assemblies (safety and regulating) are fully inserted except for the single rod assembly of highest reactivity worth which is assumed to be fully withdrawn.

IDENTIFIED LEAKAGE 1.14 IDENTIFIED LEAKAGE shall be:

a.

Leakage (except CONTROLLED LEAKAGE) into closed systems, such as pump seal or valve packing leaks that are captured and conducted.

to a sump or collecting tank, or

b.

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 DAVIS-BESSE, UNIT I 1-3 Amendment-No. 224

DEFINITIONS

c. Reactor coolant system leakage through a steam generator to the secondary system (primary to secondary leakage).

UNIDENTIFIED LEAKAGE 1.15 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE or CONTROLLED LEAKAGE.

PRESSURE BOUNDARY LEAKAGE 1.16 PRESSURE BOUNDARY LEAKAGE shall be leakage (except steam-gener-tu-be-vrimary to secondary leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.

CONTROLLED LEAKAGE 1.17 CONTROLLED LEAKAGE shall be that seal water flow from the reactor coolant pump seals.

QUADRANT POWER TILT 1.18 QUADRANT POWER TILT is defined by the following equation and is expressed in percent.

QUADRANT POWER TILT 100(

Power in any core quadrant Average power of all quadrants DOSE EQUIVALENT 1-131 1.19 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (liCi/gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, 1-133, 1-134 and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, "Calculation of Distance Factors for Power and Test Reactor Sites."

E - AVERAGE DISINTEGRATION ENERGY 1.20

&-AVERAGE DISINTEGRATION ENERGY shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies DAVIS-BESSE, UNIT 1 1-4 Amendment No.

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be > 1% Ak/k.

APPLICABILITY: MODES 1, 2, 3, 4 and 5.

ACTION:

With the SHUTDOWN MARGIN < 1% Ak/k, immediately initiate and continue boration at > 25 gpm of 7875 ppm boron or its equivalent, until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be > 1% Ak/k:

a. Within one hour after detection of an inoperable control rod(s) and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the above required SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable control rod(s).

b. When in MODES I or 2#, at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , by verifying that regulating rod groups withdrawal is within the limits of Specification 3.1.3.6.

c. When in MODE 2" within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving reactor criticality by verifying that the predicted critical control rod position is within the limits of Specification 3.1.3.6.

d. Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading by consideration of the factors of e. below, with the regulating rod groups at the maximum insertion limit of Specification 3.1.3.6.

See Special Test Exception 3.10.4

- See LCO 4*3..9, Steam GeneratorsLevel, for additional SHUTDOWN MARGIN requirements.

11With keffr> 1.0

"#With keff < 1.0 DAVIS-BESSE, UNIT 1 3/4 1-1 Amendment No. 191, 192,

FO0R I N FORMACD REACTIVITY CONTROL SYSTEMS FORINF" SURVEILLANCE REQUIREMENTS (Continued)

e.

When in MODES 3, 4 or 5, at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by consideration of the following factors:

1. Reactor coolant system boron concentration,

2.

Control rod position,

3.

Reactor coolant system average temperature,

4.

Fuel burnup based on gross thermal energy generation,

5.

Xenon concentration, and

6.

Samarium concentration.

4.1.1.1.2 The overall core reactivity balance shall be compared to predicted values to demonstrate agreement within + 1% ak/k at least once per 31 Effective Full Power Days (EFPD).

This comparison shall consider at least those factors stated in Specification 4.1.1.1.1.e, above.

The predicted reactivity values shall be adjusted (normalized) to correspond to the actual core conditions prior to exceeding a fuel burnup of 60 Effective Full Power Days after each fuel loading.

DAVIS-BESSE, UNIT 1 3/4 1-2

NiEWTS 3/4 4.5 REACTOR COOLANT SYSTEM 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY LIMITING CONDITION FOR OPERATION 3.4.5

a. SG tube integrity shall be maintained, and

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

APPLICABILITY:

MODES 1,2,3, and 4.

ACTION:

Note: These ACTIONS may be entered separately for each SG tube.

a. With one or more SG tubes satisfying the tube repair criteria and not plugged or repaired in accordance with the Steam Generator Program,

1. Within 7 days, verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection, or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and

2. Plug or repair the affected tube(s) in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following the next refueling outage or SG tube inspection.

b. With SG tube integrity not maintained, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.5.1 Verify SG tube integrity in accordance with the Steam Generator Program.

4.4.5.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged or repaired in' accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following a SG tube inspection.

DAVIS-BESSE, UNIT 1 3/4 4-6 (next page is 3/4 4-13)

Amendment No. 8, 21, 27, 62, 111,113,171,184, 192,220, 226, 252, 262,

REACTOR COOLANT SYSTEM STEAM GENERATORS LIMITING CONDITION FOR OPERATION 3.4.5 Each Steam Generator shall be OPERABLE with a minimum water level of 18 inches and the maximum specified below as applicable:

MODES 1 and 2:

a.

The acceptable operating region of Figure 3.4-5.

MODE 3*:

b.

50 inches Startup Range with the SFRCS Low Pressure Trip bypassed and one or both Main Feedwater Pump(s) capable of supplying Feedwater to any Steam Generator.

c.

96 percent Operate Range with:

1.

The SFRCS-Low Pressure Trip active.

Or

2.

The SFRCS Low Pressure Trip bypassed and both Main Feedwater Pumps incapable of supplying Feedwater to the Steam Generators.

MODE 4:

d.

625 inches Full.Range Level APPLICABILITY:

MODES 1, 2, 3, and 4, as above.

ACTION:

a.

With one or more steam generators inoperable due to steam generator tube imperfections, restore the inoperable generator(s) to OPERABLE status prior to increasing TV, above 2000 F.

b.

With one or more steam generators inoperable due to the water level being outside the limits, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

Establish adequate SHUTDOWN MARGIN to ensure the reactor will stay subcritical during a MODE 3 Main Steam Line Break.

I DAVIS-BESSE, UNIT I 3/4 4-6 Amendment No.

2Y,Y7Y,192

OLDT34 4.5 Fiqure 3.4-5 Maximum Allowable Steam Generator Level in MODES I and 2 100 (43,96)

C 03-C.

0j so 80 70 60 Unacceptable Operating.

Region Acceptable Operating Region 50 40 0

10 I20 130 140 150

-f 60 0

Main Steam Superheat (OF)

I DAVIS-BESSE, UNIT I 3/4 4-6a Amendment No.192

REACTOR COOLANT SYSTEM STEAM GENERATORS SURVEILLANCE REQUIREMENTS 4.4.5.0 Each steam generator shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.

4.4.5.1 Steam Generator Sample Selection and Inspection - Each steam generator shall be determined OPERABLE during shutdown by selecting and inspecting at least the minimum number of steam generators specified in Table 4-4.1.

4.4.5.2 Steam Generator Tube Sample Selection and Inspection -

The steam generator tube minimum sample size, inspection result classification, and the corresponding action required shall be as specified in Table 4.4-2.

The inservice inspection of steam generator tubes shall be performed at the frequencies specified in Specification 4.4.5.3 and the inspected tubes shall be verified acceptable per the acceptance criteria of Specification 4.4.5.4.

The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all steam generators; the tubes selected for these inspections shall be selected on a random basis except:

a.

The first sample inspection during each inservice inspection of each steam generator shall include:

1.

All tubes or tube sleeves that previously had detectable wall penetrations (> 20%) that have not been plugged or repaired by repair roll or sleeving in the affected area.

(Tubes repaired by sleeving or repair roll remain available for random selection).

2.

At least 50% of the tubes inspected shall be in those areas where experience has indicated potential problems.

DAVIS-BESSE - UNIT I 3/4 4-6b Amendment No.442-, 220

REACTOR COOLANT.SYSTEM LD I'S 314 SURVEILLANCE REQUIREMENTS (Continued)

3.

A tube inspection (pursuant to Specification 4.4.5.4.a.9) shall be performed on each selected tube.

If any selected tube does not permit the passage of the eddy current probe

,for a tube inspection, this shall be recorded and an adjacent tube shall be selected and subjected to a tube inspection.

b.

Tubes in the following groups may be excluded from the first random sample if all tubes in a group in both steam generators are inspected.

No credit will be taken for these tubes in meeting minimum sample size requirements.

1.

Group A-1:

Tubes within one, two or three rows of the open inspection lane.

2.

Group A-2:

Tubes having a drilled opening in the 15th support plate.

3.

Group A-3:

Tubes included in the rectangle bounded by rows 62 and 90 and by tubes 58 and 76, excluding tubes included in Group A-I.*

c.

The tubes selected as the second and third samples (if required by Table 4.4-2) during each inservice inspection may be subjected to less than a full tube inspection provided:

1.

The tubes selected for these samples include the tubes from those areas of the tube sheet array where tubes with imperfections were previously found.

2.

The inspections include those portions of the tubes where imperfections were previously found.

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

Category Inspection Results C-1 Less than 5% of the total tubes inspected are degraded tubes and none of the inspected tubes are defective.

C-2 One or more tubes, but not more than 1% of the total tubes inspected are defective, or between 5% and 10% of the total tubes inspected are degraded tubes.

C-3 More than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective.

Tubes in Group A-3 shall not be excluded after completion of the fifth refueling outage.

DAVIS-EESSE, UNIT I 3/4 4-7 Amendment No-Z;9 *;IZI'184

OLD TS 3/4 4.5I REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

Notes: (1)

In all inspections, previously degraded tubes must exhibit significant (> 10%)

further wall penetrations to be included in the above percentage calculations.

(2)

Where special inspections are performed pursuant to 4.4.5.2.b, defective or degraded tubes found as a result of the inspection shall be included in determining the Inspection Results Category for that special inspection but need not be included in determining the Inspection Results Category for the general steam generator inspection.

4.4.5.3 Inspection Frequencies - The above required inservice inspections of steam generator tubes shall be performed at the following frequencies:

a.

Inservice inspections shall be performed at intervals of not less than 12 nor more than 24 calendar months** after the previous inspection. If the results of two consecutive inspections for a given group* of tubes following service under all volatile treatment (AVT) conditions fall into the C-I category or if two consecutive inspections demonstrate that previously observed degradation has not continued and no additional degradation has occurred, the inspection interval for that group may be extended to a maximum of 40 months.

b. If the results of the inservice inspection of a steam generator performed in accordance with Table 4.4-2 at 40 month intervals for a given group* of tubes fall in Category C-3, subsequent inservice inspections shall be performed at intervals of not less than 10 nor more than 20 calendar months after the previous inspection. The increase in inspection frequency shall apply'until a subsequent inspection meets the conditions specified in 4.4.5.3a and the interval can be extended to 40 months.

c.

Additional, unscheduled inservice inspections shall be performed on each steam generator in accordance with the first sample inspection specified in Table 4.4-2 during the shutdown subsequent to any of the following conditions:

1. Primary-to-secondary tube leaks (not including leaks originating from tube-to tube sheet welds) in excess of the limits of Specification 3.4.6.2.

If the leak is determined to be from a repair roll'joint, rather than selecting a random sample, inspect 100% of the repair roll joints in the affected steam generator. If the results of this inspection fall into the C-3 category, perform additional inspections of the new roll areas in the unaffected steam generator.

A group of tubes means:

(a) All tubes inspected pursuant to 4.4.5.2.b, or (b) All tubes in a steam generator less those inspected pursuant to 4.4.5.2.b.

- An exception applies for the interval following the March 2002 inspection completed during the Thirteenth Refueling Outage. Under this exception, the next inservice inspection may be delayed until March 31, 2005.

DAVIS-BESSE, UNIT I 3/4 4-8 Amendment No. 21, 220, 262

OiLD TS3/4 4.51 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

2.

A seismic occurrence greater than the Operating Basis Earthquake.

3.

A loss-of-coolant accident requiring actuation of the engineered safeguards.

4.

A main steam line or feedwater line break.

d. The provisions of Specification 4.0.2 are not applicable.

4.4.5.4 Acceptance Criteria

a. As used in this Specification:

1. Tubing or Tube means that portion of the tube or tube sleeve which forms the primary system to secondary system boundary.

2.

Imperfection means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the nominal tube wall thickness, if detectable, may be considered as imperfections.

3.

Degradation means a service-induced cracking, wastage, wear or general corrosion occurring on either inside or outside of a tube.

4.

Degraded Tube means a tube containing imperfections > 20% of the nominal wall thickness caused by degradation that has not been repaired by repair roll or sleeving in the affected area.

5.

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

6.

Defect means an imperfection of such severity that it exceeds the repair limit.

A defective tube is a tube containing a defect that has not been repaired by repair roll or sleeving in the affected area or a sleeved tube that has a defect in the sleeve.

7.

Repair Limit means the imperfection depth at or beyond which the tube shall be removed from service by plugging or repaired by repair roll or sleeving in the affected area because it may become unserviceable prior to the next inspection and is equal to 40% of the nominal tube wall thickness. The process described in Topical Report BAW-2120P will be used for sleeving.

DAVIS-BESSE, UNIT 1 3/4 4-9 Amendment No. 21, 171, 220, 252

[OLD TS 3/4 4.5 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

(Continued) 7. The repair roll process used is described in. the Topical Report BAW-2303P, Revision 4. The new roll area must be free of degradation in order for the repair to be considered acceptable.

8. Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 4.4.5.3.c, above.

9. Tube Inspection means an inspection of the steam generator tube from the point of entry completely to the point of exit. The previously existing tube and tube roll, outboard of the new roll area in the tube sheet, can be excluded from future periodic inspection requirements because it is no longer part of the pressure boundary once the repair roll is installed.

DAVIS-BESSE, UNIT I 3/4 4-9a Amendment No. 21, 171, 220, 252

~OLD TS'3/4 4.5 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

10.

Preservice Inspection means an inspection of the full length of each tube in each steam generator performed by eddy current techniques prior to service to establish a baseline condition of the tubing.

This inspection shall be performed prior to initial POWER OPERATION using the equipment and techniques expected to be used during subsequent inservice inspections.

b. The steam generator shall be determined OPERABLE after completing the corresponding actions (plug or repair by repair roll or sleeving in the affected areas all tubes exceeding the repair limit and all tubes containing through-wall cracks) required by Table 4.4-2.

4.4.5.5 Reports

a. Following each inservice inspection of steam generator tubes, the number of tubes plugged in each steam generator shall be reported to the Commission within 15 days.

b. The complete results of the steam generator tube inservice inspection shall be submitted on an annual basis in a report for the period in which this inspection was completed.

This report shall include:

1. Number and extent of tubes inspected.

2.

Location and percent of wall-thickness penetration for each indication of an imperfection.

3. Identification of tubes plugged, sleeved or repair rolled.

c. Results of steam generator tube inspections which fall into Category C-3 and require notification of the Commission shall be reported prior to resumption of plant operation.

This report shall provide a description-of investigations conducted to determine cause of the tube degradation and corrective measures taken to prevent recurrence.

4.4.5.6 The steam generator shall be demonstrated OPERABLE by verifying steam generator level to be within limits at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4.4.5.7 When steam generator tube inspection is performed as per Section 4.4.5.2, an additional but totally separate inspection shall be performed on special interest peripheral tubes in the vicinity of the secured internal auxiliary feedwater header.

This testing shall only be required on the steam generator selected for inspection, and the test shall require inspection only between DAVIS-BESSE, UNIT 1 3/4 4-10 Amendment No.

8,27,62,171,184, 220

[~.OLD TS 3/4 4.5 REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) the upper tube sheet and the 15th tube support plate.

The tubes selected for inspection shall represent the entire circumference of the steam generator and shall total at least 150 peripheral tubes.

4.4.5.8 Visual inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves shall be performed on each steam generator through the auxiliary feedwater injection penetrations..

These inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves shall be performed during the third period of each ten-year Inservice Inspection Interval (ISI).

4.4.5.9 When steam generator tube inspection is performed as per Section 4.4.5.2, an additional but totally separate inspection shall be performed on special interest tubes that have been repaired by the repair roll process.

This inspection shall be performed on 100% of the tubes that have been repaired by the repair roll process.

The inspection shall be limited to the repair roll joint and the roll transitions of the repair roll.

Defective or degraded tubes found in the repair roll region as a result of the inspection need not be included in determining the Inspection Results Category for the general steam generator inspection.

DAVIS-BESSE,-UNIT I 3/4 4-10a Amendment No.

6*-2,9-226

8-4 4A I

4A tA TABLE 4.4-1 MINIMUM NUMBER OF STEAM GENERATORS TO BE INSPECTED DURING INSERVICE INSPECTION

--a

-a Pueseevisc Inspection No Yes No. ol Steam Generators per Unit Two i

Threeo, Two Three Four First Inservice Inspection All Oine Two Two Second & Subsequent Insarvlce Inspections One' OaeI One e2 I

On Table Notation:

I.

Tlhe Inservice inspection may be limited to one steam generator on a rotating schedule escunttnassmufs 3 N % of lhe lutbes lwhera N is the ntrmber ol steam generators in the plant) if the results of the first or previous inspettions indicate that all steam geneflitors are performing in a like manner. Note that under some circumslances. lIe ojerdmlemg. conditions in one or more steam generators may be Iouoid to be more severe than those in other steani ijeasef dOfs Under such citcuin stances the sample sequence shall be modified to Inspect the most severe conditions.

2. The other steam generator not inspected (luring the lhsu inservice inspection shall be insliecied. The 1llird and subsequent inspections should follow the instruct.,ns described en I above.

3. Each of the other two steam generators iiot inspecteil iluring the first inservice inspecitisais shall lie iisliecled during ihe second and third inspections. The lourlh and subseqluenit inspeclions shall follow lite ilisltnictioilS desuibed in I athuve.

-~<

TABLE 4.4-2 STEAM GENERATOR TUBE INSPECTION rn (A

In (D

0 m C+

C,ct0

~C+

L0F CA I ST SAMPLE INSPECTION 2ND SAMPLE INSPECTION 3RD SAMPLE INSPECTION Sample Size Result Action Required Result Action Required Result Action Required A minimum orS Tubes per S.O. (1)

C-1 None N/A N/A N/A N/A I

I 1-I C-2 Plug or repair by repair rolling or sleeving defective tubes and inspect additional 2S tubes in Ihis S.G.

C-I None N/A N/A C-2 Plug or repair by repair rolling or C-I None sleeving defective tubes and inspect additional 4S tubes in this S.O.

C-2 Plug or repair by repair rolling or sleeving defective tubes C-3 Perform action for C-3 result of I

I_ first sample I

I C-3 Perform action for C.3 result of first samole N/A N/A fis 4

+

I t

C-3 Inspect all tubes in this S.O., plug or repair by repair rolling or sleeving defective tubes and inspect 2S tubes in each other S.G. Report to the NRC prior to resumption of plant operation.

All other S.O.s are C-I None N/A N/A I

Some S.G.s C-Perform action for C-2 result of 2 but no.

second sample N/A N/A additional S.0.

are C-3 Additional S.O.

is C-3 Inspect all tubes in each 5.0. and plug or repair by repair rolling or sleeving defective tubes. Report to the NRC prior to resumptiono olant oncration.

N/A H

I~.

N/A J ______________ I _______________________________________ J __________________~.L

__________________ I ____________________________________

I (1

S3N Where N Is the number of steam generators in the unit, and n is the number of steam generators inspected during an inspection.

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.6.2 Reactor Coolant System onerational leakage shall be limited to:

a.

No PRESSURE BOUNDARY LEAKAGE,

b.

1 GPM UNIDENTIFIED LEAKAGE,

c.

150 GPD pri*m.ay to....

nd*rpima,. to secondary leakage through the-tubes-eof any one steam generator-LSG,

d.

10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System,

e.

10 GPM CONTROLLED LEAKAGE, and

f.

5 GPM leakage from any Reactor Coolant System Pressure Isolation Valve as specified in Table 3.4-2.

APPLICABILITY: MODES 1, 2, 3 and 4 ACTION:

a.

With any PRESSURE BOUNDARY LEAKAGE, or with primary to secondary leakage not within limit, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

With any Reactor Coolant System operational leakage greater than any one of the above limits, excluding PRESSURE BOUNDARY LEAKAGE or primary to secondary leakage, reduce the leakage rate to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months except as permitted by paragraph c below.

c.

In the event that integrity of any pressure isolation valve specified in Table 3.4-2 cannot be demonstrated, POWER OPERATION may continue, provided that at least two valves in each high pressure line having a non-functional valve are in and remain in, the mode corresponding to the isolated condition.(a)

d.

The provisions of Section 3.0.4 are not applicable for entry into MODES 3 and 4 for the purpose of testing the isolation valves in Table 3.4-2.

(a)Motor operated valves shall be placed in the closed position and power supplies deenergized.

DAVIS-BESSE, UNIT 1 3/4 4-15 Order dtd. 4/20/81 Amendment No. 135, 180, 220,

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System operational leakages shall be demonstrated to be within each of the above limits by:

a. Monitoring the containment atmosphere gaseous or particulate radioactivity at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. Monitoring the containment sump level and flow indication at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. Measurement of the CONTROLLED LEAKAGE from the reactor coolant pump seals to the makeup system when the Reactor Coolant System pressure is 2185 +/- 20 psig at least once per 31 days.

d. Performance of a Reactor Coolant System water inventory balance at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months during steady state operation. (1)(2)

e. An evaluation of se.ondary wat radio.h.mistiy for dete.mination otVerifving that primary to secondary'leakage is < 150 gallons per day through the-any one steam genleator-sgenerator._at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months during steady,tteo.

.,ations.

(2) 4.4.6.2.2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-2 shall be individually demonstrated OPERABLE by verifying leakage testing (or the equivalent) to be within its limit prior to entering MODE 2:

a. After each refueling outage,

b. Whenever the plant has been in COLD SHUTDOWN for 7 days, or more, and if leakage testing has not been performed in the previous 9 months, and

c. Prior to returning the valve to service following maintenance, repair or replacement work on the valve.

d. The provisions of Specification 4.0.4 are not applicable for entry into MODES 3 or 4.

4.4.6.2.3 Whenever the integrity of a pressure isolation valve listed in Table 3.4-2 cannot be demonstrated, determine and record the integrity of the high pressure flowpath on a daily basis.

Integrity shall be determined by performing either a leakage test of the remaining pressure isolation valve, or a combined leakage test of the remaining pressure isolation valve in a series with the closed motor-operated containment isolation valve. In addition, record the position of the closed motor-operated containment isolation valve located in the high pressure piping on a daily basis.

(I)

Not applicable to primary to secondary leakage.

(2) Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

DAVIS-BESSE, UNIT 1 3/4 4-16 Order dated 4/20/81 Amendment No. 54, 135, 180, 196, 220,

TABLE 3.4-2 REACTOR COOLANT SYSTEM PRESSURE ISOLATION VALVES FOR INFORMATION ONLY

.SYSTEM VALVE NUMBERS (b)

MAXIuL<4 ALLOWABLE LEAKAGE (a)(c)

1.

Decay Heat Removal CF-30 q

5.0 g.

2.

Decay Heat Removal CF-31 S.0 gpm

3.

Decay Heat Removal DI-76 5.0 gpm

4.

Decav Heat Removal OH-77 5.0 gpm Notes:

(a)

1.

Leakage rates less than or equal to 1.0 gpm are considered acceptable.

2.

Leakage rates grehter than 1.0 gpm but less than or equal to 5.0 gM are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximu permissible rate of 5.0 gpm by 0S or greater.

3.

Leakage rates greater than 1.0 gpm out less than or equal to 5.0 gpm are considered unacceptable if the latest measured rate exceeded the rate determined by the previou" test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 501 or greater.

4.

Leakage rates greater than 5.0 gpm are considered unacceptable.

(b)

Valves CF-30 and CF-31 will be tested-with the Reactor Coolant system presure 31200 psig.

Valves DH-76 and 0H-77 will be tested with nouml Core Flooding Tank pressure which Is,3575 psig.

Mini-mu differential test pressure across each valve shall not be less than 10 psid.

(c)

To satisfy ALAR requirements, leakage may be measured Indirectly (as from the performance of pressure indicators) if accomplshed in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakale criterIa.

DAVIS-BESSE, UNIT 1 314 4-16a Order dtd.

4/20/81

I NEWTS 3/47.91 3/4.7 PLANT SYSTEMS 3/4.7.9 STEAM GENERATOR LEVEL LIMITING CONDITION FOR OPERATION 3.7.9 Each Steam Generator shall have a minimum water level of 18 inches and the maximum specified below as applicable:

MODES 1 and 2:

a. The acceptable operating region of Figure 3.7-1.

MODE 3":

b. 50 inches Startup Range with the SFRCS Low Pressure Trip bypassed and one or both Main Feedwater Pump(s) capable of supplying Feedwater to any Steam Generator.

c. 96 percent Operate Range with:

1. The SFRCS Low Pressure Trip active, or

2. The SFRCS Low Pressure Trip bypassed and both Main Feedwater Pumps incapable of supplying Feedwater to the Steam Generators.

MODE 4:

d. 625 inches Full Range Level APPLICABILITY:

MODES 1, 2, 3, and 4, as above.

ACTION:

With one or more steam generator's water level outside the limits, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.7.9 The steam generator shall be demonstrated OPERABLE by verifying steam generator level to be within limits at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Establish adequate SHUTDOWN MARGIN to ensure the reactor will stay subcritical during a MODE 3 Main Steam Line Break.

DAVIS-BESSE, UNIT I 3/47-38 Amendment No. 21, 171, 192,

NEW~ TS '3/4 7.9 Figure 3.7-1 Maximum Allowable Steam Generator Level in MODES 1 and 2 100 o

80 -

Unacceptable Operating Region 70-0

"60--

0

/Acceptable SOperating S50Region 40 -

20 30 40 s0 60 Main Steam Superheat (OF)

DAVIS-BESSE, UNIT 1 3/4 7-39 Amendment No. 192,

ADMINISTRATIVE CONTROLS 6.8.4 (Continued)

f.

Ventilation Filter Testing Program (VFTP) (Continued) below when tested in accordance with ASTM D 3803-1989 at a temperature of 300 C and the relative humidity (RH) specified below.

Safety Related Ventilation System Penetration RH Shield Building Emergency Ventilation System

2.5%

95%

Control Room Emergency Ventilation System

2.5%

70%

4.

Demonstrate for each of the safety related systems that the pressure drop across the combined HEPA filters, the prefilters, and the charcoal adsorbers is less than the value specified below when tested in accordance with Regulatory Guide 1.52, Revision 2 and ANSI/ASME N510-1980 at the system flowrate specified below, +/- 10%.

Safety Related Ventilation System Delta P Flowrate Shield Building Emergency Ventilation System 6 inches Water Gauge 8000 cfm Control Room Emergency Ventilation System 4.4 inches Water Gauge 3300 cfm The provisions of SR 4.0.2 and SR 4.0.3 are applicable to the VFTP test frequencies.

g.

Steam Generator (SG) Program DAVIS-BESSE, UNIT I 6-14d Amendment No. 244, 265,

IN~SERT 6.8.4g,

g.

Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

1)

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

2)

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

a.

Structural integrity performance criterion: All in-service SG 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 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.

b.

Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG.

Leakage is not to exceed I gpm per SG, except during a SG tube rupture.

C.

The operational leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

3)

Provisions for SG tube repair criteria : Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired.

IINSERT 6.8.4.g

',,(contin~ued)

4)

Provisions for SG tube inspections: Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g.,

volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. For tubes that have undergone repair rolling, the previously existing tube and tube roll, outboard of the new roll area in the tube sheet, can be excluded from future periodic SG tube inspections because it is no longer part of the pressure boundary once the repair roll is installed. For tubes that have undergone sleeving repairs, the previously existing parent tube, from the original tubesheet roll expansion through the second (outboard) sleeve roll, can be excluded from future periodic SG tube inspections because it is no longer part of the pressure boundary once the sleeve is installed. The installed sleeve, from the sleeve tubesheet roll expansion to the end of the second (outboard) free span sleeve roll, will be included in future periodic SG tube inspections because it is part of the pressure boundary. In addition to meeting the requirements of 4.a, 4.b, and 4.c 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.

a.

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

b.

Inspect 100% of the tubes at sequential periods of 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. No SG shall operate for more than 24 effective full power months or one interval between refueling outages (whichever is less) without being inspected.

c.

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

5)

Provisions for monitoring operational primary to secondary leakage.

INSE3RT 6.8.4.g I(~Continued)

6)

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

a.

Sleeving in accordance with Topical Report BAW-2120P.

b.

Repair rolling in accordance with Topical Report BAW-2303P, Revision 4.

The new roll area must be free of degradation in order for the repair to be considered acceptable.

7)

Special interest tube inspection: For each periodic SG tube inspection, 100% of the tubes that have been repaired by the repair roll process shall be inspected. This special inspection shall be limited to the repair roll joint and the roll transitions of the repair roll.

8)

Special visual inspections: Visual inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves shall be performed on each SG through the auxiliary feedwater injection penetrations. These inspections shall be performed during the third period of each ten-year Inservice Inspection Interval (ISI).

9)

Special interest tube inspection: For each periodic SG tube inspection, a separate inspection shall be performed on peripheral tubes in the vicinity of the secured internal auxiliary feedwater header between the upper tube sheet and the 15th tube support plate. The tubes selected for inspection shall represent the entire circumference of the steam generator and shall total at least 150 peripheral tubes.

ADMINISTRATIVE CONTROLS ANNUAL OPERATING REPORT 6.9.1.4 Annual reports covering the activities of the unit during the previous calendar year shall be submitted prior to March 31 of each year.

6.9.1.5 Reports required on an annual basis shall include:

a. Deleted b.Th amet -s 4 4.S.)..Dgel dt W Itn of' 4tAm ~eeno ueinqq.'ise inqneptionq (SneA~if4AAtion

c. The results of specific activity analysis in which the primary coolant exceeded the limits of Specification 3.4.8. The following information shall be included: (1) Reactor power history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded; (2)

Results of the last isotopic analysis for radioiodine performed prior to exceeding the limit, results of analysis while limit was exceeded and results of one analysis after the radioiodine activity was reduced to less than limit. Each result should include date and time of sampling and the radioiodine concentrations; (3) Clean-up system flow history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded; (4) Graph of the 1-131 concentration and one other radioiodine isotope concentration in DAVIS-BESSE, UNIT 1 6-15 Amendment No. 9, 12, 41, 52, 73, 87, 104, 135, 258, 267,

ADMINISTRATIVE CONTROLS ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT 6.9.1.10 The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted before May 1 of each year. The report shall include summaries, interpretations, and analysis of trends of the results of the Radiological Environmental Monitoring Program for the reporting period. The material provided shall be consistent with the objectives outlined in (1) the ODCM, and (2) Sections JV.B.2, IV.B.3, and IV.C of Appendix I to 10 CFR Part 50.

RADIOACTIVE EFFLUENT RELEASE REPORT 6.9.1.11 The Radioactive Effluent Release Report covering the operation of the unit shall be submitted in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be (1) consistent with the objectives outlined in the ODCM and the Process Control-Program, and (2) in conformance with 10 CFR 50.36a and Section IV.B.1 of Appendix I to 10 CFR Part 50.

STEAM GENERATOR TUBE INSPECTION REPORT 6,9.1.12 A'report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.8.4.L. Steam Generator (SG) Program. The report shall include:

a.

The scope of inspections performed on each SG.

b.

Active degradation mechanisms found,

c.

Nondestructive examination techniques utilized for each degradation mechanism,

d.

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

e.

Number of tubes plugged or repaired during the inspection outage for each active degradation mechanism,

f.

Total number and percentage of tubes plugged or repaired to date, g,

The results of condition monitoring, including the results of tube pulls and in-situ

h.

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

i.

Repair method utilized and the number of tubes repaired by each repair method.

DAVIS-BESSE, UNIT 1 6-17a Amendment No. 86, 93, 170, 184, 272,

Docket Number 50-346 License Number NPF-3 Serial Number 3231 PROPOSED RETYPED TECHNICAL SPECIFICATION PAGES (34 pages follow)

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.4.4 PRESSURIZER.............................................

3/4 4-5 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY.................

3/4 4-6 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE Leakage Detection Systems....................................

3/4 4-13 Operational Leakage..........................................

3/4 4-15 3/4.4.7 Deleted................................................

3/4 4-17 3/4.4.8 SPECIFIC ACTIVITY........................................

3/4 4-20 3/4.4.9 PRESSURE/TEMPERATURE LIMITS Reactor Coolant System.......................................

3/4 4-24 D eleted....................................................

3/4 4-29 3/4.4.10 STRUCTURAL INTEGRITY.................................

3/4 4-30 3/4.4.11 D eleted...................................................

3/4 4-32 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3/4.5.1 CORE FLOODING TANKS...................................

3/4 5-1 3/4.5.2 ECCS SUBSYSTEMS - Tag _>280°F.............................

3/4 5-3 3/4.5.3 ECCS SUBSYSTEMS - Tayg < 280°F............................

3/4 5-6 3/4.5.4 BORATED WATER STORAGE TANK...........................

3/4 5-7 DAVIS-BESSE, UNIT 1 V

Amendment No. 135, 201, 234,

245,

INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE Safety V alves...............................................

3/4 7-1 Auxiliary Feedwater System...................................

3/4 7-4 Condensate Storage Tanks....................................

3/4 7-6 A ctivity...................................................

3/4 7-7 Main Steam Line Isolation Valves..............................

3/4 7-9 Motor Driven Feedwater Pump System..........................

3/4 7-12a Main Feedwater Control Valves and Startup Feedwater Control Valves 3/4 7-12d Turbine Stop Valves.........................................

3/4 7-12e 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION.

3/4 7-13 3/4.7.3 COMPONENT COOLING WATER SYSTEM....................

3/4 7-14 3/4.7.4 SERVICE WATER SYSTEM.................................

3/4 7-15 3/4.7.5 ULTIMATE HEAT SINK.....................................

3/4 7-16 3/4.7.6 CONTROL ROOM EMERGENCY VENTILATION SYSTEM.......

3/4 7-17 3/4.7.7 SNUBBERS...............................................

3/4 7-20 3/4.7.8 SEALED SOURCE CONTAMINATION........................

3/4 7-36 3/4.7.9 STEAM GENERATOR LEVEL................................

3/4 7-38 3/4.7.10 Deleted 3/4.8 ELECTRICAL POWER SYSTEMS 3/4.8.1 A.C. SOURCES Operating..................................................

3/4 8-1 Shutdow n..................................................

3/4 8-5 3/4.8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. Distribution - Operating..................................

3/4 8-6 A.C. Distribution -Shutdown...................................

3/4 8-7 D.C. Distribution - Operating..................................

3/4 8-8 D.C. Distribution - Shutdown..................................

3/4 8-11 DAVIS-BESSE, UNIT 1 VII Amendment No. 38, 103, 106, 135, 164, 174, 246,

INDEX BASES SECTION 3/4.0 APPLICABILITY...........................................

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL....................................

3/4.1.2 BORATION SYSTEMS.....................................

3/4.1.3 MOVABLE CONTROL ASSEMBLIES..........

3/4.2 POWER DISTRIBUTION LIMITS.............................

3/4.3 INSTRUMENTATION 3/4.3.1 and 3/4.3.2 REACTOR PROTECTION SYSTEM AND SAFETY SYSTEMS INSTRUMENTATION............................

3/4.3.3 MONITORING INSTRUMENTATION........................

3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS..............................

3/4.4.2 and 3/4.4.3 SAFETY VALVES...............................

3/4.4.4 PRESSURIZER...........................................

3/4.4.5 STEAM GENERATOR TUBE INTEGRITY....................

3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE...................

3/4.4.7 D eleted..................................................

3/4.4.8 SPECIFIC ACTIVITY......................................

3/4.4.9 PRESSURE/TEMPERATURE LIMITS........................

3/4.4.10 STRUCTURAL INTEGRITY...............................

3/4.4.11 D eleted...................................................

PAGE B 3/40-1 B 3/4 1-1 B 3/4 1-2 B 3/4 1-3 B 3/4 2-1 B 3/4 3-1 B 3/4 3-2 B 3/44-1 B 3/44-1 B 3/4 4-2 B 3/4 4-2 B 3/4 4-4 B 3/4 4-5 B 3/4 4-5 B 3/4 4-6 B 3/4 4-13 B 3/4 4-13 DAVIS-BESSE, UNIT I IX Amendment No. 135, 201,234,

INDEX BASES SECTION 3/4.7 PLANT SYSTEMS PAGE 3/4.7.1 TURBINE CYCLE.........................................

3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION 3/4.7.3 COMPONENT COOLING WATER SYSTEM...................

3/4.7.4 SERVICE WATER SYSTEM.................................

3/4.7.5 ULTIMATE HEAT SINK....................................

3/4.7.6 CONTROL ROOM EMERGENCY VENTILATION SYSTEM......

3/4.7.7 SN UBBER S...............................................

3/4.7.8 SEALED SOURCE CONTAMINATION........................

3/4.7.9 STEAM GENERATOR LEVEL...............................

3/4.7.10 Deleted 3/4.8 ELECTRICAL POWER SYSTEMS.............................

B 3/4 7-1 B 3/4 7-4 B 3/4 7-4 B 3/4 7-4 B 3/4 7-4a B 3/4 7-4a B 3/4 7-5 B 3/4 7-6 B 3/4 7-6 I B 3/4 8-1 3/4.9 REFUELING OPERATIONS 3/4.9.1 BORON CONCENTRATION................................

3/4.9.2 INSTRUMENTATION......................................

3/4.9.3 DECAY TIM E............................................

3/4.9.4 CONTAINMENT PENETRATIONS...........................

3/4.9.5 DELETED B 3/4 9-1 B 3/49-1 B 3/4 9-1 B 3/4 9-1 DAVIS-BESSE, UNIT 1 XII Amendment No. 38, 106, 135, 174, 224, 246,

INDEX ADMINISTRATIVE CONTROLS SECTION PAGE 6.1 RESPONSIBILITY.................................................

6-1 6.2 ORGANIZATION Offsite and Onsite Organizations...................................

6-1 Facility Staff..................................................

6-1 Facility Staff Overtime...........................................

6-2 6.3 FACILITY STAFF QUALIFICATIONS................................

6-3 6.4 D ELETED........................................................

6-3 6.5 REVIEW AND AUDIT 6.5.1 Deleted 6.5.2 Deleted 6.5.3 Technical Review and Control......................................

6-4 6.6 D ELETED.....................................................

6-5 6.7 DELETED.....................................................

6-5 6.8 PROCEDURES AND PROGRAMS 6-5 6.9 REPORTING REQUIREMENTS 6.9.1 Routine Reports 6-13 6.9.2 Special Reports...................................................

6-16 6.10 RECORD RETENTION..........................................

6-16 6.11 DELETED 6.12 HIGH RADIATION AREA.......................................

6-16 6.13 ENVIRONMENTAL QUALIFICATION.............................

6-19 6.14 DELETED 6-19 6.15 OFFSITE DOSE CALCULATION MANUAL (ODCM).................

6-20 6.16 CONTAINMENT LEAKAGE TESTING PROGRAM...................

6-21 6.17 TECHNICAL SPECIFICATIONS (TS) BASES CONTROL PROGRAM...

6-22 DAVIS-BESSE, UNIT 1 XV Amendment No. 38,135,170,189,231, 235, 236,240,244, 248, 249, 272,

DEFINITIONS

c. Reactor coolant system leakage through a steam generator to the secondary system (primary to secondary leakage).

UNIDENTIFIED LEAKAGE 1.15 UNIDENTIFIED LEAKAGE shall be all leakage which is not IDENTIFIED LEAKAGE or CONTROLLED LEAKAGE.

PRESSURE BOUNDARY LEAKAGE 1.16 PRESSURE BOUNDARY LEAKAGE shall be leakage (except primary to secondary leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.

CONTROLLED LEAKAGE 1.17 CONTROLLED LEAKAGE shall be that seal water flow from the reactor coolant pump seals.

QUADRANT POWER TILT 1.18 QUADRANT POWER TILT is defined by the following equation and is expressed in percent.

QUADRANT POWER TILT =

100(

Power in any core quadrant

-1)

Average power of all quadrants DOSE EQUIVALENT 1-131 1.19 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (ptCi/gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of 1-131, 1-132, 1-133, 1-134 and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, "Calculation of Distance Factors for Power and Test Reactor Sites."

- AVERAGE DISINTEGRATION ENERGY 1.20 In-AVERAGE DISINTEGRATION ENERGY shall be the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies DAVIS-BESSE, UNIT 1 1-4 Amendment No.

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be > 1% Ak/k.

APPLICABILITY: MODES 1, 2%, 3"*, 4 and 5.

ACTION:

With the SHUTDOWN MARGIN < 1% Ak/k, immediately initiate and continue boration at > 25 gpm of 7875 ppm boron or its equivalent, until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be > 1% Ak/k:

a. Within one hour after detection of an inoperable control rod(s) and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter while the rod(s) is inoperable. If the inoperable control rod is immovable or untrippable, the above required SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable control rod(s).

b. When in MODES 1 or 2#, at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , by verifying that regulating rod groups withdrawal is within the limits of Specification 3.1.3.6.

c. When in MODE 2" within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving reactor criticality by verifying that the predicted critical control rod position is within the limits of Specification 3.1.3.6.

d. Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading by consideration of the factors of e. below, with the regulating rod groups at the maximum insertion limit of Specification 3.1.3.6.

See Special Test Exception 3.10.4

- See LCO 3.7.9, Steam Generator Level, for additional SHUTDOWN MARGIN requirements.

"With kff > 1.0 "With krff < 1.0 DAVIS-BESSE, UNIT I 3/4 1-1 Amendment No. 191, 192,

REACTOR COOLANT SYSTEM 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY LIMITING CONDITION FOR OPERATION 3.4.5

a. SG tube integrity shall be maintained, and

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

APPLICABILITY:

MODES 1,2, 3, and 4.

ACTION:

Note: These ACTIONS may be entered separately for each SG tube.

a. With one or more SG tubes satisfying the tube repair criteria and not plugged or repaired in accordance with the Steam Generator Program,

1. Within 7 days, verify tube integrity of the affected tube(s) is maintained until the next refueling outage or SG tube inspection, or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months , and

2. Plug or repair the affected tube(s) in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following the next refueling outage or SG tube inspection.

b. With SG tube integrity not maintained, be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.5.1 Verify SG tube integrity in accordance with the Steam Generator Program.

4.4.5.2 Verify that each inspected SG tube that satisfies the tube repair criteria is plugged or repaired in accordance with the Steam Generator Program prior to entering HOT SHUTDOWN following a SG tube inspection.

DAVIS-BESSE, UNIT 1 3/44-6 Amendment No. 8, 21, 27, 62, (next pageis 3/4 4-13) 111,113, 171,184, 192,220, 226, 252, 262,

REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE LIMITING CONDITION FOR OPERATION 3.4.6.2 Reactor Coolant System operational leakage shall be limited to:

a.

No PRESSURE BOUNDARY LEAKAGE,

b.

1 GPM UNIDENTIFIED LEAKAGE,

c.

150 GPD primary to secondary leakage through any one steam generator (SG),

d.

10 GPM IDENTIFIED LEAKAGE from the Reactor Coolant System,

e.

10 GPM CONTROLLED LEAKAGE, and

f.

5 GPM leakage from any Reactor Coolant System Pressure Isolation Valve as specified in Table 3.4-2.

APPLICABILITY: MODES 1, 2, 3 and 4 ACTION:

a.

With any PRESSURE BOUNDARY LEAKAGE, or with primary to secondary leakage not within limit, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

With any Reactor Coolant System operational leakage greater than any one of the above limits, excluding PRESSURE BOUNDARY LEAKAGE or primary to secondary leakage, reduce the leakage rate to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months except as permitted by paragraph c below.

C.

In the event that integrity of any pressure isolation valve specified in Table 3.4-2 cannot be demonstrated, POWER OPERATION may continue, provided that at least two valves in each high pressure line having a non-functional valve are in and remain in, the mode corresponding to the isolated condition.(a)

d.

The provisions of Section 3.0.4 are not applicable for entry into MODES 3 and 4 for the purpose of testing the isolation valves in Table 3.4-2.

(a)Motor operated valves shall be placed in the closed position and power supplies deenergized.

DAVIS-BESSE, UNIT 1 3/4 4-15 Order dtd. 4/20/81 Amendment No. 135, 180, 220,

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System operational leakages shall be demonstrated to be within each of the above limits by:

a. Monitoring the containment atmosphere gaseous or particulate radioactivity at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. Monitoring the containment sump level and flow indication at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. Measurement of the CONTROLLED LEAKAGE from the reactor coolant pump seals to the makeup system when the Reactor Coolant System pressure is 2185 +/- 20 psig at least once per 31 days.

d. Performance of a Reactor Coolant System water inventory balance at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months during steady state operation.

)(2)

e. Verifying that primary to secondary leakage is < 150 gallons per day through any one steam generator, at least once per 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . (2) 4.4.6.2.2 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4-2 shall be individually demonstrated OPERABLE by verifying leakage testing (or the equivalent) to be within its limit prior to entering MODE 2:

a. After each refueling outage,

b. Whenever the plant has been in COLD SHUTDOWN for 7 days, or more, and if leakage testing has not been performed in the previous 9 months, and

c. Prior to returning the valve to service following maintenance, repair or replacement work on the valve.

d. The provisions of Specification 4.0.4 are not applicable for entry into MODES 3 or 4.

4.4.6.2.3 Whenever the integrity of a pressure isolation valve listed in Table 3.4-2 cannot be demonstrated, determine and record the integrity of the high pressure flowpath on a daily basis.

Integrity shall be determined by performing either a leakage test of the remaining pressure isolation valve, or a combined leakage test of the remaining pressure isolation valve in a series with the closed motor-operated containment isolation valve. In addition, record the position of the closed motor-operated containment isolation valve located in the high pressure piping on a daily basis.

)

Not applicable to primary to secondary leakage.

(2)

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

DAVIS-BESSE, UNIT 1 3/4 4-16 Order dated 4/20/81 Amendment No. 54, 135, 180, 196, 220,

3/4.7 PLANT SYSTEMS 3/4.7.9 STEAM GENERATOR LEVEL LIMITING CONDITION FOR OPERATION 3.7.9 Each Steam Generator shall have a minimum water level of 18 inches and the maximum specified below as applicable:

MODES 1 and 2:

a. The acceptable operating region of Figure 3.7-1.

MODE 3*"

b. 50 inches StartupRange with the SFRCS Low Pressure Trip bypassed and one or both Main Feedwater Pump(s) capable of supplying Feedwater to any Steam Generator.

c. 96 percent Operate Range with:

1. The SFRCS Low Pressure Trip active, or

2. The SFRCS Low Pressure Trip bypassed and both Main Feedwater Pumps incapable of supplying Feedwater to the Steam Generators.

MODE 4:

d. 625 inches Full Range Level APPLICABILITY:

MODES 1, 2, 3, and 4, as above.

ACTION:

With one or more steam generator's water level outside the limits, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.7.9 The steam generator shall be demonstrated OPERABLE by verifying steam generator level to be within limits at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Establish adequate SHUTDOWN MARGIN to ensure the reactor will stay subcritical during a MODE 3 Main Steam Line Break.

DAVIS-BESSE, UNIT I 3/47-38 Amendment No. 21, 171, 192,

Figure 3.7-1 Maximum Allowable Steam Generator Level in MODES I and 2 100 -

(43,96) s so -

Unacceptable Operating Region 70 60 WJ Acceptable Operating J

Region 40 40 Rei 0

10 60 Main Steam Superheat (OF)

DAVIS-BESSE, UNIT 1 3/4 7-39 Amendment No. 192,

6.0 ADMINISTRATIVE CONTROLS 6.1 RESPONSIBILITY 6.1.1 The plant manager shall be responsible for overall facility operation and shall delegate in writing the succession to this responsibility during his/her absence.

6.2 ORGANIZATION 6.2.1 OFFSITE AND ONSITE ORGANIZATIONS Onsite and offsite organizations shall be established for facility operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting the safety of the nuclear power plant.

a. Lines of authority, responsibility, and communication shall be established and defined for the highest management levels through intermediate levels up to and including all operating organization positions. These relationships shall be documented and updated, as appropriate, in the form of organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements, including the plant-specific titles of those personnel fulfilling the responsibilities of the positions delineated in these Technical Specifications, shall be documented in the Updated Safety Analysis Report.

b. A specified corporate officer shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety.

c. The plant manager shall be responsible for overall unit safe operation and shall have control over those onsite activities necessary for safe operation and maintenance of the plant.

d. The individuals who train the operating staff and those who carry out health physics and quality assurance functions may report to the appropriate onsite manager; however, they shall have sufficient organizational freedom to ensure their independence from operating pressures.

6.2.2 FACILITY STAFF

a. Each on duty shift shall be composed of at least the minimum shift crew composition shown in Table 6.2-1.

b. At least one licensed Operator shall be in the control panel area when fuel is in the reactor.

DAVIS-BESSE, UNIT 1 6-1 Amendment No. 9, 12, 27, 76, 98, 115, 135, 137, 272,

6.0 ADMINISTRATIVE CONTROLS 6.2.2 (Continued)

c. At least two licensed Operators, one of which has a Senior Reactor Operator license, shall be present in the control room while in MODES 1, 2, 3, or 4.

d. An individual qualified in radiation protection procedures shall be on site when fuel is in the reactor".

e. All CORE ALTERATIONS shall be directly supervised by either a licensed Senior Reactor Operator or Senior Reactor Operator Limited to Fuel Handling who has no other concurrent responsibilities during this operation.

f. Deleted

g. The operations manager shall either hold or have held a senior reactor operator's license on a pressurized water reactor. The assistant operations manager shall hold a senior reactor operator license for the Davis-Besse Nuclear Power Station.

6.2.3 FACILITY STAFF OVERTIME Administrative controls shall be developed and implemented to limit the working hours of personnel who perform safety-related functions (e.g., senior reactor operators, reactor operators, auxiliary operators, health physicists, and key maintenance personnel). The controls shall include guidelines on working hours that ensure that adequate shift coverage is maintained without routine heavy use of overtime for individuals.

Any deviation from the working hour guidelines shall be authorized in advance by the plant manager or his/her designees, in accordance with approved administrative procedures, and with documentation of the basis for granting the deviation. Routine deviation from the above guidelines shall not be authorized.

Controls shall be included in the procedures such that individual overtime shall be reviewed monthly by the plant manager or his/her designee(s) to ensure that excessive hours have not been assigned.

The individual qualified in radiation protection procedures may be less than the minimum requirements for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence, provided immediate action is taken to fill the required position.

DAVIS-BESSE, UNIT 1 6-2 Amendment No. 9, 18, 88, 98, 115, 135, 137, 142, 174, 212, 272,

6.0 ADMINISTRATIVE CONTROLS TABLE 6.2-1 MINIMUM SHIFT CREW COMPOSITION#

LICENSE APPLICABLE MODES CATEGORY 1, 2,3 & 4 5&6 SOL 2**

1*

OL 2

1 Non-Licensed 2

1 Shift Technical Advisor 1 **

None Required Shift crew composition may be less than the minimum requirements for a period of time not to exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in order to accommodate unexpected absence of on duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements of Table 6.2-1.

Does not include the licensed Senior Reactor Operator or Senior Reactor Operator Limited to Fuel Handling supervising CORE ALTERATIONS.

- One of the two required individuals filling the SOL positions may also assume the STA function provided the individual meets the qualifications for the combined SRO/STA position specified for Option 1 of the Commission's Policy Statement on Engineering Expertise on Shift. If this option is used for a shift, then the separate STA position may be eliminated for that shift.

6.3 FACILITY STAFF QUALIFICATIONS 6.3.1 Each member of the facility staff shall meet or exceed the minimum qualifications of ANSI N18.1-1971 for comparable positions, except for (1) the radiation protection manager who shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975, (2) the Shift Technical Advisor who shall have a bachelor's degree or equivalent in a scientific or engineering discipline with specific training in plant design, and response and analysis of the plant for transients and accidents, and (3) the operations manager whose requirement for a senior reactor operator license is as stated in Specification 6.2.2.g.

6.4 Deleted 6.5

-REVIEW AND AUDIT 6.5.1 Deleted 6.5.2 Deleted DAVIS-BESSE, UNIT 1 6-3 Amendment No. 9, 12, 27, 37, 74, 76, 86,89,93,98,99,106,109,135,137, 138,139,142,169,174,175,184,189, 231,235,236,272,

6.0 ADMINISTRATIVE CONTROLS 6.5.3 TECHNICAL REVIEW AND CONTROL ACTIVITIES 6.5.3.1 Activities which affect nuclear safety shall be conducted as follows:

a. Plant procedures required by Section 6.8.1 and changes thereto shall be prepared, reviewed and approved. Each such procedure or procedure change shall be reviewed by an individual/group other than the individual/group which prepared the procedure or procedure change, but who may be from the same organization as the individual/group which prepared the procedure or procedure change. Plant procedures, (including plant administrative procedures), Physical Security Plan Implementing Procedures and Davis' Besse Emergency Plan Implementing Procedures will be approved by procedurally authorized individuals.

b. Temporary approval of changes to plant procedures cited in Section 6.8.1 which clearly do not change the intent of the approved procedures, can be made by two members of the plant management staff, at least one of whom holds a Senior Reactor Operator's License.

For changes to plant procedures, which may involve a change in intent of the approved procedures, the person authorized in Section 6.5.3.1 a to approve the procedure shall approve the change

c. Proposed changes or modifications to plant structures, systems and components shall be reviewed as designated by procedurally authorized individuals. Each such modification shall be reviewed by an individual/group other than the individual/group which designed the modification, but who may be from the same organization as the individual/group which designed the modifications. Implementation of modifications to plant structures, systems and components shall be approved by proecdurally authorized individuals.

d. Proposed tests and experiments which affect plant nuclear safety and are not addressed in the Safety Analysis Report shall be reviewed by an individual/group other than the individual/group which prepared the proposed test or experiment and shall be approved by procedurally authorized individuals.

e. Individuals responsible for reviews performed in accordance with Section 6.5.3.1 a, b, c and d above shall meet or exceed the appropriate qualification requirements of Section 4.2, 4.3.1, 4.4 or 4.6 of ANSI 18.1, 1971, and be previously designated by procedurally authorized individuals. Each such review shall include a determination of whether an additional, cross disciplinary, review is necessary. If deemed necessary, such review shall be performed by the review personnel of the appropriate discipline.

f. Each review will include a determination of whether prior NRC approval is required pursuant to 10 CFR 50.59.

DAVIS-BESSE, UNIT 1 6-4 Amendment No. 109, 139, 248, 272,

6.0 ADMINISTRATIVE CONTROLS 6.6 Deleted 6.7 Deleted 6.8 PROCEDURES AND PROGRAMS 6.8.1 Written procedures shall be established, implemented and maintained covering the activities referenced below:

a. The applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33, February, 1978.

b. Refueling operations.

c. Surveillance and test activities of safety related equipment.

d. Physical Security Plan implementation.

e. Davis-Besse Emergency Plan implementation.

f. Fire Protection Program implementation.

g. The radiological environmental monitoring program.

h. Deleted.

i.

Offsite Dose Calculation Manual implementation.

6.8.2 Each procedure of 6.8.1 above, and changes thereto, shall be reviewed and approved prior to implementation as set forth in 6.5.3 above.

6.8.3 Deleted 6.8.4 The following programs shall be established, implemented and maintained:

a. Primary Coolant Sources Outside Containment A program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. The systems include makeup, letdown, seal injection, seal return, low pressure injection, containment spray, high pressure injection, waste gas, primary sampling and reactor coolant drain systems. The program shall include the following:

(i) Preventive maintenance and/or periodic visual inspection requirements, and DAVIS-BESSE, UNIT 1 6-5 Amendment No. 9, 27, 51, 86, 93, 98, 109, 139, 189, 235, 248, 260, 272,

6.0 ADMINISTRATIVE CONTROLS 6.8.4.a (Continued)

(ii) Integrated leak test requirements for each system at refueling cycle intervals or less.

b. In-Plant Radiation Monitoring A program which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions. This program shall include the following:

1) Training of personnel,

2) Procedures for monitoring, and

3) Provisions for maintenance of sampling and analysis equipment.

c. Deleted

d. Radioactive Effluent Controls Program A program shall be provided conforming with 10 CFR 50.36a for the control of radioactive effluents and for maintaining the doses to MEMBERS OF THE PUBLIC from radioactive effluents as low as reasonably achievable. The program (1) shall be contained in the ODCM, (2) shall be implemented by operating procedures, and (3) shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:

1) Limitations on the operability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the ODCM.

2) Limitations on the concentrations of radioactive material released in liquid effluents to UNRESTRICTED AREAS conforming to 10 CFR Part 20, Appendix B, Table II, Column 2,

3) Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the ODCM.

4) Limitations on the annual and quarterly doses or dose commitment to a MEMBER OF THE PUBLIC from radioactive materials in liquid effluents released from each unit to UNRESTRICTED AREAS conforming to Appendix I to 10 CFR Part 50, DAVIS-BESSE, UNIT I 6-6 Amendment No. 51, 84, 170, 231, 264,

6.0 ADMINISTRATIVE CONTROLS 6-.8.4.d (Continued)

5) Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days.

6) Limitations on the operability and use of the liquid and gaseous effluent treatment systems to ensure that the appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a 31-day period would exceed 2 percent of the guidelines for the annual dose or dose commitment conforming to Appendix I to 10 CFR Part 50,

7) Limitations on the dose rate resulting from radioactive material released in gaseous effluents to areas beyond the SITE BOUNDARY conforming to the doses associated with 10 CFR Part 20, Appendix B, Table II, Column 1,

8) Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

9) Limitations on the annual and quarterly doses to a MEMBER OF THE PUBLIC from Iodine-131, Iodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released from each unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

10) Limitations on the annual dose or dose commitment to any MEMBER OF THE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources conforming to 40 CFR Part 190.

e. Radiological Environmental Monitoring Program A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provide (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluent monitoring program and modeling of environmental exposure pathways. The program shall (1) be contained in the ODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:

1) Monitoring, sampling, analysis, and reporting of radiation and radionuclides in the environment in accordance with the methodology and parameters in the ODCM,

2) A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if required by the results of this census, and DAVIS-BESSE, UNIT 1 6-7 Amendment No. 170,

6.0 ADMINISTRATIVE CONTROLS 6.8.4.e (Continued)

3) Participation in an Interlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.

f. Ventilation Filter Testing Program (VFTP):

A program shall be established to implement the following required testing of safety related filter ventilation systems in accordance with Regulatory Guide 1.52, Revision 2*,

ANSI/ASME N510-1980, and ASTM D 3803-1989.

1) Demonstrate for each of the safety related systems that an in-place test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass < 1%

when tested in accordance with Regulatory Guide 1.52, Revision 2 and ANSI/ASME N510-1980 at the system flowrate specified below, +/- 10%.

Safety Related Ventilation System Flowrate Shield Building Emergency Ventilation System 8000 cfm Control Room Emergency Ventilation System 3300 cfin

2) Demonstrate for each of the safety related systems that an in-place test of the charcoal adsorber shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2 and ANSI/ASME N510-1980 at the system flowrate specified below, +/-10%.

Safety Related Ventilation System Flowrate Shield Building Emergency Ventilation System 8000 cfm Control Room Emergency Ventilation System 3300 cfim

The periodic testing for the Shield Building Emergency Ventilation System and the Control Room Emergency Ventilation System are performed once each REFUELING INTERVAL.

The need for testing following painting, a fire, or a chemical release in any ventilation zone communicating with the Shield Building Emergency Ventilation System or the Control Room Emergency Ventilation System is as specified by the VFTP. The method of testing is based on Regulatory Guide 1.52, Revision 2, except for charcoal laboratory testing which will be performed in accordance with ASTM D 3803-1989.

DAVIS-BESSE, UNIT 1 6-8 Amendment No. 170, 244, 265,

6.0 ADMINISTRATIVE CONTROLS 6.8.4.f (Continued)

3) Demonstrate for each of the safety related systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D 3803-1989 at a temperature of 30' C and the relative humidity (RH) specified below.

Safety Related Ventilation System Penetration RH Shield Building Emergency Ventilation System

< 2.5%

95%

Control Room Emergency Ventilation System

< 2.5%

70%

4) Demonstrate for each of the safety related systems that the pressure drop across the combined HEPA filters, the prefilters, and the charcoal adsorbers is less than the value specified below when tested in accordance with Regulatory Guide 1.52, Revision 2 and ANSI/ASME N510-1980 at the system flowrate specified below,

+/- 10%.

Safety Related Ventilation System Delta P Flowrate Shield Building Emergency Ventilation System 6 inches Water Gauge 8000 cfm Control Room Emergency Ventilation System 4.4 inches Water Gauge 3300 cfm The provisions of SR 4.0.2 and SR 4.0.3 are applicable to the VFTP test frequencies.

DAVIS-BESSE, UNIT I 6-9 Amendment No. 244, 265,

6.0 ADMINISTRATIVE CONTROLS 6.8.4 (Continued)

g. Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

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

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

a. Structural integrity performance criterion: All in-service SG 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 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.

b. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG.

Leakage is not to exceed I gpm per SG, except during a SG tube rupture.

c. The operational leakage performance criterion is specified in LCO 3.4.6.2, "Reactor Coolant System Operational Leakage."

DAVIS-BESSE, UNIT I 6-10 Amendment No.

6.0 ADMINISTRATIVE CONTROLS 6.8.4.g (Continued)

3) Provisions for SG tube repair criteria : Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged or repaired.

4) Provisions for SG tube inspections: Periodic SG tube inspections shall be performed.

The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. For tubes that have undergone repair rolling, the previously existing tube and tube roll, outboard of the new roll area in the tube sheet, can be excluded from future periodic SG tube inspections because it is no longer part of the pressure boundary once the repair roll is installed. For tubes that have undergone sleeving repairs, the previously existing parent tube, from the original tubesheet roll expansion through the second (outboard) sleeve roll, can be excluded from future periodic SG tube inspections because it is no longer part of the pressure boundary once the sleeve is installed. The installed sleeve, from the sleeve tubesheet roll expansion to the end of the second (outboard) free span sleeve roll, will be included in future periodic SG tube inspections because it is part of the pressure boundary. In addition to meeting the requirements of 4.a, 4.b, and 4.c 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.

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

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

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

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

DAVIS-BESSE, UNIT I 6-11 Amendment No.

6.0 ADMINISTRATIVE CONTROLS 6.8.4.g (Continued)

5) Provisions for monitoring operational primary to secondary leakage.

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

a. Sleeving in accordance with Topical Report BAW-2120P.

b. Repair rolling in accordance with Topical Report BAW-2303P, Revision 4. The new roll area must be free of degradation in order for the repair to be considered acceptable.

7) Special interest tube inspection: For each periodic SG tube inspection, 100% of the tubes that have been repaired by the repair roll process shall be inspected. This special inspection shall be limited to the repair roll joint and the roll transitions of the repair roll.

8) Special visual inspections: Visual inspections of the secured internal auxiliary feedwater header, header to shroud attachment welds, and the external header thermal sleeves shall be performed on each SG through the auxiliary feedwater injection penetrations. These inspections shall be performed during the third period of each ten-year Inservice Inspection Interval (ISI).

9) Special interest tube inspection: For each periodic SG tube inspection, a separate inspection shall be performed on peripheral tubes in the vicinity of the secured internal auxiliary feedwater header between the upper tube sheet and the 15th tube support plate. The tubes selected for inspection shall represent the entire circumference of the steam generator and shall total at least 150 peripheral tubes.

DAVIS-BESSE, UNIT I 6-12 Amendment No.

6.0 ADMINISTRATIVE CONTROLS 6.9 REPORTING REQUIREMENTS ROUTINE REPORTS 6.9.1 In addition to the applicable reporting requirements of Title 10, Code of Federal Regulations, the following reports shall be submitted to the appropriate Regional Office unless otherwise noted.

STARTUP REPORT 6.9.1.1 Deleted.

6.9.1.2 Deleted.

6.9.1.3 Deleted.

ANNUAL OPERATING REPORT 6.9.1.4 Annual reports covering the activities of the unit during the previous calendar year shall be submitted prior to March 31 of each year.

6.9.1.5 Reports required on an annual basis shall include:

a. Deleted

b. Deleted

c. The results of specific activity analysis in which the primary coolant exceeded the limits of Specification 3.4.8. The following information shall be included: (1) Reactor power history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded; (2)

Results of the last isotopic analysis for radioiodine performed prior to exceeding the limit, results of analysis while limit was exceeded and results of one analysis after the radioiodine activity was reduced to less than limit. Each result should include date and time of sampling and the radioiodine concentrations; (3) Clean-up system flow history starting 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months prior to the first sample in which the limit was exceeded; (4) Graph of the 1-131 concentration and one other radioiodine isotope concentration in microcuries per gram as a function of time for the duration of the specific activity above the steady-state level; lnd (5) The time duration when the specific activity of the primary coolant exceeded the radioiodine limit.

MONTHLY OPERATING REPORT 6.9.1.6 Deleted DAVIS-BESSE, UNIT 1 6-13 Amendment No. 8, 41, 52, 87, 93, 104, 135, 258, 267,

6.0 ADMINISTRATIVE CONTROLS CORE OPERATING LIMITS REPORT 6.9.1.7 Core operating limits shall be established and documented in the CORE OPERATING LIMITS REPORT before each reload cycle and any remaining part of a reload cycle for the following:

2.1.2 AXIAL POWER IMBALANCE Protective Limits for Reactor Core Specification 2.1.2 2.2.1 Trip Setpoint for Flux -- AFlux/Flow for Reactor Protection System Setpoints Specification 2.2.1 3.1.1.3c Negative Moderator Temperature Coefficient Limit 3.1.3.6 Regulating Rod Insertion Limits 3.1.3.7 Rod Program 3.1.3.8 Xenon Reactivity 3.1.3.9 Axial Power Shaping Rod Insertion Limits 3.2.1 AXIAL POWER IMBALANCE 3.2.2 Nuclear Heat Flux Hot Channel Factor, FQ N

3.2.3 Nuclear Enthalpy Rise Hot Channel Factor, FAH 3.2.4 QUADRANT POWER TILT The analytical methods used to determine the core operating limits addressed by the individual Technical Specifications shall be: those previously reviewed and approved by the NRC, as described in BAW-10179P-A, "Safety Criteria and Methodology for Acceptable Cycle Reload Analyses", or any other new NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable approved revision of BAW-10179P-A. The applicable approved revision number for BAW-10179P-A at the time the reload analyses are performed shall be identified in the CORE OPERATING LIMITS REPORT. The CORE OPERATING LIMITS REPORT shall also list any new NRC-approved analytical methods used to determine core operating limits that are not yet referenced in the applicable approved revision of BAW-10179P-A.

The core operating limits shall be determined so that all applicable limits (e.g., fuel thermal-mechanical limits, core thermal-hydraulic limits, ECCS limits, nuclear limits such as shutdown margin, and transient and accident analysis limits) of the safety analysis are met.

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

DAVIS-BESSE, UNIT I 6-14 Amendment No. 144, 154, 189,

6.0 ADMINISTRATIVE CONTROLS ANNUAL RADIOLOGICAL ENVIRONMENTAL OPERATING REPORT 6.9.1.10 The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted before May I of each year. The report shall include summaries, interpretations, and analysis of trends of the results of the Radiological Environmental Monitoring Program for the reporting period. The material provided shall be consistent with the objectives outlined in (1) the ODCM, and (2) Sections IV.B.2, IV.B.3, and IV.C of Appendix I to 10 CFR Part 50.

RADIOACTIVE EFFLUENT RELEASE REPORT 6.9.1.11 The Radioactive Effluent Release Report covering the operation of the unit shall be submitted in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be (1) consistent with the objectives outlined in the ODCM and the Process Control Program, and (2) in conformance with 10 CFR 50.36a and Section IV.B. 1 of Appendix Ito 10 CFR Part 50.

STEAM GENERATOR TUBE INSPECTION REPORT 6.9.1.12 A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with Specification 6.8.4.g, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

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

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

f. Total number and percentage of tubes plugged or repaired to date,

g. The results of condition monitoring, including the results of tube pulls and in-situ testing,

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

i.

Repair method utilized and the number of tubes repaired by each repair method.

DAVIS-BESSE, UNIT I 6-15 Amendment No. 86, 170, 184, 272,

6.0 ADMINISTRATIVE CONTROLS SPECIAL REPORTS 6.9.2 Special reports shall be submitted to the U.S. Nuclear Regulatory Commission in accordance with 10 CFR 50.4 within the time period specified for each report. These reports shall be submitted covering the activities identified below pursuant to the requirements of the applicable reference specifications:

a. ECCS Actuation, Specifications 3.5.2 and 3.5.3.

b. Deleted

c. Deleted

d. Deleted

e. Deleted

f. Deleted

g. Inoperable Remote Shutdown System control circuit(s) or transfer switch(es) required for a serious control room or cable spreading room fire, Specification 3.3.3.5.2.

6.10 RECORD RETENTION Records of facility activities shall be retained as described in the USAR Chapter 17 Quality Assurance Program.

6.11 Deleted 6.12 HIGH RADIATION AREA As provided in paragraph 20.1601(c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601(a) and (b) of 10 CFR Part 20:

6.12.1 High radiation areas with dose rates not exceeding 1.0 rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation:

a. Each entry way to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment.

DAVIS-BESSE, UNIT 1 6-16 Amendment No. 9, 65, 86, 93, 94, 106, 135, 170, 174, 187, 201,231,235,

6.0 ADMINISTRATIVE CONTROLS 6.12.1 (Continued)

b. Access to, and activities in, each such area shall be controlled by means of a Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.

c. Individuals qualified in radiation protection procedures (e.g., health physics personnel) and personnel continuously escorted by such individuals may be exempted from the requirement for a RWP or equivalent while performing their assigned duties provided that they are following plant radiation protection procedures for entry to, exit from, and work in such areas.

d. Each individual (whether alone or in a group) entering such an area shall possess:

1) A radiation monitoring device that continuously displays radiation dose rates in the area; or

2) A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or

3) A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area, or

4) A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and be under the surveillance, as specified in the RWP or equivalent, while in the area, by means of closed circuit television, by personnel qualified in radiation protection procedures responsible for controlling personnel radiation exposure in the area.

e. Except for individuals qualified in radiation protection procedures, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.

6.12.2 Locked high radiation areas with dose rates greater than 1.0 rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation, but less than 500 rads/hour at 1 meter from the radiation source or from any surface penetrated by the radiation:

a. Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked door, gate, or other barrier that prevents unauthorized entry, and, in addition:

DAVIS-BESSE, UNIT 1 6-17 Amendment No. 23 1,

6.0 ADMINISTRATIVE CONTROLS 6.12.2.a (Continued)

1) All keys to such doors, gates, or other barriers shall be maintained under the administrative control of the shift supervisor, radiation protection manager, or his or her designee.

2) Doors, gates, or other barriers shall remain locked except during periods of personnel or equipment entry or exit.

b. Access to, and activities in, each such area shall be controlled by means of an RWP or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures.

c. Individuals qualified in radiation protection procedures may be exempted from the requirement for a RWP or equivalent while performing radiation surveys in such areas.

provided that they are following plant radiation protection procedures for entry to, exit from, and work in such areas.

d. Each individual (whether alone or in a group) entering such an area shall possess:

1) A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint, or

2) A radiation monitoring device that continuously transmits dose rate and cumulative dose information to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or

3) A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter)

and, (i) Be under the surveillance, as specified in the RWP or equivalent, while in the area, by an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or (ii) Be under the surveillance as specified in the RWP or equivalent, while in the area, by means of closed circuit television, by personnel qualified in radiation protection procedures responsible for controlling personnel radiation exposure in the area and with the means to communicate with and control every individual in the area, or DAVIS-BESSE, UNIT 1 6-18 Amendment No. 23 1,

6.0 ADMINISTRATIVE CONTROLS 6.12.2.d (Continued)

4) In those cases where options (2) and (3), above, are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable" principle, a radiation monitoring device that continuously displays radiation dose rates in the area.

e. Except for an individual qualified in radiation protection procedures, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them.

f. Such individual areas that are within a larger area that is controlled as a high radiation area, where no enclosure exists for the purpose of locking and where no enclosure can reasonably be constructed around the individual area, need not be controlled by a locked door or gate, but shall be barricaded and conspicuous, and a clearly visible flashing light shall be activated at the area as a warning device.

6.13 ENVIRONMENTAL QUALIFICATION 6.13.1 By no later than June 30, 1982 all safety-related electrical equipment in the facility shall be qualified in accordance with the provisions of Division of Operating Reactors "Guidelines for Evaluating Environmental Qualification of Class IE Electrical Equipment in Operating Reactors" (DOR Guidelines); or, NUREG-0588 "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment", December 1979. Copies of these documents are attached to Order for Modification of License NPF-3 dated October 24, 1980.

6.13.2 By no later than December 1, 1980, complete and auditible records must be available and maintained at a central location which describe the environmental qualification method used for all safety-related electrical equipment in sufficient detail to document the degree of compliance with the DOR Guidelines or NUREG-0588. Thereafter, such records should be updated and maintained current as equipment is replaced, further tested, or otherwise further qualified.

6.14 Deleted DAVIS-BESSE, UNIT 1 6-19 Order dated 10/24/80 Amendment No. 86, 170, 231,235, 260, 272,

6.0 ADMINISTRATIVE CONTROLS 6.15 OFFSITE DOSE CALCULATION MANUAL (ODCM)

Changes to the ODCM:

a. Shall be documented and records of reviews performed shall be retained as required by the USAR Chapter 17 Quality Assurance Program. This documentation shall contain:

1) Sufficient information to support the change together with the appropriate analyses or evaluations justifying the change(s), and

2) A determination that the change will maintain the level of radioactive effluent control required by 10 CFR 20.1302, 40 CFR Part 190, 10 CFR 50.3 6a, and Appendix I to 10 CFR Part 50 and not adversely impact the accuracy or reliability of effluent, dose or setpoint calculations.

b. Shall become effective after the approval of the plant manager.

c. Shall be submitted to the Commission in the form of a complete, legible copy of the entire ODCM as part of or concurrent with the Radioactive Effluent Release Report for the period of the report in which any change to the ODCM was made. Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (e.g., month/year) the change was implemented.'

DAVIS-BESSE, UNIT 1 6-20 Amendment No. 86, 170, 184, 231, 260, 272,

6.0 ADMINISTRATIVE CONTROLS 6.16 CONTAINMENT LEAKAGE RATE TESTING PROGRAM

a. A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exceptions:

1) A reduced duration Type A test may be performed using the criteria and Total Time method specified in Bechtel Topical Report BN-TOP-1, Revision 1.

2) The fuel transfer tube blind flanges (containment penetrations 23 and 24) will not be eligible for extended test frequencies. Their Type B test frequency will remain at 30 months. However, As-found testing will not be required.

b. The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 38 psig.

c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.50% of 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 < 0.75 La for Type A tests, < 0.60 La for all penetrations and valves subject to Type B and Type C tests, and < 0.03 La for all penetrations that are secondary containment bypass leakage paths;

2) A single penetration leakage rate of < 0.15 I. for each containment purge penetration;

3) Air lock acceptance criteria are:

a) Overall air lock leakage rate is < 0.015 La when tested at> Pa, b) For each door, seal leakage rate is < 0.01 La when the volume between the door seals is pressurized to > 10 psig.

e. The provisions of Specification 4.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

f. The provisions of Specification 4.0.3 are applicable to the Containment Leakage Rate Testing Program.

DAVIS-BESSE, UNIT 1 6-21 Amendment No. 240,

6.0 ADMINISTRATIVE CONTROLS 6.17 TECHNICAL SPECIFICATIONS (TS) BASES CONTROL PROGRAM This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

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

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

2) A change to the USAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

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

d. Proposed changes that meet the criteria of 6.17b. 1 and 6.17b.2 above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

DAVIS-BESSE, UNIT 1 6-22 Amendment No. 249,

Docket Number 50-346 License Number NPF-3 Serial Number 3231 TECHNICAL SPECIFICATION BASES PAGES (10 pages follow)

Note: The Bases pages are provided for information only.

REACTOR COOLANT SYSTEM BASES 3/4.4.4 PRESSURIZER A steam bubble in the pressurizer ensures that the RCS is not a hydraulically solid system and is capable of accommodating pressure surges during operation. The steam bubble also protects the pressurizer code safety valves and pilot operated relief valve against water relief The low level limit is based on providing enough water volume to prevent the low level interlock from de-energizing the pressurizer heaters during steady state operations. The high level limit is based on providing enough steam volume to prevent water relief through the pressurizer relier valves during the most challenging anticipated pressurizer insurge transient, which is a loss of feedwater. Since prevention of water relief is a goal for abnormal transient operation, rather than a Safety Limit, the value for high pressurizer level is nominal and is not adjusted for instrument error.

The ACTION statement provides 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to restore pressurizer level prior to requiring shutdown. The 1-hour completion time is considered to be a reasonable time for restoring pressurizer level to within limits.

The pilot operated relief valve and steam bubble function to relieve RCS pressure during all design transients. Operation of the pilot operated relief valve minimizes the undesirable opening of the spring-loaded pressurizer code safety valves.

INSERT B3/4.45 3/4.4.5 STEAM GENERATORS TUBE INTEGRITY (attached),

The Surveillance Requirements for inspection of the steam generator tubes ensure that t st tural integrity of this portion of the RCS will be maintained. The program for inserv inspection of steam generator tubes is based on a modification of Re atory Guide 1.8, evision 1. Inservice inspection of steam generator tubing is e ntial in order to maint

surveillance of the conditions of the tubes in the eve at there is evidence of mech

al damage or progressive degradation due to sign, manufacturing errors, or inservice con ions that lead to corrosion. Inservice i spection of steam generator tubing also provi a means of characterizing t nature and cause of any tube degradation so that corrective sures can be taken.

process equivalent to the inspection method described in Top' 1 Report B

-2120P will be used for inservice inspection of steam generator tube sleev T

iinspection will provide ensurance of RCS integrity.

The plant is expected to be opera in a manner suc that the secondary coolant will be maintained within those che tiry limits found to resulthd negligible corrosion of the steam generator tubes. If e secondary coolant chemistry is t maintained within these chemistry limits, c Lzed corrosion may likely result in stress c osion cracking. The extent of cracki uring plant operation would be limited by the limi tion of steam generator tu eakage between the primary coolant system and the seconr coolant system imary-to-secondary leakage =150 GPD through any one steam gen ator).

Cra shaving a primary-to-secondary leakage less than this limit during operatio il ye an adequate margin of safety to withstand the loads imposed during normal DAVIS-BESSE, UNIT 1 B 3/4 4-2 Amendment No. 13 5, 171, 220, LAR No. 0 1-00 12, 05-0009

REACTOR COOLANT SYSTEM BASES (Continued) eration and by postulated accidents. Operating plants have demonstrated that primary-to-sec dary leakage of 150 GPD can be detected by monitoring the secondary coolant. Leakage in exces f this limit will require plant shutdown and an unscheduled inspection, during which th leaking t es will be located and plugged or repaired by repair rolling or sleeving in the affee ed areas.

Wastage-type de cts are unlikely with proper chemistry treatment of the secondary olant.

However, even if a fect should develop in service, it will be found during sche ed inservice steam generator tube e inations. As described in Topical Report BAW-212

, degradation as small as 20% through wa can be detected in all areas of a tube sleeve excetfor the roll expanded areas and the sleeve end, wh e the limit of detectability is 40% through all. Tubes with imperfections exceeding the re ir limit of 40% of the nominal wall t kness will be plugged or repaired by repair rolling or slee the affected areas. Davis-Bess will evaluate, and as appropriate implement, better testin ethods which are develop and validated for commercial use so as to enable detection of degrada on as small as 20% tlough wall without exception. Until such time as 20% penetration can be detec d in the roll ex nded areas and the sleeve end, inspection results will be compared to those tained dui g the baseline sleeved tube inspection.

An additional repair method for degraded steam g erator tubes consists of rerolling the tubes in the tubesheet to create a new roll area and press e b ndary for the tube. The repair roll process will ensure that the area of degradation will serve as pressure boundary, thus permitting the tube to remain in service. The degraded a a of the tube c be excluded from future periodic inspection requirements because it is no onger part of the pre ure boundary once the repair roll is installed in the tubesheet.

All tubes which have been repa ed using the repair roll process will hye the new roll area inspected during the inservic inspection. Defective or degraded tube in ications found in the new roll area as a result of thei spection of the repair roll and any indications fnd in the originally rolled region of the rer ed tube need not be included in determining theInsp tion Results Category for the ge al steam generator inspection.

The repair roll rocess will be performed as described in the Topical Report BAW-23 P, Revision

4. The new 11 area must be free of degradation in order for the repair to be considered ceptable.

After the ew roll area is initially deemed acceptable, future degradation in the new roll are ill be anal to determine if the tube is defective and needs to be removed from service. Leakage Io rep

rolls will be accounted for to ensure post-accident primary-to-secondary leakage will not e ceed that assumed in the safety analyses.

DAVIS-BESSE, UNIT 1 B 3/4 4-3 Amendment No. 171, 184, 192, 220, 252

REACTOR COOLANT SYSTEM BASES (Continued) never the results of any steam generator tubing inservice inspection fall into Category C-3, these results s be reported to the Commission prior to resumption of plant operation. Such cases wil considered by ommission on a case-by-case basis and may result in a requirement f

ysis, laboratory examination s

, additional eddy-current inspection, and revision of echnical Specifications, if necessary_.

The steam generator water level limits are co ent with th tal assumptions in the USAR. While in MODE 3, examples of Main Feedwater Pumps that

.capable of supplying feedwater to the Steam Generators are tripped pumps or a manual va osed in t charge flowpath. The reactivity requirements to ensure adequate SHIJ MARGIN are provi

.n plant operating procedures.

The steam g enerator um water level requirement is met by verifying the in i steam generator level is greater or equal to the value that corresponds to the required actual minimum above the DAVIS-BESSE, UNIT 1 B 3/4,4-3a Amendment No. 171, 184, 192, 220, LAR No. 00-0001

IINSRT B3/4.4.5 Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4.1, "Coolant Loops and Coolant Circulation - Startup and Power Operation," and LCO 3.4.1.2, "Coolant Loops and Coolant Circulation - Shutdown and Hot Standby."

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

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

Specification 6.8.4.g, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 6.8.4.g, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational leakage. The SG performance criteria are described in Specification 6.8.4.g. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by NEI 97-06, "Steam Generator Program Guidelines."

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

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

[NSRTWA74A.5 (conitinued)

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

A SG tube has integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 6.8.4.g, "Steam Generator (SG)

Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

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

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

Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification. This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB and Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

The accident induced leakage performance criterion ensures that the primary to secondary leakage caused by a design basis accident, other than a steam generator tube rupture (SGTR), is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG. The accident

INSETB 3/4.4.5 (cotiued)j induced leakage rate includes any primary to secondary leakage existing prior to the accident in addition to primary to secondary leakage induced during the accident.

The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on operational leakage is contained in LCO 3.4.6.2, "Reactor Coolant System - Operational Leakage," and limits primary to secondary leakage through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under

.the stress conditions of a LOCA or a main steam line break. If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.

ACTION statement 3.4.5.a applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged or repaired in accordance with the Steam Generator Program as required by SR 4.4.5.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged or repaired has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspectiQn. If it is determined that tube integrity is not being maintained, ACTION statement 3.4.5.b applies.

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, ACTION statement 3.4.5.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 or repaired prior to entering HOT SHUTDOWN following the next refueling outage or SG inspection. This completion time is acceptable since operation until the next inspection is supported by the operational assessment.

If the requirements of ACTION statement 3.4.5.a are not met or if SG tube integrity is not being maintained, the reactor must be brought to HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . 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.

During shutdown periods the SGs are inspected as required by SR 4.4.5.1 and the Steam Generator Program. NEI 97-06, "Steam Generator Program Guidelines," and its referenced EPRI Guidelines, establish the content of the Steam Generator Program. Use

JSERT.B3/4.4.5 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 4.4.5.1. The frequency is determined by the operational assessment and other limits in the SG examination guidelines (EPRI "Pressurized Water Reactor Steam Generator Examination Guidelines"). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 6.8.4.g contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

Surveillance Requirement 4.4.5.2 requires verification that each inspected SG tube that satisfies the tube repair criteria is plugged or repaired in accordance with the SG Program. The tube repair criteria delineated in Specification 6.8.4.g 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). NEI 97-06, "Steam Generator Program Guidelines,"

provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

Steam generator tube repairs are only performed using approved repair methods as described in the Steam Generator Program.

The SR 4.4.5.2 frequency of "prior to entering HOT SHUTDOWN following a SG tube inspection" ensures that the surveillance has been completed and all tubes meeting the repair criteria are plugged or repaired prior to subjecting the SG tubes to significant primary to secondary pressure differential.

REACTOR COOLANT SYSTEM BASES 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.6.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to detect and monitor leakage from the Reactor Coolant Pressure Boundary. These detection systems are consistent with the recommendation of Regulatory Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.

3/4.4.6.2 OPERATIONAL LEAKAGE PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative.of an impending gross failure of the pressure boundary. Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.

Industry experience has shown that, while a limited amount of leakage is expected from the RCS, the UNIDENTIFIED LEAKAGE portion of this can be reduced to a threshold value of less that 1 GPM. This threshold value is sufficiently low to ensure early detection of additional leakage.

The steam generator tube leakage limit of 150 GPD through any one steam generator ensures that the dosage contribution from tube leakage will be limited to a small fraction of 10 CFR Part 100 limits in the event of either a steam generator tube rupture or steam line break.

A 1 GPM total primary to secondary leakage limit is used in the analysis of these accidents.

The limit of 150 GPD ner steam generator (SG) is based on the operational leakage performance criterion in NEI 97-06. "Steam Generator Program Guidelines." The Steam Generator Program operational leakage performance criterion in NEI 97-06 states. "The RCS onerational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizin2 the frequencv of steam generator tube ruptures.

Surveillance Requirement 4.4.6.2.1.d is not applicable to primary to secondary leakage because leakage of 150 gallons per day cannot be measured accurately by an RCS inventory water balance, Surveillance Requirement 4.4.6.2.1.e verifies that primary to secondary leakage is less than or eaual 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 Prog-am is met. If this SR is not met, compliance with LCO 3.4.5. "Steam Generator (SG) Tube

.Interitv." should be evaluated. The 150 gallons per day limit is measured at room temperature as described in the EPRI "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

The operational leakage rate limit atplies to leakage through any one SG. If it is not practical DAVIS-BESSE, UNIT I B 3/4 4-4 Amendment 180, 220, LAR No. 05-0009

REACTOR COOLANT SYSTEM BASES to assign the leakage to an individual SG. all the primary to secondary leakage should be conservatively assumed to be from one SG. The Surveillance Requirement is modified by a note which states that the Surveillance Reauirement is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary leakage determination, steady state is defined as stable RCS nressure. temperature. power level, pressurizer and makeu= tank levels, makeut and letdown, and RCP seal injection and return flows. The Surveillance Reguirement freauency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend prmary to secondary leakage and recogaizes the importance of early leakage detection in the prevention of accidents. The primary to secondary leakage is determined using continuous trocess radiation monitors or radiochemical grab sampling in accordance with the EPRI "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

The 10 GPM IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the leakage detection systems.

The CONTROLLED LEAKAGE limit of 10 GPM restricts operation with a total RCS leakage from all RC pump seals in excess of 10 GPM.

The surveillance requirements for RCS Pressure Isolation Valves provide added assurance of valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS Pressure Isolation Valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.

3/4.4.7 CHEMISTRY Deleted 3/4.4.8 SPECIFIC ACTIVITY The limitations on the specific activity of the primary coolant ensure that the resulting 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months doses at the site boundary will not exceed an appropriately small fraction of the Part 100 limit following a steam generator tube rupture accident in conjunction with an assumed steady state primary-to-secondary steam generator leakage rate of 1.0 GPM. The values for the limits on specific activity represent interim limits based upon a parametric evaluation by the NRC of typical site locations. These values are conservative in the specific site parameters of the site, such as site boundary location and meteorological conditions, were not considered in this evaluation. The NRC is finalizing site specific criteria which will be used as the basis for the reevaluation of the specific activity limits of this site. This reevaluation may result in higher limits.

DAVIS-BESSE, UNIT 1 B 3/4 4-5 Amendment 180, 234, LAR No. 05-0009

PLANT SYSTEMS BASES 3/4.7.8 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requiring leak testing, including alpha emitters, is based on 10 CFR 70.3 9(c) limits for plutonium. This limitation will ensure that leakage from by-product, source, and special nuclear material sources will not exceed allowable intake values.

3/4.7.9 FIE SUPPRESSION SYSTEMS DELETEDSTEAM GENERATOR LEVEL The steam generator water level limits are consistent with the initial assumptions in the USAR. While in MODE 3, examples of Main Feedwater Pumps that are incapable of supplying feedwater to the Steam Generators are tripped pumps or a manual valve closed in the discharge flowpath. The reactivity requirements to ensure adequate SHUTDOWN MARGIN are provided in plant operating procedures.

The steam generator minimum water level requirement is met by verifying the indicated steam generator level is greater than or equal to the value that corresponds to the required actual minimum level above the tubesheet.

3/4.7.10 FIRE BARRIERS -- DELETED DAVIS-BESSE, UNIT 1 B 3/4 7-6 Amendment No. 9, 106, 135, 174, LAR No. 05-0009

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Enclosure I Page 1 of 12 Correlation of TSTF-449 Changes versus the Proposed DBNPS License Amendment Changes TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments Index pages Revises Index pages These are administrative changes to update titles consistent with other and page numbers as listed in the Index pages.

proposed changes.

Similar administrative changes to the NUREG-1430 Table of Contents pages are typically not addressed in TSTF packages.

1.1 - Definitions An editorial change Definition 1.14.c, Revises definitions The TSTF uses the terminology "primary to was made to the Definition 1.16 to meet the intent of secondary LEAKAGE", whereas the DBNPS definition of the TSTF.

change uses the terminology "primary to LEAKAGE, changing secondary leakage". This difference is due to the terminology from "SG fact that "LEAKAGE" is a defined term in LEAKAGE" to NUREG-1430, whereas in the current DBNPS "primary to secondary TS, "LEAKAGE" is not a stand-alone defined LEAKAGE" term. Section 1.0 of the current DBNPS TS includes four definitions related to leakage: 1.14, "IDENTIFIED LEAKAGE"; 1.15, "UNIDENTIFIED LEAKAGE"; 1.16, "PRESSURE BOUNDARY LEAKAGE"; and 1.17, "CONTROLLED LEAKAGE". Adoption of the NUREG-1430 terminology would result in additional changes to the DBNPS TS that are I beyond the scope of the TSTF.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 2 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments N/A No changes.

LCO 3.1.1.1 Revise the double-This change is associated with the change to TS asterisked footnote 3/4.4.5 described below. There is no to refer to LCO 3.7.9 corresponding change in the TSTF since in lieu of LCO 3.4.5 NUREG-1430 LCO 3.1.1 does not include a for additional similar cross-reference.

shutdown margin requirements.

LCO 3.4.13 -

Deleted limit of 1 gpm LCO 3.4.6.2 No change. Current Current LCO is already consistent with the RCS primary to secondary LCO does not revised LCO proposed by the TSTF.

Operational LEAKAGE through all include this limit.

Leakage SGs LCO 3.4.13 -

Revised limit of [720]

LCO 3.4.6.2.c No Change. Current Current LCO is already consistent with the RCS gallons per day primary LCO already revised LCO proposed by the TSTF.

Operational to secondary contains a 150 Leakage LEAKAGE through gallons per day limit any one SG to 150 as proposed in the gallons per day TSTF.

ACTION Revised ACTION to LCO 3.4.6.2, Revises terminology These administrative changes are consistent with 3.4.13.A use the terminology Action 3.4.6.2.a to "Reactor Coolant the title of the LCO.

"RCS operational System operational LEAKAGE" rather leakage", consistent than "RCS with the intent of the

_LEAKAGE" I

TSTF.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 3 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (B1WOG STS)

Description Specification Description Comments ACTIONS Revised ACTIONS to Action 3.4.6.2.a, Revises action 3.4.13.A and B eliminate the four hour Action 3.4.6.2.b statement, consistent time period to restore with the intent of the primary to secondary TSTF.

LEAKAGE within limits, in the event it is not within limits SR 3.4.13.1 Inserted Note 2 to SR 4.4.6.2.1.d Inserts new Note 1 New Note 2 indicates that SR 4.4.6.2.1.d is not indicate that this SR is with wording required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after not applicable to proposed by TSTF establishment of steady state operation.

primary to secondary Note 2. Also inserts LEAKAGE new Note 2 consistent with NUREG-1430.

SR 3.4.13.1 Revised SR SR 4.4.6.2.1 Revises terminology This administrative change is consistent with the terminology from to "Reactor Coolant title of the LCO.

"RCS operational System operational Leakage" to "RCS leakages", consistent operational with the intent of the LEAKAGE" TSTF.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 4 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments SR 3.4.13.2 Replaced the SR with a SR 4.4.6.2.1.e Revises SR to match The current SR 4.4.6.2.1.e explicitly states that an requirement to verify the intent of the evaluation of secondary water radiochemistry is primary to secondary TSTF.

performed to satisfy this surveillance. Consistent LEAKAGE is less or with the TSTF, the proposed SR 4.4.6.2.1.e does equal to 150 gallons not mention that secondary water radiochemistry per day through any is used. However, secondary water one SG, with a radiochemistry evaluations will continue to be frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months performed to satisfy this surveillance.

SR 3.4.13.2 Inserted a NOTE that SR 4.4.6.2..e Inserts new Note 2 New Note 2 also applies to SR 4.4.6.2..d.

the SR is not required consistent with the to be performed until TSTF.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady I state operation

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 5 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments 3.4.17 - Steam Inserted a new 3/4.4.5 Replaces current The current Specification 3/4.4.5 includes SG Generator (SG)

Specification specification with a level requirements and SG tube surveillance Tube Integrity new one containing requirements. The SG level requirements are the same relocated to Specification 3/4.7.9 (see description requirements as below). In NUREG-1430, plant-specific SG tube proposed by the surveillance requirements were located, in the TSTF.

Administrative Controls Section, rather than in an individual LCO. The TSTF removes the plant-specific SG tube surveillance requirements and replaces them with a Steam Generator Program.

Hence, the proposed removal of SG tube surveillance requirements from the DBNPS TS is-consistent with the TSTF.

N/A No changes.

3/4.7.9 Creates a new There are no technical changes to the specification requirements. Location of steam generator level containing steam requirements in the "Plant Systems" section of TS generator level is consistent with NUREG-1430 LCO 3.7.18.

requirements that There is no corresponding change in the TSTF were previously package since the NUREG already had a separate included in LCO containing steam generator level I TS 3/4.4.5.

requirements.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 6 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments 5.5.9 - Steam Replaced the 6.8.4.g Inserts a new New administrative control section is consistent Generator (SG) programmatic administrative with the TSTF, with the following plant-specific Program requirements in their control requiring a exceptions: 1) mention is made in new TS entirety steam generator 6.8.4.g.4 of an exclusion applicable to tubes that program-have undergone repair rolling, consistent with current TS 4.4.5.4.a.9, and an exclusion applicable to tubes that have undergone sleeving repairs; 2) special interest tube inspection requirements are included in new TS 6.8.4.g.7, consistent with current TS 4.4.5.9; 3) special visual inspection requirements are included in new TS 6.8.4.g.8, consistent with current TS 4.4.5.8; and 4) special interest tube inspection requirements are included in new TS 6,8.4.g.9, consistent with current TS 4.4.5.7.

N/A No changes.

6.9.1.5.b Deletes a cross-Reporting requirements will now be contained in reference to an new TS 6.9.1.12. There is no corresponding annual report for change in the TSTF package since reporting steam generator tube requirements for SG tube inspections are already inservice centrally located in NUREG-1430 Section 5.6.9.

inspections.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 7 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change

.. (BWOG STS)-

Description Specification Description Comments 5.6.9 - Steam Replaced the reporting 6.9.1.12 Inserts a new Generator Tube requirements in their administrative Inspection entirety control for reporting, Report consistent with the TSTF.

BASES 3.4.5, Revised LCO sections N/A No changes.

SG tube surveillance requirements are currently 3.4.6, and 3.4.7 of BASES to delete included in Specification 3/4.4.5. rather than in a references to Steam "Steam Generator Tube Surveillance Program" Generator Tube Administrative Controls Section (Section 5.5.9 of Surveillance Program NUREG-1430 as it existed prior to the TSTF).

Therefore there are no existing references to this program in the DBNPS TS Bases that require revision, and this portion of the TSTF is not applicable.

BASES 3.4.13 Revised N/A No changes.

This portion of the TSTF, an editorial correction, BACKGROUND is not applicable to the DBNPS TS Bases.

section of BASES to make an editorial correction, changing "are" to "is"

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 8 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments BASES General Bases General The DBNPS has not yet converted to the improved Standard TS (NUREG-1430).

Therefore the content of the current DBNPS TS Bases is not as extensive as that of the NUREG-1430 Bases. FENOC intends to incorporate the key changes in the Bases portion of the TSTF package. However, the NUREG-1430 format for the Bases section will not be incorporated at this time. Markups showing draft changes to the TS Bases are provided in Enclosure 1 Attachment 3 of this license amendment applications. These markups are provided for information only. The changes to the affected TS Bases will be incorporated in accordance with the TS Bases Control Program.

BASES 3.4.13 Revised APPLICABLE Bases 3/4.4.6.2 No change.

The 150 gallons per day limit is currently a SAFETY ANALYSES requirement of the DBNPS TSs, and the section of BASES to associated Bases already includes a discussion of describe the its significance. No additional Bases changes are significance of the new warranted at this time.

150 gallon per day LCO limit

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 9 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments BASES 3.4.13 Replaced the Bases 3/4.4.6.2 Inserts a new The DBNPS TS do not currently include the discussion of the LCO paragraph discussing 1 gpm leakage limit. Therefore, a discussion of section of BASES the 150 gpd limit, the bases for this requirement is not provided in regarding the 1 gpm consistent with the the DBNPS Bases, and this portion of the TSTF primary to secondary TSTF.

package is not applicable. The portion of the LEAKAGE limit (this TSTF package discussing the 150 gpd limit is limit has been removed planned to be adopted with only minor from the LCO) with a administrative changes.

discussion of the new 150 gallon per day limit BASES 3.4.13 Revised ACTIONS Bases 3/4.4.6.2 No changes.

The DBNPS TS Bases do not provide a detailed section of BASES to individual discussion of the Action statements.

reflect the elimination The changes included in this portion, of the TSTF of the four hour time package are considered minor and are not planned period to restore to be adopted at this time.

primary to secondary LEAKAGE within limits, in the event it is not within limits

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 10 of 12 I

Comments Revised the SURVEILLANCE REQUIREMENTS SECTION of the BASES for SR 3.4.13.1 to reflect the associated changes to the SR, which excludes verification of primary to secondary LEAKAGE from the RCS water inventory balance Inserts a new paragraph discussing the reason why the RCS water inventory balance is not applicable to primary to secondary leakage.

The portion of the TSTF package discussing the RCS water inventory balance exclusion is planned to be adopted with only minor administrative changes.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 11 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments BASES 3.4.13 Revised the Bases 3/4.4.6.2 Inserts a new The portion of the TSTF package discussing the SURVEILLANCE paragraph discussing SR which verifies that the 150 gpd limit is REQUIREMENTS the SR which planned to be adopted with only minor section of the BASES verifies that the 150 administrative changes.

forSR 3.4.13.2 to gpd limit is met.

reflect the associated changes to the SR, which verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG, with a frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months BASES 3.4.13 Revised the Bases 3/4.4.6.2 Changes made to The TSTF package provides for a separate section REFERENCES section incorporate the listing references. The DBNPS TS Bases do not of the BASES to intent of the TSTF.

provide a separate section for references. In lieu include two additional of adding a separate references section, the references: 1) NEI 97-applicable information for the two listed 06, "Steam Generator documents are incorporated into the applicable Program Guidelines";

portion of the Bases at the point of reference.

and 2) EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines"

Docket Number 50-346 License Number NPF-3 Serial Number 3231 Page 12 of 12 TSTF Corresponding Specification TSTF Change DBNPS DBNPS Change (BWOG STS)

Description Specification Description Comments BASES 3.4.17 Inserted BASES Bases 3/4.4.5 Changes made to All key portions of the TSTF package are adopted corresponding to the incorporate the with minor administrative changes, reformatted to new Specification intent of the TSTF.

meet the format of the current DBNPS TS Bases.

Some information, for example the APPLICABLE SAFETY ANALYSES section and the APPLICABILITY section are beyond the level of detail of the current DBNPS TS Bases, and are therefore not planned to be incorporated at this time. In addition, the DBNPS TS Bases do not provide a separate section for references. In lieu of adding a separate references section, the applicable information for the two listed documents are incorporated into the applicable portion of the Bases at the point of reference.

N/A No changes.

Bases 3/4.7.9 Creates a new Bases This change is associated with the relocation of section containing steam generator level requirements from TS steam generator 3/4.4.5 to TS 3/4.7.9. There are no technical level requirement changes to the information that is being relocated.

information that was There is no corresponding change in the TSTF previously included package since the NUREG already had a separate in Bases 3/4.4.5.

LCO (and associated Bases) containing steam I generator level requirements.

Docket Number 50-346 License Number NPF-3 Serial Number 3231 COMMITMENT LIST The following list identifies those actions committed to by the Davis-Besse Nuclear Power Station, Unit Number 1, (DBNPS) in this document. Any other actions discussed in the submittal represent intended or planned actions by the DBNPS. They are described only for information and are not regulatory commitments. Please notify Gregory A. Dunn, Manager -

FENOC Fleet Licensing (330)315-7243 of any questions regarding this document or associated regulatory commitments.

COMMITMENTS DUE DATE The changes to the affected TS Bases pages will be Upon implementation of the incorporated in accordance with the TS Bases Control associated license amendment Program.

for the proposed license amendment application.

ML061560134

Text

Subject:

Subject:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

Navigation menu

Search