Text

Changes to Technical Specification Bases - Revisions 32 Through 35
	ML080780560
Person / Time
Site:	Wolf Creek
Issue date:	03/07/2008
From:	Flannigan R; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 08-0023
	Download: ML080780560 (69)
	v • d • e

W0LF CREEKINUCLEAR OPERATING CORPORATION Richard D. Flannigan Manager Regulatory Affairs March 7, 2008 RA 08-0023 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 32 through 35 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 32 through 35) under the provisions of TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2007 through December 31, 2007.

This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4117, or Diane Hooper at (620) 364-4041.

Sincerely, Richard D.! Flannigan RDF/rlt Enclosure cc: E. E. Collins (NRC), w/e V. G. Gaddy (NRC), w/e B. K. Singal (NRC), w/e 7, Senior Resident Inspector (NRC), w/e P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831(*

An Equal Opportunity Employer M/F/HC/VET

Enclosure to RA 08-0023 Wolf Creek Generating Station Changes to the Technical Specification Bases

LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY BASES LCOs LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

LCO 3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered. The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

Wolf Creek - Unit 1 B 3.0-1 Revision 34

LCO Applicability B 3.0 BASES LCO 3.0.2 Completing the Required Actions is not required when an LCO is met or is (continued) no longer applicable, unless otherwisestated in the individual Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational problems.

Entering ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience. Additionally, if intentional entry into ACTIONS would result in redundant equipment being inoperable, alternatives should be used instead. Doing so limits the time both subsystems/trains of a safety function are inoperable and limits the time conditions exist which may result in LCO 3.0.3 being entered. Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable, and the ACTIONS Condition(s) are entered.

LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or Wolf Creek- Unit 1 B 3.0-2 'Revision 0

LCO Applicability B 3.0 BASES LCO 3.0.6 Cross train checks to identify a loss of safety function for those support (continued) systems that support multiple and redundant safety systems are required.

The cross train check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

LCO 3.0.7 There are certain special tests and .operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions.

Test Exception LCO 3.1.8 allows specified Technical Specification (TS) requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the. requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Test Exception LCO represents a condition not necessarily in compliance with the normal requirements of the TS.

Compliance with Test Exception LCOs is optional. A special operation may be performed either under the provisions of the appropriate Test Exception LCO or Under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Test Exception LCO, the requirements of the Test Exception LCO shall be followed.

LCO 3.0.8 LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures are specified in the snubber requirements, which are located outside of the Technical Specifications (TS) Under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee.

Wolf Creek - Unit 1 B 3.0-9 Revision 34

LCO Applicability B 3.0 BASES LCO 3.0.8 If the allowed time expires and the snubber(s) are unable to perform their (continued) associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore the snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.

LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to restore the snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function.

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perform their associated support function.

Wolf Creek - Unit 1 B 3.0-10 Revision 34

SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance(s) are known not to be met between required'Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a test exception are only applicable when the test exception is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given MODE or other specified condition.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2.

Post maintenance testing may not be possible in the current MODE or Wolf Creek - Unit 1 B 3.&-l11 Revision 34 1

SR Applicability B 3.0 BASES SR 3.0.1 other specified conditions in the Applicability due to the necessary unit (continued) parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per..." interval.

SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Therefore, when a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the SRs include a Note in the Frequency stating, "SR 3.0.2 is not applicable." An example of an exception when the test interval is not specified in the regulations is the Note in the Containment Leakage Rate Testing Program, "SR 3.0.2 is not applicable." This exception is provided because the program already includes extension of test intervals.

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic CompletionTime that requires performance on a "once per ..." basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action With a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes Wolf Creek - Unit 1 B 3.0-12 . Revision 34 1

SR Applicability B 3.0 BASES SR 3.0.2 the function of the inoperable equipment in an alternative manner.

(continued)

The provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or up to the limit of the specified Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified,' SR 3.0.3allows for the full delay period of up to the specified Frequency to perform the Surveillance.

However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which 'is not intended to be used as an operational Wolf Creek - Unit 1 B.310-1 3 Revision 34 1

SR Applicability B 3.0 BASES SR 3.0.3 convenience to extend Surveillance intervals. While up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or the (continued) limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."

This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

Wolf Creek - Unit 1 B 3.0-14 Revision 34 1

SR Applicability B 3.0 BASES SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.

This Specification ensures that system and component OPERABILITY requirements and variable limits are, met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or component to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4.

However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change.

When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment., When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other'specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, MODE 4 to MODE 5, and MODE 5 to MODE 6.

Wolf Creek - Unit 1 13,3.0-15 Revision 34 1

SR Applicability B3.0 BASES SR 3.0.4 The precise requirements for performance of SRs are specified such that (continued) exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met.

Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.

Wolf Creek - Unit 1 B 3.0-16 Revision 34 1

Pressurizer Safety Valves B 3.4.10 BASES LCO more valves could result in exceeding the SL if a transient were to occur.

(continued) The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor operation.

APPLICABILITY In MODES 1, 2, and 3, OPERABILITY of three valves is required because the combined capacity is required to keep reactor coolant pressure below 110% of its design value during certain accidents. MODE 3 is conservatively included, although the listed accidents may not require the safety valves for protection.

The LCO is not applicable in MODE 4, MODE 5, or MODE 6 with the reactor vessel head on because LTOP is in service. Overpressure protection is not required in MODE 6 with the reactor vessel head removed (vent path > 2.0 square inches).

The Note allows entry into MODE 3 with the lift settings outside the LCO limits. This method permits the inplace testing and examination of the safety valves at high pressure and temperature near their normal operating range, but only after the valves have had a preliminary cold setting. The cold setting gives assurance that the valves are OPERABLE near their design condition. Only one valve at a time will be removed from service for testing. The 54 hour6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months exception is based on 18 hour2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months outage time for each of the three valves. The 18 hour2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months period is derived from operating experience that hot testing can be performed in this timeframe.

ACTIONS A.1 With one pressurizer safety valve inoperable, restoration must take place within 15 minutes. The Completion Time of 15 minutes reflects the importance of maintaining the RCS Overpressure Protection System. An inoperable safety valve coincident with an RCS overpressure event could challenge the integrity of the pressure boundary.

B.1 and B.2 If the Required Action of A. 1 cannot be met within the required Completion Time or iftwo or more pressurizer safety valves are inoperable, 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 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within Wolf Creek - Unit 1 B 3.4.10-3 Revision 0

Pressurizer Safety Valves B 3.4.10 BASES ACTIONS B.1 and B.2 (continued) 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. With any RCS cold leg temperatures at or below 368 0 F, overpressure protection is provided by the LTOP System. The change from MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power and pressure), lowers the potential for large pressurizer insurges, and thereby removes the need for overpressure protection by three pressurizer safety valves.

Addition to the RCS of borated water with a concentration greater than or equal to the minimum required RWST concentration shall not be.

considered a positive reactivity change. Cooldown of the RCS for restoration of OPERABILITY of a pressurizer code safety valve, with a negative moderator temperature coefficient, shall not be considered a positive reactivity change provided the RCS is borated to the COLD SHUTDOWN, xenon-free condition per Specification 3.1.1 (Ref. 5).

SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the Inservice Testing Program. Pressurizer safety valves are to be tested in accordance with the requirements of the ASME Code (Ref. 4), which provides the activities and Frequencies necessary to satisfy the SRs. No additional requirements are specified.

The pressurizer safety valve setpoint tolerance is +/- 2% for OPERABILITY, however, the valves shall be set at 2460 psig +/- 1% per Ref. 1 to allow for drift.

REFERENCES 1. ASME, Boiler and Pressure Vessel Code, Section II1.

2. USAR, Chapter 15.

3. WCAP-7769, Rev. 1, June 1972.

4. ASME Code for Operation and Maintenance of Nuclear Power I . "

Plants.

5. NRC letter (W. Reckley to N. Cams) dated November 22, 1993:

"Wolf Creek Generating Station - Positive Reactivity Addition; Technical Specification Bases Change."

Wolf Creek - Unit 1 B 3.4.10-4 Revision 32

Pressurizer PORVs B 3.4.11 BASES ACTIONS G.1 and G.2 (continued)

If the Required Actions of Condition F are not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion.Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES, 3 (with any RCS cold leg temperature <

3680 F), 4, 5, and 6 (with the reactor vessel head on) automatic PORV OPERABILITY may be required. See LCO 3.4.12.

SURVEILLANCE SR 3.4.11.1 REQUIREMENTS Block valve cycling verifies that the valve(s) can be opened and closed.

The basis for the Frequency of 92 days is the ASME Code (Ref. 4).

The Note modifies this SR by stating that it is not required to be performed with the block valve closed, in accordance with the Required Actions of this LCO. Opening the block valve in this condition increases the risk of an unisolable leak from the RCS since the PORV is already inoperable.

SR 3.4.11.2 SR 3.4.11.2 requires a complete cycle of each PORV. Operating a PORV through one complete cycle ensures that the PORV can be manually actuated for mitigation of an SGTR. Operating experience has shown that these valves usually pass the Surveillance when performed at the required Inservice Testing Program frequency. The Frequency is acceptable from a reliability standpoint.

REFERENCES 1. USAR, Figure 7.2-1 (Sheet 11) and 7.6-4 (Sheets 1-3).

2. Regulatory Guide 1.32, February 1977.

3. USAR, Section 15.2.

4. ASME Code for Operation and Maintenance of Nuclear Power Plants.

Wolf Creek - Unit I B 3.4.11-7 Revision 32

LTOP System B 3.4.12 BASES ACTIONS G. 1 (continued)

The RCS must be depressurized and a vent must be established within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months when:

a. Both required RCS relief valves are inoperable; or

b. A Required Action and associated Completion Time of Condition A, B, D, E, or F is not met; or

c. The LTOP System is inoperable for any reason other than Condition A, B, C, D, E, or F.

The vent must be sized > 2.0 square inches to ensure that the flow capacity is greater than that required for the worst case mass input transient reasonable during the applicable MODES. This action is needed to protect the RCPB from a low temperature overpressure event and a possible brittle failure of the reactor vessel.

The Completion Time considers the time required to place the plant in this Condition and the relatively low probability of an overpressure event during this time period due to increased operator awareness of administrative control requirements.

SURVEILLANCE SR 3.4.12.1, SR 3.4.12.2, and SR 3.4.12.3 REQUIREMENTS To minimize the potential for a low temperature overpressure event by limiting the mass input capability, a maximum of zero safety injection pumps and a maximum of one charging pump are verified to be capable of injecting into the RCS and the accumulator discharge isolation valves are verified closed and with power removed from the valve operator.

Verification that each accumulator is isolated is only required when accumulator pressure is greater than or equal to the maximum RCS pressure for the existing RCS cold leg temperature allowed by the P/T limit curves provided in the PTLR.

The safety injection pumps and one centrifugal charging pumps are rendered incapable of injecting into the RCS through removing the power from the pumps by racking the breakers out under administrative control.

An alternate method of cold overpressure protection may be employed using at least two independent means to render a pump incapable of injecting into the RCS such that a single failure or single action will not Wolf Creek - Unit 1 B 3.4.12-11 Revision 0

LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1, SR 3.4.12.2, and SR 3.4.12.3 (continued)

REQUIREMENTS result in an injection into the RCS. This may be accomplished by placing the pump control switch in pull to lock and closing at least one valve in the discharge flow path, or-by closing at least one valve in the discharge flow path and removing power from the valve operator, or by closing at least one manual valve in the discharge flow path under administrative control.

Providing pumps are rendered incapable of injecting into the RCS, they may be energized for purposes such as testing or for filling accumulators.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment.

SR 3.4.12.4 Each required RHR suction relief valve shall be demonstrated OPERABLE by verifying its RHR suction isolation valves are open and by testing it in accordance with the Inservice Testing Program. This Surveillance is only required to be performed ifthe RHR suction relief valve is being used to meet this LCO.

The RHR suction isolation valves are verified to be opened every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The Frequency is considered adequate in view of other administrative controls such as valve status indications available to the operator in the control room that verify the RHR suction isolation valves remain open.

The ASME Code (Ref. 8), test per Inservice Testing Program verifies OPERABILITY by proving proper relief valve mechanical motion and by measuring and, if required, adjusting the lift setpoint.

SR 3.4.12.5 The RCS vent of > 2.0 square inches is proven OPERABLE by verifying its open condition either:

a. Once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for a'valve that is not locked, sealed, or otherwise secured in the open position.

Wolf Creek - Unit 1 B 3.4.12-12 Revision 32

LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.5 (continued)

REQUIREMENTS

b. Once every 31 days for other vent paths (e.g., for a vent valve, a valve that is locked, sealed, or otherwise secured in position). A removed pressurizer safety valve or open manway fits this category.

Any passive vent path arrangement must only be open when required to be OPERABLE. This Surveillance is required ifthe vent is being used to satisfy the pressure relief requirements of the LCO 3.4.12.d.

SR 3.4.12.6 The PORV block valve must be verified open every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to provide the flow path for each required PORV to perform its function when actuated. The valve must be remotely verified open in the main control room: This Surveillance is only required to be performed if the PORV is being used to meet this LCO.

The block valve is a remotely controlled, motor operated valve. The power to the valve operator is not required removed, and the manual operator is not required locked in the inactive position. Thus, the block valve can be closed in the event the PORV develops excessive leakage or does not close (sticks open) after relieving an overpressure situation.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is considered adequate in view of other administrative controls available to the operator in the control room, such as valve position indication, that verify that the PORV block valve remains open.

SR 3.4.12.7 Not Used.

SR 3.4.12.8 Performance of a COT is required within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS temperature to < 3680 F andevery 31 days on each required PORV to verify and, as necessary, adjust its lift Setpoint. The COT will verify the setpoint is within the PTLR allowed maximum limits in the PTLR. PORV actuation could depressurize the RCS and is not required.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance considers the unlikelihood of a low temperature overpressure event during this time.

Wolf.Creek - Unit 1 B3.4.12-13 Revision 0

LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.8 (continued)

REQUIREMENTS A Note has been added indicating that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to _<368°F.

SR 3.4.12.9 Performance of a CHANNEL CALIBRATION on each required PORV actuation channel is required every 18 months to adjust the whole channel so that it responds and the valve opens within the required range and accuracy to known input.

REFERENCES 1. 10 CFR 50, Appendix G.

2. Generic Letter 88-11.

3. ASME, Boiler and Pressure Vessel Code,Section III.

4. USAR, Chapter 15.

5. 10 CFR 50, Section 50.46.

6. 10 CFR 50, Appendix K.

7. Generic Letter 90-06.

8. ASME Code for Operation and Maintenance of Nuclear Power Plants'

9. USAR, Section 5.2.2.10.

Wolf Creek - Unit 1 B*3.4.12-14 Revision 32

RCS Operational LEAKAGE B 3.4.13 BASES LCO b. Unidentified LEAKAGE (continued)

One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE Through Any One SG The limit of 150 gallons per day per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, "Steam Generator Program Guidelines," (Ref. 6). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational LEAKAGE rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

APPLICABILITY In MODES 1. 2. 3. and 4. the potential for RCS operational LEAKAGE is I greatest when the RCS is pressurized.

Wolf Creek - Unit 1 .B 3.4.13ý-3 Revision 29

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABILITY In MODES 5 and 6, RCS operational LEAKAGE limits are not required (continued) because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

ACTIONS A.1 Unidentified LEAKAGE or identified LEAKAGE in excess of the LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 If any pressure boundary LEAKAGE exists or primary to secondary LEAKAGE is not within limit, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting~on the RCPB are much lower, and further deterioration is much less 'likely.

SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS operational LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be 'noted that LEAKAGE past seals and Wolf Creek - Unit 1 B 3.4.13-4 Revision 35

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 (continued)

REQUIREMENTS gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be met with the reactor at steady state operating conditions (stable temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The Surveillance is modified by two Notes. Note 1 states that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.

Steady state operation is preferred when performing a proper inventory balance since calculations during non-steady state conditions must account for the changing parameters. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows. An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation."

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory balance. Primary to secondary LEAKAGE is determined by SR 3.4.13.2 and is not determined by an RCS water inventory balance. For determining identified LEAKAGE, identified LEAKAGE includes primary to secondary LEAKAGE as defined in Section 1.1, "Definitions."

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. When non-steady state operation precludes surveillance performance, the surveillance should be performed in accordance with the Note, provided greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months have elapsed since the last performance.

SR 3.4.13.2 .

This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per day through any one SG. Satisfying the primary to Wolf Creek - Unit 1 B 3.4:13-5 Revision 35

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.2 (continued)

REQUIREMENTS secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.17, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 7. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 7).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 4 and 30.

2. Regulatory Guide 1.45, May 1973.

3. USAR, Section 15.6.3.

4. NUREG-1061, Volume 3, November 1984.

5. 10 CFR 100.

6. NEI 97-06, "Steam Generator Guidelines."

7. EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Wolf Creek - Unit 1 B 3.4.1:3-6 Revision. 29

RCS PIV Leakage B 3.4.14 BASES SURVEILLANCE SR 3.4.14.1 (continued)

REQUIREMENTS 0.5 gpm per inch of nominal valve diameter up to 5 gpm maximum applies to each valve. Leakage testing requires a stable pressure condition.

For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves. If the PIVs are not individually leakage tested, one valve may have failed completely and not be detected ifthe other valve in series meets the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

Testing is to be performed every 18 months, a typical refueling cycle, if the plant does not go into MODE 5 for at least 7 days. The 18 month Frequency is within the frequency allowed by the American Society of Mechanical Engineers (ASME) Code (Ref. 6), and is based on the need to perform such surveillances under the conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Test pressures less. than 2235 psig but greater than 150 psig are allowed for valves where higher pressures could tend to diminish leakage channel opening. Observed leakage shall be adjusted for actual pressure to 2235 psig assuming the leakage to be directly proportional to pressure differential to the one half power.

In addition, testing must be performed once after the check valve has been opened by flow or exercised to ensure tight reseating. PIVs disturbed in the performance of this Surveillance should also be tested unless documentation shows that an infinite testing loop cannot practically be avoided. Testing must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the check valve has been reseated. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable and practical time limit for performing this test after opening or reseating a check valve.

The leakage limit is to be met at the RCS pressure associated with MODES. 1 and 2:: This permits leakage testing at high differential pressures with stable conditions not possible in the MODES with lower pressures.

Wolf Creek - Unit 1 B 3.4.*14-5 Revision 32

RCS PIV Leakage B 3.4.14 BASES SURVEILLANCE SR 3.4.14.1 (continued)

REQUIREMENTS Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable conditions to allow for performance of this Surveillance. The Note that allows this provision is complementary to the Frequency of prior to entry into MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months. In addition, this Surveillance is not required to be performed on the RHR System when the RHR System is aligned to the RCS in the shutdown cooling mode of operation. PIVs contained in the RHR shutdown cooling flow path must be leakage rate tested after RHR is secured and stable unit conditions and the necessary differential pressures are established.

SR 3.4.14.2 The RHR suction isolation valve interlock setpoint that prevents the valves from being opened is set so the actual RCS pressure must be < 425 psig to open the valves. This setpoint ensures the RHR design pressure will not be exceeded and the RHR relief valves will not lift. The 18 month Frequency is based on the need to perform the Surveillance under conditions that apply during a plant outage. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment. This SR is not required to be performed when the RHR suction isolation valves are open to satisfy LCO 3.4.12.

REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. 10 CFR 50, Appendix A, Section V, GDC 55.

4. WASH-1400 (NUREG-75/014), Appendix V, October 1975.

5. NUREG-0677, May 1980.

6. ASME Code for Operation and Maintenance of Nuclear Power Plants.

Wolf Creek - Unit 1 B'3.4'114-6 Revision. 32

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 (continued)

REQUIREMENTS problems is required by the ASME Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. The following ECCS pumps are required to develop the indicated differential pressure on recirculation flow:

Centrifugal Charging Pump . __2490 psid Safety Injection Pump _ 1468.9 psid RHR Pump > 183.6 psid This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the plant safety analysis. SRs are specified in the applicable portions of the Inservice Testing Program, which encompasses the ASME Code. The ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

SR 3.5.2.5 and SR 3.5.2.6 These Surveillances demonstrate that each automatic ECCS valve actuates to the required position on an actual or simulated SI signal and on an actual or simulated RWST Level Low-Low 1 Automatic Transfer signal coincident with an SI signal and that each ECCS pump starts on receipt of an actual or simulated SI signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for unplanned plant transients if the Surveillances were performed with the reactor at power.

The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

The actuation logic is-tested as part of. ESF Actuation System testing, and equipment performance is monitored as part of the Inservice Testing Program:

Wolf Creek - Unit 1 B ;3.5.2ý9 Revision 35

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.7 REQUIREMENTS (continued) The position of throttle valves in the flow path is necessary for proper ECCS performance. These valves are necessary to restrict flow to a ruptured cold leg, ensuring, that the other cold legs receive at least the required minimum flow. The 18 month Frequency is based on the same reasons as those stated in SR 3.5.2.5 and SR 3.5.2.6. The ECCS throttle valves are set to ensure proper flow resistance and pressure drop in the piping to each injection point in the event of a LOCA. Once set, these throttle valves are secured with locking devices and mechanical position stops. These devices help to ensure that the following safety analyses assumptions remain valid: (1) both the maximum and minimum total system resistance; (2) both the maximum and minimum branch injection line resistance; and (3) the maximum and minimum ranges of potential pump performance. These resistances and pump performance ranges are used to calculate the maximum and minimum ECCS flows assumed in the LOCA analyses of Reference 3.

SR 3.5.2.8 This SR requires verification that each ECCS train containment sump inlet is not restricted by debris and the suction inlet strainers show no evidence of structural distress or abnormal corrosion. A visual inspection of the suction inlet piping verifies the piping is unrestricted. A visual inspection of the accessible portion of the containment sump strainer assembly verifies no evidence of structural distress or abnormal corrosion.

Verification of no evidence of structural distress ensures there are no openings in excess of the maximum designed strainer opening. The 18 month Frequency has been found to be sufficient to detect abnormal degradation and is confirmed by operating experience.

REFERENCES 1. ' 10 CFR 50, Appendix A, GDC 35.

2. 10 CFR 50.46.

3. USAR, Sections 6.3 and 15.6.

4. USAR, Chapter 15, "Accident Analysis."

5. NRC Memorandum to V. Stello, Jr., from R.L. Baer, "Recommended Interim Revisions to LCOs for ECCS Components,"

December 1, 1975.

6. IE Information Notice No. 87,01.

7. BTP EICSB-18, Application of the Single Failure Criteria to Manually-Controlled Electrically-Operated Valves.

B 3.5.2-10 Revision 33 Wolf Creek Wolf -

Unit 1 Creek - Unit 1 B 3.5.2'-10 Revision 33

Containment Spray and Cooling Systems B 3.6.6 BASES ACTIONS F.1 (continued)

With two containment spray trains or any combination of three or more containment spray and cooling trains inoperable, the unit is in a condition outside the accident analysis. Therefore, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.6.6.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the containment spray flow path provides assurance that the proper flow paths will exist for Containment Spray System operation. The correct alignment for the Containment Cooling System valves is provided in SR 3.7.8.1. This SR does not apply to manual vent/drain valves and to valves that cannot be advertently misaligned such as check valves. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these were verified to be in the correct position prior to locking, sealing, or securing. This SR does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown (which may include the use of local or remote indicators), that those valves outside containment and

-capable of potentially being mispositioned are in the correct position. The 31 day Frequency is based on engineering judgement, is consistent with administrative controls governing valve operation, and ensures correct valve positions.

SR 3.6.6.2 Operating each containment cooling train fan unit for _ 15 minutes ensures that all fan units are OPERABLE. It also ensures the abnormal conditions or degradation of the fan unit can be detected for corrective action. The 31 day Frequency was developed considering the known reliability of the fan units and controls, the two train redundancy available, and the low probability of significant degradation of the containment cooling train occurring between surveillances. It has also been shown to be acceptable through operating experience.

SR 3.6.6.3 Not.Used..

SR 3.6.6.4 Verifying each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential pressure are normal tests of centrifugal pump performance BASES Wolf-Creek - Unit 1 B 3.6.6-7, Revision 0

Containment Spray and Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.4 (continued)

REQUIREMENTS required by the ASME Code (Ref. 5). Since the containment spray pumps cannot be tested with flow through. the spray headers, they are tested on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by abnormal performance. The Frequency of the SR is in accordance with the Inservice Testing Program.

This test ensures that each pump develops a differential pressure of greater than or equal to 219 psid at a nominal flow of 300 gpm when on recirculation (Ref. 6).

SR 3.6.6.5 and SR 3.6.6.6 These SRs require verification that each automatic containment spray valve actuates to its correct position and that each containment spray pump starts upon receipt of an actual or simulated actuation of a containment High-3 pressure signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillances when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

The surveillance of containment sump isolation valves is also required by SR 3.5.2.5. A single surveillance may be used to satisfy both requirements.

SR 3.6.6.7 This SR requires verification that each containment cooling train actuates upon receipt of an actual or simulated safety injection signal. Upon actuation, each fan in the train starts in slow speed or, if operating, shifts to slow speed and the cooling water flow rate increases to Ž_2000 gpm to each cooler train. The 18 month Frequency is based on engineering judgment and has been shown to be acceptable through operating experience. See SR 3.6.6.5 and SR 3.6.6.6, above, for further discussion of the basis for the 18 month Frequency.

Wolf Creek - Unit 1 B 3.6.6-8 .Revision 32

Containment Spray and Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.8 REQUIREMENTS (continued) With the containment spray inlet valves closed and the spray header drained of any solution, low pressure air or smoke can be blown through test connections. This SR ensures that each spray nozzle is unobstructed and provides assurance that spray coverage of the containment during an accident is not degraded. Due to the passive design of the nozzle, a test at 10 year intervals is considered adequate to detect obstruction of the nozzles.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41. GDC 42, and GDC 43, and GDC 50.

2. 10 CFR 50, Appendix K.

3. USAR, Section 6.2.1.

4. USAR, Section 6.2.2.

5. ASME Code for Operation and Maintenance of Nuclear Power Plants.

6. Performance Improvement Request 2002-0945.

Wolf.Creek - Unit 1 B 3.6.6-9 Revision 32

MSSVs B 3.7.1 BASES ACTIONS B.1 and B.2 (continued) operating experience in resetting all channels of protective function and on the low probability of the occurrence of a transient that could result in steam generator overpressure during this period.

A sensitivity study (Ref. 7) was performed to analyze the loss of load/turbine trip event initiated from power levels based on Table 3.7.1-1 and assuming both beginning of life and end of life reactivity feedback conditions. The results of all cases studied showed that the secondary system peak pressure was maintained below 110% of the secondary system design pressure limit.

Required Action B.2 is modified by a Note, indicating that the Power Range Neutron Flux-High reactor trip setpoint reduction is only required in MODE 1. In MODES 2 and 3 the Reactor Protection System trips specified in LCO 3.3.1, "Reactor Trip System Instrumentation," provides sufficient protection.

The allowed Completion Times are reasonable based on operating experience to accomplish the Required Actions in an orderly manner without challenging unit systems.

C.1 and C.2 If the Required Actions are not completed within the associated Completion Time, or if one or more steam generators have _>4 inoperable MSSVs, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS This SR verifies the OPERABILITY of the MSSVs by the verification of each MSSV lift setpoint in accordance with the Inservice Testing Program.

The ASME Code (Ref. 5), requires that safety and relief valve tests be performed in accordance with ANSI/ASME OM-1-1987 (Ref. 6).

According to Reference 6, the following tests are required:

Wolf Creek - Unit I B 3.7.1-5 Revision 32

MSSVs B 3.7.1 BASES SURVEILLANCE SR 3.7.1.1 (continued)

REQUIREMENTS

a. Visual examination;

b. Seat tightness determination;

c. Setpoint pressure determination (lift setting); and

d. Compliance with owner's seat tightness criteria.

The ANSI/ASME Standard requires that all valves be tested every 5 years, and a minimum of 20% of the valves be tested every 24 months.

The ASME Code specifies the activities and frequencies necessary to satisfy the requirements. Table 3.7.1-2 allows a +/- 3% setpoint tolerance for OPERABILITY; however, the valves are reset to +/- 1% during the Surveillance to allow for drift. The lift settings, according to Table 3.7.1-2, correspond to ambient conditions of the valve at nominal operating temperature and pressure.

This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. The MSSVs may be either bench tested or tested in situ at hot conditions using an assist device to simulate lift pressure. If the MSSVs are not tested at hot conditions, the lift setting pressure shall be corrected to ambient conditions of the valve at operating temperature and pressure.

REFERENCES 1. USAR, Section 10.3.2.

2. ASME, Boiler and Pressure Vessel Code,Section III, Article NC-7000, Class 2 Components.

3. USAR, Section 15.2.

4. NRC Information Notice 94-60, "Potential Overpressurization of the Main Steam System," August 22, 1994.

5. ASME Code for Operation and Maintenance of Nuclear Power Plants.

6. ANSI/ASME OM-1 -1987.

7. AN-94-017 Rev. 0, "RETRAN-02 MSSV Analysis for ITIP 2625,"

M. L. Howard, May 1994.

Wolf Creek - Unit 1 B 3.7.1-6 Revision 32

MFIVs B 3.7.3 BASES ACTIONS D.1 (continued)

Required Action D.1 provides assurance that the appropriate Action is entered for the affected MFIV if its associated actuator trains become inoperable. Failure of both actuator trains for a single MFIV results in the inability to close the affected MFIV on demand.

E.1 With three or more MFIV actuator trains inoperable or when Required Action A.1, B.1, or C.1 cannot be completed within the required Completion Time, the affected MFIVs may be incapable of closing on demand and must be immediately declared inoperable. Having three actuator trains inoperable could involve two inoperable actuator trains on one MFIV and one inoperable actuator train on another MFIV, or an inoperable actuator train on each of three MFIVs, for which the inoperable actuator trains could all be in the same separation group or be staggered among the two separation groups.

Depending on which of these conditions or combinations is in effect, the condition or combination could mean that all of the affected MFIVs remain capable of closing on demand (due to the dual-redundant actuator train design), or that at least one MFIV is inoperable, or.that with an additional single failure up to three MFIVs could be incapable of closing on demand.

Therefore, in some cases, immediately declaring the affected MFIVs inoperable is conservative (when some or all of the affected MFIVs may still be capable of closing on demand even with a single additional failure),

while in other cases it is appropriate (when at least one of the MFIVs would. be inoperable, or up to three could be rendered inoperable by an additional single failure). Required Action E.1 is conservatively based on the worst-case condition and therefore requires immediately declaring all the affected MFIVs inoperable.

F.1 and F.2 Condition F is modified by a Note indicating that separate Condition entry is allowed for each MFIV.

With one MFIV in one or moreflow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable ,affected valves within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . When these valves are closed, they are performing. their required safety function.. Condition F is entered when one or more MFIV is inoperable in MODE 1, including when both actuator trains for one MFIV are inoperable. When only one actuator train is inoperable on one MFIV, Condition A applies.

Wolf Creek - Unit 1 B 3.7.3-5. Revision 30

MFIVs B 3.7.3 BASES ACTIONS F.1 and F.2 (continued)

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the redundancy afforded by the dual-redundant actuators on the MFIVs and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience.

Inoperable MFIVs that are closed must be verified on a periodic basis that they are closed. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of valve status indications available in the control room, and other administrative controls, to ensure that these valves are closed.

G.1 and G.2 If the MFIV(s) cannot be restored to OPERABLE status, or closed, within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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

SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that the closure time of each MFIV is _<5 seconds on an actual or simulated main feedwater isolation actuation signal from each actuator train. The MFIV closure time is assumed in the accident and containment analyses. This Surveillance is normally performed upon returning the unit to operation following a refueling outage. This is consistent with Regulatory Guide 1.22 (Ref. 3)

The Frequency for this SR is in accordance with the Inservice Testing Program. Operating experience has shown that these components usually pass the Surveillance when performed at the Inservice Testing Program Frequency. This test is conducted in MODE 3 with the unit at nominal operating temperature and pressure, as discussed in Reference

2. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

Wolf Creek - Unit 1 B 3.7.3-6 Revision 32

MFIVs B 3.7.3 BASES SURVEILLANCE SR 3.7.3.2 REQUIREMENTS (continued) This SR verifies that each actuator train can close its respective MFIV on an actual or simulated actuation signal. The manual close hand switch in the control room provides an acceptable actuation signal. This Surveillance is normally performed upon returning the plant to operation following a refueling outage. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated The frequency of MFIV testing is every 18 months. The 18 month Frequency for testing is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section 10.4.7.

2. ASME Code for Operation and Maintenance of Nuclear Power Plants.

3. Regulatory Guide 1.22, Rev.O.

Wolf Creek - Unit 1 B 3.7.3-7 Revision 32

AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the AFW System water and steam supply flow paths provides assurance that the proper flow paths will exist for AFW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to manual vent/drain valves, and to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day Frequency, based on engineering judgment, is consistent with procedural controls governing valve operation, and ensures correct valve positions.

This SR is modified by a Note indicating that the SR is not required to be performed for the AFW flow control valves until the AFW System is placed in standby or THERMAL POWER is above 10% RTP.

SR 3.7.5.2 Verifying that each AFW pump's developed head at the flow test point is greater than or equal to the required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrifugal pump performance required by the ASME Code (Ref. 2). Because it is undesirable to introduce cold AFW into the steam generators while they are operating, this testing is performed on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

Performance of inservice testing discussed in the ASME Code (Ref. 2)

(only required at 3 month intervals) satisfies this requirement. The test Frequency in accordance with the Inservice Testing Program results in testing each pump once every 3 months, as required by Reference 2.

Wolf Creek - Unit 1 B 3.7.5-7 Revision 32

AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.2 (continued)

REQUIREMENTS When on recirculation, the required differential pressure for the AFW pumps (Ref. 4) when tested in accordance with the Inservice Testing Program is:

Motor Driven Pumps _ 1514 psid at a nominal flow of 110 gpm Turbine Driven Pump _ 1616.4 psid at a nominal flow of 130 gpm This SR is modified by a Note indicating that the SR should be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.

SR 3.7.5.3 This SR verifies that AFW can be delivered to the appropriate steam generator in the event of any accident or transient that generates an ESFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation signal.

This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient ifthe Surveillance were performed with the reactor at power. The 18 month Frequency is acceptable based on operating experience and the design reliability of the equipment.

This SR includes the requirement to verify that each AFW motor-operated discharge valve limits the flow from the motor driven AFW pump to each steam generator to < 320 gpm and that valves in the ESW suction flowpath actuate to the full-open position upon receipt of an Auxiliary Feedwater Pump Suction Pressure-Low signal.

SR 3.7.5.4 This SR verifies that the AFW pumps will start in the event of any accident or transient that generates an AFAS by demonstrating that each AFW pump starts automatically on an actual or simulated actuation signal. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Wolf Creek - Unit 1 B 3.7.5-8 Revision.14

AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.4 (continued)

REQUIREMENTS This SR is modified by a Note. The Note indicates that the SR be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.

SR 3.7.5.5 This SR verifies that the AFW is properly aligned by verifying the flow paths from the CST to each steam generator prior to entering MODE 2 after more than 30 days in MODE 5 or 6. OPERABILITY of AFW flow paths must be verified before sufficient core heat is generated that would require the operation of the AFW System during a subsequent shutdown.

The Frequency is reasonable, based on engineering judgement and other administrative controls that ensure that flow paths remain OPERABLE.

To further ensure AFW System alignment, flow path OPERABILITY is verified following extended outages to determine no misalignment of valves has occurred. This SR ensures that the flow path from the CST to the steam generators is properly aligned.

REFERENCES 1. USAR, Section 10.4.9.

2. ASME Code for Operation-and Maintenance of Nuclear Power Plants.

3. NRC letter (C. Poslusny to 0. Maynard) dated December 16, 1998:

"Wolf Creek Generating Station - Technical Specification Bases Change, Auxiliary Feedwater System."

4. Performance Improvement Request 2002-0945.

5. Condition Report 2006-000188.

Wolf Creek - Unit 1 B 3.7.5-9 Revision 32

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 (continued)

REQUIREMENTS provide standby power to the associated emergency buses. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source. The IDG shall be operated continuously for the 60 minute time period per the guidance of Regulatory Guide 1.9, Position 2.2.2 (Ref. 3).

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The DG is considered OPERABLE during performance of the Surveillance, i.e., while it is paralleled to the offsite power source, consistent with the Technical Evaluation (i.e., Section 4.0) contained in the Safety Evaluation provided for Amendment No. 154 (Reference 17).

This includes consideration of the potential challenges to the DG, its response to a LOCA and/or a loss of offsite power, and appropriate operator actions to restore the DC.

The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3).

This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients, because of changing bus loads, do not invalidate this test. Momentary power factor transients outside the normal range are acceptable during this surveillance since no power factor requirements are established by this SR. Note 3 indicates that this Surveillance should be conducted on only one DC at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful IDC start must precede this test to credit satisfactory performance.

SR 3.8.1.4 This SR provides verification that, with the DC in a standby condition, the fuel oil transfer pump starts on low level in the day tank standpipe and shuts down on high level in the day tank standpipe to automatically maintain the day tank fuel oil level above the DC fuel headers. The fuel Wolf Creek - Unit 1 B 3.8.1-21 B3812 eiin333 Revision

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.4 (continued)

REQUIREMENTS oil standpipe must have adequate level to keep the fuel oil supply header to the engine injector pumps full, so that the engine can meet the required 12 second start time. The minimum fuel oil free surface elevation is required to be at least 86 inches from the bottom (outside diameter) of the tank. The transfer pump start/stop setpoints are controlled to maintain level in the standpipe in order to ensure there is sufficient fuel to meet the 12 second start requirement for the DG. This level also ensures adequate fuel oil for a minimum of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of DG operation at full load plus 10%.

The 31 day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 10). This SR is for preventative maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. This is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel-transfer systems are OPERABLE.

The Frequency for this SR is 31 days.

Wolf Creek - Unit 1 B 3:8.1-22 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 (continued)

REQUIREMENTS Periodically, the capability of the fuel oil transfer pump to supply the opposite train DG via the installed cross-connect line is verified.

SR 3.8.1.7 See SR 3.8.1.2.

SR 3.8.1.8 Not Used.

SR 3.8.1.9 Not Used.

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without.overspeed tripping or exceeding the predetermined voltage limits.

The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

In order to ensure that the DG is tested under load conditions that are as close to design basis.conditions as possible, testing must be performed using a power factor >_0.8 and _< 0.9. :This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.

The DG is considered OPERABLE while it is paralleled to the offsite power sourceconsistent with the Technical Evaluation (i.e., Section 4.0) contained in the Safety Evaluation provided for Amendment No. 154 (Reference 17). This includes consideration of the potential challenges to the DG, its response to a LOCA and/or a loss of offsite power, and appropriate operator actions to restore the DG.

Wolf Creek - Unit 1 B-3.8.1-23 Revision 33

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 (continued)

REQUIREMENTS The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9, Rev. 3 (Ref. 3), and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.11 As required by Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(1), this Surveillance demonstrates the as-designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.

The DG autostart time of 12 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all-starting transients have decayed and stability is achieved.

The requirement to verify the connection and power supply of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR)systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9, Rev. 3 (Ref. 3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be

.consistent with expected fuel cycle lengths.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, Wolf Creek - Unit 1 B 3.8.1-24 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

The Note 2 restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite.system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (12 seconds) from the design basis actuation signal (LOCA signal) and operates for > 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d and SR,3.8.1..12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on an ESF signal without loss of offsite power.

The requirement to verify the connection of permanent and autoconnected loads is intended to satisfactorily show the relationship of these loads to.the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, ECCS injection valves are not desired to be stroked open,:or high pressure injection systems are not capable of being operated at full flow, or RHR systems performing a decay. heat removal function are not desired to be realigned to the-ECCS mode of operation. In lieu of actual demonstration Wolf Creek - Unit 1 B 3.8.1.-25 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 (continued)

REQUIREMENTS of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 18 months takes into consideration unit conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that during operation with the reactor critical, performance of this Surveillance could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems..

The Note 2 restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.13 This Surveillance demonstrates that DG noncritical protective functions are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. The noncritical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to Wolf Creek- Unit 1 B 3.8.1-26 I ý Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.13 (continued)

REQUIREMENTS mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 18 month Frequency is based on engineering judgment and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.8.1.14 Regulatory Guide 1.9, Rev. 3, (Ref. 3), requires demonstration once per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , _>

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG (Refer to discussion of Note 3 below). The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, .discussed in SR 3.8.1.3, are applicable to this SR.

In ýorder to ensure that-the DG is tested under load conditions that are as close to design conditions as possible, testing must be performed using a power factor of _ 0.8 and _<0.9 at a voltage of 4160 +160 -420 volts and a frequency of 60 + 1.2 Hz. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

Administrative controls for performing this SR in MODES 1 or 2, with the DG connected to an offsite circuit,:ensure or require that:

a. Weather conditions are conducive for performing this SR.

b. The offsite power supply and switchyard conditions are conducive for performing this SR, which includes ensuring that switchyard access is restricted and no elective maintenance within the switchyard is performed.

c. No equipment or systems assumed to be available for supporting the performance of the SR are removed from service.

Wolf Creek - Unit 1 B 3..8.1"27 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.14 (continued)

REQUIREMENTS The DG is considered OPERABLE during performance of the Surveillance, i.e., while it is paralleled to the offsite power source, consistent with the Technical Evaluation (i.e., Section 4.0) contained in the Safety Evaluation provided for Amendment No. 154 (Reference 17).

This includes consideration of the potential challenges to the DG, its response to a LOCA and/or a loss of offsite power, and appropriate operator actions to restore the DG.

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9, Rev. 3 (Ref. 3), and is intended to be consistent with expected fuel cycle lengths.

This Surveillance is modified by two Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients outside the power factor range will not invalidate the test. Note 2 permits the elimination of the 2-hour overload test, provided that the combined emergency loads on a DG do not exceed its continuous duty rating.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 12 seconds. The 12 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9, Rev. 3 (Ref. 3).

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changingbus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

Wolf Creek - Unit 1 B-3.8.1-28 Revision 33

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 REQUIREMENTS (continued) As required by Regulatory Guide 1.9, Rev. 3 (Ref. 3), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to ready to load status when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in ready to load status when the DG is at rated speed and voltage, the output breaker is open and can receive a close signal on bus undervoltage, and the load sequence timers are reset.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1 .9, Rev. 3 (Ref. 3), and takes into consideration unit conditions required to perform the Surveillance.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

The restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or

.. enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1, 2, 3 or 4. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.17 Demonstration of the test mode (parallel mode) override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to ready to load operation. if a Safety Injection actuation signal is received during operation in the test mode. Ready to load operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by IEEE-308 (Ref. 13),

paragraph 6.2.6(2).

Wolf Creek - Unit 1 B 3.8. 1.ý':2 9 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of Connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9, Rev. 3 (Ref. 3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

The restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE I or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1. 18 Under accident and loss of offsitepower conditions loads are sequentially connected to the bus by the LSELS. The sequencing logic controls the permissive and starting; signals to motor breakers to, prevent overloading of the DGs due to high motor starting currents. The 10% load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that Wolf Creek - Unit 1 B,3.8.1-30 Revision 33 1 -

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.18 (continued)

REQUIREMENTS safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESF buses.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9, Rev. 3 (Ref. 3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. Theyreason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

The restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This. testing may include any series of sequential, overlapping, or~total steps so that-the entire connection and loading sequence is verified. .

Wolf Creek - Unit 1 B 3.8:1 ý3,1 Revision 33 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.19 (continued)

REQUIREMENTS The Frequency of 18 months takes into consideration unit conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 18 months.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

The Note 2 restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of.

Regulatory Guide 1.108 (Ref.,9).

This SR is modified by a Note. The'reasonfor the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil temperature maintained consistent with manufacturer recommendations.

Wolf Creek - Unit 1 B 3'8.1-32 Revision 33 1

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) 68052, 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 33

RHR and Coolant Circulation - High Water Level B 3.9.5 B 3.9 REFUELING OPERATIONS B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation - High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchanger(s), where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR System for normal cooldown or decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant through the RHR heat exchanger(s) and the bypass lines. Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System.

APPLICABLE If the reactor coolant temperature is not maintained below 2000 F, boiling SAFETY ANALYSES of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to boron plating out on components near the areas of the boiling activity.

The loss of reactor coolant and the subsequent plate out of boron would eventually challenge the integrity of the fuel cladding, which is a fission product barrier. One train of the RHR System is required to be operational in MODE 6, with the water level > 23 ft above the top of the reactor vessel flange, to prevent this challenge. The LCO does permit de-energizing the RHR pump for short durations, under the condition that the boron concentration is not diluted. This conditional de-energizing of the RHR pump does not result in a challenge to the fission product barrier.

Although the RHR System does not meet a specific criterion of the NRC Policy Statement, it was identified in 10 CFR 50.36(c)(2)(ii) as an important contributor to risk reduction. Therefore, the RHR System is retained as a Specification.

LCO Only one RHR loop is required for decay heat removal in MODE 6, with the water level > 23 ft above the top of the reactor vessel flange. Only one RHR loop is required to be OPERABLE, because the volume of water above the reactor vessel flange provides backup decay heat Wolf Creek - Unit 1 B 3.9.5-1 Revision 0

RHR and Coolant Circulation - High Water Level B 3.9.5 BASES LCO removal capability. At least one RHR loop must be OPERABLE (continued) and in operation to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor coolant temperature.

An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the RCS temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs.

The LCO is modified by a Note that allows the required operating RHR loop to be removed from service for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period, provided no operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to meet the minimum boron concentrationof LCO 3.9.1. Boron concentration reduction with coolant at boron concentrations less than required to assure the minimum required RCS boron concentration is maintained is prohibited because uniform concentration distribution cannot be ensured without forced circulation. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzles and RCS to RHR isolation valve testing. During this 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period, decay heat is removed by natural convection to the large mass of water in the refueling pool.

The acceptability of the LCO and the LCO Note is based on preventing core boiling in the event of the loss of RHR cooling. An evaluation (Ref. 2) was performed which demonstrated that there is adequate flow communication to provide sufficient decay heat removal capability and preclude core uncovery, thus preventing core damage, in the event of a loss of RHR cooling with the reactor cavity filled and the upper internals installed in the reactor vessel.

APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level >_23 ft above the top of the reactor vessel flange, to provide decay heat removal.. The 23 ft water level was selected because it corresponds to the 23 ft requirement established for fuel movement in LCO 3.9.7, "Refueling Pool-Water Level." Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level <.23 ft are located in LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level."

Wolf Creek - Unit 1 B 3.9.5-2 Revision 32

RHR and Coolant Circulation - High Water Level B 3.9.5 BASES ACTIONS RHR loop requirements are met by having one RHR loop OPERABLE and in operation, except as permitted in the Note to the LCO.

A.1 If RHR loop requirements are not met, there will be no forced circulation to provide mixing to establish uniform boron concentrations.

Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit of LCO 3.9.1 is required to assure continued safe operation. Introduction of coolant inventory must be from sources that have a boron concentration greater than that required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation.

A.2 If RHR loop requirements are not met, actions shall be taken immediately to suspend loading of irradiated fuel assemblies in the core.

With no forced circulation cooling, decay heat removal from the core occurs by natural convection to the heat sink provided by the water above the core. A minimum refueling water level of 23 ft above the reactor vessel flange provides.an adequate available heat sink.

Suspending any operation that would increase decay heat load, such as loading a fuel assembly, is a prudent action under this condition.

Performance of Required Action A.2 shall not preclude completion of movement of a component to a safe condition.

A.3 If RHR loop requirements are not met, actions shall be initiated and continued in order to satisfy RHR.loop requirements. With the unit in MODE 6 and the refueling water level _> 23 ft above the top of the reactor vessel flange, corrective actions shall be initiated immediately.

A.4 If RHR loop requirements are not met, all containment penetrations providing direct access from the containment atmosphere to the outside atmospherermust be closed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . With the RHR loop requirements not met,the potential exists for the coolant to boil and release radioactive.gas to the containment atmosphere. Closing containment penetrations that are open to the outside atmosphere ensures dose limits are not exceeded.

Wolf Creek - Unit 1 B 3.9.5-3 Revision 32 1

RHR and Coolant Circulation - High Water Level B 3.9.5 BASES ACTIONS A.4 (continued)

The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on the low probability of the coolant boiling in that time.

SURVEILLANCE SR 3.9.5.1 REQUIREMENTS This Surveillance demonstrates that the RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator in the control room for monitoring the RHR System.

REFERENCES 1. USAR, Section 5.4.7.

2. SAP-06-113, "Loss of RHR Analysis with the Refuel Cavity Flooded and Upper Internals Installed," November 16, 2006.

Wolf Creek - Unit 1 B 3.9.5-4 Revision 32,

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents i 0 Amend. No. 123 12/18/99 ii 29 DRR 06-1984 10/17/06 iii 2 DRR 00-0147 4/24/00 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 14 DRR 03-0102 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 34 DRR 07-1057 7/10/07 B 3.0-10 34 DRR 07-1057 7/10/07 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 Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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 0 Amend. No. 123 12/18/99 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 0 Amend. No. 123 12/18/99 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 0 Amend. No. 123 12/18/99 B 3.1.7-4 0 Amend. No. 123 12/18/99 B 3.1.7-5 0 Amend. No. 123 12/18/99 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 D 2e) II ) A , A,. kl,-, 4")V 01121 /iO AmendI. oU. 123 I/18 I/U B 3.2.1-2 0 Amend. No. 123 12/18/99 B 3.2.1-3 0 Amend. No. 123 12/18/99 B 3.2.1-4 0 Amend. No. 123 12/18/99 B 3.2.1-5 1 DRR 99-1624 12/18/99 B 3.2.1-6 12 DRR 02-1 062 9/26/02 B 3.2.1-7 0 Amend. No. 123 12/18/99 B 3.2.1-8 29 DRR 06-1984 10/17/06 B 3.2.1-9 29 DRR 06-1984 10/17/06 B 3.2.1-10 29 DRR 06-1984 10/17/06 B 3.2.2-1 0 Amend. No. 123 12/18/99 B 3.2.2-2 0 Amend. No. 123 12/18/99 B 3.2.2-3 0 Amend. No. 123 12/18/99 B 3.2.2-4 0 Amend. No. 123 12/18/99 B 3.2.2-5 0 Amend. No. 123 12/18/99 B 3.2.2-6 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 ii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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 0 Amend. No. 123 12/18/99 B 3.2.4-4 0 Amend. No. 123 12/18/99 B 3.2.4-5 0 Amend. No. 123 12/18/99 B 3.2.4-6 0 Amend. No. 123 12/18/99 B 3.2.4-7 0 Amend. No. 123 12/18/99 TAB - B 3.3 INSTRUMENTATION 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 12/18/99 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 20 DRR 04-1533 2/16/05 B 3.3.1-34 20 DRR 04-1533 2/16/05 B 3.3.1-35 20 DRR 04-1533 2/16/05 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 3.31-39 25 DRR 06-0800 5/18/06 Wolf Creek - Unit 1 iii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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 20 DRR 04-1533 2/16/05 B 3.3.1-47 20 DRR 04-1533 2/16/05 B 3.3.1-48 20 DRR 04-1533 2/16/05 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 0 Amend. No. 123 12/18/99 B 3.3.2-20 0. Amend. No. 123 12/18/99 B 3.3.2-21 0 Amend. No. 123 12/18/99 B 3.3.2-22 0 Amend. No. 123 12/18/99 B 3.3.2-23 0 Amend. No. 123 12/18/99 B 3.3.2-24 0 Amend. No. 123 12/18/99 B 3.3.2-25 0 Amend. No. 123 12/18/99 B 3.3.2-26 0 Amend. No. 123 12/18/99 B 3.3.2-27 0 Amend. No. 123 12/18/99 B 3.3.2-28 7 DRR 01-0474 5/1/01 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 Revision 35

LIST OF EFFECTIVE PAGES - TECHNICALSPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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 25 DRR 06-0800 5/18/06 B 3.3.2-42 20 DRR 04-1533 2/16/05 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 20 DRR 04-1533 2/16/05 B 3.3.2-48 20 DRR 04-1533 2/16/05 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 20 DRR 04-1533 2/16/05 B 3.3.2-52 20 DRR 04-1533 2/16/05 B 3.3.2-53 25 DRR 06-0800 5/18/06 B 3.3.2-54 20 DRR 04-1533 2/16/05 B 3.3.2-55 20 DRR 04-1533 2/16/05 B 3.3.2-56 20 DRR 04-1533 2/16/05 B 3.3.2-57 20 DRR 04-1533 2/16/05 B 3.3.2-58 20 DRR 04-1533 2/16/05 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 3.313-10 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 Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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 35

LIST OF EFFECTIVE PAGES -'TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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

B 3.4.5-5 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 3.4.65 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 29 DRR 06-1984 10/17/06 B 3.4.7-4 12 DRR 02-1062 9/26/02 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 19 DRR 04-1414 10/12/04 B 3.4.8-3 12 DRR 02-1062 9/26/02 B 3.4.8-4 12 DRR 02-1062 9/26/02 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 99-1624 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 07-01139 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 3.4.1.3-3 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 B 3.4.14-1 0 Amend. No. 123 12/18/99 Wolf Creek - UnIt 1 vii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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

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 29 DRR 06-1984 10/17/06 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 29 DRR 06-1984 10/17/06 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 DRR 99-1624 12/18/99 1

B 3.5.1-7 1 DRR 03-1497 11/4/03 B 3.5.1-8 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 0 Amend. No. 123 12/18/99 B 3.5.2-6 0 Amend. No. 123 12/18/99 B 3.5.2-7 Amend. No. 123 12/18/99 B 3.5.2-8 24 DRR 06-0051 2/28/06 B 3.5.2-9 .35 DRR 07-1553 9/28/07 B 3.5.2-10 33 DRR 07-0656 5/1/07 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 B 3.5.4-1 0 Amend. No. 123 12/18/99-B 3.5.4-2 0 Amend. No. 123 12/18/99 Wolf Creek - UnIt 1 viii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

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

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 0 Amend. No. 123 12/18/99

.B 3.6.3-5 8 DRR 01-1235 9/19/01 B 3.6.3-6 8 *DRR 01-1235 9/19/01 B 3.6.3-7 8 DRR 01-1235 9/19/01 B 3.6.3-8 8 DRR 01-1235 9/19/01 B 3.6.3-9 8 DRR 01-1235 9/19/01 B 3.6.3-10 8 DRR 01-1235 9/19/01 B 3.6.3-11 9 DRR 02-0123 2/28/02 B 3.6.3-12 20 DRR 04-1533 2/16/05 B 3.6.3-13 9 DRR 02-0123 2/28/02 B 3.6.3-14 9 DRR 02-0123 2/28/02 B 3.6.4-1 2 DRR 00-0147 4/24/00 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 0 Amend. No. 123 12/18/99 B 3.6.5-3 1,3 DRR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12/18/99 B 3.6.6-1 0 Amend. No. 123 12/18/99 B 3.6.6-2. 0 Amend. No. 123 12/18/99 B 3.6.6-3 1 DRR 99-1624 12/18/99 B 3.6.6-4 -0 Amend. No. 123 12/18/99 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 Wolf Creek - Unit 1 ix ,Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.7-1 0 Amend. No. 123 12/18/99 B 3.6.7-2 0 Amend. No. 123 12/18/99 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 29 -DRR 06-1984 10/17/06 B 3.6.8-1 0 Amend. No. 123 12/18/99 B 3.6.8-2 0 Amend. No. 123 12/18/99 B 3.6.8-3 19 DRR 04-1414 10/12/04 B 3.6.8-4 0 Amend. No. 123 12/18/99 B 3.6.8-5 0 Amend. No. 123 12/18/99 TAB - B 3.7 PLANT SYSTEMS B 3.7.1-1 0 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 2/7/07 B 3.7.2-1 30 DRR 06-2329 11/8/06 B 3.7.2-2 30 DRR 06-2329 11/8/06 B 3.7.2-3 30 DRR 06-2329 11/8/06 B 3.7.2-4 30 DRR 06-2329 11/8/06 B 3.7.2-5 30 DRR 06-2329 11/8/06 B 3.7.2-6 30 DRR 06-2329 11/8/06 B 3.7.2-7 30 DRR 06-2329 11/8/06 B 3.7.2-8 30 DRR 06-2329 11/8/06 B 3.7.3-1 30 DRR 06-2329 11/8/06 B 3.7.3-2 30 DRR 06-2329 11/8/06 B 3.7.3-3 30 DRR 06-2329 11/8/06 B 3.7.3-4 30 DRR 06-2329 11/8/06 B 3.7.3-5 30 DRR 06-2329 11/8/06 B 3.7.3-6 32 DRR 07-0139 2/7/07 B 3.7.3-7 32 DRR 07-0139 2/7/07 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 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 26 DRR 06-1350 7/24/06 B 3.7.5-5 19 DRR 04-1414 10/12/04 B 3.7.5-6 19 DRR 04-1414 10/12/04 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 Wolf Creek - Unit 1 X Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.7 PLANT SYSTEMS (continued)

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 0 Amend. No. 123 12/18/99 B 3.7.1.0-2 15 DRR 03-0860 7/10/03 B 3.7.10-3 0 Amend. No. 123 12/18/99 B 3.7.10-4 0 Amend. No. 123 12/18/99 B 3.7.10-5 0 Amend. No. 123 12/18/99 B 3.7.10-6 0 Amend. No. 123 12/18/99 B 3.7.10-7 0 Amend. No. 123 12/18/99 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 DRR 99-1624 12/18/99 B 3.7.13-3 24 DRR 06-0051 2/28/06 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 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 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 25 DRR 06-0800 5/18/06 B 3.8.1-4 25 DRR 06-0800 5/18/06 Wolf Creek - UnIt 1 xi Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

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 26 DRR 06-1350 7/24/06 B 3.8.1-10 26 DRR 06-1350 7/24/06 B 3.8.1-11 26 DRR 06-1350 7/24/06 B 3.8.1-12 35 DRR 07-1553 9/28/07 B 3.8.1-13 26 DRR 06-1350 7/24/06 B 3.8.1-14 26 DRR 06-1350 7/24/06 B 3.8.1-15 26 DRR 06-1350 7/24/06 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 33 DRR 07-0656 5/1/07 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 33 DRR 07-0656 5/1/07 B 3.8.2-1 0 Amend. No. 123 12/18/99 B 3.8.2-2 0 Amend. No. 123 12/18/99 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 1 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 O 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 Wolf Creek - Unit 1 xii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

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 01 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 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 S"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 Wolf Creek - Unit 1 xiii Revision 35

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES 1~

PAGE (1) REVISION NO. (2) CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.9 REFUELING OPERATIONS (continued)

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 19 DRR 04-1414 10/12/04 B 3.9.6-3 12 DRR 02-1062 9/26/02..

B 3.9.6-4 12 DRR 02-1062 9/26/02 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 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 xiv Revision 35

ML080780560

Text

Subject:

Navigation menu

Search