Text

Submittal of Technical Specification Bases Changes Revisions 24 & 25
	ML021640502
Person / Time
Site:	Brunswick
Issue date:	06/05/2002
From:	O'Neil E; Carolina Power & Light Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BSEP 02-0114, TS 5.5.10.d
	Download: ML021640502 (77)
	v • d • e

I CP&L A Progress Energy Company JUN 05MR SERIAL: BSEP 02-0114 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO. 1 DOCKET NO. 50-325/LICENSE NO. DPR-71 SUBMITTAL OF TECHNICAL SPECIFICATION BASES CHANGES REVISIONS 24 AND 25 Ladies and Gentlemen:

In accordance with Technical Specification (TS) 5.5.10.d for the Brunswick Steam Electric Plant (BSEP), Unit No. 1, Carolina Power & Light Company is submitting Revisions 24 and 25 to the BSEP Unit 1 TS Bases. Revision 24 and 25 were implemented on June 1, 2002, in support of Amendments 221 and 222 to the Operating License for BSEP Unit No. 1. The NRC issued Amendment 221 (i.e., Alternative Source Term) on May 30, 2002, and Amendment 222 (i.e., Extended Power Uprate) on May 31, 2002.

Please refer any questions regarding this submittal to Mr. Leonard R. Beller, Supervisor Licensing/Regulatory Programs, at (910) 457-2073.

Sincerely, Edward T. O'Neil Manager - Regulatory Affairs Brunswick Steam Electric Plant MAT/mat

Enclosures:

1. Summary of Revisions to Technical Specification Bases

2. Technical Specification Bases Pages Replacement Instructions

3. Replacement Bases Pages - Unit 1 Brunswick Nuclear Plant CrCO P.0 Box 10429 Southport, NC 28461

Document Control Desk BSEP 02-0114 / Page 2 cc (with enclosures except as noted):

U. S. Nuclear Regulatory Commission, Region II ATTN: Mr. Luis A. Reyes, Regional Administrator Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, GA 30303-8931 U. S. Nuclear Regulatory Commission (w/o enclosures)

ATTN: Mr. Theodore A. Easlick, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission ATTN: Ms. Brenda L. Mozafari (Mail Stop OWFN 8G9) 11555 Rockville Pike Rockville, MD 20852-2738 Ms. Jo A. Sanford (w/o enclosures)

Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510 Mr. Mel Fry Director - Division of Radiation Protection North Carolina Department of Environment and Natural Resources 3825 Barrett Drive Raleigh, NC 27609-7221

BSEP 02-0114 Page 1 of 1 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO. 1 DOCKET NO. 50-325/LICENSE NO. DPR-71 SUBMITTAL OF TECHNICAL SPECIFICATION BASES CHANGES REVISIONS 24 AND 25 Summary of Revisions to Technical Specification Bases Revision Affected Units Date Implemented Title/Description 24 1

06/01/02

Title:

Alternative Source Term

==

Description:==

This Bases revision reflects Amendment 221, which revised the Technical Specifications to replace the current accident source term used in design basis radiological analyses with an alternative source term pursuant to 10 CFR 50.67, "Accident Source Term."

25 1

06/01/02

Title:

Extended Power Uprate

==

Description:==

This Bases revision reflects Amendment 222, which revised the maximum power level from 2558 megawatts thermal (MWt) to 2923 MWt.

BSEP 02-0114 Page 1 of 2 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO. 1 DOCKET NO. 50-325/LICENSE NO. DPR-71 SUBMITTAL OF TECHNICAL SPECIFICATION BASES CHANGES REVISIONS 24 AND 25 Technical Specification Bases Panes Replacement Instructions Unit 1 - Bases Book 1 Remove

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ENCLOSURE 3 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO. 1 DOCKET NO. 50-325/LICENSE NO. DPR-71 SUBMITTAL OF TECHNICAL SPECIFICATION BASES CHANGES REVISIONS 24 AND 25 Reulacement Bases Pages - Unit 1

Unit 1 Bases Book 1 Replacement Pages

BASES TO THE FACILITY OPERATING LICENSE DPR-71 TECHNICAL SPECIFICATIONS FOR BRUNSWICK STEAM ELECTRIC PLANT UNIT 1 CAROLINA POWER & LIGHT COMPANY REVISION 25

LIST OF EFFECTIVE Page No.

Revision No.

Title Page 25 List of Effective Pages - Book 1 LOEP-1 LOEP-2 LOEP-3 LOEP-4 i ii 2.0-1 2.0-2 2.0-3 2.0-4 2.0-5 2.0-6 2.0-7 2.0-8 3.0-1 3.0-2 3.0-3 3.0-4 3.0-5 3.0-6 3.0-7 3.0-8 3.0-9 3.0-10 3.0-11 3.0-12 3.0-13 3.0-14 3.0-15 3.1-1 3.1-2 3.1-3 3.1-4 3.1-5 3.1-6 25 25 24 22 21 21 0

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Revision 24 1 LOEP-3

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES 3.5 psi.

Thus, the bundle flow with a 4.5 psi driving head will be > 28 x 103 lb/hr.

Full scale ATLAS test data taken at pressures from 14.7 psia (0 psig) to 800 psia (785 psig) indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt.

With the design peaking factors, this corresponds to a THERMAL POWER > 46% RTP.

Thus, a THERMAL POWER limit of 23% RTP for reactor pressure < 785 psig is conservative.

2.1.1.2 MCPR The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit is not violated.

Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur.

Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit.

However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power.

Therefore, the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition, considering the power distribution within the core and all uncertainties.

The MCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power.

The probability of the occurrence of boiling transition is determined using the approved General Electric Critical Power correlations.

Details of the fuel cladding integrity SL calculation are given in Reference 1.

Reference I also includes, by reference, a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the MCPR SL statistical analysis.

(continued)

Revision No.

25 1 Brunswick Unit 1 B 2.0-3

Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued) 2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active irradiated fuel to provide core cooling capability.

In conjunction with LCOs, the limiting safety system settings, defined in LCO 3.3.1.1 as the Allowable Values, establish the threshold for protective system action to prevent exceeding acceptable limits, including this reactor vessel water level SL, during Design Basis Accidents.

With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat.

If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced.

This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height.

The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be monitored and to also provide adequate margin for effective action.

SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to prevent the release of radioactive materials to the environs.

SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria.

SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent-elevated clad temperatures and resultant clad perforations.

APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.

SAFETY LIMIT Exceeding an SL may cause fuel damage and create a potential VIOLATIONS for radioactive releases in excess of 10 CFR 50.67, "nAccident Source Term," limits (Ref. 2).

Therefore, it is required to insert all insertable control rods and restore (continued)

Revision No.

24 1 I

Brunswick Unit I B 2.0-4

Reactor Core SLs B 2.1.1 BASES SAFETY LIMIT compliance with the SLs within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months VIOLATIONS Completion Time ensures that the operators take prompt (continued) remedial action and also ensures that the probability of an accident occurring during this period is minimal.

REFERENCES

1.

NEDE-24011-P-A (latest approved revision).

2.

10 CFR 50.67.

Brunswick Unit B

I B 2.0-5 Revision No. 24 1

RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)

B 2.1.2 Reactor Coolant System (RCS)

Pressure SL BASES BACKGROUND The SL on reactor steam dome pressure protects the RCS against overpressurization.

In the event of fuel cladding failure, fission products are released into the reactor coolant.

The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere.

Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity.

According to the UFSAR (Ref. 1), the reactor coolant pressure boundary (RCPB) shall be designed with sufficient margin to ensure that the design conditions are not exceeded during normal operation and anticipated operational occurrences (AOOs).

During normal operation and AQOs, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2).

Hydrostatic testing with fuel in the core may be done under LCO 3.10.1, "Inservice Leak and Hydrostatic Testing Operation."

RCS components shall be pressure tested in accordance with the requirements of ASME Code,Section XI (Ref. 3).

Overpressurization of the RCS could result in a breach of the RCPB, reducing the number of protective barriers designed to prevent radioactive releases from exceeding the limits specified in 10 CFR 50.67, "Accident Source Term,"

(Ref. 4).

If this occurred in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere.

APPLICABLE SAFETY ANALYSES The RCS safety/relief valves and the Reactor Protection System Reactor Vessel Steam Dome Pressure-High Function have settings established to ensure that the RCS pressure SL will not be exceeded.

The RCS pressure SL has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered.

The reactor pressure vessel is designed to Section III of the ASME, Boiler and Pressure Vessel Code, 1965 Edition, including Addenda through the summer of 1967 (Ref. 5), which permits a maximum pressure (continued)

Revision No. 24 I I

Brunswick Unit 1 B 2.0-6

RCS Pressure SL B 2.1.2 BASES APPLICABLE SAFETY ANALYSES (continued)

SAFETY LIMITS APPLICABILITY SAFETY LIMIT VIOLATIONS transient of 110% (1375 psig) of the design pressure of 1250 psig.

The SL of 1325 psig, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS.

The RCS is designed to the USAS Nuclear Power Piping Code, Section B31.1, 1967 Edition, including Addenda (Ref. 6), for the reactor recirculation piping, which permits a maximum pressure transient of 120%

of design pressures of 1150 psig for suction piping and 1325 psig for discharge piping.

The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.

The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code,Section III, is 110% of design pressure.

The maximum transient pressure allowable in the RCS piping, valves, and fittings is 120% of design pressures of 1150 psig for suction piping and 1325 psig for discharge piping.

The most limiting of these allowances is the 110%

of the RCS pressure vessel design pressure; therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome.

SL 2.1.2 applies in all MODES.

Exceeding the RCS pressure SL may cause RCS failure and create a potential for radioactive releases in excess of 10 CFR 50.67, "Accident Source Term," limits (Ref.

4).

Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during this period is minimal.

REFERENCES

1. UFSAR Section 3.1.2.2.6.

2.

ASME, Boiler and Pressure Vessel Code,Section III, Article N-910, 1965 Edition.

3.

ASME, Boiler and Pressure Vessel Code,Section XI, Article IW-5000.

4.

10 CFR 50.67.

(continued)

Revision No. 24 1 I

I Brunswick Unit 1 B 2.0-7

Control Rod OPERABILITY B 3.1.3 BASES ACTIONS C.1 and C.2 (continued) within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Inserting a control rod ensures the shutdown and scram capabilities are not adversely affected and allows coupling attempts to be initiated for an uncoupled control rod when greater than the low power setpoint of the RWM.

The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations.

The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves.

The control rods can be electrically disarmed by disconnecting power from all four directional control valve solenoids.

Required Action C.1 is modified by a Note, which allows the inoperable control rods to be bypassed in the RWM or the RWM to be bypassed, if required, to allow insertion of the inoperable control rods and continued operation.

LCO 3.3.2.1 provides additional requirements when one or more control rods are bypassed in the RWM or when the RWM is bypassed to ensure compliance with the BPWS analysis (Ref. 6).

The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems.

D.1 and D.2 Out of sequence control rods may increase the potential reactivity worth of a dropped control rod during a CRDA.

At

8.75% RTP, the generic BPWS analysis (Ref. 6) requires inserted control rods not in compliance with BPWS to be separated by at least two OPERABLE control rods in all directions, including the diagonal.

Therefore, if two or more inoperable control rods are not in compliance with BPWS and not separated by at least two OPERABLE control rods, action must be taken to restore compliance with BPWS or restore the control rods to OPERABLE status.

Condition D is modified by a Note indicating that the Condition is not applicable when THERMAL POWER is > 8.75% RTP, since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3.1.6.

The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is acceptable, considering the low probability of a CRDA occurring.

(continued)

Revision No.

25 1 Brunswick Unit 1 B 3.1-17

Control Rod OPERABILITY Control Rod OPERABILITY B 3.1.3 BASES ACTIONS E.1 (continued)

If any Required Action and associated Completion Time of Condition A, C, or D are not met, or there are nine or more inoperable control rods, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

This ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods.

The number of control rods permitted to be inoperable when operating above 8.75% RTP (e.g., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken.

The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.3.1 REQUIREMENTS The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns.

Control rod position may be determined by the use of OPERABLE reed switch position indicators (including "full-in" or "full-out" indication), by moving control rods to a position with an OPERABLE reed switch indicator, or by the use of other appropriate methods.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.

SR 3.1.3.2 and SR 3.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves.

The control rod may then be returned to its original position.

This ensures the control rod is not stuck and is free to insert on a scram signal.

As noted, SR 3.1.3.2 and SR 3.1.3.3 are not required to be performed until 7 days and 31 days, respectively, after the control rod is withdrawn (continued)

Rrunswick Unit I B 3.1-18 Revision No. 25 I

Rod Pattern Control B 3.1.6 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control BASES BACKGROUND APPLICABLE SAFETY ANALYSES Control rod patterns during startup conditions are controlled by the operator and the rod worth minimizer (RWM)

(LCO 3.3.2.1, "Control Rod Block Instrumentation"),

so that only specified control rod sequences and relative positions are allowed over the operating range of all control rods inserted to 8.75% RTP.

The sequences limit the potential amount of reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA).

This Specification assures that the control rod patterns are consistent with the assumptions of the CRDA analyses of References 1, 2 and 3.

The analytical methods and assumptions used in evaluating the CRDA are summarized in References 2 and 3.

CRDA analyses assume that the reactor operator follows prescribed withdrawal sequences.

These sequences define the potential initial conditions for the CRDA analysis.

The RWM (LCO 3.3.2.1) provides backup to operator control of the withdrawal sequences to ensure that the initial conditions of the CRDA analysis are not violated.

Prevention or mitigation of positive reactivity insertion events is necessary to limit the energy deposition in the fuel, thereby preventing significant fuel damage which could result in the undue release of radioactivity.

Since the failure consequences for UO2 have shown that sudden fuel pin rupture requires a fuel energy deposition of approximately 425 cal/gm (Ref. 4), the fuel damage limit of 280 cal/gm provides a margin of safety from significant core damage which would result in release of radioactivity (Ref. 5).

Generic evaluations (Refs. 2 and 6) of a design basis CRDA (i.e., a CRDA resulting in a peak fuel energy deposition of 280 cal/gm) have shown that if the peak fuel enthalpy remains below 280 cal/gm, then the maximum reactor pressure will be less than the required ASME Code limits (Ref.

7) and the calculated offsite doses will be well within the required limits (Ref. 8).

(continuedl Revision No.

25 I I

Brunswick Unit 1 B 3.1-33

Rod Pattern Control B 3.1.6 BASES APPLICABLE SAFETY ANALYSES (continued)

Control rod patterns analyzed in Reference 2 follow the banked position withdrawal sequence (BPWS).

The BPWS is applicable from the condition of all control rods fully inserted to 8.75% RTP (Ref. 3).

For the BPWS, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions (e.g., between notches 08 and 12).

The banked positions are established to minimize the maximum incremental control rod worth without being overly restrictive during normal plant operation.

Generic analysis of the BPWS has demonstrated that the 280 cal/gm fuel damage limit will not be violated during a CRDA while following the BPWS during a plant startup or shutdown.

The generic BPWS analysis (Ref.

9) also evaluates the effect of fully inserted, inoperable control rods not in compliance with the sequence, to allow a limited number (i.e., eight) and a required distribution of fully inserted, inoperable control rods.

Rod pattern control satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref.

10).

LCO Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the BPWS.

This LCO only applies to OPERABLE control rods.

For inoperable control rods required to be inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the BPWS.

APPLICABILITY In MODES I and 2, when THERMAL POWER is

8.75% RTP, the CRDA is a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required.

When THERMAL POWER is > 8.75% RTP, there is no credible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 3).

In MODES 3, 4, and 5, since the reactor is shut down and interlocks allow only a single control rod to be withdrawn from a core cell containing fuel assemblies in MODE 5, adequate SDM ensures that the consequences of a CRDA are acceptable.

This is due to the fact that the reactor will remain subcritical with a single control rod withdrawn.

(continued)

Revision No.

25 1 I

Brunswick Unit I B 3.1-34

Rod Pattern Control Rod Pattern Control B 3.1.6 BASES (continued)

ACTIONS A.1 and A.2 With one or more OPERABLE control rods not in compliance with the prescribed control rod sequence, actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Noncompliance with the prescribed sequence may be the result of "double notching;" drifting as a result of a control rod drive cooling water transient or leaking scram valves; or a power reduction to : 8.75% RTP before establishing the correct control rod pattern.

The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight, to prevent the operator from attempting to correct a control rod pattern that significantly deviates from the prescribed sequence.

When the control rod pattern is not in compliance with the prescribed sequence, all control rod movement should be stopped except for moves needed to correct the rod pattern, or scram if warranted.

Required Action A.1 is modified by a Note which allows an individual control rod to be bypassed in the RWM or the entire RWM to be bypassed to allow the affected control rods to be returned to their correct position.

LCO 3.3.2.1 requires verification of control rod movement by a second licensed operator or other qualified member of the technical staff.

This ensures that the control rods will be moved to the correct BPWS position.

A control rod not in compliance with the prescribed sequence is not considered inoperable except as required by Required Action A.2.

OPERABILITY of control rods is determined by compliance with LCO 3.1.3, "Control Rod OPERABILITY,"

LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators."

The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is reasonable, considering the restrictions on the number of allowed out of sequence control rods and the low probability of a CRDA occurring during the time the control rods are out of sequence.

B.1 and B.2 If nine or more OPERABLE control rods are out of sequence, the control rod pattern significantly deviates from the prescribed sequence.

Control rod withdrawal should be suspended immediately to prevent the potential for further (continued)

Revision No. 25 I Brunswick Unit I B 3.1-35

Rod Pattern Control B 3.1.6 BASES ACTIONS B.1 and B.2 (continued) deviation from the prescribed sequence.

Control rod insertion to correct the position of control rods withdrawn beyond their allowed position is allowed since, in general, insertion of control rods has less impact on control rod worth than withdrawals have.

Required Action B.1 is modified by a Note which allows an individual control rod to be bypassed in the RWM or the entire RWM to be bypassed to allow the affected control rods to be returned to their correct position.

LCO 3.3.2.1 requires verification of control rod movement by a second licensed operator or other qualified member of the technical staff.

When nine or more OPERABLE control rods are not in compliance with BPWS, the reactor must be manually scrammed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

This ensures the reactor is shut down and, as such, does not meet the applicability requirements of this LCO.

The allowed Completion Time of I hour is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.

SURVEILLANCE SR 3.1.6.1 REQUIREMENTS The control rod pattern is verified to be in compliance with the BPWS at a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency to ensure the assumptions of the CRDA analyses are met.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency was developed considering that the primary check on compliance with the BPWS is performed by the RWM (LCO 3.3.2.1), which provides control rod blocks to enforce the required sequence and is required to be OPERABLE when operating at S8.75% RTP.

REFERENCES

1.

UFSAR, Section 15.4.

2.

NEDE-24011-P-A-11-US, General Electric Standard Application for Reactor Fuel, Supplement for United States, Section 2.2.3.1, November 1995.

(continued)

Revision No. 25 I I

B 3.1-36 Brunswick Unit I

Rod Pattern Control B 3.1.6 BASES REFERENCES (continued)

3.

NRC Safety Evaluation Report, Acceptance For Referencing of Licensing Topical Report NEDE-24011-P-A, General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17; December 27, 1987.

4.

UFSAR, Section 4.3.2.5.

5.

NUREG-0800, Section 15.4.9, Revision 2, July 1981.

6.

NEDO-21778-A, Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors, December 1978.

7.

ASME, Boiler and Pressure Vessel Code.

8.

10 CFR 50.67.

9.

NEDO-21231, Banked Position Withdrawal Sequence, January 1977.

10.

10 CFR 50.36(c)(2)(ii).

Revision No.

24 1 I

Brunswick Unit 1 B 3.1-37

SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory (which is at the peak of the xenon transient) to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement.

The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated transient without scram.

The SLC System is also used to maintain suppression pool pH level above 7 following a loss of coolant accident (LOCA) involving significant fission product releases.

Maintaining suppression pool pH levels greater than 7 following an accident ensures that iodine will be retained in the suppression pool water (Ref. 2).

The SLC System consists of a boron solution storage tank, two positive displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel (RPV).

The borated solution is discharged near the bottom of the core shroud, where it then mixes with the cooling water rising through the core.

A smaller tank containing demineralized water is provided for testing purposes.

APPLICABLE SAFETY ANALYSES The SLC System is manually initiated from the main control room, as directed by the emergency operating procedures, if the operator believes the reactor cannot be shut down, or kept shut down, with the control rods.

The SLC System is used in the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the normal manner.

The SLC System injects borated water into the reactor core to add negative reactivity to compensate for all of the various reactivity effects that could occur during plant operations.

To meet this objective, it is necessary for both SLC pumps to inject a quantity of boron which produces a concentration of 660 ppm of natural boron in the reactor coolant at 70°F with normal reactor vessel (continued)

Revision No.

24 I B 3.1-38 Brunswick Unit I

SLC System B 3.1.7 BASES APPLICABLE SAFETY ANALYSES (continued)

LCO water level.

To allow for potential leakage and imperfect mixing in the reactor system, an additional amount of boron equal to 25% of the amount cited above is added (Ref. 3).

The volume versus concentration limits in Figure 3.1.7-1 and the temperature versus concentration limits in Figure 3.1.7-2 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water volume in the residual heat removal shutdown cooling piping and in the recirculation loop piping.

This quantity of borated solution is the amount that is above the pump suction level in the boron solution storage tank.

No credit is taken for the portion of the tank volume that cannot be injected.

Following a LOCA, offsite doses from the accident will remain within 10 CFR 50.67 limits (Ref. 4) provided sufficient iodine activity is retained in the suppression pool.

Credit for iodine deposition in the suppression pool is allowed (Ref. 2) as long as suppression pool pH is maintained greater than 7.

BSEP Alternative Source Term analyses credit the use of the SLC System for maintaining the pH of the suppression pool greater than 7.

The SLC System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii) (Ref. 5) because operating experience and probabilistic risk assessments have shown the SLC System to be important to public health and safety.

Thus, it is retained in the Technical Specifications.

The OPERABILITY of the SLC System provides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods.

The OPERABILITY of the SLC System is based on the conditions (concentration and temperature) of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves.

Two SLC subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.

In addition, the boron solution concentration should be within the limits of Figure 3.1.7-1 and the boron solution temperature should be within the limits of Figure 3.1.7-2.

(continued)

Revision No.

24 1 I

I Brunswick Unit 1 B 3.1-39

SLC System B 3.1.7 BASES (continued)

APPLICABILITY ACTIONS In MODES I and 2, shutdown capability is required.

In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in the shutdown position and a control rod block is applied.

This provides adequate controls to ensure that the reactor remains subcritical.

In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies.

Determination of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)")

ensures that the reactor will not become critical with the analytically determined strongest control rod withdrawn.

Therefore, the SLC System is not required to be OPERABLE when only a single control rod can be withdrawn.

A. I If one SLC subsystem is inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days.

In this condition, the remaining OPERABLE subsystem is adequate to perform the original licensing basis shutdown function.

However, the overall capability is reduced since the remaining OPERABLE subsystem cannot meet the requirements of Reference 1.

The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the original licensing basis SLC System function and the low probability of a Design Basis Accident (DBA) or severe transient occurring concurrent with the failure of the control rods to shut down the plant.

B.1 If both SLC subsystems are inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Both SLC subsystems are considered inoperable if the boron solution concentration or temperature is outside the limits of the associated figures.

The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is considered acceptable given the low probability of a DBA or transient occurring concurrent with the failure of the control rods to shut down the reactor.

(Conti nued)

Revision No.

24 I Brunswick Unit I B 3.1-40

SLC System B 3.1.7 BASES ACTIONS C.1 (continued)

If any Required Action and associated Completion Time is not met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 are 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Surveillances verifying certain characteristics of the SLC System (e.g.,

the volume and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation.

These Surveillances ensure that the proper borated solution volume and temperature, including the temperature of the pump suction and discharge piping up to the SLC injection valves, are maintained.

Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out in the storage tank or in the pump suction piping.

The temperature versus concentration curve of Figure 3.1.7-2 ensures that a 5°F margin will be maintained above the saturation temperature.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience and has shown there are relatively slow variations in the measured parameters of volume and temperature.

SR 3.1.7.4 SR 3.1.7.4 verifies the continuity of the explosive charges in the SLC injection valves to ensure that proper operation will occur if required.

Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed.

The 31 day Frequency is based on operating experience and has demonstrated the reliability of the explosive charge continuity.

(continued)

Revision No. 24 1 Brunswick Unit 1 B 3.1-41

SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron (measured in weight %

sodium pentaborate) exists in the storage tank.

SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits.

SR 3.1.7.5 must also be performed anytime the temperature is restored to within the limits of Figure 3.1.7-2, to ensure that no significant boron precipitation occurred during the time period temperature was outside the limits of the Figure.

The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between Surveillances.

SR 3.1.7.6 Demonstrating that each SLC System pump develops a flow rate

_ 41.2 gpm at a discharge pressure _ 1190 psig ensures that pump performance has not degraded during the fuel cycle.

This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay.

This test confirms one point on the pump design curve and is indicative of overall performance.

Such inservice tests confirm component OPERABILITY and detect incipient failures by indicating abnormal performance.

The Frequency of this Surveillance is in accordance with the Inservice Testing Program.

SR 3.1.7.7 This Surveillance ensures that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve.

The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch (continued)

Revision No.

24 I Brunswick Unit I B 3.1-42

SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS SR 3.1.7.7 (continued) that has been certified by having one of that batch successfully fired.

The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 48 months at alternating 24 month intervals.

The Surveillance may be performed in separate steps to prevent injecting boron into the RPV.

An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has demonstrated these components will usually pass the Surveillance when performed at the 24 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1.

10 CFR 50.62.

2.

NUREG-1465, Accident Source Terms for Light-Water Nuclear Power Plants, Final Report, February 1, 1995.

3.

UFSAR, Section 9.3.4.

4.

10 CFR 50.67

5.

10 CFR 50.36(c)(2)(ii).

Revision No. 24 I I

I I

I Brunswick Unit I B 3.1-43

SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES BACKGROUND APPLICABLE SAFETY ANALYSES The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram.

During a scram, the SDV vent and drain valves close to contain reactor water.

The SDV is a volume of header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume.

There are two SDVs (headers) and two instrument volumes, each receiving approximately one half of the control rod drive (CRD) discharges.

The two instrument volumes are connected to a common drain line with two valves in series.

The two headers are connected to a common vent line with two valves in series.

The header piping is sized to receive and contain all the water discharged by the CRDs during a scram.

The Design Basis Accident and transient analyses assume the control rods are capable of scramming.

The acceptance criteria for the SDV vent and drain valves are that they operate automatically to:

a.

Close during scram to limit the amount of reactor coolant discharged so that adequate core cooling is maintained and offsite doses remain within the limits of 10 CFR 50.67 (Ref. 1); and

b.

Open on scram reset to maintain the SDV vent and drain path open so that there is sufficient volume to accept the reactor coolant discharged during a scram.

Isolation of the SDV can also be accomplished by manual closure of the SDV valves.

Additionally, the discharge of reactor coolant to the SDV can be terminated by scram reset or closure of the HCU manual isolation valves.

For a bounding leakage case, the offsite doses are well within the limits of 10 CFR 50.67 (Ref. 1), and adequate core cooling is maintained (Ref. 2).

The SDV vent and drain valves allow continuous drainage of the SDV during normal plant operation (continued)

Revision No. 24 1 I

I Brunswick Unit 1 B 3.1-44

SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE SR 3.1.8.3 (continued)

REQU IREMENTS need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has demonstrated these components will usually pass the Surveillance when performed at the 24 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1.

10 CFR 50.67.

2.

NUREG-0803, Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping, August 1981.

3.

10 CFR 50.36(c)(2)(ii).

Revision No. 24 I I

Brunswick Unit I B 3.1-48

APLHGR B 3.2.1 BASES APPLICABLE SAFETY ANALYSES (continued) generated.

Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which turbine stop valve closure and turbine control valve fast closure scram trips are bypassed, both high and low core flow MAPFACp limits are provided for operation at power levels between 23% RTP and the previously mentioned bypass power level.

The exposure dependent APLHGR limits are reduced by MAPFACP and MAPFACf at various operating conditions to ensure that all fuel design criteria are met for normal operation and AO0s.

A complete discussion of the analysis code is provided in Reference 8.

LOCA analyses are then performed to ensure that the above determined APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46.

The analysis is performed using calculational models that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 9.

The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly.

The APLHGR limits specified are equivalent to the LHGR of the highest powered fuel rod assumed in the LOCA analysis divided by its local peaking factor.

A conservative multiplier is applied to the LHGR assumed in the LOCA analysis to account for the uncertainty associated with the measurement of the APLHGR.

For single recirculation loop operation, Reference 5 shows that no APLHGR reduction is required.

The APLHGR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii)

(Ref.

10).

LCO The APLHGR limits for each type of fuel as a function of axial location and average planar exposure specified by reference in the COLR are the result of the fuel design, DBA, and transient analyses.

For two recirculation loops operating, the limit is determined by multiplying the smaller of the MAPFACp and MAPFACf factors times the exposure dependent APLHGR limits.

The APLHGR limits have been approved for the respective fuel and lattice type and determined by the approved methodology described in Reference 1.

When hand calculations are required, the APLHGR for each type of fuel as a function of average planar (continued)

Revision No. 25 1 I

Brunswick Unit 1 B 3.2-2

APLHGR B 3.2.1 BASES LCO exposure shall not exceed the limiting value, adjusted for (continued) core flow and core power, for the most limiting lattice (excluding natural uranium) for each type of fuel shown in the applicable figures of the COLR.

Limits have been provided in the COLR for two recirculation loop operation and single recirculation loop operation.

The limits on single recirculation loop operation are provided to allow operation in this condition in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating."

APPLICABILITY The APLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses that are assumed to occur at high power levels.

Studies and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases.

This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs.

When in MODE 2, the intermediate range monitor scram function provides prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance concern in MODE 2.

At THERMAL POWER levels

23% RTP, the reactor is operating with substantial margin to the APLHGR limits.

For consistency with the 2.1.1.1 SL, this power level was selected for LCO applicability.

ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA and transient analyses may not be met.

Therefore, prompt action should be taken and continued to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions and within design limits of the fuel rods.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the APLHGR out of specification.

B.1 If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which (continued)

Revision No. 25 I Brunswick Unit I B 3.2-3

APLHGR B 3.2.1 BASES ACTIONS B.1 (continued) the LCO does not apply.

To achieve this status, THERMAL POWER must be reduced to < 23% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is

23% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER Ž 23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES

1. NEDO-24011-P-A "General Electric Standard Application for Reactor Fuel" (latest approved version).

2.

UFSAR, Chapter 4.

3.

UFSAR, Chapter 6.

4.

UFSAR, Chapter 15.

5.

NEDC-31776P, Brunswick Steam Electric Plant Units 1 and 2 Single-Loop Operation, December 1989.

6.

NEDC-31654P, Maximum Extended Operating Domain Analysis for Brunswick Steam Electric Plant, February 1989.

7.

NEDO-20953-A, Three-Dimensional BWR Core Simulator, October 1978.

8.

NEDO-24154, Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors, October 1978.

(continued)

Revision No.

25 1 B 3.2-4 Brunswick Unit I

MCPR B 3.2.2 BASES APPLICABLE SAFETY ANALYSES (continued) state (MCPRf and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Ref. 7).

Flow dependent MCPR limits are determined using the methodology described in Reference 2 to analyze slow flow runout transients.

The operating limit is dependent on the maximum core flow limiter setting in the Recirculation Flow Control System.

Power dependent MCPR limits (MCPRp) are determined using the methodology described in Reference 2.

Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scrams are bypassed, high and low flow MCPR, operating limits are provided for operating between 23% RTP and the previously mentioned bypass power level.

The MCPR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii)

(Ref. 8).

LCO The MCPR operating limits, as a function of core flow, core power, and cycle exposure, specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

The operating limit MCPR is determined by the larger of the MCPRf and MCPRp limits.

APPLICABILITY The MCPR operating limits are primarily derived-from transient analyses that are assumed to occur at high power levels.

Below 23% RTP, the reactor is operating at a minimum recirculation pump speed and the moderator void ratio is small.

Surveillance of thermal limits below 23% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.

Statistical analyses indicate that the nominal value of the initial MCPR expected at 23% RTP is

> 3.5.

Studies of the variation of limiting transient behavior have been performed over the range of power and flow conditions.

These studies encompass the range of key actual plant parameter values important to typically limiting transients.

The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as (continued)

Revision No.

25 1 I

I I

I B 3.2-7 Brunswick Unit I

MCPR B 3.2.2 BASES APPLICABILITY (continued)

ACTIONS power is reduced to 23% RTP.

This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs.

When in MODE 2, the intermediate range monitor provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern.

Therefore, at THERMAL POWER levels

< 23% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.

A.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met.

Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply.

To achieve this status, THERMAL POWER must be reduced to < 23% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 23% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is

23% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and (continued)

Revision No.

25 I l

I I

J I

Brunswick Unit I B 3.2-8

MCPR B 3.2.2 BASES SURVEILLANCE SR 3.2.2.1 (continued)

REQUIREMENTS recognition of the slowness of changes in power distribution during normal operation.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER

23% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analysis.

SR 3.2.2.2 determines the value of T, which is a measure of the actual scram speed distribution compared with the assumed distribution.

The MCPR operating limit is then determined based on an interpolation between the applicable limits for ODYN Option A (scram times of LCO 3.1.4, "Control Rod Scram Times") and ODYN Option B (realistic scram times) analyses.

The MCPR operating limits for the ODYN Option A and ODYN Option B analyses are specified in the COLR.

The parameter T must be determined once within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each set of scram time tests required by SR 3.1.4.1, SR 3.1.4.2, and SR 3.1.4.4 because the effective scram speed distribution may change during the cycle.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is acceptable due to the relatively minor changes in T expected during the fuel cycle.

REFERENCES

1.

UFSAR Section 4.4.2.1.

2.

NEDO-24011-P-A, General Electric Standard Application for Reactor Fuel (latest approved version).

3.

UFSAR, Chapter 4.

4.

UFSAR, Chapter 6.

5.

UFSAR, Chapter 15.

6.

NEDC-31776P, Brunswick Steam Electric Plant Units I and 2 Single-Loop Operation, December 1989.

(continued)

Revision No. 25 1 Brunswick Unit I B 3.2-9

RPS Instrumentation RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Average Power Range Monitor (APRM)

(continued)

SAFETY ANALYSES, LCO, and channel is assigned to one, two or four OPRM "cells,"

APPLICABILITY forming a total of 24 separate OPRM cells per APRM channel, each with either three or four detectors.

LPRMs near the edge of the core are assigned to either one or two OPRM cells.

A minimum of 18 OPRM cells in an APRM channel must have at least two OPERABLE LPRMs for the OPRM Upscale Function 2.f to be OPERABLE (Ref.

22).

2.a.

Average Power Range Monitor Neutron Flux-High (Setdown)

For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range.

For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown)

Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints.

With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide the primary trip signal for a core-wide increase in power.

No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux-High (Setdown)

Function.

However, this Function is credited in calculations used to eliminate the need to perform the spatial analysis required for the Intermediate Range Monitor Neutron Flux-High Function (Ref. 6).

In addition, the Average Power Range Monitor Neutron Flux-High (Setdown)

Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow.

Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER < 23% RTP.

The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 23% RTP.

The Average Power Range Monitor Neutron Flux-High (Setdown)

Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists.

(continued)

Revision No. 25 1 Brunswick Unit I B 3.3-8

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.a.

Average Power Range Monitor Neutron Flux-High SAFETY ANALYSES, (Setdown)

(continued)

LCO, and APPLICABILITY In MODE 1, the Average Power Range Monitor Simulated Thermal Power-High and Neutron Flux-High Functions provide protection against reactivity transients and the RWM and Rod Block Monitor protect against control rod withdrawal error events.

2.b.

Average Power Range Monitor Simulated Thermal Power-High The Average Power Range Monitor Simulated Thermal Power-High Function monitors neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant.

The APRM neutron flux is electronically filtered with a time constant, nominally 6 seconds, representative of the fuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in the reactor.

The trip level is varied as a function of rated recirculation drive flow (W) in percent and is clamped at an upper limit that is always lower than the Average Power Range Monitor Neutron Flux-High Function Allowable Value.

The Average Power Range Monitor Simulated Thermal Power-High Function provides a general definition of the licensed core power/core flow operating domain.

A note is included, applicable when the plant is in single recirculation loop operation per LCO 3.4.1, which requires reducing by aW the flow value used in the Allowable Value equation.

The value of AU is defined in plant procedures.

The value of AU is established to adjust the SLO limit down in power approximatley 8.5% RTP to reflect the difference between the analyzed limits for two-recirculation loop operation (TLO) and SLO.

The adjustment maintains the SLO limits at approximately the same absolute thermal power level as was established prior to extended power uprate.

The 8.5% RTP has been converted to an equivalent "AW" value for convenience of representation and to reflect the way the adjustment is actually made in the APRM equipment.

In addition to this adjustment, the actual AW value entered into the equipment includes an allowance for additional flow measurement uncertainties that may occur in SLO.

The (continued)

Revision No.

25 I Brunswick Unit 1 8 3.3-9

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.b.

Average Power Range Monitor Simulated Thermal SAFETY ANALYSES, Power-High (continued)

LCO, and APPLICABILITY allowable value equation for single loop operation is only valid for flows down to W =L8W, at which point the allowable value is equal to the TLO "offset" value, the minimum required.

The Average Power Range Monitor Simulated Thermal Power-High Function is not associated with an LSSS.

Operating limits established for the licensed operating domain are used to develop the Average Power Range Monitor Simulated Thermal Power-High Function Allowable Values, including the clamp value, to provide pre-emptive reactor scram and prevent gross violation of the licensed operating domain.

Operation outside the licensed operating domain may result in anticipated operational occurrences and postulated accidents being initiated from conditions beyond those assumed in the safety analysis.

Each APRM channel uses one total recirculation drive flow signal representative of total core flow.

The total drive flow signal is generated by the flow processing logic, part of the APRM channel, by summing the flow calculated from two flow transmitter signal inputs, one from each of the two recirculation loops.

The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function.

The Average Power Range Monitor Simulated Thermal Power-High Function uses a trip level generated based on recirculation loop drive flow.

Changes in the core flow to drive flow functional relationship may vary over the core flow operating range.

These changes can result from gradual changes in the Recirculation System and core components over the reactor life time as well as specific maintenance performed on these components (e.g., jet pump cleaning).

The proper representation of drive flow as a representation of core flow is ensured through drive flow alignment, accomplished by SR 3.3.1.1.18.

The Average Power Range Monitor Simulated Thermal Power-High Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive (continued)

Revision No. 25 1 Brunswick Unit I B 3.3-10

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY

8.

Turbine Stop Valve-Closure (continued)

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the four TSVs.

Two independent position switches are associated with each stop valve.

One of the two switches provides input to RPS trip system A; the other, to RPS trip system B.

Thus, each RPS trip system receives an input from four Turbine Stop Valve-Closure channels, each consisting of one position switch.

The logic for the Turbine Stop Valve-Closure Function is such that three or more TSVs must be closed to produce a scram.

In addition, certain combinations of two valves closed will result in a half-scram.

This Function must be enabled at THERMAL POWER Ž 26% RTP.

This is accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function.

The Turbine Stop Valve-Closure Allowable Value is selected to be high enough to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Eight channels of Turbine Stop Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if any three TSVs should close.

This Function is required, consistent with analysis Vassumptions, whenever THERMAL POWER is Ž 26% RTP.

This Function is not required when THERMAL POWER is < 26% RTP since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

9.

Turbine Control Valve Fast Closure, Control Oil Pressure--Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited.

Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves.

The Turbine Control Valve Fast Closure, Control Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 2.

For (continued)

Revision No. 25 I I

I I B 3.3-21 Brunswick Unit 1

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE

9.

Turbine Control Valve Fast Closure, Control Oil SAFETY ANALYSES, Pressure-Low (continued)

LCO, and APPLICABILITY this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.

Turbine Control Valve Fast Closure, Control Oil Pressure-Low signals are initiated by the electrohydraulic control (EHC) fluid pressure at each control valve.

One pressure switch is associated with each control valve, and the signal from each switch is assigned to a separate RPS logic channel.

This Function must be enabled at THERMAL POWER ý 26% RTP.

This is accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function.

The Turbine Control Valve Fast Closure, Control Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, Control Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is Ž 26% RTP.

This Function is not required when THERMAL POWER is < 26% RTP, since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Monitor Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

10.

Reactor Mode Switch-Shutdown Position The Reactor Mode Switch-Shutdown Position Function provides signals, via the manual scram logic channels, to two RPS logic channels, which are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability.

This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

(continued)

Brunswick Unit I B 3.3-22 Revision No. 25

RPS Instrumentation RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.3 REQUIREMENTS (continued)

To ensure that the APRMs are accurately indicating the true core average power, the APRMs are adjusted to conform to the reactor power calculated from a heat balance.

The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.8.

A restriction to satisfying this SR when < 23% RTP is provided that requires the SR to be met only at Ž 23% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 23% RTP.

At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR and APLHGR).

At Ž 23% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2.

A Note is provided which allows an increase in THERMAL POWER above 23% if the 7 day Frequency is not met per SR 3.0.2.

In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reaching or exceeding 23% RTP.

Twelve I hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodol ogy.

As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM Functions cannot be performed in MODE I without utilizing jumpers, lifted leads, or movable links.

This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2.

In this event, the SR must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref.

11).

(continued)

Revision No. 25 1 Brunswick Unit I B 3.3-31

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued)

The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic and simulated automatic operation for a specific channel.

The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.

The LOGIC SYSTEM FUNCTIONAL TEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-Out-Of-4 Voter channel inputs to check all combinations of two tripped inputs to the 2-Out-Of-4 logic in the voter channels and APRM related redundant RPS relays.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has demonstrated that these components will usually pass the Surveillance when performed at the 24 month Frequency.

SR 3.3.1.1.16 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Control Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is ý 26% RTP.

This is satisfied by calibration of the bypass channels.

Adequate margins for the instrument setpoint methodologies are incorporated into the Allowable Value and the actual setpoint.

Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed during an in-service calibration at THERMAL POWER ! 26% RTP to ensure that the calibration is I valid.

If any bypass channel setpoint is nonconservative (i.e., the Functions are bypassed at t 26% RTP, either due to open main I turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Control Oil Pressure-Low Functions are considered inoperable.

Alternatively, the bypass channel can be placed (continued)

Revision No.

25 I B 3.3-37 Brunswick Unit I

Control Rod Block Instrumentation Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND peripheral control rod is selected (Ref.

1).

A rod block (continued) signal is also generated if an RBM inoperable trip occurs, since this could indicate a problem with the RBM channel.

The inoperable trip will occur if, during the nulling (normalization) sequence, the RBM channel fails to null or too few LPRM inputs are available, if a critical self-test fault has been detected, or the RBM instrument mode switch is moved to any position other than "Operate."

The purpose of the RWM is to control rod patterns during startup and shutdown, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 8.75% RTP.

The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA.

Prescribed control rod sequences are stored in the RWM, which will initiate control rod withdrawal and insert blocks when the actual sequence deviates beyond allowances from the stored sequence.

The RWM determines the actual sequence based position indication for each control rod.

The RWM also uses steam flow signals to determine when the reactor power is above the preset power level at which the RWM is automatically bypassed.

The RWM is a single channel system that provides input into the RMCS rod withdraw permissive circuit.

With the reactor mode switch in the shutdown position, a control rod Withdrawal block is applied to all control rods to ensure that the shutdown condition is maintained.

This Function prevents inadvertent criticality as the result of a control rod withdrawal during MODE 3 or 4, or during MODE 5 when the reactor mode switch is required to be in the shutdown position.

The reactor mode switch has two channels, each inputting into a separate RMCS rod block circuit.

A rod block in either RMCS circuit will provide a control rod block to all control rods.

APPLICABLE

1. Rod Block Monitor SAFETY ANALYSES, LCO, and The RBM is designed to prevent violation of the MCPR APPLICABILITY SL and the cladding 1% plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE) event.

The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 2.

A statistical analysis of RWE events was performed to (continued)

Revision No.

25 I Brunswick Unit 1 B 3.3-54

Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE

1. Rod Block Monitor (continued)

SAFETY ANALYSES,

LCO, and Power Range-Upscale Function is OPERABLE.

Similarly, the APPLICABILITY OPERABILITY requirement for the Intermediate Power Range-Upscale Function is satisfied if the High Power Range-Upscale Function is OPERABLE.

2.

Rod Worth Minimizer The RWM enforces the banked position withdrawal sequence (BPWS) to ensure that the initial conditions of the CRDA analysis are not violated.

The analytical methods and assumptions used in evaluating the CRDA are summarized in References 4, 5, and 6.

The BPWS requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions.

Requirements that the control rod sequence is in compliance with the BPWS are specified in LCO 3.1.6, "Rod Pattern Control."

The RWM Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

The RWM is a microprocessor-based system with the principle task to reinforce procedural control to limit the reactivity worth of control rods under lower power conditions.

Only one channel of the RWM is available and required to be OPERABLE.

Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY,"

and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the BPWS.

As required by these conditions, one or more control rods may be bypassed in the RWM or the RWM may be bypassed.

However, the RWM must be considered inoperable and the Required Actions of this LCO followed since the RWM can no longer enforce compliance with the BPWS.

Compliance with the BPWS, and therefore OPERABILITY of the

RWM, is required in MODES 1 and 2 when THERMAL POWER is s 8.75% RTP.

When THERMAL POWER is

> 8.75% RTP, there is no I possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs.

5 and 6).

In MODES 3 and 4, all (continued)

Revision No. 25 I B 3.3-58 Brunswick Unit I

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.1 (continued)

REQUIREMENTS input.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 184 days is based on reliability analyses (Refs. 8, 9, and 10).

SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the system will perform the intended function.

The CHANNEL FUNCTIONAL TEST for the RWM is performed by selecting a control rod not in compliance with the prescribed sequence and verifying proper annunciation of the selection error, and by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs.

As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until I hour after any control rod is withdrawn in MODE 2.

As noted, SR 3.3.2.1.3 is not required to be performed until I hour after THERMAL POWER is - 8.75% RTP in MODE 1. This allows I

entry into MODE 2 for SR 3.3.2.1.2, and entry into MODE 1 when THERMAL POWER is

8.75% RTP for SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2.

The I hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

Operating experience has demonstrated these components will usually pass the Surveillances when performed at the 92 day Frequency.

Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.3.2.1.4 The RBM setpoints are automatically varied as a function of power.

Three Allowable Values are specified in Table 3.3.2.1-1, one corresponding to each specific power range.

The purpose of this SR is to assure that for each RBM power range, the RBM flux trip rod block outputs are enabled (not bypassed) and that the RBM flux trip setpoint being applied is equal to or more conservative than the (continued)

Revision No.

25 I Brunswick Unit I B 3.3-63

Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2.1.4 (continued)

REQUIREMENTS SR 3.3.2.1.4.c is satisfied if, for an APRM Simulated Thermal Power level Ž the high power level setpoint Allowable Value defined in the COLR, the RBM flux trip rod block outputs are not bypassed and the RBM flux trip setpoint being applied is less than or equal to the high trip setpoint Allowable Value defined in the COLR.

SR 3.3.2.1.5 The RWM is automatically bypassed when power is above a specified value.

The power level is determined from steam flow signals.

The automatic bypass setpoint must be verified periodically to be > 8.75% RTP.

If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable.

Alternately, the low power setpoint channel can be placed in the conservative condition (nonbypass).

If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable.

The Frequency is based on the trip setpoint methodology utilized for the low power setpoint channel.

SR 3.3.2.1.6 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch-Shutdown Position Function to ensure that the channel will perform the intended function.

The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs.

As noted in the SR, the Surveillance is not required to be performed until I hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable links.

This allows entry into MODES 3 and 4 if the 24 month Frequency is not met per SR 3.0.2.

The I hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

(continued)

Revision No. 25 1 Brunswick Unit I B 3.3-65

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES APPLICABLE The high water level trip indirectly initiates a reactor SAFETY ANALYSES scram from the main turbine trip (above 26% RTP) and trips (continued) the feedwater pumps, thereby terminating the event.

The reactor scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref.

2).

LCO The LCO requires three channels of the reactor vessel high water level instrumentation to be OPERABLE to ensure that the feedwater pump turbines and main turbine trip on a valid high water level signal.

Two of the three channels are needed to provide trip signals in order for the feedwater and main turbine trips to occur.

Each channel must have its setpoint set within the specified Allowable Value of SR 3.3.2.2.2.

The Allowable Value is set to ensure that the thermal limits are not exceeded during the event.

The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions.

Trip setpoints are specified in the setpoint calculations.

The setpoints are selected to ensure that the trip settings do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS.

Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptable.

A channel is inoperable if its actual trip setting is not within its required Allowable Value.

Trip setpoints are those predetermined values of output at which an action should take place.

The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state.

The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis.

The trip setpoints are determined from the analytic limits corrected for defined process, calibration, and instrument errors.

The Allowable Values are then determined, based on the trip setpoint values, by accounting for calibration based errors.

These calibration based instrument errors are limited to instrument drift, errors associated with measurement and test equipment, and calibration tolerance of loop components.

The trip setpoints and Allowable Values determined in this manner provide adequate protection (continued)

Revision No. 25 1 I

B 3.3-69 Brunswick Unit I

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES LCO because instrumentation uncertainties, process effects, (continued) calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for and appropriately applied for the instrumentation.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at Ž 23% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the feedwater controller failure, maximum demand event.

As discussed in the Bases for LCO 3.2.1, "Average Planar Linear Heat Generation Rate (APLHGR),"

and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," sufficient margin to these limits exists below 23% RTP; therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A Note has been provided to modify the ACTIONS related to feedwater and main turbine high water level trip instrumentation channels.

Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.

Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.

However, the Required Actions for inoperable feedwater and main turbine high water level trip instrumentation channels provide appropriate compensatory measures for separate inoperable channels.

As such, a Note has been provided that allows separate Condition entry for each inoperable feedwater and main turbine high water level trip instrumentation channel.

A.1 With one channel inoperable, the remaining two OPERABLE channels can provide the required trip signal.

However, overall instrumentation reliability is reduced because a single failure in one of the remaining channels concurrent (continued)

Revision No.

25 I B 3.3-70 Brunswick Unit I

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES B.1 (continued) during this period.

It is also consistent with the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provided in LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not restored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 23% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

As discussed in the Applicability section of the Bases, operation below 23% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event.

The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is based on operating experience to reduce THERMAL POWER to < 23% RTP from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains feedwater and main turbine high water level trip capability.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based on the reliability analysis (Ref. 3) assumption that 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is the average time required to perform channel Surveillance.

That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the feedwater pump turbines and main turbine will trip when necessary.

SR 3.3.2.2.1 Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ensures that a gross failure of instrumentation has not occurred.

A CHANNEL CHECK is normally a comparison of the parameter (continued)

Revision No.

25 1 ACTIONS l l l

Brunswick Unit I B 3.3-72

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Main Steam Line Isolation l.a.

Reactor Vessel Water Level-Low Level 3 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result.

Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Level--Low Level 3 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals.

The Reactor Vessel Water Level-Low Level 3 Function associated with isolation is assumed in the analysis of the recirculation line break (Ref.

1).

The isolation of the MSLs on Level 3 supports actions to ensure that offsite dose limits are not exceeded for a DBA.

Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

Four channels of Reactor Vessel Water Level--Low Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Level 3 Allowable Value is chosen to be the same as the ECCS Level 3 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 50.67 limits.

The Allowable Value is referenced from reference level zero.

Reference level zero is 367 inches above the vessel zero point.

This Function isolates the Group 1 valves.

].b.

Main Steam Line Pressure-Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than 100°F/hr if the pressure loss is allowed to continue.

The Main Steam Line Pressure-Low Function is directly assumed in the analysis of the pressure regulator (continued)

Revision No. 24 1 I

Brunswick Unit I B 3.3-150

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 1.b.

Main Steam Line Pressure-Low (continued)

SAFETY ANALYSES LCO, and failure (Ref.

2).

For this event, the closure of the MSIVs APPLICABILITY ensures that no significant thermal stresses are imposed on the RPV.

In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded.

(This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 25% RTP.)

The MSL low pressure signals are initiated from four transmitters that are connected to the MSL header.

The transmitters are arranged such that each transmitter is able to detect low MSL pressure.

Four channels of Main Steam Line Pressure-Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Value was selected to be far enough below normal turbine inlet pressures to avoid spurious isolations, yet high enough to provide timely detection of a pressure regulator malfunction.

The Main Steam Line Pressure-Low Function is only required to be OPERABLE in MODE I since this is when the assumed transient can occur (Ref. 2).

This Function isolates the Group I valves except for sample line isolation valves B32-FO19 and B32-F020.

I.c.

Main Steam Line Flow-High Main Steam Line Flow-High is provided to detect a break of the MSL and to initiate closure of the MSIVs.

If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover.

If the RPV water level decreases too far, fuel damage could occur.

Therefore, the isolation is initiated on high flow to prevent or minimize core damage.

The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break (MSLB)

(Ref. 5).

The isolation action, along with the scram function of the Reactor Protection System (RPS),

ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite doses do not exceed the 10 CFR 50.67 limits.

(continued)

Revision No.

24 I Brunswick Unit I B 3.3-151

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE 2.a. Reactor Vessel Water Level-Low Level I (continued)

SAFETY ANALYSES, LCO, and limit the release of fission products.

The isolation of the APPLICABILITY primary containment on Level I supports actions to ensure that offsite dose limits of 10 CFR 50.67 are not exceeded.

The Reactor Vessel Water Level-Low Level 1 Function associated with isolation is implicitly assumed in the UFSAR analysis as these leakage paths are assumed to be isolated post LOCA.

Reactor Vessel Water Level-Low Level 1 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

Four channels of Reactor Vessel Water Level-Low Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Level I Allowable Value was chosen to be the same as the RPS Level 1 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical to orderly plant shutdown.

The Allowable Value is referenced from reference level zero.

Reference level zero is 367 inches above the vessel zero point.

This Function isolates the Group 2, 6, and 8 valves.

2.b.

Drywell Pressure-High High drywell pressure can indicate a break in the RCPB inside the primary containment.

The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 50.67 are not exceeded.

The Drywell Pressure-High Function, associated with isolation of the primary containment, is implicitly assumed in the UFSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.

High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell.

Four channels of Drywell Pressure-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

(continued)

Revision No.

24 I B 3.3-154 Brunswick Unit I

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Brunswick Unit I Revision 25 1 LOEP-5

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE SAFETY ANALYSES (continued)

A plant specific LOCA analysis has been performed assuming only one operating recirculation loop.

This analysis has demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, without the requirement to modify the APLHGR requirements (Ref. 3).

However, the COLR may require APLHGR limits to restrict the peak clad temperature for a LOCA with a single recirculation loop operating below the corresponding temperature for both loops operating.

The transient analyses of Chapter 15 of the UFSAR have also been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed without the requirement to modify the MCPR requirements.

During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM)

Simulated Thermal Power-High Allowable Value is required to account for the different analyzed limits between two-recirculation drive flow loop operation and operation with only one loop.

The APRM channel subtracts the AW value from the measured recirculation drive flow to effectively shift the limits and uses the adjusted recirculation drive flow value to determine the APRM Simulated Thermal Power-High Function trip setpoint.

Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO Two recirculation loops are normally required to be in operation with their recirculation pump speeds matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied.

Alternately, with only one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"),

MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"),

and APRM Simulated Thermal Power-High (continued)

Revision No.

25 1 Brunswick Unit I B 3.4-3

RCS Specific Activity B 3.4.6 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.6 RCS Specific Activity BASES BACKGROUND APPLICABLE SAFETY ANALYSES During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the reactor coolant and activation of corrosion products in the reactor coolant.

These radioactive materials in the reactor coolant can plate out in the RCS, and, at times, an accumulation will break away to spike the normal level of radioactivity.

The release of coolant during a Design Basis Accident (DBA) could send radioactive materials into the environment.

Limits on the maximum allowable level of radioactivity in the reactor coolant are established to ensure that in the event of a release of any radioactive material to the environment during a DBA, radiation doses are maintained within the limits of 10 CFR 50.67 (Ref.

1).

This LCO contains iodine specific activity limits.

The iodine isotopic activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT 1-131.

The allowable levels are intended to limit the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months radiation dose to an individual at the site boundary to a small fraction of the 10 CFR 50.67 limit.

Analytical methods and assumptions involving radioactive material in the primary coolant are presented in References 2 and 3.

The specific activity in the reactor coolant (the source term) is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside containment.

No fuel damage is postulated in the MSLB accident, and the release of radioactive material to the environment is assumed to end when the main steam isolation valves (MSIVs) close completely.

This MSLB release forms the basis for determining offsite doses (Ref. 2).

The limits on the specific activity of the primary coolant, assumed in the Reference 3 analyses, ensure (continued)

Revision No.

24 I Brunswick Unit 1 B 3.4-25

RCS Specific Activity B 3.4.6 BASES APPLICABLE that the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thyroid and whole body doses at the site SAFETY ANALYSES boundary, resulting from an MSLB outside containment during (continued) steady state operation, will not exceed 10% of the dose guidelines of 10 CFR 50.67.

RCS specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO The specific iodine activity is limited to

0.2 pCi/gm DOSE EQUIVALENT 1-131.

This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded, so any release of radioactivity to the environment during an MSLB is less than a small fraction of the 10 CFR 50.67 limits.

APPLICABILITY In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary containment.

In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an escape path does not exist.

In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced.

ACTIONS A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT 1-131 limit, but is : 4.0 pCi/gm, samples must be analyzed for DOSE EQUIVALENT 1-131 at least once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

In addition, the specific activity must be restored to the LCO limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The Completion Time of once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is based on the time needed to take and analyze a sample.

The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes or crud bursts) to be cleaned up with the normal processing systems.

The upper limit of 4.0 pCi/gm ensures that the thyroid dose from an MSLB will not exceed the dose guidelines of 10 CFR 50.67 or control room operator dose limits specified in GDC 19 of 10 CFR 50, Appendix A (Ref.

5).

(continued)

Revision No. 24 I B 3.4-26 Brunswick Unit I

RCS Specific Activity B 3.4.6 BASES ACTIONS A.1 and A.2 (continued)

A Note to the Required Actions of Condition A excludes the MODE change restriction of LCO 3.0.4.

This exception allows entry into the applicable MODE(S) while relying on the ACTIONS even though the ACTIONS may eventually require plant shutdown.

This exception is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to power operation.

B.1, B.2.1, B.2.2.1, and B.2.2.2 If the DOSE EQUIVALENT 1-131 cannot be restored to : 0.2 pCi/gm within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , or if at any time it is > 4.0 pCi/gm, it must be determined at least once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and all the main steam lines must be isolated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Isolating the main steam lines precludes the possibility of releasing radioactive material to the environment in an amount that is more than a small fraction of the requirements of 10 CFR 50.67 during a postulated MSLB I accident.

Alternatively, the plant can be placed in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within*36 hours.

This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads).

In MODE 4, the requirements of the LCO are no longer applicable.

The Completion Time of once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the time needed to take and analyze a sample.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to isolate the main steam lines in an orderly manner and without challenging plant systems.

Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for placing the unit in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

(continued)

Revision No. 24 1 Brunswick Unit I B 3.4-27

RCS Specific Activity B 3.4.6 BASES (continued)

SURVEILLANCE SR 3.4.6.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation.

The 7 day Frequency is adequate to trend changes in the iodine activity level.

This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.

REFERENCES

1.

10 CFR 50.67.

2.

UFSAR, Section 15.6.3.

3.

NEDC-32466P, Power Uprate Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2, dated September 1995.

4.

10 CFR 50.36(c)(2)(ii).

5.

10 CFR 50, Appendix A, GDC 19.

Revision No.

24 I I

Brunswick Unit I B 3.4-28

Primary Containment B 3.6.1.1 BASES BACKGROUND (continued)

APPLICABLE SAFETY ANALYSES are in conformance with 10 CFR 50, Appendix J, Option B (Ref. 3), as modified by exceptions listed in Specification 5.5.12, "Primary Containment Leakage Rate Testing Program."

The safety design basis for the primary containment is that it must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.

The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA.

In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.

Analytical methods and assumptions involving the primary containment are presented in References 1, 2, and 4.

The safety analyses assume a nonmechanistic fission product release following a DBA, which forms the basis for determination of offsite doses.

The fission product release is, in turn, based on an assumed leakage rate from the primary containment.

OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.

The maximum allowable leakage rate for the primary containment (L ) is 0.5% by weight of the containment air per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months at the maximum peak containment pressure (Pa) of 49 psig.

The value of P_ (49 psig) is conservative with respect to the current calculated peak drywell pressure of 46.4 psig (Ref. 4).

Primary containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO Primary containment OPERABILITY is maintained by limiting leakage to : 1.0 L, except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test.

At this time, the applicable leakage limits must be met.

In addition, the leakage from the drywell to the suppression chamber must be limited to ensure the pressure suppression function is accomplished and the suppression chamber pressure does not exceed design (continued)

Revision No.

25 I I

Brunswick Unit I B 3.6-2

Primary Containment B 3.6.1.1 BASES REFERENCES

4.

NEDC-33039P, Safety Analysis Report for Brunswick (continued)

Steam Electric Plant Units I and 2, Extended Power Uprate, August 2001.

5.

10 CFR 50.36(c)(2)(ii).

6.

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Rate Testing Program, September 1995.

7.

Nuclear Energy Institute (NEI) 94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR 50 Appendix J, July 26, 1995.

8.

ANSI/ANS 56.8-1994.

9.

NRC SER; Issuance of Amendment No.

181 to Facility Operating License No. DPR-71 and Amendment No. 213 to Facility Operating License No. DPR-62 Regarding 10 CFR 50 Appendix J, Option B - Brunswick Steam Electric Plant, Units 1 and 2 (BSEP 95-0316) (TAC Nos.

M93679 and M93680); dated February 1, 1996.

10.

Bechtel Topical Report BN-TOP-1, Revision 1, November 1, 1972.

11.

NRC SER, Exemption from the Requirements of Appendix J for Brunswick Steam Electric Plant, Units 1 and 2, dated February 17, 1988.

12.

NRC SER, Technical Exemption from the Requirements of Appendix J, dated May 12, 1987.

Revision No. 25 1 B 3.6-6 Brunswick Unit 1

PCIVs B 3.6.1.3 BASES SURVEILLANCE SR 3.6.1.3.3 (continued)

REQUIREMENTS administrative controls, such as those that limit the shelf life of the explosive charges, must be followed.

The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.

SR 3.6.1.3.4 Verifying the isolation time of each power operated and each automatic PCIV is within limits is required to demonstrate OPERABILITY.

MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.5.

The isolation time test ensures that each valve will isolate in a time period less than or equal to that assumed in the safety analyses.

The isolation time and Frequency of this SR are in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.5 Verifying that the isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY.

The isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA and transient analyses.

This ensures that the calculated radiological consequences of these events remain within 10 CFR 50.67 limits.

The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.

SR 3.6.1.3.6 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA.

This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal.

This SR includes verifying that each automatic PCIV in the Containment Atmosphere Dilution System flow path will actuate to its isolation position on the associated Group 2 and 6 primary containment isolation signals.

The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment Isolation (continued)

Revision No.

24 I B 3.6-26 Brunswick Unit I

Drywell Air Temperature B 3.6.1.4 BAS ES SURVEILLANCE REQUIREMENTS SR 3.6.1.4.1 (continued)

The following locations are monitored to obtain the drywell average temperature:

a.

Below 5 ft elevation;

b.

Between 10 ft and 23 ft elevation;

c.

Between 28 ft and 45 ft elevation;

d.

Between 70 ft and 80 ft elevation; and

e.

Above 90 ft elevation.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of the SR is based on operating experience related to drywell average air temperature variations and temperature instrument drift during the applicable MODES and the low probability of a DBA occurring between surveillances.

Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room to alert the operator to an abnormal drywell air temperature condition.

REFERENCES

1.

UFSAR, Section 6.2.

2.

GE-NE-A22-00113-22-01, Brunswick Nuclear Plant Units 1 and 2, Extended Power Uprate - Task T0400 - Containment System Response, May 2001.

3.

UFSAR, Section 6.2.1.1.1.

4.

10 CFR 50.36(c)(2)(ii).

Revision No.

25 1 Brunswick Unit I B 3.6-33

Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS E.1 and E.2 (continued)

If suppression pool average temperature cannot be maintained at

120°F, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the reactor pressure must be reduced to < 200 psig within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and the plant must be brought to at least MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

Continued addition of heat to the suppression pool with suppression pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure.

Furthermore, if a blowdown were to occur when the temperature was

> 120°F, the maximum allowable bulk and local temperatures could be exceeded very quickly.

SURVEILLANCE SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied.

The average temperature is determined using an algorithm with inputs from OPERABLE suppression pool water temperature channels.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown, based on operating experience, to be acceptable.

When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently.

The 5 minute Frequency during testing is justified by the rates at which tests will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeded.

The Frequencies are further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES

1. NEDC-33039P, Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2, Extended Power Uprate, August 2001.

2.

NUREG-0783.

3.

10 CFR 50.36(c)(2)(ii).

Revision No. 25 I Brunswick Unit 1 B 3.6-53

Suppression Pool Water Level B 3.6.2.2 BASES ACTIONS (continued)

B.I and B.2 If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

SURVEILLANCE SR 3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to ensure that the required limits are satisfied.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR has been shown to be acceptable based on operating experience.

Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.

REFERENCES

1.

UFSAR, Section 6.2.1.1.3.2.

2.

NEDC-33039P, Safety Analysis Report for Brunswick Steam Electric Plant Units I and 2, Extended Power Uprate, August 2001.

3.

10 CFR 50.36(c)(2)(ii).

Revision No. 25 1 Brunswick Unit I B 3.6-56

CAD System B 3.6.3.2 BASES ACTIONS B.1 (continued)

If Required Action A.1 cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 2 within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.2.1 REQUIREMENTS Verifying that there is a 4350 gal of liquid nitrogen supply in the CAD System will ensure at least 29 days of post-LOCA CAD operation.

This minimum volume of liquid nitrogen allows sufficient time after an accident to replenish the nitrogen supply for long term inerting.

This is verified every 31 days to ensure that the system is capable of performing its intended function when required.

The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on the availability of other hydrogen mitigating systems.

SR 3.6.3.2.2 Verifying the correct alignment for manual, power operated, and automatic valves in each of the CAD subsystem flow paths provides assurance that the proper flow paths exist for system operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis.

This is acceptable because the CAD System is manually initiated.

This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

(continued)

Revision No.

25 1 Brunswick Unit I B 3.6-67

Main Condenser Offgas B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Main Condenser Offgas BASES BACKGROUND During unit operation, steam from the low pressure turbine is exhausted directly into the main condenser.

Air and noncondensible gases are collected in the main condenser, then exhausted through the steam jet air ejectors (SJAEs) to the Main Condenser Offgas System.

The offgas from the main condenser normally includes radioactive gases.

The Main Condenser Offgas System for the purposes of this specification consists of the components in the following flow path from the main condenser SJAEs to the plant stack.

Offgas is discharged from the main condenser via the SJAEs and diluted with steam to keep hydrogen levels below explosive concentrations.

The offgas is then passed through an Offgas Recombiner System where hydrogen and oxygen are catalytically recombined into water.

After recombination, the offgas is routed to an offgas condenser to remove moisture.

The offgas then passes through a 30 minute delay pipe before entering the Augmented Offgas Charcoal Adsorber System.

The radioactivity of the offgas recombiner effluent is monitored downstream of the offgas condenser prior to entering the 30 minute delay pipe.

The Augmented Offgas Charcoal Adsorber System provides a long delay period for radioisotope decay as the offgas passes through the system.

Offgas exiting the Augmented Offgas Charcoal Adsorber System is routed to the plant stack for release to the environment.

APPLICABLE SAFETY ANALYSES The main condenser offgas gross gamma activity rate is an initial condition of the Main Condenser Offgas System failure event, discussed in the UFSAR, Section 11.3 (Ref.

1).

The analysis assumes a gross failure in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary.

The gross gamma activity rate is controlled to ensure that, during the event, the calculated offsite doses will be well within the limits of 10 CFR 50.67 (Ref. 2).

The main condenser offgas limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

(continued)

Revision No.

24 1 I

Brunswick Unit I B 3.7-33

Main Condenser Offgas B 3.7.5 BASES ACTIONS B.1, B.2, B.3.1, and B.3.2 (continued)

An alternative to Required Actions B.1 and B.2 is to place the unit in a MODE in which the LCO does not apply.

To achieve this status, the unit must be placed in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

SURVEILLANCE SR 3.7.5.1 REQUIREMENTS This SR, on a 31 day Frequency, requires an isotopic analysis of an offgas sample (taken at the discharge of the main condenser air ejector prior to dilution or discharge) to ensure that the required limits are satisfied.

The noble gases to be sampled are Xe-133, Xe-135, Xe-138, Kr-85m, Kr-87, and Kr-88.

If the measured rate of radioactivity increases significantly (by Ž 50% after correcting for expected increases due to changes in THERMAL POWER),

an isotopic analysis is also performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months after the increase is indicated (by the condenser air ejector noble gas activity monitor), to ensure that the increase is not indicative of a sustained increase in the radioactivity rate.

The 31 day Frequency is adequate in view of other instrumentation that continuously monitor the offgas, and is acceptable, based on operating experience.

This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation.

Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at significant rates.

REFERENCES

1.

UFSAR, Section 11.3.

2.

10 CFR 50.67.

3.

10 CFR 50.36(c)(2)(ii).

Revision No. 24 1 I

Brunswick Unit I B 3.7-35

Main Turbine Bypass System B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Main Turbine Bypass System BASES BACKGROUND APPLICABLE SAFETY ANALYSES The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown.

It allows excess steam flow from the reactor to the condenser without going through the turbine.

The bypass capacity of the system is 20.6% of the Nuclear Steam Supply System rated steam flow.

Sudden load reductions within the capacity of the steam bypass can be accommodated without reactor scram.

The Main Turbine Bypass System consists of four valves connected to the main steam lines between the main steam isolation valves and the turbine stop valves.

The bypass valves are controlled by the pressure regulation function of the Turbine Electro Hydraulic Control System, as discussed in the UFSAR, Section 7.7.1.4 (Ref.

1).

The bypass valves are normally closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine.

If the Speed Control System or load limit restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves.

When the bypass valves open, the steam flows through connecting piping and bypass valve pressure reducers to the condenser.

The Main Turbine Bypass System is assumed to function during the generator load rejection transient, the turbine trip transient, and the feedwater controller failure maximum demand transient, as described in the UFSAR, Section 15.2.1 (Ref. 2), Section 15.2.2 (Ref. 3), and Section 15.1.2 (Ref. 4).

Opening the bypass valves during the pressurization event mitigates the increase in reactor vessel pressure, which affects the MCPR during the event.

An inoperable Main Turbine Bypass System may result in APLHGR and MCPR penalties.

The Main Turbine Bypass System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

(continued)

Revision No. 25 I I

Brunswick Unit I B 3.7-36

Main Turbine Bypass System B 3.7.6 BASES (continued)

LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable limits during events that cause rapid pressurization, so that the Safety Limit MCPR is not exceeded.

With the Main Turbine Bypass System inoperable, modifications to the APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)")

and the MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)")

may be applied to allow this LCO to be met.

The APLHGR and MCPR limits for the inoperable Main Turbine Bypass System are specified in the COLR.

An OPERABLE Main Turbine Bypass System requires the minimum number of bypass valves, specified in the COLR, to open in response to increasing main steam line pressure.

This response is within the assumptions of the applicable analysis (Refs.

2, 3,

and 4).

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at

>-23% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the turbine generator load rejection transient.

As discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient margin to these limits exists at

< 23% RTP.

Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1 If the Main Turbine Bypass System is inoperable (one or more bypass valves as specified in the COLR inoperable), and the APLHGR and MCPR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not applied, the assumptions of the design basis transient analysis may not be met.

Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status or adjust the APLHGR and MCPR limits accordingly.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

(continued)

Brunswick Unit I B 3.7-37 Revision No.

25

Main Turbine Bypass System B 3.7.6 BASES ACTIONS B.1 (continued)

If the Main Turbine Bypass System cannot be restored to OPERABLE status and the APLHGR and MCPR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 23% RTP.

As discussed in the Applicability section, operation at < 23% RTP results in I sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the applicable safety analyses transients.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves are mechanically OPERABLE and will function when required.

The 31 day Frequency is based on manufacturer's recommendations (Ref.

6), is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

Operating experience has shown that these components usually pass the SR when performed at the 31 day Frequency.

Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.6.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function.

This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

(continued)

Revision No. 25 I Brunswick Unit I B 3.7-38

Control Rod Testing-Operating B 3.10.7 BASES APPLICABLE SAFETY ANALYSES (continued)

LCO As described in LCO 3.0.7, compliance with Special Operations LCOs is optional, and therefore, no criteria of 10 CFR 50.36(c)(2)(ii) (Ref. 2) apply.

Special Operations LCOs provide flexibility to perform certain operations by appropriately modifying requirements of other LCOs.

A discussion of the criteria satisfied for the other LCOs is provided in their respective Bases.

As described in LCO 3.0.7, compliance with this Special Operations LCO is optional.

Control rod testing may be performed in compliance with the prescribed sequences of LCO 3.1.6, and during these tests, no exceptions to the requirements of LCO 3.1.6 are necessary.

For testing performed with a sequence not in compliance with LCO 3.1.6, the requirements of LCO 3.1.6 may be suspended, provided additional administrative controls are placed on the test to ensure that the assumptions of the special safety analysis for the test sequence are satisfied.

Assurances that the test sequence is followed can be provided by either programming the test sequence into the RWM, with conformance verified as specified in SR 3.3.2.1.8 and allowing the RWM to monitor control rod withdrawal and provide appropriate control rod blocks if necessary, or by verifying conformance to the approved test sequence by a second licensed operator or other qualified member of the technical staff.

These controls are consistent with those normally applied to operation in the startup range as defined in the SRs and ACTIONS of LCO 3.3.2.1, "Control Rod Block Instrumentation."

APPLICABILITY Control rod testing, while in MODES I and 2, with THERMAL POWER greater than 8.75% RTP, is adequately controlled by the existing LCOs on power distribution limits and control rod block instrumentation.

Control rod movement during these conditions is not restricted to prescribed sequences and can be performed within the constraints of LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR),"

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"

and LCO 3.3.2.1.

With THERMAL POWER less than or equal to 8.75% RTP, the provisions of this Special Operations LCO are I necessary to perform special tests that are not in conformance with the prescribed sequences of LCO 3.1.6.

(continued)

Revision No.

25 1 Brunswick Unit I B 3.10-30

BSEP 02-0114, Submittal of Technical Specification Bases Changes Revisions 24 & 25

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