Text

Changes to Technical Specification Bases - Revisions 45 Through 49
	ML110750036
Person / Time
Site:	Wolf Creek
Issue date:	03/10/2011
From:	Sen G; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 11-0030
	Download: ML110750036 (71)
	v • d • e

WOLF CREEK NUCLEAR OPERATING CORPORATION Gautam Sen Manager Regulatory Affairs March 10, 2011 RA 11-0030 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Subject:

Docket No. 50-482: Wolf Creek Generating Station Changes to Technical Specification Bases - Revisions 45 through 49 Gentlemen:

The Wolf Creek Generating Station (WCGS) Unit 1 Technical Specifications (TS), Section 5.5.14, "Technical Specifications (TS) Bases Control Program," provide the means for making changes to the Bases without prior NRC approval. In addition, TS Section 5.5.14 requires that changes made without NRC approval be provided to the NRC on a frequency consistent with 10 CFR 50.71(e). The Enclosure provides those changes made to the WCGS TS Bases (Revisions 45 through 49) under the provisions of TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2010 through December 31, 2010.

This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4175.

Sincerely, Gautam Sen GS/rlt Enclosure cc: E. E. Collins (NRC), w/e G. B. Miller (NRC), w/e B. K. Singal (NRC), w/e Senior Resident Inspector (NRC), w/e 4oo(

P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET

Enclosure to RA 11-0030 Wolf Creek Generating Station Changes to the Technical Specification Bases (35 pages)

Rod Group Alignment Limits B 3.1.4 BASES APPLICABLE 2. Reactor Coolant System (RCS) pressure boundary SAFETY ANALYSES integrity; and (continued)

b. The core remains subcritical after accident transients.

Two types of misalignment are distinguished. During movement of a control rod group, one rod may stop moving, while the other rods in the group continue. This condition may cause excessive power peaking. The second type of misalignment occurs if one rod fails to insert upon a reactor trip and remains stuck fully withdrawn. This condition requires an evaluation to determine that sufficient reactivity worth is held in the control rods to meet the SDM requirement, with the maximum worth rod stuck fully withdrawn.

Two types of analysis are performed in regard to static rod misalignment (Ref. 3). With control banks at their insertion limits, one type of analysis considers the case when any one rod is completely inserted into the core.

The second type of analysis considers the case of a completely withdrawn single rod from bank D inserted to its insertion limit. Satisfying limits on departure from nucleate boiling ratio in both of these cases bounds the situation when a rod is misaligned from its group by 12 steps.

Another type of misalignment occurs if one RCCA fails to insert upon a reactor trip and remains stuck fully withdrawn. This condition is assumed in the evaluation to determine that the required SDM is met with the maximum worth RCCA also fully withdrawn (Ref. 3).

The Required Actions in this LCO ensure that either deviations from the alignment limits will be corrected or that THERMAL POWER will be adjusted so that excessive local linear heat rates (LHRs) will not occur, and that the requirements on SDM and ejected rod worth are preserved.

Continued operation of the reactor with a misaligned control rod is allowed if the heat flux hot channel factor (FQ(Z)) (and the nuclear enthalpy hot channel factor (FH) are verified to be within their limits in the COLR and the safety analysis is verified to remain valid. When a control rod is misaligned, the assumptions that are used to determine the rod insertion limits, AFD limits, and quadrant power tilt limits are not preserved.

Therefore, the limits may not preserve the design peaking factors, and FQ(Z) and FXH must be verified directly by core power distribution measurement. Bases Section 3.2 (Power Distribution Limits) contains more complete discussions of the relation of FQ(Z) and FXH to the operating limits.

Wolf Creek - Unit 1 B 3.1.4-3 Revision 48

Rod Group Alignment Limits B 3.1.4 BASES APPLICABLE Shutdown and control rod OPERABILITY and alignment are directly SAFETY ANALYSES related to power distributions and SDM, which are initial conditions (continued) assumed in safety analyses. Therefore they satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The limits on shutdown or control rod alignments ensure that the assumptions in the safety analysis will remain valid. The requirements on rod OPERABILITY ensure that upon reactor trip, the assumed reactivity will be available and will be inserted. The rod OPERABILITY requirements are separate from the alignment requirements which ensure that the RCCAs and banks maintain the correct power distribution and rod alignment. The rod OPERABILITY requirement is satisfied provided the rod is trippable and meets the rod drop time requirements of SR 3.1.4.3.

Rod control malfunctions that result in the inability to move a rod (i.e. rod lift coil failures), but that do not impact trippability, do not necessarily result in rod inoperability.

The requirement to maintain the rod alignment to within plus or minus 12 steps of their group step counter demand position is conservative. The minimum misalignment assumed in safety analysis is 24 steps (15 inches), and in some cases a total misalignment from fully withdrawn to fully inserted is assumed.

Failure to meet the requirements of this LCO may produce unacceptable power peaking factors and LHRs, or unacceptable SDMs, all of which may constitute initial conditions inconsistent with the safety analysis.

APPLICABILITY The requirements on RCCA OPERABILITY and alignment are applicable in MODES 1 and 2 because these are the only MODES in which neutron (or fission) power is generated, and the OPERABILITY (i.e., trippability) and alignment of rods have the potential to affect the safety of the plant.

In MODES 3, 4, 5, and 6, the alignment limits do not apply because the reactor is shut down and not producing fission power, and verification of SDM is not dependent upon verification of rod insertion limits as in MODES 1 and 2. In the shutdown MODES, the OPERABILITY of the shutdown and control rods has the potential to affect the required SDM, but this effect can be compensated for by an increase in the boron concentration of the RCS. See LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," for SDM in MODES 3, 4, and 5 and LCO 3.9.1, "Boron Concentration," for boron concentration requirements during refueling.

Wolf Creek - Unit 1 B 3.1.4-4 Revision 0

Rod Group Alignment Limits B 3.1.4 BASES ACTIONS A. 1.1 and A. 1.2 When one or more rods are inoperable, there is a possibility that the required SDM may be adversely affected. Under these conditions, it is important to determine the SDM, and if it is less than the required value, initiate boration until the required SDM is recovered. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is adequate for determining SDM and, if necessary, aligning and starting the necessary systems and components to initiate boration.

In this situation, SDM verification must include the worth of the untrippable rod, as well as a rod of maximum worth.

A.2 If the inoperable rod(s) cannot be restored to OPERABLE status, the plant must be brought to a MODE or condition in which the LCO requirements are not applicable. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The allowed Completion Time is reasonable, based on operating experience, for reaching MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

B..1 When a rod becomes misaligned, it can usually be moved and is still trippable. If the rod can be realigned within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , local xenon redistribution during this short interval will not be significant, and operation may proceed without further restriction.

An alternative to realigning a single misaligned RCCA to the group demand position is to align the remainder of the group to the position of the misaligned RCCA. However, this must be done without violating the bank sequence, overlap, and insertion limits specified in LCO 3.1.5, "Shutdown Bank Insertion Limits," and LCO 3.1.6, "Control Bank Insertion Limits." The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months gives the operator sufficient time to adjust the rod positions in an orderly manner.

Wolf Creek - Unit 1 B 3.1.4-5 Revision 0

Rod Group Alignment Limits B 3.1.4 BASES ACTIONS B.2.1.1 and B.2.1.2 (continued)

With a misaligned rod, SDM must be verified to be within limit or boration must be initiated to restore SDM to within limit.

In many cases, realigning the remainder of the group to the misaligned rod may not be desirable. For example, realigning control bank B to a rod that is misaligned 15 steps from the top of the core would require a significant power reduction, since control bank D must be fully inserted and control bank C must be inserted to approximately 100 steps in order to maintain proper overlap.

Power operation may continue with one RCCA OPERABLE but misaligned, provided that SDM is verified within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months represents the time necessary for determining the actual unit SDM and, if necessary, aligning and starting the necessary systems and components to initiate boration.

B.2.2, B.2.3. B.2.4, B.2.5, and B.2.6 For continued operation with a misaligned rod, reactor power must be reduced, SDM must periodically be verified within limits, hot channel factors (FQ(Z) and FýH) must be verified within limits, and the safety analyses must be re-evaluated to confirm continued operation is permissible.

Reduction of power to 75% RTP ensures that local LHR increases due to a misaligned RCCA will not cause the core design criteria to be exceeded (Ref. 4). The Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months gives the operator sufficient time to accomplish an orderly power reduction without challenging the Reactor Protection System.

When a rod is known to be misaligned, there is a potential to impact the SDM. Since the core conditions can change with time, periodic verification of SDM is required. A Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient to ensure this requirement continues to be met.

Verifying that FQ(Z) and FH are within the required limits ensures that current operation at 75% RTP with a rod misaligned is not resulting in power distributions that may invalidate safety analysis assumptions at full power. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allows sufficient time to obtain core power distribution measurements using either the incore flux mapping system or the Power Distribution Monitoring System and to calculate FQ(Z) and F,..

Wolf Creek - Unit 1 B 3.1.4-6 Revision 48

Rod Position Indication B 3.1.7 BASES LCO These requirements ensure that rod position indication during power (continued) operation and startup are accurate, and that, design assumptions are not challenged. OPERABILITY of the position indicator channels ensures that inoperable, misaligned, or mispositioned rods can be detected.

Therefore, power peaking, ejected rod worth, and SDM can be controlled within acceptable limits.

APPLICABILITY The requirements on the DRPI and step counters are only applicable in MODES 1 and 2 (consistent with LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6),

because these are the only MODES in which power is generated, and the OPERABILITY and alignment of rods have the potential to affect the safety of the plant. In the shutdown MODES, the OPERABILITY of the shutdown and control banks has the potential to affect the required SDM, but this effect can be compensated for by an increase in the boron concentration of the Reactor Coolant System.

ACTIONS The ACTIONS table is modified by a Note indicating that a separate Condition entry is allowed for each inoperable rod position indicator and each demand position indicator. This is acceptable because the Required Actions for each Condition provide appropriate compensatory actions for each inoperable position indicator.

A.1 When one DRPI per group fails, the position of the rod may still be determined indirectly by core power distribution measurement using either the movable incore detectors or the Power Distribution Monitoring System.

Based on experience, normal power operation does not require excessive movement of banks. If a bank has been significantly moved, the Required Action of C.1 or C.2 below is required. Therefore, verification of RCCA position within the Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is adequate for allowing continued full power operation, since the probability of simultaneously having a rod significantly out of position and an event sensitive to that rod position is small.

A.2 Reduction of THERMAL POWER to _ 50% RTP puts the core into a condition where rod position is not significantly affecting core peaking factors (Ref. 2).

Wolf Creek - Unit 1 B 3.1.7-3 Revision 48

Rod Position Indication B 3.1.7 "BASES ACTIONS A.2 (continued)

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, for reducing power to _ 50% RTP from full power conditions without challenging plant systems and allowing for rod position determination by Required Action A.1 above.

B.1. B.2, B.3 and B.4 .

Placing the Rod Control System in manual assures unplanned rod motion will not occur. The Immediate Completion Time for placing the Rod Control System in manual reflects the urgency with which unplanned rod motion must be prevented while in this Condition. Monitoring and recording Reactor Coolant System Tavg help to assure that significant changes in power distribution and SDM are avoided. The once per hour Completion Time is acceptable because only minor fluctuations in RCS temperature are expected at steady state plant operating conditions.

When more than one DRPI per group fails, the position of the rod(s) can still be determined indirectly by core power distribution measurement using either the movable incore detectors or the Power Distribution Monitoring System. Based on experience, normal power operation does not require excessive movement of banks. If one or more banks has been significantly moved, the Required Action of C.1 or C.2 is required.

Therefore, verification of RCCA position within the Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is adequate for allowing continued full power operation for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months since the probability of simultaneously having a rod significantly out of position and an event sensitive to that position is small.

C.1 and C.2 These Required Actions clarify that when one or more rods with inoperable DRPIs have been moved in excess of 24 steps in one direction, since the position was last determined, the Required Actions of A.1 and B.1, as applicable, are still appropriate but must be initiated promptly under Required Action C.1 to begin indirectly verifying that these rods are still properly positioned, relative to their group positions.

If, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the rod positions have not been determined, THERMAL POWER must be reduced to <_50% RTP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to avoid undesirable power distributions that could result from continued operation at > 50% RTP, if one or more rods are misaligned by more than 24 steps.

Wolf Creek - Unit 1 B 3.1.7-4 Revision 48

Rod Position Indication B 3.1.7 BASES ACTIONS C.1 and C.2 (continued)

The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months provides an acceptable period of time to verify the rod positions using either the movable incore detectors or the Power Distribution Monitoring System.

D.1.1 and D.1.2 With one demand position indicator per bank inoperable, the rod positions can be determined by the DRPI System. Since normal power operation does not require excessive movement of rods, verification by administrative means that the rod position indicators are OPERABLE and the most withdrawn rod and the least withdrawn rod within each affected bank are < 12 steps apart within the allowed Completion Time of once every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is adequate.

D.2 Reduction of THERMAL POWER to_< 50% RTP puts the core into a condition where rod position is not significantly affecting core peaking factors. The allowed Completion Time of 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months s-provides an acceptable period of time to verify the rod positions per Required Actions D.1.1 and D.1.2 or reduce power to _<50% RTP.

E.1 If the Required Actions cannot be co mplete'd within the associated Completion Time, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months s: The allowed Completion Time is reasonable, based on operating experience, for reaching the required MODE from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.7.1 REQUIREMENTS Verification that the DRPI agrees with the demand position within 12 steps ensures that the DRPI is operating correctly. Verification at 24, 48, 120, and 228 steps withdrawn for the control banks and at 18, 210, and 228 steps withdrawn for the shutdown banks provides assurance that the DRPI is operating correctly over the full range of indication. Since the DRPI does not display the actual shutdown rod positions between 18 and Wolf Creek - Unit 1 B 3.1.7-5 Revision 48

Rod Position Indication B 3.1.7 BASES SURVEILLANCE SR 3.1.7.1 (continued)

REQUIREMENTS 210 steps, only points within the indicated ranges are required in comparison.

This surveillance is performed prior to reactor criticality after each removal of the reactor head as there is the potential for unnecessary plant transients if the SR were performed with the reactor at power.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 13.

2. USAR, Chapter 15.

Wolf Creek - Unit 1 B 3.1.7-6 Revision 0

FQ(Z) (FQ Methodology)

B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 Heat Flux Hot Channel Factor (FQ(Z)) (Fa Methodology)

BASES BACKGROUND The purpose of the limits on the values of F,(Z) is to limit the local (i.e., pellet) peak power density. The value of FQ(Z) varies along the axial height (Z) of the core.

FQ(Z) is defined as the maximum local fuel rod linear power density divided by the average fuel rod linear power density, assuming nominal fuel pellet and fuel rod dimensions. Therefore, FQ(Z) is a measure of the peak fuel pellet power within the reactor core.

During power operation, the global power distribution is limited by LCO 3.2.3, "AXIAL FLUX DIFFERENCE (AFD)," and LCO 3.2.4, "QUADRANT TILT POWER RATIO (QPTR)," which are directly and continuously measured process variables. These LCOs, along with LCO 3.1.4, "Rod Group Alignment Limits," LCO 3.1.5, "Shutdown Bank Insertion Limits," and LCO 3.1.6, "Control Bank Insertion Limits," maintain the core limits on power distributions on a continuous basis.

FQ(Z) varies with fuel loading patterns, control bank insertion, fuel bumup, and changes in axial power distribution.

FQ(Z) is not directly measurable but is inferred from a power distribution measurement obtained with either the movable incore detector system or the Power Distribution Monitoring System (PDMS). The results of the three-dimensional power distribution measurement are analyzed to derive a measured value for FQ(Z). These measurements are generally taken with the core at or near equilibrium conditions. However, because this value represents an equilibrium condition, it does not include the variations in the value of FQ(Z) that are present during nonequilibrium situations, such as load following.

To account for these possible variations, the steady state value of FQ(Z) is adjusted by an elevation dependent factor that accounts for the calculated worst case transient conditions.

Core monitoring and control under nonsteady state conditions are accomplished by operating the core within the limits of the appropriate LCOs, including the limits on AFD, QPTR, and control rod insertion.

Wolf Creek - Unit I B 3.2.1 -1 Revision 48

FQ(Z) (FQ Methodology)

B 3.2.1 BASES APPLICABLE This LCO precludes core power distributions that violate the following fuel SAFETY ANALYSES design criteria:

a. During a large break loss of coolant accident (LOCA), the peak cladding temperature must not exceed 2200°F (Ref. 1);

b. During a loss of forced reactor coolant flow accident, there must be at least 95% probability at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel rod in the core does not experience a departure from nucleate boiling (DNB) condition;

c. During an ejected rod accident, the average fuel pellet enthalpy at the hot spot in irradiated fuel must not exceed 200 cal/gm (Ref. 2);

and

d. The control rods must be capable of shutting down the reactor with a minimum required SDM with the highest worth control rod stuck fully withdrawn (Ref. 3).

Limits on FQ(Z) ensure that the value of the initial total peaking factor assumed in the accident analyses remains valid. Other criteria must also be met (e.g., maximum cladding oxidation, maximum hydrogen generation, coolable geometry, and long term cooling). However, the LOCA peak cladding temperature is typically most limiting.

FQ(Z) limits assumed in the LOCA analysis are typically limiting relative to (i.e., lower than) the FQ(Z) limit assumed in safety analyses for other postulated accidents. Therefore, this LCO provides conservative limits for other postulated accidents.

FQ(Z) satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The Heat Flux Hot Channel Factor, FQ(Z), shall be limited by the following relationships:

RQ( Z )- CFQ K(Z) for P > 0.5 P

Fo ( Z )!5 CFQ KK(Z) for P! _0.5

0.5 where

CFQ = FQRTP is the FQ(Z) limit at RTP provided in the COLR, Wolf Creek - Unit I B 3.2.1-2 Revision 0

FQ(Z) (FQ Methodology)

B 3.2.1 BASES LCO K(Z) is the normalized FQ(Z) as a function of core height provided in the (continued) COLR, and P THERMAL POWER RTP The actual values of CFQ and K(Z) are given in the COLR.

For Relaxed Axial Offset Control operation, FQ(Z) is approximated by FQc(Z) and FQw(Z). Thus, both Fac(Z) and FQ (Z) must meet the preceding limits on FQ(Z).

An Fac(Z) evaluation requires obtaining a power distribution measurement in MODE 1, from which we obtain the measured value (FaM(Z)) of FQ(Z).

If the power distribution measurement is obtained with the movable incore detector system, FQc(Z) = FQM(Z) (1.03) (1.05) = FQM(Z) (1.0815) (Eq. 1) where 1.03 is a factor that accounts for fuel manufacturing tolerances and 1.05 is a factor that accounts for flux map measurement uncertainty.

(Ref. 4)

If the power distribution measurement is obtained with the Power Distribution Monitoring System, FQC(Z) = FQM(Z) (1.03) (1.00 + Ua/1 00) where 1.03 is a factor that accounts for fuel manufacturing tolerances and Ua is a factor that accounts for Power Distribution Monitoring System measurement uncertainty (%), determined as described in Reference 6.

FaC(Z) is an excellent approximation for FQ(Z) when the reactor is at the steady state power at which the power distribution measurement was taken.

The expression for FaW(Z) is:

F0 w(Z) = F0 c(Z) W(Z) where FQc(Z) is per Eq. 1 and W(Z) is a cycle dependent function that accounts for power distribution transients encountered during normal operation. W(Z) information is included in the COLR. For the PDMS, FaM(Z) reflects the measured power distribution at HFP, ARO, equilibrium Xe conditions.

Wolf Creek - Unit I B 3.2.1-3 Revision 48

FQ(Z) (FQ Methodology)

B 3.2.1 BASES LCO The Fa(Z) limits define limiting values for core power peaking that (continued) precludes peak cladding temperatures above 2200°F during either a large or small break LOCA.

This LCO requires operation within the bounds assumed in the safety analyses. Calculations are performed in the core design process to confirm that the core can be controlled in such a manner during operation that it can stay within the LOCA FQ(Z) limits. If FQ(Z) cannot be maintained within the LCO limits, reduction of the core power is required.

Violating the LCO limits for F,(Z) may produce unacceptable consequences if a design basis event occurs while F,(Z) is outside its specified limits.

APPLICABILITY The FQ(Z) limits must be maintained in MODE 1 to prevent core power distributions from exceeding the limits assumed in the safety analyses.

Applicability in other MODES is not required because there is either insufficient stored energy in the fuel or insufficient energy being transferred to the reactor coolant to require a limit on the distribution of core power.

ACTIONS A.1 Reducing THERMAL POWER by _ 1% RTP for each 1% by which Fac(Z) exceeds its limit, maintains an acceptable absolute power density. Fac(Z) is FQM(Z) multiplied by factors which account for manufacturing tolerances and measurement uncertainties. FQM(Z) is the measured value of FQ(Z).

The Completion Time of 15 minutes provides an acceptable time to reduce power in an orderly manner and without allowing the plant to remain in an unacceptable condition for an extended period of time. The maximum allowable power level initially determined by Required Action A.1 may be affected by subsequent determinations of FQc(Z) and would require power reductions within 15 minutes of the FaC(Z) determination, if necessary to comply with the decreased maximum allowable power level.

Decreases in FQC(Z) would allow increasing the maximum allowable power level and increasing power up to this revised limit.

Calculate the percent FQC(Z) exceeds its limit by the following expression:

over Z

[ FQC CFQ X K(Z)

-1 X 100 forP___0.5 L maximum p JJ Wolf Creek - Unit I B 3.2.1-4 Revision 48 1

FQ(Z) (Fo Methodology)

B 3.2.1 BASES ACTIONS A.1 (continued) maximum

{over Z

[ FQc(Z)

CFQ X 1 0.5 J) 1 1(Z J

X 100 for P < 0.5 A.2 A reduction of the Power Range Neutron Flux - High trip setpoints by _ 1%

for each 1% by which F0 c(Z) exceeds its limit, is a conservative action for protection against the consequences of severe transients with unanalyzed power distributions. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is sufficient considering the small likelihood of a severe transient in this time period and the preceding prompt reduction in THERMAL POWER in accordance with Required Action A.1. The maximum allowable Power Range Neutron Flux - High trip setpoints initially determined by Required Action A.2 may be affected by subsequent determinations of FQc(Z) and would require Power Range Neutron Flux - High trip setpoint reductions within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of FQc(Z) determination, if necessary to comply with the decreased maximum allowable Power Range Neutron Flux - High trip setpoints.

A.3 Reduction in the Overpower AT trip setpoints by _ 1% for each 1% by which Fac(Z) exceeds its limit, is a conservative action for protection against the consequences of severe transients with unanalyzed power distributions. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is sufficient considering the small likelihood of a severe transient in this time period, and the preceding prompt reduction in THERMAL POWER in accordance with Required Action A.1. The maximum allowable Overpower AT trip setpoints initially determined by Required Action A.3 may be affected by subsequent determinations of Fac(Z) and would require Overpower AT trip setpoint reductions within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of the FQc(Z) determination, if necessary to comply with the decreased maximum allowable Overpower AT trip setpoints. Decreases in Fac(Z) would allow increasing the maximum Overpower AT trip setpoints.

A.4 Verification that Fac(Z) has been restored to within its limit, by performing SR 3.2.1.1 prior to increasing THERMAL POWER above the limit Wolf Creek - Unit 1 B 3.2.1-5 Revision 48 1

FQ(Z) (FQ Methodology)

B 3.2.1 BASES ACTIONS A. 4 (continued) imposed by Required Action A.1, ensures that core conditions during operation at higher power levels are consistent with safety analyses assumptions. Inherent in this action is identification of the cause of the out of limit condition and the correction of the cause to the extent necessary to allow safe operation at the higher power level.

B.1 If it is found that the maximum calculated value of FQ(Z) that can occur during normal maneuvers, Faw(Z), exceeds its specified limits, thee exists a potential for Fac(Z) to become excessively high if a normal operational transient occurs. Tightening both the positive and negative AFD limits by

Ž_1% for each 1% by which FQw(Z) exceeds its limit within the allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , restricts the axial flux distribution such that even if a transient occurred, core peaking factors are not exceeded.

Calculate the percent FaW(Z) exceeds its limit by the following expression:

L 1 I

I [ II }

(Z)X W(Z)

CýFQ X K(Z)I pP FC-(Z) X W(Z)

I =1}

-1 X 100 forP _0.5 X 100 forP < 0.5 CF-Q X K(Z) 0.5 C.A If Required Actions A.1 through A.4 or B.1 are not met within their associated Completion Times, the plant must be placed in a mode or condition in which the LCO requirements are not applicable. This is done by placing the plant in at least MODE 2 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

This allowed Completion Time is reasonable based on operating experience regarding the amount of time it takes to reach MODE 2 from full power operation in an orderly manner and without challenging plant systems.

Wolf Creek - Unit I B 3.2.1-6 Revision 48 1

FQ(Z) (FQ Methodology)

B 3.2.1 BASES SURVEILLANCE SR 3.2.1.1 and SR 3.2.1.2 are modified by a Note. The Note applies REQUIREMENTS during power ascensions following a plant shutdown (leaving MODE 1).

The Note allows for power ascensions ifthe surveillances are not current.

It states that THERMAL POWER may be increased until an equilibrium power level (i.e., equilibrium conditions) has been achieved at which a power distribution measurement can be obtained. This allowance is I modified,however, by one of the Frequency conditions that requires verification that Fac(Z) and Faw(Z) are within their specified limits after a power rise of more than 10% RTP over the THERMAL POWER at which theya were last verified to be within specified limits. Because FQc(Z) and Fa (Z) could not have previously been measured in a reload core, there is a second Frequency condition, applicable only for reload cores, that requires determination of these parameters before exceeding 75% RTP.

This ensures that some determination of FQc(Z) and Faw(Z) are made at a lower power level at which adequate margin is available before going to 100% RTP. Also, this Frequency condition, together with the Frequency condition requiring verification of FQc(Z) and FQw(Z) following a power increase of more than 10%, ensures that they are verified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months from when equilibrium conditions are achieved at RTP (or any other level for extended operation). Equilibrium conditions are achieved when the core is sufficiently stable at the intended operating conditions to perform a power distribution measurement. In the absence of these Frequency conditions, it is possible to increase power to RTP and operate for 31 days without verification of FQc(Z) and Faw(Z). The Frequency condition is not intended to require verification of these parameters after every 10% increase in power level above the last verification. Itonly requires verification after a power level is achieved for extended operation that is 10% higher than that power at which F. was last measured.

SR 3.2.1.1 Verification that Foc(Z) is within its specified limits involves increasing FQM(Z) to allow for manufacturing tolerance and measurement uncertainties in order to obtain FQc(Z), as described in the preceeding LCO section.

The limit with which FQc(Z) is compared varies inversely with power above 50% RTP and directly with a function called K(Z) provided in the COLR.

Performing this Surveillance in MODE 1 prior to exceeding 75% RTP ensures that the Fac(Z) limit is met when RTP is achieved, because peaking factors generally decrease as power level is increased.

Wolf Creek - Unit 1 B 3.2.1-7 Revision 48

FQ(Z) (FQ Methodology)

B 3.2.1 BASES SURVEILLANCE SR 3.2.1.1 (continued)

REQUIREMENTS If THERMAL POWER has been increased by _ 10% RTP since the last determination of Fac(Z), another evaluation of this factor is required within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions at this higher power level (to ensure that FQc(Z) values are being reduced sufficiently with power increase to stay within the LCO limits).

The Frequency of 31 EFPD is adequate to monitor the change of power distribution with core bumup because such changes are slow and well controlled when the plant is operated in accordance with the Technical Specifications (TS).

SR 3.2.1.2 The nuclear design process includes calculations performed to determine that the core can be operated within the FQ(Z) limits. Because power distribution measurements are taken at or near equilibrium conditions, the variations in power distribution resulting from normal operational maneuvers are not present in the measurements. These variations are, however, conservatively calculated by considering a wide range of unit maneuvers in normal operation. The maximum peaking factor increase over steady state values, calculated as a function of core elevation, Z, is called W(Z). Multiplying the measured total peaking factor, Fac(Z), by W(Z) gives the maximum FQ(Z) calculated to occur in normal operation, Fow(Z).

The limit with which Faw(Z) is compared varies inversely with power and directly with the function K(Z) provided in the COLR.

The W(Z) are provided for discrete core elevations. Flux map data are typically taken for 30 to 75 core elevations. Faw(Z) evaluations are not applicable for the following axial core regions, measured in percent of core height:

a. Lower core region, from 0 to 15% inclusive; and

b. Upper core region, from 85 to 100% inclusive.

The amount of the axial core region that can be excluded during the performance of SR 3.2.1.2 shall not exceed 15% of the upper and lower core regions, and may be reduced on a cycle-specific basis as determined during the core reload design process. The amount of the axial core region that can be excluded during the performance of SR 3.2.1.2 is identified in the COLR. The axial core regions are excluded from the evaluation because of the low probability that these regions would be more limiting in the safety analyses and because of the difficulty of making Wolf Creek - Unit I B 3.2.1-8 Revision 48

FQ(Z) (FQ Methodology)

B 3.2.1 BASES SURVEILLANCE SR 3.2.1.2 (continued)

REQUIREMENTS a precise measurement in these regions. It should be noted that while the transient Fa(Z) limits are not measured in these axial core regions, the analytical transient FQ(Z) limits in these axial core regions are demonstrated to be satisfied during the core reload design process.

This Surveillance has been modified by a Note that may require more frequent surveillances be performed. When Fac(Z) is measured, an evaluation of the expression below is required to account for any increase to FQ(Z) that may occur and cause the FQ(Z) limit to be exceeded before the next required FQ(Z) evaluation.

If the two most recent FQ(Z) evaluations show an increase in the expression

[z~ z maximum over z it is required to meet the FQ(Z) limit with the last FQw(Z) increased by the appropriate factor specified in the COLR, or to evaluate FQ(Z) more frequently, each 7 EFPD. These alternative requirements prevent FQ(Z) from exceeding its limit for any significant period of time without detection.

Performing the Surveillance in MODE 1 prior to exceeding 75% RTP ensures that the FQ(Z) limit will be met when RTP is achieved, because peaking factors are generally decreased as power level is increased.

FQ(Z) is verified at power levels > 10% RTP above the THERMAL POWER of its last verification, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions to ensure that F,(Z) is within its limit at higher power levels.

The Surveillance Frequency of 31 EFPD is adequate to monitor the change of power distribution with core burnup. The Surveillance may be done more frequently if required by the results of FQ(Z) evaluations.

The Frequency of 31 EFPD is adequate to monitor the change of power distribution because such a change is sufficiently slow, when the plant is operated in accordance with the TS, to preclude adverse peaking factors between 31 day surveillances.

Wolf Creek - Unit 1 B 3.2.1-9 Revision 29

FQ(Z) (FQ Methodology)

B 3.2.1 BASES REFERENCES 1. 10 CFR 50.46, 1974.

2. USAR, Section 15.4.8.

3. 10 CFR 50, Appendix A, GDC 26.

4. WCAP-7308-L-P-A, "Evaluation of Nuclear Hot Channel Factor Uncertainties," June 1988.

5. Performance Improvement Request 2005-3311.

6. WCAP-12472-P-A, "BEACON Core Monitoring and Operations Support System," August 1994 (including Addendum 1-A, January 2000).

Wolf Creek - Unit 1 B 3.2.1 -10 Revision 48

FL.

B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 Nuclear Enthalpy Rise Hot Channel Factor (FXH)

BASES BACKGROUND The purpose of this LCO is to establish limits on the power density at any point in the core so that the fuel design criteria are not exceeded and the accident analysis assumptions remain valid. The design limits on local (pellet) and integrated fuel rod peak power density are expressed in terms of hot channel factors. Control of the core power distribution with respect to these factors ensures that local conditions in the fuel rods and coolant channels do not challenge core integrity at any location during either normal operation or a postulated accident analyzed in the safety analyses.

FNAH is defined as the ratio of the integral of the linear power along the fuel rod with the highest integrated power to the average integrated fuel rod power. Therefore, FNA His a measure of the maximum total power produced in a fuel rod.

FXH is sensitive to fuel loading patterns, bank insertion, and fuel bumup.

FNAH is not directly measurable but is inferred from a power distribution measurement obtained with either the movable incore detector system or the Power Distribution Monitoring System. Specifically, the results of the three dimensional power distribution measurement are analyzed to determine FH . This factor is calculated at least every 31 EFPD.

However, during power operation, the global power distribution is monitored by LCO 3.2.3, "AXIAL FLUX DIFFERENCE (AFD)," and LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)," which address directly and continuously measured process variables. Compliance with these LCOs, along with the LCOs governing shutdown and control rod insertion and alignment, maintains the core limits on power distribution on a continuous basis.

The COLR provides peaking factor limits that ensure that the design basis value of the departure from nucleate boiling (DNB) is met for normal operation, operational transients, and any transient condition arising from events of moderate frequency. All DNB limited transient events are assumed to begin with an FNA value that satisfies the LCO requirements.

Operation outside the LCO limits may produce unacceptable consequences if a DNB limiting event occurs. The DNB design basis ensures that there is no overheating of the fuel that results in possible Wolf Creek - Unit 1 B 3.2.2-1 Revision 48

B 3.2.2 BASES BACKGROUND cladding perforation with the release of fission products to the reactor (continued) coolant.

APPLICABLE Limits on FL preclude core power distributions that exceed the SAFETY ANALYSES following fuel design limits:

a. There must be at least 95% probability at the 95% confidence level (the 95/95 DNB criterion) that the hottest fuel rod in the core does not experience a DNB condition;

b. During a large break loss of coolant accident (LOCA), peak cladding temperature (PCT) must not exceed 2200°F;

c. During an ejected rod accident, the average fuel pellet enthalpy at the hot spot in irradiated fuel must not exceed 200 cal/gm (Ref. 1);

and

d. Fuel design limits required by GDC 26 (Ref. 2) for the condition when control rods must be capable of shutting down the reactor with a minimum required SDM with the highest worth control rod stuck fully withdrawn.

For transients that may be DNB limited, the Reactor Coolant System flow and FL are the core parameters of most importance. The limits on FX ensure that the DNB design basis is met for normal operation, operational transients, and any transients arising from events of moderate frequency.

The DNB design basis is met by limiting the minimum DNBR to the 95/95 DNB criterion applicable to a specific DNBR correlation. This value provides a high degree of assurance that the hottest fuel rod in the core does not experience a DNB condition.

The allowable FL limit increases with decreasing power level. This functionality in FJ is included in the analyses that provide the Reactor Core Safety Limits (SLs) of SL 2.1.1. Therefore, any DNB events in which the calculation of the core limits is modeled implicitly use this variable value of FL in the analyses. Likewise, all transients that may be DNB limited are assumed to begin with an initial FI as a function of power level defined by the COLR limit equation.

The LOCA safety analysis indirectly models FL as an input parameter.

The Nuclear Heat Flux Hot Channel Factor (FQ(Z)) and the axial peaking factors are inserted directly into the LOCA safety analyses that verify the Wolf Creek - Unit 1 B 3.2.2-2 Revision 0

FXH B 3.2.2 BASES APPLICABLE acceptability of the resulting peak cladding temperature (Ref. 3).

SAFETY ANALYSES (continued) The fuel is protected in part by Technical Specifications, which ensure that the initial conditions assumed in the safety and accident analyses remain valid. The following LCOs ensure this: LCO 3.2.3, "AXIAL FLUX DIFFERENCE (AFD)," LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)," LCO 3.1.6, "Control Bank Insertion Limits," LCO 3.2.2, "Nuclear Enthalpy Rise Hot Channel Factor (FNAH )," and LCO 3.2.1, "Heat Flux Hot Channel Factor (FQ(Z))."

FNAH and FQ(Z) are measured periodically using either the movable incore detector system or the Power Distribution Monitoring System.

Measurements are generally taken with the core at, or near, steady state conditions. Core monitoring and control under transient conditions (Condition I events) are accomplished by operating the core within the limits of the LCOs on AFD, QPTR, and Bank Insertion Limits.

FXH satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO FNAH shall be maintained within the limits of the relationship provided in the COLR.

The FNAH limit is representative of the coolant flow channel with the maximum enthalpy rise. This channel has the least heat removal capability and thus the highest probability for a DNB.

The limiting value of FNAH , described by the equation contained in the COLR, is the design radial peaking factor used in the unit safety analyses.

A power multiplication factor in this equation includes an additional allowance for higher radial peaking from reduced thermal feedback and greater control rod insertion at low power levels. The limiting value of FNAH is allowed to increase by a cycle-dependent factor, PFAH, specified in the COLR for each 1% RTP reduction in THERMAL POWER.

APPLICABILITY The FNAH limits must be maintained in MODE 1 to preclude core power distributions from exceeding the fuel design limits for DNBR and PCT.

Applicability in other modes is not required because there is either insufficient stored energy in the fuel or insufficient energy being transferred to the coolant to require a limit on the distribution of core power.

Wolf Creek - Unit 1 B 3.2.2-3 Revision 48

FXH B 3.2.2 BASES ACTIONS A.1.1 With FNAH exceeding its limit, the unit is allowed 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to restore FNAH to within its limits. This restoration may, for example, involve realigning any misaligned rods or reducing power enough to bring FNAJ within its power dependent limit. When the FN AH limit is exceeded, the DNBR limit is not likely violated in steady state operation, because events that could significantly perturb the FNAH value (e.g., static control rod misalignment) are considered in the safety analyses. However, the DNBR limit may be violated if a DNB limiting event occurs. Thus, the allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months provides an acceptable time to restore FNAH to within its limits without allowing the plant to remain in an unacceptable condition for an extended period of time. The restoration of the peaking factor to within its limits by power reduction or control rod movement does not restore compliance with the LCO. Thus, this condition can not be exited until a valid surveillance demonstrates compliance with the LCO.

Condition A is modified by a Note that requires that Required Actions A.2 and A.3 must be completed whenever Condition A is entered. Thus, if power is not reduced because this Required Action is completed within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months time period, Required Action A.2 nevertheless requires another measurement and calculation of FXH within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in accordance with SR 3.2.2.1.

However, if power is reduced below 50% RTP, Required Action A.3 requires that another determination of FNAH must be done prior to exceeding 50% RTP, prior to exceeding 75% RTP, and within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching or exceeding 95% RTP.

A.1.2.1 and A.1.2.2 If the value of FNAH is not restored to within its specified limit either by adjusting a misaligned rod or by reducing THERMAL POWER, the alternative option is to reduce THERMAL POWER to < 50% RTP in accordance with Required Action A.1.2.1 and reduce the Power Range Neutron Flux - High to _ 55% RTP in accordance with Required Action A.1.2.2. Reducing power to < 50% RTP increases the DNB margin and does not likely cause the DNBR limit to be violated in steady state operation. The reduction in trip setpoints ensures that continuing operation remains at an acceptable low power level with adequate DNBR margin. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for Required Action A.1.2.1 is consistent with those allowed for in Required Action A.1.1 and provides an acceptable time to reach the required power level from full power operation without allowing the plant to remain in an unacceptable Wolf Creek - Unit 1 B 3.2.2-4 Revision 48 1

FH B 3.2.2 BASES ACTIONS A.1.2.1 and A.1.2.2 (continued) condition for an extended period of time. The Completion Times of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for Required Actions A.1.1 and A.1.2.1 are not additive.

The allowed Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to reset the trip setpoints per Required Action A.1.2.2 recognizes that, once power is reduced, the safety analysis assumptions are satisfied and there is no urgent need to reduce the trip setpoints.

A.2 Once the power level has been reduced to < 50% RTP per Required Action A.1.2.1, a power distribution measurement (SR 3.2.2.1) must be obtained and the measured value of FNAH verified not to exceed the allowed limit at the lower power level. The unit is provided 68 additional hours to perform this task over and above the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allowed by either Action A.1.1 or Action A.1.2.1. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is acceptable because of the increase in the DNB margin, which is obtained at lower power levels, and the low probability of having a DNB limiting event within this 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months period. Additionally, operating experience has indicated that this Completion Time is sufficient to obtain the power distribution measurement, perform the required calculations, and evaluate FXH.

A.3 Verification that FNAH is within its specified limits after an out of limit occurrence ensures that the cause that led to the FNAH exceeding its limit is identified, to the extent necessary, and corrected, and that subsequent operation proceeds within the LCO limit. This Action demonstrates that the FN A limit is within the LCO limits prior to exceeding 50% RTP, again prior to exceeding 75% RTP, and within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 95% RTP.

This Required Action is modified by a Note that states that THERMAL POWER does not have to be reduced prior to performing this Action.

B.1 When Required Actions A.1.1 through A.3 cannot be completed within their required Completion Times, the plant must be placed in a mode in which the LCO requirements are not applicable. This is done by placing the plant in at least MODE 2 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Wolf Creek - Unit 1 B 3.2.2-5 Revision 48

FH B 3.2.2 BASES ACTIONS B.1 (continued)

Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience regarding the time required to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.2.1 REQUIREMENTS SR 3.2.2.1 is modified by a Note. The Note applies during power ascensions following a plant shutdown (leaving MODE 1). The Note allows for power ascensions ifthe surveillances are not current. It states that THERMAL POWER may be increased until an equilibrium power level has been achieved at which a power distribution measurement can be obtained. Equilibrium conditions are achieved when the core is sufficiently stable at the intended operating conditions to perform the measurement.

The value of FNAH is determined by using either the movable incore detector system or the Power Distribution Monitoring System to obtain a power distribution measurement. A calculation determines the maximum value of FNAH from the measured power distribution. The measured value of FNA Hmust be increased by 4% (if using the movable incore detector system) or increased by UAH% (if using the Power Distribution Monitoring System, where UAH is determined as described in Reference 4, with a minimum value of 4%) to account for measurement uncertainty before making comparisons to the FNAH limit After each refueling, FNAH must be determined in MODE 1 prior to exceeding 75% RTP. This requirement ensures that FNAH limits are met at the beginning of each fuel cycle.

The 31 EFPD Frequency is acceptable because the power distribution changes relatively slowly over this amount of fuel bumup. Accordingly, this Frequency is short enough that the FN AH limit cannot be exceeded for any significant period of operation.

REFERENCES 1. USAR, Section 15.4.8.

2. 10 CFR 50, Appendix A, GDC 26.

3. 10 CFR 50.46.

4. WCAP-12472-P-A, "BEACON Core Monitoring and Operations Support System," August 1994 (including Addendum 1-A, January 2000).

Wolf Creek - Unit 1 B 3.2.2-6 Revision 48

QPTR B 3.2.4 BASES ACTIONS A.1 (continued) within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of QPTR determination, if necessary to comply with the decreased maximum allowable THERMAL POWER level. Decreases in QPTR would allow raising the maximum allowable THERMAL POWER level and increasing THERMAL POWER up to this revised limit.

A.2 After completion of Required Action A.1, the QPTR alarm may still be in its alarmed state. As such, any additional changes in the QPTR are detected by requiring a check of the QPTR once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter.

If the QPTR continues to increase, THERMAL POWER has to be reduced accordingly. A 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is sufficient because any additional change in QPTR would be relatively slow.

A.3 The peaking factors FN AH and FQ(Z) are of primary importance in ensuring that the power distribution remains consistent with the initial conditions used in the safety analyses. Performing SRs on FNAH and FQ(Z) within the Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions from a THERMAL POWER reduction per Required Action A.1 ensures that these primary indicators of power distribution are within their respective limits.

Equilibrium conditions are achieved when the core is sufficiently stable at the intended operating conditions to support a power distribution measurement using either the movable incore detector system or the Power Distribution Monitoring System. A Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions from a THERMAL POWER reduction per Required Action A.1 takes into consideration the rate at which peaking factors are likely to change, and the time required to stabilize the plant and perform a power distribution measurement. If these peaking factors are not within their limits, the Required Actions associated with these Surveillances provide an appropriate response for the abnormal condition. If the QPTR remains above its specified limit, the peaking factor surveillances are required each 7 days thereafter to evaluate FNAH and F,(Z) with changes in power distribution. Relatively small changes are expected due to either bumup and xenon redistribution or correction of the cause for exceeding the QPTR limit.

Wolf Creek - Unit 1 B 3.2.4-3 Revision 48

QPTR B 3.2.4 BASES ACTIONS A.4 (continued)

A reduction of the Power Range Neutron Flux - High trip setpoints by __3%

for each 1% by which QPTR exceeds 1.00, is a conservative action for protection against the consequences of severe transients with potentially unanalyzed power distributions. Performance of this Required Action results in earlier trip setpoint reduction than would be required pursuant to the Required Actions of the Fj and FQ(Z) specifications. The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each QPTR determination is sufficient considering the small likelihood of a severe transient in this time period and the preceding prompt reduction in THERMAL POWER in accordance with Required Action A. 1.

The Power Range Neutron Flux-High trip setpoint initially determined by Required Action A.4 may be affected by subsequent determinations of QPTR, similar to that of the maximum allowable THERMAL POWER determined by Required Action A. 1.

A.5 Although Fj and FQ(Z) are of primary importance as initial conditions in the safety analyses, other changes in the power distribution may occur as the QPTR limit is exceeded and may have an impact on the validity of the safety analysis. A change in the power distribution can affect such reactor parameters as bank worths and peaking factors for rod malfunction accidents. When the QPTR exceeds its limit, it does not necessarily mean a safety concern exists. It does mean that there is an indication of a change in the gross radial power distribution that requires an investigation and evaluation that is accomplished by examining the incore power distribution. Specifically, the core peaking factors and the quadrant tilt must be evaluated because they are the factors that best characterize the core power distribution. This re-evaluation is required to ensure that, before increasing THERMAL POWER and Power Range Neutron Flux-High trip setpoints to above the limits of Required Actions A. 1 and A.4, the reactor core conditions are consistent with the assumptions in the safety analyses.

Wolf Creek - Unit I B 3.2.4-4 Revision 0

QPTR B 3.2.4 BASES ACTIONS A.6 (continued)

If the QPTR remains above the 1.02 limit and a re-evaluation of the safety analysis is completed and shows that safety requirements are met, the excore detectors are normalized to restore QPTR to within limit prior to increasing THERMAL POWER to above the limit of Required Action A.1.

The process of normalization is accomplished by measuring currents for each detector during core distribution measurement, using either the movable incore detector system or the Power Distribution Monitoring System, and using this information to normalize the output from each

.detector (either through calibration of the NIs or through the use of constants in calculations) in such a manner that the indicated QPTR following normalization is near 1.00. This is done to detect any subsequent significant changes in QPTR.

Required Action A.6 is modified by two Notes. Note 1 states that excore detectors are not normalized to restore QPTR to within limit until after the re-evaluation of the safety analysis has determined that core conditions at RTP are within the safety analysis assumptions (i.e., Required Action A.5). Note 2 states that if Required Action A.6 is performed, then Required Action A.7 shall be performed. Required Action A.6 normalizes the excore detectors to restore QPTR to within limit, which restores compliance with LCO 3.2.4. Thus, Note 2 prevents exiting the Actions prior to completing a power distribution measurement to verify peaking factors per Required Action A.7. These Notes are intended to prevent any ambiguity about the required sequence of actions.

A.7 Once the excore detectors are normalized to restore QPTR to within limit (i.e., Required Action A.6 is performed), it is acceptable to return to full power operation. However, as an added check that the core power distribution at RTP is consistent with the safety analysis assumptions, Required Action A.7 requires verification that FQ(Z) and FN&I are within their specified limits within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of achieving equilibrium conditions.

Equilibrium conditions are achieved when the core is sufficiently stable at the intended operating conditions to support power distribution measurement, using either the movable incore detector system or the Power Distribution Monitoring System. As an added precaution, if the core power does not reach RTP within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , but is increased slowly, then the peaking factor surveillances must be performed within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after increasing THERMAL POWER above the limit of Required Action A.1. These Completion Times are intended to allow adequate time to increase THERMAL POWER to above the limit of Required Action A.1, while not permitting the core to remain with unconfirmed power distributions for extended periods of time.

Wolf Creek - Unit I B 3.2.4-5 Revision 48

QPTR B 3.2.4 BASES ACTIONS A.7 (continued)

Required Action A.7 is modified by a Note that states that the peaking factor surveillances must be completed when the excore detectors have been normalized to restore QPTR to within limit (i.e., Required Action A.6). The intent of this Note is to have the peaking factor surveillances performed at operating power levels, which can only be accomplished after the excore detectors are normalized to restore QPTR to within limit.

B._1 If Required Actions A. 1 through A.7 are not completed within their associated Completion Times, the unit must be brought to a MODE or condition in which the requirements do not apply. To achieve this status, THERMAL POWER must be reduced to < 50% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on operating experience regarding the amount of time required to reach the reduced power level without challenging plant systems.

SURVEILLANCE SR 3.2.4.1 REQUIREMENTS SR 3.2.4.1 is modified by two Notes. Note 1 allows QPTR to be calculated with three power range channels ifTHERMAL POWER is

!575% RTP and the input from one Power Range Neutron Flux channel is inoperable. Note 2 allows performance of SR 3.2.4.2 in lieu of SR 3.2.4.1 to confirm the indication of the remaining three excore channels.

This Surveillance verifies that the QPTR, as indicated by the Nuclear Instrumentation System (NIS) excore channels, is within its limits. The Frequency of 7 days takes into account other information and alarms available to the operator in the control room.

For those causes of QPT that occur quickly (e.g., a dropped rod), there typically are other indications of abnormality that prompt a verification of core power tilt.

SR 3.2.4.2 This Surveillance is modified by a Note, which states that it is not required until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the input from one Power Range Neutron Flux channel is inoperable and the THERMAL POWER is > 75% RTP.

Wolf Creek - Unit 1 B 3.2.4-6 Revision 0

QPTR B 3.2.4 BASES SURVEILLANCE SR 3.2.4.2 (continued)

REQUIREMENTS With an NIS power range channel inoperable, tilt monitoring for a portion of the reactor core becomes degraded. Large tilts are likely detected with the remaining channels, but the capability for detection of small power tilts in some quadrants is decreased. Performing SR 3.2.4.2 at a Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months provides an accurate alternative means for ensuring that any tilt remains within its limits.

For purposes of monitoring the QPTR when one power range channel is inoperable, either the movable incore detector system or the Power Distribution Monitoring System is used to confirm that the normalized symmetric power distribution is consistent with the indicated QPTR and any previous data indicating a tilt. The incore detector monitoring is performed with a full incore flux map or two sets of four thimble locations with quarter core symmetry. The two sets of four symmetric thimbles is a set of eight unique detector locations. These locations are C-8, E-5, E-1 1, H-3, H-13, L-5, L-11, and N-8.

The symmetric thimble flux map can be used to generate symmetric thimble "tilt." This can be compared to a reference symmetric thimble tilt, from the most recent full core flux map, to generate an incore QPTR. If one of the symmetric thimbles is not available, then other pairs (triples) of symmetric thimbles can be monitored to gain information about the quadrant with the out-of-service thimble, provided the reference case is set up with the same thimble groupings. Therefore, incore monitoring of QPTR can be used to confirm that QPTR is within limits.

With one NIS channel inoperable, the indicated tilt may be changed from the value indicated with all four channels OPERABLE. To confirm that no change in tilt has actually occurred, which might cause the QPTR limit to be exceeded, the power distribution may be compared against previous core power distribution measurements either using the symmetric thimbles as described above or a complete core power distribution measurement.

REFERENCES 1. 10 CFR 50.46.

2. USAR, Section 15.4.8.

3. 10 CFR 50, Appendix A, GDC 26.

Wolf Creek - Unit 1 B 3.2.4-7 Revision 48

RTS Instrumentation B 3.3.1 BASES ACTIONS D.1.1, D.1.2, and D.2 (continued) continued unit operation at power levels > 75% RTP. At power levels

_<75% RTP, operation of the core with radial power distributions beyond the design limits, at a power level where DNB conditions may exist, is prevented. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is consistent with the Surveillance Requirement Frequency in LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)." Required Action D.1.1 has been modified by a Note which only requires SR 3.2.4.2 to be performed if the Power Range Neutron Flux input to QPTR becomes inoperable. Failure of a component in the Power Range Neutron Flux Channel which renders the High Flux Trip Function inoperable may not affect the capability to monitor QPTR.

As such, determining QPTR using core power distribution measurement information may not be necessary.

The NIS power range detectors provide input to the Rod Control System and, therefore, have a two-out-of-four trip logic. A known inoperable channel must be placed in the tripped condition. This results in a partial trip condition requiring only one-out-of-three logic for actuation. The 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed to place the inoperable channel in the tripped condition is justified in Reference 12.

As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. Seventy-eight (78) hours are allowed to place the plant in MODE 3. The 78-hour Completion Time includes 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for channel corrective maintenance, and an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for the MODE reduction as required by Required Action D.2. This is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems. If Required Actions cannot be completed within their allowed Completion Times, LCO 3.0.3 must be entered.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypass condition for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months while performing routine surveillance testing of other channels. The Note also allows placing the inoperable channel in the bypass condition to allow setpoint adjustments of other channels when required to reduce the setpoint in accordance with other Technical Specifications. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months time limit is justified in Reference 12.

E.1 and E.2 Condition E applies to the following reactor trip Functions:

0 Power Range Neutron Flux- Low; Wolf Creek - Unit 1 B 3.3.1-33 Revision 48

RTS Instrumentation B 3.3.1 BASES ACTIONS E.1 and E.2 (continued)

Overtemperature AT;

Overpower AT;

Power Range Neutron Flux -High Positive Rate;

Power Range Neutron Flux- High Negative Rate;

Pressurizer Pressure-High; and

SG Water Level - Low Low.

A known inoperable channel must be placed in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Placing the channel in the tripped condition results in a partial trip condition requiring only one-out-of-three logic for actuation of the two-out-of-four trip logic. The 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed to place the inoperable channel in the tripped condition is justified in Reference 12.

If the inoperable channel cannot be placed in the trip condition within the specified Completion Time, the unit must be placed in a MODE where these Functions are not required OPERABLE. An additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is allowed to place the unit in MODE 3. Six hours is a reasonable time, based on operating experience, to place the unit in MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months while performing routine surveillance testing of the other channels. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months time limit is justified in Reference 12.

F.1 and F.2 Condition F applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint and one channel is inoperable. Above the P-6 setpoint and below the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. IfTHERMAL POWER is greater than the P-6 setpoint but less than the P-1 0 setpoint, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed to reduce THERMAL POWER below the P-6 setpoint or to increase THERMAL POWER above the P-10 setpoint. The NIS Intermediate Range Neutron Flux channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capability of the power range, P-10. If THERMAL POWER is greater than the P-10 setpoint, the NIS power range detectors perform the monitoring and protection Wolf Creek - Unit I B 3.3.1-34 Revision 20

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.2 (continued)

REQUIREMENTS The primary error contributor to the instrument uncertainty for a secondary side power calorimetric measurement is the feedwater flow measurement, which is determined by a AP measurement across a feedwater venturi.

While the measurement uncertainty remains constant in AP span as power decreases, when translated into flow the uncertainty increases as a square term. Therefore, a 1% flow error at 100% power can approach a 10% flow error at 30% RTP even though the AP error has not changed.

Thus, it is required to adjust the setpoint of the Power Range Neutron Flux

- High bistables to < 80% RTP: 1) prior to adjustment of the power range channel output in the decreasing power direction due to a part-power calorimetric below 45% RTP; or 2) for a post refueling startup. The evaluation of extended operation at part-power conditions concludes that the potential need to adjust the indication of the Power Range Neutron Flux in the decreasing power direction is quite small, primarily to address operation in the intermediate range about P-1 0 (nominally 10% RTP) to allow enabling of the Power Range Neutron Flux - Low setpoint and the Intermediate Range Neutron Flux reactor trips. Before the Power Range Neutron Flux - High bistables are reset to _ 109% RTP, the power range channel adjustment must be confirmed based on a calorimetric performed at Ž_45% RTP.

The Note to SR 3.3.1.2 clarifies that this Surveillance is required only if reactor power is _>15% RTP and that 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed for performing the first Surveillance after reaching 15% RTP. A power level of 15% RTP is chosen based on plant stability, i.e., automatic rod control capability and the turbine generator synchronized to the grid. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance after increasing THERMAL POWER above 15% RTP provides a reasonable time to attain a scheduled power plateau, establish the requisite conditions, perform the calorimetric measurement, and make any required adjustments in a controlled, orderly manner and without introducing the potential for extended operation at high power levels with instrumentation that has not been verified to be OPERABLE for subsequent use.

The Frequency of every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Together these factors demonstrate that a difference between the calorimetric heat balance calculation and the power range channel output of more than + 2% RTP is not expected in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period.

Wolf Creek - Unit I B 3.3.1-45 Revision 20 1

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.2 (continued REQUIREMENTS In addition, control room operators periodically monitor redundant indications and alarms to detect deviations in channel outputs.

SR 3.3.1.3 SR 3.3.1.3 compares the core power distribution measurement, obtained using either the movable incore detector system or the Power Distribution Monitoring System, to the NIS channel output every 31 EFPD. If the absolute difference is __3%, the NIS channel is still OPERABLE, but must be readjusted. The excore NIS channel shall be adjusted if the absolute difference between the incore and excore AFD is >_3%.

If the NIS channel cannot be properly readjusted, the channel is declared inoperable. This Surveillance is performed to verify the f(AI) input to the Overtemperature AT Function.

The Note to SR 3.3.1.3 clarifies that the Surveillance is required only if reactor power is >_50 % RTP, and that 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed for performing the first Surveillance after reaching 50% RTP. This Note allows power ascensions and associated testing to be conducted in a controlled and orderly manner, at conditions that provide acceptable results and without introducing the potential for extended operation at high power levels with instrumentation that has not been verified to be OPERABLE for subsequent use. Due to such effects as shadowing from the relatively deep control rod insertion and, to a lesser extent, the axially-dependent radial leakage which varies with power level, the relationship between the incore and excore indications of axial-flux difference (AFD) at lower power levels is variable. Thus, it is acceptable to defer the calibration of the excore AFD against the incore AFD until more stable conditions are attained (i.e., withdrawn control rods and a higher power level). The AFD is used as an input to the Overtemperature AT reactor trip function and for assessing compliance with LCO 3.2.3., "AXIAL FLUX DIFFERENCE (AFD)." Due to the DNB benefits gained by administratively restricting power level to 50% RTP, no limits on AFD are imposed below 50% RTP by LCO 3.2.3; thus, the proposed change is consistent with the LCO 3.2.3 requirements below 50% RTP. Similarly, sufficient DNB margins are realized through operation below 50% RTP that the intended function of the Overtemperature AT reactor trip function is maintained, even though the excore AFD indication may not exactly match the incore AFD indication. Based on plant operating experience, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a Wolf Creek - Unit I B 3.3.1-46 Revision 48

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.3 (continued)

REQUIREMENTS reasonable time frame to limit operation above 50% RTP while completing the procedural steps associated with the surveillance in an orderly manner.

The Frequency of every 31 EFPD is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Also, the slow changes in neutron flux during the fuel cycle can be detected during this interval.

SR 3.3.1.4 SR 3.3.1.4 is the performance of a TADOT every 62 days on a STAGGERED TEST BASIS. This test shall verify OPERABILITY by actuation of the end devices.

The RTB test shall include separate verification of the undervoltage and shunt trip mechanisms. Independent verification of RTB undervoltage and shunt trip Function is not required for the bypass breakers. No capability is provided for performing such a test at power. The independent test for bypass breakers is included in SR 3.3.1.14. The bypass breaker test shall include a local manual shunt trip. A Note has been added to indicate that this test must be performed on the bypass breaker prior to placing it in service.

The Frequency of every 62 days on a STAGGERED TEST BASIS is justified in Reference 13.

SR 3.3.1.5 SR 3.3.1.5 is the performance of an ACTUATION LOGIC TEST. The SSPS is tested every 92 days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypass condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function, including operation of the P-7 permissive which is a logic function only. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

Wolf Creek - Unit I B 3.3.1-47 Revision 20

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.6 REQUIREMENTS (continued) SR 3.3.1.6 is a calibration of the excore channels to the core power distribution, measured using either the movable incore detector system or the Power Distribution Monitoring System. If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the core power distribution measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f(AI) input to the Overtemperature AT Function.

A Note modifies SR 3.3.1.6. The Note states that this Surveillance is not required to be performed until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after achieving equilibrium conditions with THERMAL POWER _>75% RTR Equilibrium conditions are achieved when the core is sufficiently stable at intended operating conditions to obtain a core power distribution measurement. The SR is deferred until a scheduled testing plateau above 75% RTP is attained during a power ascension. During a typical power ascension, it is usually necessary to control the axial flux difference at lower power levels through control rod insertion. After equilibrium conditions are achieved at the specified power plateau, a core power distribution measurement must be taken and the required data collected. The data is typically analyzed and the appropriate excore calibrations completed within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months after achieving equilibrium conditions. An additional time allowance of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is provided during which the effects of equipment failures may be remedied and any required re-testing may be performed.

The allowance of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after equilibrium conditions are attained at the testing plateau provides sufficient time to allow power ascensions and associated testing to be conducted in a controlled and orderly manner at conditions that provide acceptable results and without introducing the potential for extended operation at high power levels with instrumentation that has not been verified to be OPERABLE for subsequent use.

The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.

SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT every 184 days.

A COT is performed on each required channel to ensure the channel will perform the intended Function.

Setpoints must be within the Allowable Values specified in Table 3.3.1-1.

Wolf Creek - Unit 1 B 3.3.1-48 Revision 48

ESFAS Instrumentation B 3.3.2 BASES ACTIONS H.1 Not Used.

(continued) 1.1 and 1.2 Condition I applies to:

SG Water Level - High High (P-14);

If one channel is inoperable, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months are allowed to restore one channel to OPERABLE status or to place it in the tripped condition. If placed in the tripped condition, the Function is then in a partial trip condition where one-out-of-three logic will result in actuation. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is justified in Reference 12. Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months requires the unit to be placed in MODE 3 within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The allowed Completion Time of Required Action 1.2 is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, these Functions are no longer required OPERABLE.

The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for surveillance testing of other channels. The 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed to place the inoperable channel in the tripped condition, and the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed for a second channel to be in the bypassed condition for testing, are justified in Reference 12.

Wolf Creek - Unit 1 B 3.3.2-41 Revision 45 1

ESFAS Instrumentation B 3.3.2 BASES ACTIONS J.1 and J.2 Condition J applies to the AFW pump start on trip of all MFW pumps.

This action addresses the train orientation of the BOP ESFAS for the auto start function of the AFW System on loss of all MFW pumps. The OPERABILITY of the AFW System must be assured by allowing automatic start of the AFW System pumps. If one or more channel(s) are inoperable, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to place the channel in the tripped condition.

If the channel cannot be tripped in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , 6 additional hours are allowed to place the unit in MODE 3. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, the unit does not have any analyzed transients or conditions that require the use of the protection function noted above.

The Required Actions are modified by a Note that allows one inoperable channel to be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

A MFW pump is in service when the pump's stop valves are open, the governor control valves are either in manual or automatic control, and feedwater is being supplied to the steam generators (i.e., the MFW pump is at the required operating speed). One MFW pump may be in service in MODE 1 at reduced power levels ifthe other MFW pump has been removed from service for maintenance or has not yet been placed into service during power ascension. During the process of removing a MFW pump from service and prior to placing a MFW pump into service, its control circuitry is placed in a reset condition such that the two oil pressure switch channels on that pump continue to experience oil pressures indicative of an operating pump and, therefore, would not satisfy the AFW start function actuation logic (one tripped channel on each MFW pump in the same separation group will initiate an auxiliary feedwater actuation).

This ESFAS actuation function is an anticipatory start signal for which no credit is taken in any safety analysis. The safety analyses credit actuation of the motor driven AFW pumps upon a low-low steam generator water level signal in any steam generator and after a safety injection signal.

K.1, K.2.1, and K.2.2 Condition K applies to the RWST Level - Low Low Coincident with Safety Injection Function.

RWST Level - Low Low Coincident with Sl provides actuation of switchover to the containment recirculation sumps. Note that this Function requires the bistables to energize to perform their required Wolf Creek - Unit 1 B 3.3.2-42 Revision 45

Containment Isolation Valves B 3.6.3 BASES APPLICABLE The LOCA offsite dose analysis assumes leakage from the containment SAFETY ANALYSES at a maximum leak rate of 0.20 percent of the containment volume per (continued) day for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and at 0.10 percent of the containment volume per day for the duration of the accident.

The single failure criterion required to be imposed in the conduct of plant safety analyses was considered in the original design of the 18 inch containment mini-purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred. The inboard and outboard isolation valves on each line are provided with independent electrical power sources to solenoids that open the pneumatically operated spring closed actuators. The actuators fail closed on the loss of power or air.

This arrangement was designed to preclude common mode failures from disabling both valves on a purge line.

The 36 inch purge valves may be unable to close against the buildup of pressure following a LOCA. Therefore, each of the purge valves is required to remain sealed closed or closed and blind flange installed during MODES 1, 2, 3, and 4. The Containment Shutdown Purge System valve design precludes a single failure from compromising the containment boundary as long as the system is operated in accordance with the subject LCO.

The containment isolation valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Containment isolation valves form a part of the containment boundary.

The containment isolation valves' safety function is related to minimizing the loss of reactor coolant inventory and establishing the containment boundary during a DBA.

The automatic power operated isolation valves are required to have isolation times within limits and to actuate on an automatic isolation signal.

The 36 inch containment purge supply and exhaust valves must be maintained sealed closed or closed and blind flange installed. The valves covered by this LCO are listed along with their associated stroke times in the USAR (Ref. 2).

The normally closed containment isolation valves are considered OPERABLE when manual valves are closed, automatic valves are de-activated and secured in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves/devices are those listed in Reference 2.

Wolf Creek - Unit 1 B 3.6.3-3 Revision 0

Containment Isolation Valves B 3.6.3 BASES LCO Containment purge valves with resilient seals must meet additional (continued) leakage rate requirements. The other containment isolation valve leakage rates are addressed by LCO 3.6.1, "Containment," as Type C testing.

This LCO provides assurance that the containment isolation valves and purge valves will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the containment boundary during accidents.

This LCO is modified by a Note that allows the reactor coolant pump seal injection valves (BBHV8351 A,BBHV8351 B, BBHV8351 C, and BBHV8351 D) be considered OPERABLE with the valve open and power removed. The valves are normally open containment isolation valves and do not receive any automatic isolation signal. The valves are open with power removed to prevent potential damage to the reactor coolant pump seals if the valves were to spuriously close in the event of a fire. (Reference 9)

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed in LCO 3.9.4, "Containment Penetrations."

ACTIONS The ACTIONS are modified by a Note allowing penetration flow paths, except for 36 inch containment purge supply and exhaust valve penetration flow paths, to be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for containment isolation is indicated. Due to the size of the containment purge line penetration and the fact that those penetrations exhaust directly from the containment atmosphere to the environment via the unit vent, the penetration flow path containing these valves may not be opened under administrative controls. A single valve in a penetration flow path may be opened to effect repairs to an inoperable valve, as allowed by SR 3.6.3.1.

A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation valves are governed by subsequent Condition entry and application of associated Required Actions.

Wolf Creek - Unit 1 B 3.6.3-4 Revision 49

Containment Isolation Valves B 3.6.3 BASES ACTIONS The ACTIONS are further modified by a third Note, which ensures (continued) appropriate remedial actions are taken, if necessary, if the affected systems are rendered inoperable by an inoperable containment isolation valve.

Inthe event the containment isolation valve leakage results in exceeding the overall containment leakage rate acceptance criteria, Note 4 directs entry into the applicable Conditions and Required Actions of LCO 3.6.1.

A.1 and A.2 Inthe event one containment isolation valve in one or more penetration flow paths is inoperable except for purge valve leakage not within limit, the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve (this includes power operated valves with power removed),

a blind flange, or a check valve with flow through the valve secured. For a penetration flow path isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available one to containment. The isolation barrier utilized to satisfy Required Action A.1 must have been demonstrated to meet the leakage requirements of SR 3.6.1.1. Required Action A.1 must be completed within the Completion Time specified for each Category of containment isolation valves identified in Table B 3.6.3-1. The Completion Times are justified in Reference 8.

For an affected penetration flow path that cannot be restored to OPERABLE status within the specified Completion Time and that have been isolated in accordance with Required Action A.1, the affected penetration flow paths must be verified to be isolated on a periodic basis.

This is necessary to ensure that containment penetrations required to be isolated following an accident and no longer capable of being automatically isolated will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation. Rather, it involves verification, through a system walkdown (which may include the use of local or remote indicators), that those isolation devices outside containment and capable of being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside containment" is appropriate considering the fact that the devices are operated under administrative controls and the probability of their misalignment is low. For the isolation devices inside containment, the time period specified as "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.

Wolf Creek - Unit 1 B 3.6.3-5 Revision 49 1

Containment Isolation Valves B 3.6.3 BASES ACTIONS A.1 and A.2 (continued)

Condition A is applicable to those penetration flow paths with two containment isolation valves and penetration flow paths with only one containment isolation valve and a closed system. The closed system must meet the requirement of Reference 5. The Containment Spray System and ECCS are closed ESF-grade systems outside containment, which meet the requirements of Reference 5, and serve as the second containment isolation barrier (Ref. 6).

Required Action A.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment of these devices once they have been verified to be in the proper position, is small.

B.1 With two containment isolation valves in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve (this includes power operated valves with power removed), and a blind flange. For a penetration flow path isolated in accordance with Required Action B.1, the device used to isolate the penetration should be the closest available one to containment. The isolation barrier utilized to satisfy Required Action B.1 must have been demonstrated to meet the leakage requirements of SR 3.6.1.1. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1. In the event the affected penetration is isolated in accordance with Required Action B.1, the affected penetration must be verified to be isolated on a periodic basis per Required Action A.2, which remains in effect. This periodic verification is necessary to assure that penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration flow path is isolated is appropriate considering the fact that the valves are operated under administrative control and the probability of their misalignment is low.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves.

Wolf Creek - Unit I B 3.6.3-6 Revision 49 1

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulating Valves (MFRVs) and MFRV Bypass Valves BASES BACKGROUND The MFIVs isolate main feedwater (MFW) flow to the secondary side of the steam generators following a high energy line break (HELB). The Main Feedwater Regulation Valves (MFRVs) and MFRV bypass valves function to control feedwater flow to the SGs and provide backup isolation of MFW flow in the event an MFIV fails to close.

The MFIV is a 14-inch gate valve with system-medium actuation trains.

Either actuation train can independently perform the safety function to fast-close the MFIV on demand. For each MFIV, one actuator train is associated with separation group 4 ("yellow"), and one actuator trains is associated with separation group 1 ("red").

The MFRVs are air-operated angle valves used to control feedwater flow to the SGs from between 30% and full power. The MFRV bypass valves are air-operated globe valves used to control flow to the SGs up to approximately 30% power.

Closure of the MFIVs or MFRVs and MFRV bypass valves terminates main feedwater flow to the steam generators, terminating the event for feedwater line breaks (FWLBs) occurring upstream of the MFIVs or MFRVs and MFRV bypass valves. The consequences of events occurring in the main steam lines or in the MFW lines downstream from the MFIVs will be mitigated by their closure. Closure of the MFIVs or MFRVs and MFRV bypass valves effectively terminates the addition of main feedwater to an affected steam generator, limiting the mass and energy release for steam line breaks (SLBs) or FWLBs inside containment, and reducing the cooldown effects for SLBs.

The MFIVs isolate the nonsafety related portions from the safety related portions of the system. In the event of a secondary side pipe rupture inside containment, the valves limit the quantity of high energy fluid that enters containment through the break, and provide a pressure boundary for the controlled addition of auxiliary feedwater (AFW) to the intact loops.

One MFIV and one MFRV are located on each MFW line, outside but close to containment. The MFRV bypass valves are located in six inch lines that bypass flow around the MFRVs during low power operations.

An MFIV cannot be isolated with closed manual valves; the MFRV can be isolated upstream by a closed manual valve; and the MFRV bypass valves can be isolated both upstream and downstream with a closed manual valve. The MFIVs and MFRVs and MFRV bypass valves are Wolf Creek - Unit 1 B 3.7.3-1 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES BACKGROUND located upstream of the AFW injection point so that AFW may be supplied (continued) to the steam generators following MFIV or MFRV and MFRV bypass valve closure. The piping volume from these valves to the steam generators is accounted for in calculating mass and energy releases, and refilled prior to AFW reaching the steam generator following either an SLB or FWLB.

The MFIVs and MFRVs and MFRV bypass valves close on receipt of any safety injection signal, a Tavg - Low coincident with reactor trip (P-4), a low-low steam generator level, or steam generator water level - high high signal. The MFIVs may also be actuated manually. In addition to the MFIVs and MFRVs and MFRV bypass valves, check valves are located in Area 5 inside the auxiliary building, upstream of the auxiliary feedwater connection and downstream of the MFIVs. The check valve isolates the feedwater line penetrating containment and ensures the pressure boundary of any intact loop not receiving auxiliary feedwater. The MFRV and MFRV bypass valve actuators consist of two separate actuation trains each receiving an actuation signal from one of the redundant ESFAS channels. Both trains are required to actuate to close the valve.

The MFIV actuators consist of two separate system-medium actuation trains each receiving an actuation signal from one of the redundant ESFAS channels. A single active failure in one power train would not prevent the other power train from functioning. The MFIVs provide the primary success path for events requiring feedwater isolation and isolation of nonsafety related portions from the safety related portion of the system, such as, for auxiliary feedwater addition.

A description of the MFIVs, MFRVs, and MFRV bypass valve is found in the USAR, Section 10.4.7 (Ref. 1).

APPLICABLE Credit is taken in accident analysis for the MFIVs to close on demand.

SAFETY ANALYSES The safety function of the MFRVs and associated bypass valves credited in accident analysis is to provide a backup to the MFIVs for the potential failure of an MFIV to close even though the MFRVs are located in the nonsafety related portion of the feedwater system. Further assurance of feedwater flow termination is provided by the SGFP trip function; however, this is not credited in accident analysis. The accident analysis credits the main feedwater check valves as backup to the MFIVs to prevent SG blowdown for pipe ruptures in the non-seismic Category I portions of the feedwater system outside containment.

Wolf Creek - Unit 1 B 3.7.3-2 Revision 46

AC Sources - Operating B 3.8.1 BASES APPLICABLE meeting the design basis of the unit. This results in maintaining at least SAFETY ANALYSES one train of the onsite or offsite AC sources OPERABLE during Accident (continued) conditions in the event of:

a. An assumed loss of all offsite power or all onsite AC power; and

b. A worst case single failure.

The AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Two qualified circuits between the offsite transmission network and the onsite Class 1E Electrical Power System, separate and independent DGs for each train, and redundant LSELS for each train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESF buses.

One offsite circuit consists of the #7 transformer feeding through the 13-48 breaker power the ESF transformer XNBO1, which, in turn powers the NB01 bus through its normal feeder breaker. Transformer XNB01 may also be powered from the SL-7 supply through the 13-8 breaker provided the offsite 69 KV line is not connected to the 345 kV system.

The offsite circuit energizing NB01 is considered inoperable when the East 345 kV bus is only energized from the transmission network through the 345-50 and 345-60 main generator breakers. For this configuration, switchyard breakers 345-120 and 345-90 OR 345-120 and 345-80 are open.

Another offsite circuit consists of the startup transformer feeding through breaker PA201 powering the ESF transformer XNB02, which, in turn powers the NB02 bus through its normal feeder breaker.

Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 12 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions.

Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.

Wolf Creek - Unit 1 B 3.8.1-3 Revision 47

AC Sources - Operating B 3.8.1 BASES LCO Upon failure of the DG lube oil keep warm system when the DG is in the (continued) standby condition, the DG is considered inoperable due to the inability to maintain engine lubrication (Ref. 15). Upon failure of the DG jacket water keep warm system, the DG remains OPERABLE as long as jacket water temperature is >_105 OF (Ref. 13).

Initiating an EDG start upon a detected undervoltage or degraded voltage condition, tripping of nonessential loads, and proper sequencing of loads, is a required function of LSELS and required for DG OPERABILITY. In addition, the LSELS Automatic Test Indicator (ATI) is an installed testing aid and is not required to be OPERABLE to support the sequencer function. Absence of a functioning ATI does not render LSELS inoperable.

The AC sources in one train must be separate and independent of the AC sources in the other train. For the DGs, separation and independence are complete.

For the offsite AC source, separation and independence are to the extent practical. A circuit may be connected to more than one ESF bus provided the appropriate LCO Required Actions are entered for loss of one offsite power source.

APPLICABILITY The AC sources and LSELS are required to be OPERABLE in MODES 1,

.2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources- Shutdown."

ACTIONS A Note prohibits the application of LCO 3.0.4b. to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4b., which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

Wolf Creek - Unit 1 B 3.8.1-4 Revision 47 1

AC Sources - Operating B 3.8.1 BASES ACTIONS B.4.1. B.4.2.1. and B4.2.2 (continued) time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. This limits the time the plant can alternate between Conditions A, B, and E (see Completion Time Example 1.3-3). The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

Tracking the 6 day Completion Time is a requirement for beginning the Completion Time "clock" that is in addition to the normal Completion Time requirements. With respect to the 6 day Completion Time, the "time zero" is specified as beginning at the time LCO 3.8.1 was initially not met, instead of at the time Condition B was entered. This results in the requirement, when in this Condition, to track the time elapsed from both the Condition B "time zero," and the "time zero" when LCO 3.8.1 was initially not met. Refer to Section 1.3, "Completion Times," for a more detailed discussion of the purpose of the "from discovery of failure to meet the LCO portion of the Completion Time."

The Required Actions are modified by a Note that states that Required Actions B.4.2.1 and B.4.2.2 are only applicable for voluntary planned maintenance and may be used once per cycle per DG. Required Actions B.4.2.1 and B.4.2.2 only applies when a DG is declared or rendered inoperable for the performance of voluntary, planned maintenance activities. Required Action B.4.2.1 provides assurance that the required Sharpe Station gensets are available when a DG is out of service for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The availability of the required gensets are verified once per 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months by locally monitoring various genset parameters.

The 7-day Completion Time of Required Action B.4.2.2 is a risk-informed allowed outage time (AOT) based on a plant-specific risk analysis. The Completion Time was established on the assumption that it would be used only for voluntary planned maintenance, inspections and testing. Use of Required Actions B.4.2.1 and B.4.2.2 are limited to once within an operating cycle (18 months) for each DG. Administrative controls applied during use of Required Action B.4.2.2 for voluntary planned maintenance activities ensure or require that (Ref. 16):

a. Weather conditions are conducive to an extended DG Completion Time. The extended DG Completion Time applies during the period of September 7 through April 5.

Wolf Creek - Unit 1 B 3.8.1 -11 Revision 36

AC Sources - Operating B 3.8.1 BASES ACTIONS B.4.1. B.4.2.1, and B4.2.2 (continued)

b. The offsite power supply and switchyard condition are conducive to an extended DG Completion Time, which includes ensuring that switchyard access is restricted and no elective maintenance within the switchyard is performed that would challenge offsite power availability. Elective maintenance or testing that would challenge offsite power availability is that activity that could result in an electrical power distribution system (offsite circuit or transmission network) transient or make the offsite circuit(s) unavailable or inoperable (Reference 19). The operational risk assessment procedure provides a list of equipment that could challenge offsite power availability.

c. Prior to relying on the required Sharpe Station gensets, the gensets are started and proper operation verified (i.e., the gensets reach rated speed and voltage). The Sharpe Station is not required to be operating the duration of the allowed outage time of the DG, however, it shall be capable of providing greater than 16 MW power to a dead bus (station blackout conditions) to power I ESF train. Within 8 months prior to utilization of Required Action B.4.2.2, a load capability test/verification will be performed on the Sharpe Station gensets. The load capability testing/verification will consist of either 1) crediting a running of the gensets for load for commercial reasons for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or 2) tested by loading of the gensets for greater than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to a load equal to or greater than required to supply safety related loads in the event of a station blackout.

d. No equipment or systems assumed to be available for supporting the extended DG Completion Time are removed from service. The equipment or systems assumed to be available (including required support systems, i.e., associated room coolers, etc.) are as follows:

Auxiliary Feedwater System (three trains)

" Component Cooling Water System (both trains and all four pumps)

Essential Service Water System (both trains)

Emergency Core Cooling System (two trains).

If,while Required Action B.4.2.2 is being used, one (or more) of the above systems or components is determined or discovered to be inoperable, or if Wolf Creek - Unit 1 B 3.8.1-12 Revision 47

AC Sources - Operating B 3.8.1 BASES ACTIONS B.4.1. B.4.2.1. and B4.2.2 (continued) an emergent condition affecting DG OPERABILITY is identified, re-entry into Required Action B.2 and B.3 would be required, as applicable. In addition, the effect on plant risk would be assessed and any additional or compensatory actions taken, in accordance with the plant's program for implementation of 10 CFR 50.65(a)(4). The 7-day Completion Time would remain in effect for the DG if Required Action B.2 and B.3 are satisfied.

The second Completion Time specified in Required Action B.4.2.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . If the offsite circuit is restored to OPERABLE status within the required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , this could lead to a total of 10 days since initial failure to meet the LCO, to restore compliance with the LCO (i.e., restore the DG). At this time, an offsite circuit could again become inoperable and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed prior to complete restoration of the LCO. The 10 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. Although highly unlikely, this could occur indefinitely if not limited.

This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. This limits the time the plant can alternate between Conditions A, B, and E (see Example 1.3-3).

Tracking the 10 day Completion Time is a requirement for beginning the Completion Time "clock" that is in addition to the normal Completion Time requirements. With respect to the 10 day Completion Time, the "time zero" is specified as beginning at the time LCO 3.8.1 was initially not met, instead of at the time Condition B was entered. This results in the requirement, when in this Condition, to track the time elapsed from both the Condition B "time zero," and the "time zero" when LCO 3.8.1 was initially not met. Refer to Section 1.3, "Completion Times," for a more detailed discussion of the purpose of the "from discovery of failure to meet the LCO portion of the Completion Time."

C.1 If the availability of the required Sharpe Station gensets cannot be verified, the DG must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time begins upon entry into Condition C.

However, the total time to restore an inoperable DG cannot exceed 7 days (per the Completion Time of Required Action B.4.2.2).

Wolf Creek - Unit 1 B 3.8.1-13 Revision 47 1

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1 (continued)

The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is consistent with Regulatory Guide 1.93 (Ref. 6). The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and low probability of a DBA occurring during this period.

D.1 and D.2 Required Action D.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required features. These redundant required features are those that are assumed to function to mitigate an accident, coincident with a loss of offsite power, in the safety analyses, such as the Emergency Core Cooling System and Auxiliary Feedwater System. These redundant features do not include monitoring requirements, such as Post Accident Monitoring and Remote Shutdown. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps and the turbine driven auxiliary feedwater pump which must be available for mitigation of a feedwater line break. Single train features, other than the turbine driven auxiliary feedwater pump, are not included in this Condition. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. A Note is added to this Required Action stating that in MODES 1, 2, and 3, the turbine driven auxiliary feedwater pump is considered a required redundant feature. The reason for the Note is to confirm the OPERABILITY of the turbine driven auxiliary feedwater pump in this Condition, since the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action D.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a. All required offsite circuits are inoperable; and

b. A required feature is inoperable and not in the safeguards position.

Wolf Creek - Unit 1 B 3.8.1-14 Revision 47 1

AC Sources - Operating B 3.8.1 BASES ACTIONS D.1 and D.2 (continued)

If at any time during the existence of Condition D (two offsite circuits inoperable) a required feature becomes inoperable, this Completion Time begins to be tracked.

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition D for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.

Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.

However, two factors tend to decrease the severity of this level of degradation:

a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A.

Wolf Creek - Unit 1 B 3.8.1-15 Revision 47 1

AC Sources - Operating B 3.8.1 BASES ACTIONS E.1 and E.2 (continued)

Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de -

energization. Therefore, the Required Actions of Condition E are modified by a Note to indicate that when Condition E is entered with no AC source to any given train (i.e., to Train A or Train B), the Conditions and Required Actions for LCO 3.8.9, "Distribution Systems - Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.819 provides the appropriate restrictions for a de-energized train.

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition E for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

In Condition E, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

F.1 With Train A and Train B DGs inoperable, there are no remaining standby AC sources. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

Wolf Creek - Unit 1 B 3.8.1-16 Revision 26

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.21 REQUIREMENTS (continued) SR 3.8.1.21 is the performance of an ACTUATION LOGIC TEST using the LSELS automatic tester for each load shedder and emergency load sequencer train except that the continuity check does not have to be performed, as explained in the Note. This test is performed every 31 days on a STAGGERED TEST BASIS. The Frequency is adequate based on industry operating experience, considering instrument reliability and operating history data.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. USAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3.

4. USAR, Chapter 6.

5. USAR, Chapter 15.

6. Regulatory Guide 1.93, Rev. 0, December 1974.

7. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.

8. 10 CFR 50, Appendix A, GDC 18.

9. Regulatory Guide 1.108, Rev. 1, August 1977.

10. Regulatory Guide 1.137, Rev. 0, January 1978.

11. ANSI C84.1-1982.

12. IEEE Standard 308-1978.

13. Configuration Change Package (CCP) 08052, Revision 1, April 23, 1999.

14. Amendment No. 161, April 21, 2005.

15. Performance Improvement Request 2005-3184.

16. Amendment No. 163, April 26, 2006.

17. Amendment No. 154, August 4, 2004.

Wolf Creek - Unit 1 B 3.8.1-33 Revision 39 1

AC Sources - Operating B 3.8.1 BASES REFERENCES 18. Amendment No. 8, May 29, 1987.

(continued)

19. Condition Report 15727. I Wolf Creek - Unit 1 B 3.8.1-34 Revision 47

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TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents i 34 DRR 07-1057 7/10/07 ii 29 DRR 06-1984 10/17/06 iii 44 DRR 09-1744 10/28/09 TAB - B 2.0 SAFETY LIMITS (SLs)

B 2.1.1-1 0 Amend. No. 123 12/18/99 B 2.1.1-2 14 DRR 03-0102 2/12/03 B 2.1.1-3 14 DRR 03-0102 2/12/03 B 2.1.1-4 0 Amend. No. 123 2/12/03 B 2.1.2-1 0 Amend. No. 123 12/18/99 B 2.1.2-2 12 DRR 02-1062 9/26/02 B 2.1.2-3 0 Amend. No. 123 12/18/99 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY B 3.0-1 34 DRR 07-1057 7/10/07 B 3.0-2 0 Amend. No. 123 12/18/99 B 3.0-3 0 Amend. No. 123 12/18/99 B 3.0-4 19 DRR 04-1414 10/12/04 B 3.0-5 19 DRR 04-1414 10/12/04 B 3.0-6 19 DRR 04-1414 10/12/04 B 3.0-7 19 DRR 04-1414 10/12/04 B 3.0-8 19 DRR 04-1414 10/12/04 B 3.0-9 42 DRR 09-1009 7/16/09 B 3.0-10 42 DRR 09-1009 7/16/09 B 3.0-11 34 DRR 07-1057 7/10/07 B 3.0-12 34 DRR 07-1057 7/10/07 B 3.0-13 34 DRR 07-1057 7/10/07 B 3.0-14 34 DRR 07-1057 7/10/07 B 3.0-15 34 DRR 07-1057 7/10/07 B 3.0-16 34 DRR 07-1057 7/10/07 TAB - B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1-1 0 Amend. No. 123 12/18/99 B 3.1.1-2 0 Amend. No. 123 12/18/99 B 3.1.1-3 0 Amend. No. 123 12/18/99 B 3.1.1-4 19 DRR 04-1414 10/12/04 B 3.1.1-5 0 Amend. No. 123 12/18/99 B 3.1.2-1 0 Amend. No. 123 12/18/99 B 3.1.2-2 0 Amend. No. 123 12/18/99 B 3.1.2-3 0 Amend. No. 123 12/18/99 B 3.1.2-4 0 Amend. No. 123 12/18/99 B 3.1.2-5 0 Amend. No. 123 12/18/99 B 3.1.3-1 0 Amend. No. 123 12/18/99 B 3.1.3-2 0 Amend. No. 123 12/18/99 B 3.1.3-3 0 Amend. No. 123 12/18/99 B 3.1.3-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 Reision49

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TAB- B 3.1 REACTIVITY CONTROL SYSTEMS (continued)

B 3.1.3-5 0 Amend. No. 123 12/18/99 B 3.1.3-6 0 Amend. No. 123 12/18/99 B 3.1.4-1 0 Amend. No. 123 12/18/99 B 3.1.4-2 0 Amend. No. 123 12/18/99 B 3.1.4-3 48 DRR 10-3740 12/28/10 B 3.1.4-4 0 Amend. No. 123 12/18/99 B 3.1.4-5 0 Amend. No. 123 12/18/99 B 3.1.4-6 48 DRR 10-3740 12/28/10 B 3.1.4-7 0 Amend. No. 123 12/18/99 B 3.1.4-8 0 Amend. No. 123 12/18/99 B 3.1.4-9 0 Amend. No. 123 12/18/99 B 3.1.5-1 0 Amend. No. 123 12/18/99 B 3.1.5-2 0 Amend. No. 123 12/18/99 B 3.1.5-3 0 Amend. No. 123 12/18/99 B 3.1.5-4 0 Amend. No. 123 12/18/99 B 3.1.6-1 0 Amend. No. 123 12/18/99 B 3.1.6-2 0 Amend. No. 123 12/18/99 B 3.1.6-3 0 Amend. No. 123 12/18/99 B 3.1.6-4 0 Amend. No. 123 12/18/99 B 3.1.6-5 0 Amend. No. 123 12/18/99 B 3.1.6-6 0 Amend. No. 123 12/18/99 B 3.1.7-1 0 Amend. No. 123 12/18/99 B 3.1.7-2 0 Amend. No. 123 12/18/99 B 3.1.7-3 48 DRR 10-3740 12/28/10 B 3.1.7-4 48 DRR 10-3740 12/28/10 B 3.1.7-5 48 DRR 10-3740 12/28/10 B 3.1.7-6 0 Amend. No. 123 12/18/99 B 3.1.8-1 0 Amend. No. 123 12/18/99 B 3.1.8-2 0 Amend. No. 123 12/18/99 B 3.1.8-3 15 DRR 03-0860 7/10/03 B 3.1.8-4 15 DRR 03-0860 7/10/03 B 3.1.8-5 0 Amend. No. 123 12/18/99 B 3.1.8-6 5 DRR 00-1427 10/12/00 TAB - B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1-1 48 DRR 10-3740 12/28/10 B 3.2.1-2 0 Amend. No. 123 12/18/99 B 3.2.1-3 48 DRR 10-3740 12/28/10 B 3.2.1-4 48 DRR 10-3740 12/28/10 B 3.2.1-5 48 DRR 10-3740 12/28/10 B 3.2.1-6 48 DRR 10-3740 12/28/10 B 3.2.1-7 48 DRR 10-3740 12/28/10 B 3.2.1-8 48 DRR 10-3740 12/28/10 B 3.2.1-9 29 DRR 06-1984 10/17/06 B 3.2.1-10 48 DRR 10-3740 12/28/10 B 3.2.2-1 48 DRR 10-3740 12/28/10 B 3.2.2-2 0 Amend. No. 123 12/18/99 B 3.2.2-3 48 DRR 10-3740 12/28/10 B 3.2.2-4 48 DRR 10-3740 12/28/10 B 3.2.2-5 48 DRR 10-3740 12/28/10 B 3.2.2-6 48 DRR 10-3740 12/28/10 Wolf Creek - Unit 1 ii Re0sion49

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TAB - B 3.2 POWER DISTRIBUTION LIMITS (continued)

B 3.2.3-1 0 Amend. No. 123 12/18/99 B 3.2.3-2 0 Amend. No. 123 12/18/99 B 3.2.3-3 0 Amend. No. 123 12/18/99 B 3.2.4-1 0 Amend. No. 123 12/18/99 B 3.2.4-2 0 Amend. No. 123 12/18/99 B 3.2.4-3 48 DRR 10-3740 12/28/10 B 3.2.4-4 0 Amend. No. 123 12/18/99 B 3.2.4-5 48 DRR 10-3740 12/28/10 B 3.2.4-6 0 Amend. No. 123 12/18/99 B 3.2.4-7 48 DRR 10-3740 12/28/10 TAP - R 'A 'A IIMTPII IMMTATIANI B 3.3.1 *-1 0 Amend. No. 123 12/18/99 B 3.3.1-2 0 Amend. No. 123 12/18/99 B 3.3.1-3 0 Amend. No. 123 12/18/99 B 3.3.1-4 0 Amend. No. 123 12/18/99 B 3.3.1-5 0 Amend. No. 123 12/18/99 B 3.3.1-6 0 Amend. No. 123 12/18/99 B 3.3.1-7 5 DRR 00-1427 10/12/00 B 3.3.1-8 0 Amend. No. 123 12/18/99 B 3.3.1-9 0 Amend. No. 123 12/18/99 B 3.3.1-10 29 DRR 06-1984 10/17/06 B 3.3.1-11 0 Amend. No. 123 12/18/99 B 3.3.1-12 0 Amend. No. 123 12/18/99 B 3.3.1-13 0 Amend. No. 123 12/18/99 B 3.3.1-14 0 Amend. No. 123 12/18/99 B 3.3.1-15 0 Amend. No. 123 12/18/99 B 3.3.1-16 0 Amend. No. 123 12/18/99 B 3.3.1-17 0 Amend. No. 123 12/18/99 B 3.3.1-18 0 Amend. No. 123 12/18/99 B 3.3.1-19 0 Amend. No. 123 12/18/99 B 3.3.1-20 0 Amend. No. 123 12/18/99 B 3.3.1-21 0 Amend. No. 123 12/18/99 B 3.3.1-22 0 Amend. No. 123 12/18/99 B 3.3.1-23 9 DRR 02-0123 2/28/02 B 3.3.1-24 0 Amend. No. 123 12/18/99 B 3.3.1-25 0 Amend. No. 123 12/18/99 B 3.3.1-26 0 Amend. No. 123 12/18/99 B 3.3.1-27 0 Amend. No. 123 12/18/99 B 3.3.1-28 2 DRR 00-0147 4/24/00 B 3.3.1-29 1 DRR 99-1624 12118/99 B 3.3.1-30 1 DRR 99-1624 12/18/99 B 3.3.1-31 0 Amend. No. 123 12/18/99 B 3.3.1-32 20 DRR 04-1533 2/16/05 B 3.3.1-33 48 DRR 10-3740 12/28/10 B 3.3.1-34 20 DRR 04-1533 2/16/05 B 3.3.1-35 19 DRR 04-1414 10/13/04 B 3.3.1-36 20 DRR 04-1533 2/16/05 B 3.3.1-37 20 DRR 04-1533 2/16/05 B 3.3.1-38 20 DRR 04-1533 2/16/05 B 3.3.1-39 25 DRR 06-0800 5/18/06 Wolf Creek - Unit 1 iii Revision49

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.1-40 20 DRR 04-1533 2/16/05 B 3.3.1-41 20 DRR 04-1533 2/16/05 B 3.3.1-42 20 DRR 04-1533 2/16/05 B 3.3.1-43 20 DRR 04-1533 2/16/05 B 3.3.1-44 20 DRR 04-1533 2/16/05 B 3.3.1-45 20 DRR 04-1533 2/16/05 B 3.3.1-46 48 DRR 10-3740 12/28/10 B 3.3.1-47 20 DRR 04-1533 2/16/05 B 3.3.1-48 48 DRR 10-3740 12/28/10 B 3.3.1-49 20 DRR 04-1533 2/16/05 B 3.3.1-50 20 DRR 04-1533 2/16/05 B 3.3.1-51 21 DRR 05-0707 4/20/05 B 3.3.1-52 20 DRR 04-1533 2/16/05 B 3.3.1-53 20 DRR 04-1533 2/16/05 B 3.3.1-54 20 DRR 04-1533 2/16/05 B 3.3.1-55 25 DRR 06-0800 5/18/06 B 3.3.1-56 20 DRR 04-1533 2/16/05 B 3.3.1-57 20 DRR 04-1533 2/16/05 B 3.3.1-58 29 DRR 06-1984 10/17/06 B 3.3.1-59 20 DRR 04-1533 2/16/05 B 3.3.2-1 0 Amend. No. 123 12/18/99 B 3.3.2-2 0 Amend. No. 123 12/18/99 B 3.3.2-3 0 Amend. No. 123 12/18/99 B 3.3.2-4 0 Amend. No. 123 12/18/99 B 3.3.2-5 0 Amend. No. 123 12/18/99 B 3.3.2-6 7 DRR 01-0474 5/1/01 B 3.3.2-7 .0 Amend. No. 123 12/18/99 B 3.3.2-8 0 Amend. No. 123 12/18/99 B 3.3.2-9 0 Amend. No. 123 12/18/99 B 3.3.2-10 0 Amend. No. 123 12/18/99 B 3.3.2-11 0 Amend. No. 123 12/18/99 B 3.3.2-12 0 Amend. No. 123 12/18/99 B 3.3.2-13 0 Amend. No. 123 12/18/99 B 3.3.2-14 2 DRR 00-0147 4/24/00 B 3.3.2-15 0 Amend. No. 123 12/18/99 B 3.3.2-16 0 Amend. No. 123 12/18/99 B 3.3.2-17 0 Amend. No. 123 12/18/99 B 3.3.2-18 0 Amend. No. 123 12/18/99 B 3.3.2-19 37 DRR 08-0503 4/8/08 B 3.3.2-20 37 DRR 08-0503 4/8/08 B 3.3.2-21 37 DRR 08-0503 4/8/08 B 3.3.2-22 37 DRR 08-0503 4/8/08 B 3.3.2-23 37 DRR 08-0503 4/8/08 B 3.3.2-24 39 DRR 08-1096 8/28/08 B 3.3.2-25 39 DRR 08-1096 8/28/08 B 3.3.2-26 39 DRR 08-1096 8/28/08 B 3.3.2-27 37 DRR 08-0503 4/8/08 B 3.3.2-28 37 DRR 08-0503 4/8/08 B 3.3.2-29 0 Amend. No. 123 12/18/99 B 3.3.2-30 0 Amend. No. 123 12/18/99 B 3.3.2-31 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 iv Revision49

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-32 0 Amend. No. 123 12/18/99 B 3.3.2-33 0 Amend. No. 123 12/18/99 B 3.3.2-34 0 Amend. No. 123 12/18/99 B 3.3.2-35 20 DRR 04-1533 2/16/05 B 3.3.2-36 20 DRR 04-1533 2/16/05 B 3.3.2-37 20 DRR 04-1533 2/16/05 B 3.3.2-38 20 DRR 04-1533 2/16/05 B 3.3.2-39 25 DRR 06-0800 5/18/06 B 3.3.2-40 20 DRR 04-1533 2/16/05 B 3.3.2-41 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-42 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-43 20 DRR 04-1533 2/16/05 B 3.3.2-44 20 DRR 04-1533 2/16/05 B 3.3.2-45 20 DRR 04-1533 2/16/05 B 3.3.2-46 20 DRR 04-1533 2/16/05 B 3.3.2-47 43 DRR 09-1416 9/2/09 B 3.3.2-48 37 DRR 08-0503 4/8/08 B 3.3.2-49 20 DRR 04-1533 2/16/05 B 3.3.2-50 20 DRR 04-1533 2/16/05 B 3.3.2-51 43 DRR 09-1416 9/2/09 B 3.3.2-52 43 DRR 09-1416 9/2/09 B 3.3.2-53 43 DRR 09-1416 9/2/09 B 3.3.2-54 43 DRR 09-1416 9/2/09 B 3.3.2-55 43 DRR 09-1416 9/2/09 B 3.3.2-56 43 DRR 09-1416 9/2/09 B 3.3.2-57 43 DRR 09-1416 9/2/09 B 3.3.3-1 0 Amend. No. 123 12/18/99 B 3.3.3-2 5 DRR 00-1427 10/12/00 B 3.3.3-3 0 Amend. No. 123 12/18/99 B 3.3.3-4 0 Amend. No. 123 12/18/99 B 3.3.3-5 0 Amend. No. 123 12/18/99 B 3.3.3-6 8 DRR 01 -1235 9/19/01 B 3.3.3-7 21 DRR 05-0707 4/20/05 B 3.3.3-8 8 DRR 01-1235 9/19/01 B 3.3.3-9 8 DRR 01-1235 9/19/01 B 3.3.3-10 19 DRR 04-1414 10/12/04 B 3.3.3-11 19 DRR 04-1414 10/12/04 B 3.3.3-12 21 DRR 05-0707 4/20/05 B 3.3.3-13 21 DRR 05-0707 4/20/05 B 3.3.3-14 8 DRR 01-1235 9/19/01 B 3.3.3-15 8 DRR 01-1235 9/19/01 B 3.3.4-1 0 Amend. No. 123 12/18/99 B 3.3.4-2 9 DRR 02-1023 2/28/02 B 3.3.4-3 15 DRR 03-0860 7/10/03 B 3.3.4-4 19 DRR 04-1414 10/12/04 B 3.3.4-5 1 DRR 99-1624 12/18/99 B 3.3.4-6 9 DRR 02-0123 2/28/02 B 3.3.5-1 0 Amend. No. 123 12/18/99 B 3.3.5-2 1 DRR 99-1624 12/18/99 B 3.3.5-3 1 DRR 99-1624 12/18/99 Wolf Creek - Unit 1 V Revision49

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.5-4 1 DRR 99-1624 12/18/99 B 3.3.5-5 0 Amend. No. 123 12/18/99 B 3.3.5-6 22 DRR 05-1375 6/28/05 B 3.3.5-7 22 DRR 05-1375 6/28/05 B 3.3.6-1 0 Amend. No. 123 12/18/99 B 3.3.6-2 0 Amend. No. 123 12/18/99 B 3.3.6-3 0 Amend. No. 123 12/18/99 B 3.3.6-4 .0 Amend. No. 123 12/18/99 B 3.3.6-5 0 Amend. No. 123 12/18/99 B 3.3.6-6 0 Amend. No. 123 12/18/99 B 3.3.6-7 0 Amend. No. 123 12/18/99 B 3.3.7-1 0 Amend. No. 123 12/18/99 B 3.3.7-2 0 Amend. No. 123 12/18/99 B 3.3.7-3 0 Amend. No. 123 12/18/99 B 3.3.7-4 0 Amend. No. 123 12/18/99 B 3.3.7-5 0 Amend. No. 123 12/18/99 B 3.3.7-6 0 Amend. No. 123 12/18/99 B 3.3.7-7 0 Amend. No. 123 12/18/99 B 3.3.7-8 0 Amend. No. 123 12/18/99 B 3.3.8-1 0 Amend. No. 123 12/18/99 B 3.3.8-2 0 Amend. No. 123 12/18/99 B 3.3.8-3 0 Amend. No. 123 12/18/99 B 3.3.8-4 0 Amend. No. 123 12/18/99 B 3.3.8-5 0 Amend. No. 123 12/18/99 B 3.3.8-6 24 DRR 06-0051 2/28/06 B 3.3.8-7 0 Amend. No. 123 12/18/99 TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.1-1 0 Amend. No. 123 12/18/99 B 3.4.1-2 10 DRR 02-0411 4/5/02 B 3.4.1-3 10 DRR 02-0411 4/5/02 B 3.4.1-4 0 Amend. No. 123 12/18/99 B 3.4.1-5 0 Amend. No. 123 12/18/99 B 3.4.1-6 0 Amend. No. 123 12/18/99 B 3.4.2-1 0 Amend. No. 123 12/18/99 B 3.4.2-2 0 Amend. No. 123 12/18/99 B 3.4.2-3 0 Amend. No. 123 12/18/99 B 3.4.3-1 0 Amend. No. 123 12/18/99 B 3.4.3-2 0 Amend. No. 123 12/18/99 B 3.4.3-3 0 Amend. No. 123 12/18/99 B 3.4.3-4 0 Amend. No. 123 12/18/99 B 3.4.3-5 0 Amend. No. 123 12/18/99 B 3.4.3-6 0 Amend. No. 123 12/18/99 B 3.4.3-7 0 Amend. No. 123 12/18/99 B 3.4.4-1 0 Amend. No. 123 12/18/99 B 3.4.4-2 29 DRR 06-1984 10/17/06 B 3.4.4-3 0 Amend. No. 123 12/18/99 B 3.4.5-1 0 Amend. No. 123 12/18/99 B 3.4.5-2 17 DRR 04-0453 5/26/04 B 3.4.5-3 29 DRR 06-1984 10/17/06 B 3.4.5-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vi Revision 49

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IMPLEMENTED TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.5-5 12 DRR 02-1062 9/26/02 B 3.4.5-6 12 DRR 02-1062 9/26/02 B 3.4.6-1 17 DRR 04-0453 5/26/04 B 3.4.6-2 29. DRR 06-1984 10/17/06 B 3.4.6-3 12 DRR 02-1062 9/26/02 B 3.4.6-4 12 DRR 02-1062 9/26/02 B 3.4.6-5 12 DRR 02-1062 9/26/02 B 3.4.7-1 12 DRR 02-1062 9/26/02 B 3.4.7-2 17 DRR 04-0453 5/26/04 B 3.4.7-3 42 DRR 09-1009 7/16/09 B 3.4.7-4 42 DRR 09-1009 7/16/09 B 3.4.7-5 12 DRR 02-1062 9/26/02 B 3.4.8-1 17 DRR 04-0453 5/26/04 B 3.4.8-2 42 DRR 09-1009 7/16/09 B 3.4.8-3 42 DRR 09-1009 7/16/09.

B 3.4.8-4 42 DRR 09-1009 7/16/09 B 3.4.9-1 0 Amend. No. 123 12/18/99 B 3.4.9-2 0 Amend. No. 123 12/18/99 B 3.4.9-3 0 Amend. No. 123 12/18/99 B 3.4.9-4 0 Amend. No. 123 12/18/99 B 3.4.10-1 5 DRR 00-1427 10/12/00 B 3.4.10-2 5 DRR 00-1427 10/12/00 B 3.4.10-3 0 Amend. No. 123 12/18/99 B 3.4.10-4 32 DRR 07-0139 2/7/07 B 3.4.11-1 0 Amend. No. 123 12/18/99 B 3.4.11-2 1 DRR 99-1624 12/18/99 B 3.4.11-3 19 DRR 04-1414 10/12/04 B 3.4.11-4 0 Amend. No. 123 12/18/99 B 3.4.11-5 1 DRR 99-1624 12/18/99 B 3.4.11-6 0 Amend. No. 123 12/18/99 B 3.4.11-7 32 DRR 07-0139 2/7/07 B 3.4.12-1 1 DRR 99-1624 12/18/99 B 3.4.12-2 1 DRR 99-1 624 12/18/99 B 3.4.12-3 0 Amend. No. 123 12/18/99 B 3.4.12-4 1 DRR 99-1624 12/18/99 B 3.4.12-5 1 DRR 99-1624 12/18/99 B 3.4.12-6 1 DRR 99-1624 12/18/99 B 3.4.12-7 0 Amend. No. 123 12/18/99 B 3.4.12-8 1 DRR 99-1624 12/18/99 B 3.4.12-9 19 DRR 04-1414 10/12/04 B 3.4.12-10 0 Amend. No. 123 12/18/99 B 3.4.12-11 0 Amend. No. 123 12/18/99 B 3.4.12-12 32 DRR 07-0139 2/7/07 B 3.4.12-13 0 Amend. No. 123 12/18/99 B 3.4.12-14 32 DRR 07-0139 2/7/07 B 3.4.13-1 0 Amend. No. 123 12/18/99 B 3.4.13-2 29 DRR 06-1984 10/17/06 B 3.4.13-3 29 DRR 06-1984 10/17/06 B 3.4.13-4 35 DRR 07-1553 9/28/07 B 3.4.13-5 35 DRR 07-1553 9/28/07 B 3.4.13-6 29 DRR 06-1984 10/17/06 Wolf Creek - Unit 1 vii Revision 49

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TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.14-1 0 Amend. No. 123 12/18/99 B 3.4.14-2 0 Amend. No. 123 12/18/99 B 3.4.14-3 0 Amend. No. 123 12/18/99 B 3.4.14-4 0 Amend. No. 123 12/18/99 B 3.4.14-5 32 DRR 07-0139 2/7/07 B 3.4.14-6 32 DRR 07-0139 2/7/07 B 3.4.15-1 31 . DRR 06-2494 12/13/06 B 3.4.15-2 31 DRR 06-2494 12/13/06 B 3.4.15-3 33 DRR 07-0656 5/1/07 B 3.4.15-4 33 DRR 07-0656 5/1/07 B 3.4.15-5 31 DRR 06-2494 12/13/06 B 3.4.15-6 31 DRR 06-2494 12/13/06 B 3.4.15-7 31 DRR 06-2494 12/13/06 B 3.4.15-8 31 DRR 06-2494 12/13/06 B 3.4.16-1 31 DRR 06-2494 12/13/06 B 3.4.16-2 31 DRR 06-2494 12/13/06 B 3.4.16-3 31. DRR 06-2494 12/13/06 B 3.4.16-4 31 DRR 06-2494 12/13/06 B 3.4.16-5 31 DRR 06-2494 12/13/06 B 3.4.17-1 29 DRR 06-1984 10/17/06 B 3.4.17-2 44 DRR 09-1744 10/28/09 B 3.4.17-3 29 DRR 06-1984 10/17/06 B 3.4.17-4 29 DRR 06-1984 10/17/06 B 3.4.17-5 29 DRR 06-1984 10/17/06 B 3.4.17-6 29 DRR 06-1984 10/17/06 B 3.4.17-7 44 DRR 09-1744 10/28/09 TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1-1 .0 Amend. No. 123 12/18/99 B 3.5.1-2 0 Amend. No. 123 12/18/99 B 3.5.1-3 0 Amend. No. 123 12/18/99 B 3.5.1-4 0 Amend. No. 123 12/18/99 B 3.5.1-5 1 DRR 99-1624 12/18/99 B 3.5.1-6 1 DRR 99-1624 12/18/99 B 3.5.1-7 16 DRR 03-1497 11/4/03 B 3.5.1-8 1 DRR 99-1624 12/18/99 B 3.5.2-1 0 Amend. No. 123 12/18/99 B 3.5.2-2 0 Amend. No. 123 12/18/99 B 3.5.2-3 0 Amend. No. 123 12/18/99 B 3.5.2-4 0 Amend. No. 123 12/18/99 B 3.5.2-5 41 DRR 09-0288 3/20/09 B 3.5.2-6 42 DRR 09-1009 7/16/09 B 3.5.2-7 42 DRR 09-1009 7/16/09 B 3.5.2-8 38 DRR 08-0624 5/1/08 B 3.5.2-9 38 DRR 08-0624 5/1/08 B 3.5.2-10 41 DRR 09-0288 3/20/09 B 3.5.2-11 41 DRR 09-0288 3/20/09 B 3.5.3-1 16 DRR 03-1497 11/4/03 B 3.5.3-2 19 DRR 04-1414 10/12/04 B 3.5.3-3 19 DRR 04-1414 10/12/04 B 3.5.3-4 16 DRR 03-1497 11/4/03 Wolf Creek - Unit 1 viii Revision49

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(4)

IMPLEMENTED TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) (continued)

B 3.5.4-1 0 Amend. No. 123 12/18/99 B 3.5.4-2 0 Amend. No. 123 12/18/99 B 3.5.4-3 0 Amend. No. 123 12/18/99 B 3.5.4-4 0 Amend. No. 123 12/18/99 B 3.5.4-5 0 Amend. No. 123 12/18/99 B 3.5.4-6 26 DRR 06-1350 7/24/06 B 3.5.5-1 21 DRR 05-0707 4/20/05 B 3.5.5-2 21 DRR 05-0707 4/20/05 B 3.5.5-3 2 Amend. No. 132 4/24/00 B 3.5.5-4 21 DRR 05-0707 4/20/05 TAB - B 3.6 CONTAINMENT SYSTEMS B 3.6.1-1 0 Amend. No. 123 12/18/99 B 3.6.1-2 0 Amend. No. 123 12/18/99 B 3.6.1-3 0 Amend. No. 123 12/18/99 B 3.6.1-4 17 DRR 04-0453 5/26/04 B 3.6.2-1 0 Amend. No. 123 12/18/99 B 3.6.2-2 0 Amend. No. 123 12/18/99 B 3.6.2-3 0 Amend. No. 123 12/18/99 B 3.6.2-4 0 Amend. No. 123 12/18/99 B 3.6.2-5 0 Amend. No. 123 12/18/99 B 3.6.2-6 0 Amend. No. 123 12/18/99 B 3.6.2-7 0 Amend. No. 123 12/18/99 B 3.6.3-1 0 Amend. No: 123 12/18/99 B 3.6.3-2 0 Amend. No. 123 12/18/99 B 3.6.3-3 0 Amend. No. 123 12/18/99 B 3.6.3-4 49 DRR 11-0014. 131/11 B 3.6.3-5 49 DRR 11-0014 1/31/11 B 3.6.3-6 49 DRR 11-0014 1/31/11 B 3.6.3-7 41 DRR 09-0288 3/20/09 B 3.6.3-8 36 DRR 08-0255 3/11/08 B 3.6.3-9 36 DRR 08-0255 3/11/08 B 3.6.3-10 8 DRR 01-1235 9/19/01 B 3.6.3-11 36 DRR 08-0255 3/11/08 B 3.6.3-12 36 DRR 08-0255 3/11/08 B 3.6.3-13 36 DRR 08-0255 3/11/08 B 3.6.3-14 36 DRR 08-0255 3/11/08 B 3.6.3-15 39 DRR 08-1096 8/28/08 B 3.6.3-16 39 DRR 08-1096 8/28/08 B 3.6.3-17 36 DRR 08-0255 3/11/08 B 3.6.3-18 36 DRR 08-0255 3/11/08 B 3.6.3-19 36 DRR 08-0255 3/11/08 B 3.6.4-1 39 DRR 08-1096 8/28/08 B 3.6.4-2 0 Amend. No. 123 12/18/99 B 3.6.4-3 0 Amend. No. 123 12/18/99 B 3.6.5-1 0 Amend. No. 123 12/18/99 B 3.6.5-2 37 DRR 08-0503 4/8/08 B 3.6.5-3 13 DRR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12/18/99 B 3.6.6-1 42 DRR 09-1009 7/16/09 B 3.6.6-2 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 ix Revision 49

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TAB - B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.6-3 37 DRR 08-0503 4/8/08 B 3.6.6-4 42 DRR 09-1009 7/16/09 B 3.6.6-5 0 Amend. No. 123 12/18/99 B 3.6.6-6 18 DRR 04-1018 9/1/04 B 3.6.6-7 0 Amend. No. 123 12/18/99 B 3.6.6-8 32 DRR 07-0139 2/7/07 B 3.6.6-9 32 DRR 07-0139 2/7/07 B 3.6.7-1 0 Amend. No. 123 12/18/99 B 3.6.7-2 42 DRR 09-1009 7/16/09 B 3.6.7-3 0 Amend. No. 123 12/18/99 B 3.6.7-4 29 DRR 06-1984 10/17/06 B 3.6.7-5 42 DRR 09-1009 7/16/09 TAB - B 3.7 PLANT SYSTEMS D O.1.1-1 v Amend. No. 123 12/18/99 B 3.7.1-2 0 Amend. No. 123 12/18/99 B 3.7.1-3 0 Amend. No. 123 12/18/99 B 3.7.1-4 0 Amend. No. 123 12/18/99 B 3.7.1-5 32 DRR 07-0139 2/7/07 B 3.7.1-6 32 DRR 07-0139 277107 B 3.7.2-1 44 DRR 09-1744 10/28/09 B 3.7.2-2 44 DRR 09-1744 10/28/09 B 3.7.2-3 44 DRR 09-1744 10/28/09 B 3.7.2-4 44 DRR 09-1744 10/28/09 B 3.7.2-5 44 DRR 09-1744 10/28/09 B 3.7.2-6 44 DRR 09-1744 10/28/09 B 3.7.2-7 44 DRR 09-1744 10/28/09 B 3.7.2-8 44 DRR 09-1744 10/28/09 B 3.7.2-9 44 DRR 09-1744 10/28/09 B 3.7.2-10 44 DRR 09-1744 10/28/09 B 3.7.2-11 44 DRR 09-1744 10/28/09 B 3.7.3-1 37 DRR 08-0503 4/8/08 B 3.7.3-2 46 DRR 10-0719 4/22/10 B 3.7.3-3 37 DRR 08-0503 4/8/08 B 3.7.3-4 37 DRR 08-0503 4/8/08 B 3.7.3-5 37 DRR 08-0503 4/8/08 B 3.7.3-6 37 DRR 08-0503 4/8/08 B 3.7.3-7 37 DRR 08-0503 4/8/08 B 3.7.3-8 37 DRR 08-0503 4/8/08 B 3.7.3-9 37 DRR 08-0503 4/8/08 B 3.7.3-10 38 DRR 08-0624 5/1/08 B 3.7.3-11 37 DRR 08-0503 4/8/08 B 3.7.4-1 1 DRR 99-1624 12/18/99 B 3.7.4-2 1 DRR 99-1624 12/18/99 B 3.7.4-3 19 DRR 04-1414 10/12/04 B 3.7.4-4 19 DRR 04-1414 10/12/04 B 3.7.4-5 1 DRR 99-1624 12/18/99 B 3.7.5-1 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 X Revision 49

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TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.5-2 0 Amend. No. 123 12/18/99 B 3.7.5-3 0 Amend. No. 123 12/18/99 B 3.7.5-4 44 DRR 09-1744 10/28/09 B 3.7.5-5 44 DRR 09-1744 10/28/09 B 3.7.5-6 44 DRR 09-1744 10/28/09 B 3.7.5-7 32 DRR 07-0139 2/7/07 B 3.7.5-8 14 DRR 03-0102 2/12/03 B 3.7.5-9 32 DRR 07-0139 2/7/07 B 3.7.6-1 0 Amend. No. 123 12/18/99 B 3.7.6-2 0 Amend. No. 123 12/18/99 B 3.7.6-3 0 Amend. No. 123 12/18/99 B 3.7.7-1 .0 Amend. No. 123 12/18/99 B 3.7.7-2 0 Amend. No. 123 12/18/99 B 3.7.7-3 0 Amend. No. 123 12/18/99 B 3.7.7-4 1 DRR 99-1624 12/18/99 B 3.7.8-1 0 Amend. No. 123 12/18/99 B 3.7.8-2 0, Amend. No. 123 12/18/99 B 3.7.8-3 0 Amend. No. 123 12/18/99 B 3.7.8-4 0 Amend. No. 123 12/18/99 B 3.7.8-5 0 Amend. No. 123 12/18/99 B 3.7.9-1 3 Amend. No. 134 7/14/00 B 3.7.9-2 3 Amend. No. 134 7/14/00 B 3.7.9-3 3 Amend. No. 134 7/14/00 B 3.7.9-4 3 Amend. No. 134 7/14/00 B 3.7.10-1 41 DRR 09-0288 3/20/09 B 3.7.10-2 41 DRR 09-0288 3/20/09 B 3.7.10-3 41 DRR 09-0288 3/20/09 B 3.7.10-4 41 DRR 09-0288 3/20/09 B 3.7.10-5 41 DRR 09-0288 3/20/09 B 3.7.10-6 41 DRR 09-0288 3/20/09 B 3.7.10-7 41 DRR 09-0288 3/20/09 B 3.7.10-8 41 DRR 09-0288 3/20/09 B 3.7.10-9 .41 DRR 09-0288 3/20/09 B 3.7.11-1 0 Amend. No. 123 12/18/99 B 3.7.11-2 0 Amend. No. 123 12/18/99 B 3.7.11-3 0 Amend. No. 123 12/18/99 B 3.7.11-4 0 Amend. No. 123 12/18/99 B 3.7.12-1 0 Amend. No. 123 12/18/99 B 3.7.13-1 24 DRR 06-0051 2/28/06 B 3.7.13-2 1 DRR 99-1624 12/18/99 B 3.7.13-3 42 DRR 09-1009 7/16/09 B 3.7.13-4 1 DRR 99-1624 12/18/99 B 3.7.13-5 1 DRR 99-1624 12/18/99 B 3.7.13-6 12 DRR 02-1062 9/26/02 B 3.7.13-7 1 DRR 99-1624 12/18/99 B 3.7.13-8 1 DRR 99-1624 12/18/99 B 3.7.14-1 0 Amend. No. 123 12/18/99 B 3.7.15-1 0 Amend. No. 123 12/18/99 B 3.7.15-2 0 Amend. No. 123 12/18/99 B 3.7.15-3 0 Amend. No. 123 12/18/99 B 3.7.16-1 5 DRR 00-1427 10/12/00 Wolf Creek - Unit 1 xi Revision 49

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TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.16-2 23 DRR 05-1995 9/28/05 B 3.7.16-3 5 DRR 00-1427 10/12/00 B 3.7.17-1 7 DRR 01-0474 5/1/01 B 3.7.17-2 7 DRR 01-0474 5/1/01 B 3.7.17-3 5 DRR 00-1427 10/12/00 B 3.7.18-1 0 Amend. No. 123 12/18/99 B 3.7.18-2 0 Amend. No. 123 12/18/99 B 3.7.18-3 0 Amend. No. 123 12/18/99 B 3.7.19-1 44 DRR 09-1744 10/28/09 B 3.7.19-2 44 DRR 09-1744 10/28/09 B 3.7.19-3 44 DRR 09-1744 10/28/09 B 3.7.19-4 44 DRR 09-1744 10/28/09 B 3.7.19-5 44 DRR 09-1744 10/28/09 TAB - B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1-1 0 Amend. No. 123 12/18/99 B 3.8.1-2 0 Amend. No. 123 12/18/99 B 3.8.1-3 47 DRR 10-1089 6/16/10 B 3.8.1-4 47 DRR 10-1089 6/16/10 B 3.8.1-5 25 DRR 06-0800 5/18/06 B 3.8.1-6 25 DRR 06-0800 5/18/06 B 3.8.1-7 26 DRR 06-1350 7/24/06 B 3.8.1-8 35 DRR 07-1553 9/28/07 B 3.8.1-9 42 DRR 09-1009 7/16/09 B 3.8.1-10 39 DRR 08-1096 8/28/08 B 3.8.1-11 36 DRR 08-0255 3/11/08 B 3.8.1-12 47 DRR 10-1089 6/16/10 B 3.8.1-13 47 DRR 10-1089 6/16/10 B 3.8.1-14 47 DRR 10-1089 6/16/10 B 3.8.1-15 47 DRR 10-1089 6/16/10 B 3.8.1-16 26 DRR 06-1350 7/24/06 B 3.8.1-17 26 DRR 06-1350 7/24/06 B 3.8.1-18 26 DRR 06-1350 7/24/06 B 3.8.1-19 26 DRR 06-1350 7/24/06 B 3.8.1-20 26 DRR 06-1350 7/24/06 B 3.8.1-21 33 DRR 07-0656 5/1/07 B 3.8.1-22 33 DRR 07-0656 5/1/07 B 3.8.1-23 40 DRR 08-1846 12/9/08 B 3.8.1-24 33 DRR 07-0656 5/1/07 B 3.8.1-25 33 DRR 07-0656 5/1/07 B 3.8.1-26 33 DRR 07-0656 5/1/07 B 3.8.1-27 33 DRR 07-0656 5/1/07 B 3.8.1-28 33 DRR 07-0656 5/1/07 B 3.8.1-29 33 DRR 07-0656 5/1/07 B 3.8.1-30 33 DRR 07-0656 5/1/07 B 3.8.1-31 33 DRR 07-0656 5/1/07 B 3.8.1-32 33 DRR 07-0656 5/1/07 B 3.8.1-33 39 DRR 08-1096 8/28/08 B 3.8.1-34 47 DRR 10-1089 6/16/10 B 3.8.2-1 0 Amend. No. 123 12/18/99 B 3.8.2-2 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 xii Re~vision49

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.2-3 0 Amend. No. 123 12/18/99 B 3.8.2-4 0 - Amend. No. 123 12/18/99 B 3.8.2-5 12 DRR 02-1062 9/26/02 B 3.8.2-6 12 DRR 02-1062 9/26/02 B 3.8.2-7 12 DRR 02-1062 9/26/02 B 3.8.3-1 1 DRR 99-1624 12/18/99 B 3.8.3-2 0 Amend. No. 123 12/18/99 B 3.8.3-3 0 Amend. No. 123 12/18/99 B 3.8.3-4 i DRR 99-1624 12/18/99 B 3.8.3-5 0 Amend. No. 123 12/18/99 B 3.8.3-6 0 Amend. No. 123 12/18/99 B 3.8.3-7 12 DRR 02-1062 9/26/02 B 3.8.3-8 1 DRR 99-1624 12/18/99 B 3.8.3-9 0 Amend. No. 123 12/18/99 B 3.8.4-1 0 Amend.: No. 123 *12/18/99 B 3.8.4-2 0 Amend. No. 123 12/18/99 B 3.8.4-3 0 Amend. No. 123 12/18/99 B 3.8.4-4 0 Amend. No. 123 12/18/99 B 3.8.4-5 0 Amend. No. 123 12/18/99 B 3.8.4-6 0 Amend. No. 123 12/18/99 B 3.8.4-7 6 DRR 00-1541 3/13/01 B 3.8.4-8 0 Amend. No. 123 12/18/99 B 3.8.4-9 2 DRR 00-0147 4/24/00 B 3.8.5-1 0 Amend. No. 123 12/18/99 B 3.8.5-2 0 Amend. No. 123 12/18/99 B 3.8.5-3 0 Amend. No. 123 12/18/99 B 3.8.5-4 12 DRR 02-1062 9/26/02 B 3.8.5-5 12 DRR 02-1062 9/26/02 B 3.8.6-1 0 Amend. No. 123 12/18/99 B 3.8.6-2 0 Amend. No. 123 12/18/99 B 3.8.6-3 0 Amend. No. 123 12/18/99 B 3.8.6-4 0 Amend. No. 123 12/18/99 B 3.8.6-5 0 Amend. No. 123 12/18/99 B 3.8.6-6 0 Amend. No. 123 12/18/99 B 3.8.7-1 0 Amend. No. 123 12/18/99 B 3.8.7-2 5 DRR 00-1427 10/12/00 B 3.8.7-3 0 Amend. No. 123 12/18/99 B 3.8.7-4 0 Amend. No. 123 12/18/99 B 3.8.8-1 0 Amend. No. 123 12/18/99 B 3.8.8-2 0 Amend. No. 123 12/18/99 B 3.8.8-3 0 Amend. No. 123 12/18/99 B 3.8.8-4 12 DRR 02-1062 9/26/02 B 3.8.8-5 12 DRR 02-1062 9/26/02 B 3.8.9-1 0 Amend. No. 123 12/18/99 B 3.8.9-2 0 Amend. No. 123 12/18/99 B 3.8.9-3 0 Amend. No. 123 12/18/99 B 3.8.9-4 0 Amend. No. 123 12/18/99 B 3.8.9-5 0 Amend. No. 123 12/18/99 B 3.8.9-6 0 Amend. No. 123 12/18/99 B 3.8.9-7 0 Amend. No. 123 12/18/99 B 3.8.9-8 1 DRR 99-1624 12/18/99 Wolf Creek - Unit 1 xiii Revision49

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)-

B 3.8.9-9 0 Amend. No. 123 12/18/99 B 3.8.10-1 0 Amend. No. 123 12/18/99 B 3.8.10-2 0 Amend. No. 123 12/18/99 B 3.8.10-3 0 Amend. No. 123 12/18/99 B 3.8.10-4 0 Amend. No. 123 12/18/99 B 3.8.10-5 12 DRR 02-1062 9/26/02 B 3.8.10-6 12 DRR 02-1062 9/26/02 TAB - B 3.9 REFUELING OPERATIONS B 3.9.1-1 0 Amend. No. 123 12/18/99 B 3.9.1-2 19 DRR 04-1414 10/12/04 B 3.9.1-3 19 DRR 04-1414 10/12/04 B 3.9.1-4 19 DRR 04-1414 10/12/04 B 3.9.2-1 0 Amend. No. 123 12/18/99 B 3.9.2-2 0 Amend. No. 123 12/18/99 B 3.9.2-3 0 Amend. No. 123 12/18/99 B 3.9.3-1 24 DRR 06-0051 2/28/06 B 3.9.3-2 24 DRR 06-0051 2/28/06 B 3.9.3-3 24 DRR 06-0051 2/28/06 B 3.9.3-4 24 DRR 06-0051 2/28/06 B 3.9.4-1 23 DRR 05-1995 9/28/05 B 3.9.4-2 13 DRR 02-1458 12/03/02 B 3.9.4-3 25 DRR 06-0800 5/18/06 B 3.9.4-4 23 DRR 05-1995 9/28/05 B 3.9.4-5 33 DRR 07-0656 5/1/07 B 3.9.4-6 23 DRR 05-1995 9/28/05 B 3.9.5-1 0 Amend. No. 123 12/18/99 B 3.9.5-2 32 DRR 07-0139 2/7/07 B 3.9.5-3 32 DRR 07-0139 2/7/07 B 3.9.5-4 32 DRR 07-0139 2/7/07 B 3.9.6-1 0 Amend. No. 123 12/18/99 B 3.9.6-2 42 DRR 09-1009 7/16/09 B 3.9.6-3 42 DRR 09-1009 7/16/09 B 3.9.6-4 42 DRR 09-1009 7/16/09 B 3.9.7-1 25 DRR 06-0800 5/18/06 B 3.9.7-2 0 Amend. No. 123 12/18/99 B 3.9.7-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 AiV Re~vision49

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IMPLEMENTED (4)

Note 1 The page number is listed on the center of the bottom of each page.

Note 2 The revision number is listed in the lower right hand corner of each page. The Revision number will be page specific.

Note 3 The change document will be the document requesting the change. Amendment No.

123 issued the improved Technical Specifications and associated Bases which affected each page. The NRC has indicated that Bases changes will not be issued with License Amendments. Therefore, the change document should be a DRR number in..

accordance with AP 26A-002.

Note 4 The date effective or implemented is the date the Bases pages are issued by Document Control.

Wolf Creek - Unit 1 XV Revision49

ML110750036

Text

Subject:

0.5 where

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