Text

Changes to Technical Specification Bases - Revisions 17 Through 19
	ML050770415
Person / Time
Site:	Wolf Creek
Issue date:	03/10/2005
From:	Moles K; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 05-0028
	Download: ML050770415 (96)
	v • d • e

WOLF CREEK 'NUCLEAR OPERATING CORPORATION Kevin J. Moles Manager Regulatory Affairs March 10, 2005 RA 05-0028 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 17 through 19 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 17 through 19) under the provisions of TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2004 through December 31, 2004..

There are no commitments contained in this submittal.

If you have any questions concerning this matter, please contact me at (620) 364-4126, or Diane Hooper at (620) 364-4041.

Very truly yours,

- - Kvin J.Mol KJM/rIg Enclosure cc: J. N. Donohew (NRC), w/a D. N. Graves (NRC), w/a B. S. Mallett (NRC), w/a Senior Resident Inspector (NRC), w/a P.O. Box 411 / Burlington, KS 66839 Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET

Enclosure to RA 05-0028 Wolf Creek Generating Station Changes to the Technical Specification Bases

LCO Applicability B 3.0 BASES LCO 3.0.3 b. The condition of the unit is not specifically addressed by the (continued) associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.- -

A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs:

a. The LCO is now met.

b. A Condition exists for which the Required Actions have now been performed.

c. ACTIONS exist that do not have expired Completion Times.

These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.

Wolf Creek - Unit 1 B 3.0-3 :Revision 0

i It LCO Applicability B.3.0 BASES LCO 3.0.3 The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months for the unit to be in (continued) MODE 5 when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE applies. If a lower MODE is reached in less time than allowed, however, the total allowable time to reach MODE 5, or other applicable MODE, is not reduced. For example, if MODE 3 is reached in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , then the time allowed for reaching MODE 4 is the next 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months , because the total time for reaching MODE 4 is not reduced from the allowable limit of 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months . Therefore, if remedial measures are completed that would permit'a return to MODE 1, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.

In MODES 1, 2, 3, and 4, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 5 and 6 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, 3, or 4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.15, " Fuel Storage Pool Water Level." LCO 3.7.15 has an Applicability of "During movement of irradiated fuel assemblies in the fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.15 are not met while in MODE 1, 2, 3, or 4, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.15 of "Suspend movement of irradiated fuel assemblies in the fuel storage pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g.,

the Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with LCO 3.0.4a., LCO 3.0.4b., or LCO 3.0.4c.

Wolf Creek - Unit 1 B 3.0-4 Revision 19

LCO Applicability B 3.0 BASES LCO 3.0.4 LCO 3.0.4a. allows entry into a MODE or other specified condition in the (continued) Applicability with the LCO not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status'of the unit before or after the MODE change.

Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions.

LCO 3.0.4b. allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable'systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions; if appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4b., must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01; "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, 'actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

Wolf Creek - Unit I B 3.0-5' Revision 19

I ~if LCO Applicability B 3.0 BASES LCO 3.0.4 LCO 3.0.4b. may be used with single, or multiple systems and (continued) components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4b. risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4b. allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0.4b. allowance is prohibited. The LCOs governing these system and components contain Notes prohibiting the use of LCO 3.0.4b. by stating that LCO 3.0.4b. is not applicable.

LCO 3.0.4c. allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which'states LCO 3.0.4c. is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation f6r an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4b. usually only consider systems and c6mpornents. For this reason, LCO 3.0.4c. is typically applied to Specifications which describe values and parameters (e.g., Containment Air Temperature, Containment Pressure, Moderator Temperature Coefficient), and may be applied to other Specifications based on NRC plant-specific approval.

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

The provisions of LCO 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 LCO 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 Wolf Creek - Unit 1 B 3.0-6 Revision 19

LCO Applicability B 3.0 BASES LCO -3.0.4 as a change in MODE or other specified condition in the Applicability (continued) associated with transitioning from MODE I to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, MODE 4 to MODE 5, and MODE 5 to MODE 6.

Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, unitil the LCO is met, or until the unit is not within the Applicability of the Technical Specification.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.

LCO 3.0.5: LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of required testing to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the required testing to demonstrate OPERABILITY. This Specification does not provide time to perform any other preventive or corrective maintenance.

An example of demonstrating the OPERABILITY of the equipment being returned to service istreopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the required testing .

An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of Wolf Creek - Unit 1 B 3.0-7 Revision.19

LCO Applicability B 3.0 BASES LCO 3.0.5 required testing on another channel in the other trip system. A similar (continued) example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the unit is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions. When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the unit is maintained in a safe condition in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system.

This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

Specification 5.5.15, "Safety Function Determination Program (SFDP),"

ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

Wolf Creek - Unit 1 B 3.0-8 Revision 19 1

LCO Applicability B3.0 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.

Wolf Creek - Unit I B 3.0-9 Revision 19 l

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 3.0-10 Revision 19 l

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 (eg., 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 Completion Time 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 3.0-11 Revision 19 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 3.0.3 allows 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 3.0-12 Revision 19 l

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 3.0-1 3 Revision 19 1

I, 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 B 3.0-14 Revision 19

SR Applicability B 3.0 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 I 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.

I Wolf Creek - Unit 1 B 3.0-15 Revision 19

SDM B 3.1.1 BASES APPLICABLE with respect to potential fuel damage' before a reactor trip occurs, is a SAFETY ANALYSES guillotine break of a main steam line inside containment initiated at the (continued) end of core life with RCS Tvg equal to 557 0F. The positive reactivity addition from the moderator temperature decrease will terminate when the affected SG boils dry, thus terminating RCS heat removal and cooldown.

'Following the MSLB, a post trip return to power may occur; however, no fuel damage occurs as a result of the post trip return to power, and THERMAL POWER does not violate the Safety Limit (SL) requirement of SL 2.1.1.

In the boron dilution analysis, the required SDM defines the reactivity difference between an initial subcritical boron concentration and the corresponding critical boron concentration. These values, in conjunction with the configuration of the RCS and the assumed dilution flow rate, directly affect the results of the analysis. This event is most limiting at the beginning of core life, when critical boron concentrations are highest.

Depending on the system initial conditions and reactivity insertion rate, the uncontrolled rod withdrawal transient is terminated by either a high power level trip or a high pressurizer pressure trip. In all cases, power level, RCS pressure, linear heat rate, and the DNBR do not exceed allowable limits.

The startup of an inactive RCP is administratively precluded in MODES 1 and 2. In MODE 3, the startup of an inactive RCP can not result in a "cold water" criticality, even if the maximum difference in temperature exists between the SG and the core. 'The maximum positive reactivity addition that can occur due to an inadvertent RCP start is less than half the minimum required SDM. Startup-of an idle RCP cannot, therefore, produce a return to power from the hot standby condition.

The ejection of a control rod rapidly adds reactivity to the reactor core reactor core causing both the core power level and heat flux to increase with corresponding increases in reactor coolant temperatures and pressure. The ejection of a rod also produces a time dependent redistribution of core power.

SDM satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). Even though it is not directly observed from the control room, SDM is considered an initial condition process variable because it is periodically monitored to ensure that the unit is operating within the bounds of accident analysis assumptions.

Wolf Creek - Unit 1 B 3.1.1-3 Revision 0

SDM B 3.1.1 BASES LCO SDM is a core design condition that can be ensured during operation through control rod positioning (control and shutdown banks) and through the soluble boron concentration.

The MSLB (Ref. 2) and the boron dilution (Ref. 3) accidents are the most limiting analyses that establish the SDM value of the LCO. For MSLB accidents, if the LCO is violated, there is a potential to exceed the DNBR limit and to exceed 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4).

For the boron dilution accident, if the LCO is violated; the minimum required time assumed for operator action to terminate dilution may no longer be sufficient. The required SDM limit is specified in the COLR.

APPLICABILITY In MODE 2 with kff < 1.0 and in MODES 3,4, and 5, the SDM requirements are applicable to provide sufficient negative reactivity to meet the assumptions of the safety analyses discussed above. In MODE 6, the shutdown reactivity requirements are given in LCO 3.9.1, "Boron Concentration." In MODES 1 and 2, SDM is ensured by complying with LCO 3.1.5, "Shutdown Bank Insertion Limits," and LCO 3.1.6, 'Control Bank Insertion Limits."

The risk assessments of LCO 3.0.4b. may only be utilized for systems and components, not Criterion 2 values or parameters such as SDM.

Therefore, a risk assessment per LCO 3.0.4b. to allow MODE changes with single or multiple system/equipment inoperabilities may not be used to allow a MODE change into or within this LCO while not meeting the SDM limits, even if risk assessment specifically includes consideration of SDM.

ACTIONS A. 1 If the SDM requirements are not met, boration must be initiated promptly.

A Completion Time of 15 minutes is adequate for an operator to correctly align and start the required systems and components. It is assumed that boration will be continued until the SDM requirements are met.

In the determination of the required combination of boration flow rate and boron concentration, there is no unique requirement that must be satisfied. Since it is imperative to raise the boron concentration of the RCS as soon as possible, the borated water source should be a highly concentrated solution, such as that normally found in the boric acid storage tank, or the refueling water storage tank. The operator should borate with the best source available for the plant conditions.

Wolf Creek - Unit 1 B 3.1.1-4 Revision 19

RTS Instrumentation B 3.3.1 BASES ACTIONS A.1 (continued)

Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those found in the referenced Conditions and Required Actions.

B.1 and B.2.

Condition B applies to the Manual Reactor Trip in MODE I or 2. This action addresses the train orientation of the SSPS for this Function. With one channel inoperable, the inoperable channel must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . Inthis Condition, the remaining OPERABLE channel is adequate to perform the safety function.

The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is reasonable considering that there are two automatic actuation trains and another manual initiation channel OPERABLE, and the low probability of an event occurring during this interval.

If the Manual Reactor Trip Function cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time, the unit must be brought to a MODE in which the requirement does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 additional hours (54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months total time). The 6 additional hours to reach MODE 3 is reasonable, based on operating experience, to reach MODE 3 from full power operation in an orderly manner and without challenging unit systems. With the unit in MODE 3, Condition C is entered if the Manual Reactor Trip Function has not been restored and the Rod Control System is capable of rod withdrawal or one or more rods are not fully inserted.

C.1. C.2.1. and C.2.2 .

Condition C applies to the following reactor trip Functions in MODE 3, 4, or 5 with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted:

Manual Reactor Trip;

RTBs;

-. RTB Undervoltage and Shunt Trip Mechanisms; and

. Automatic Trip Logic.

Wolf Creek - Unit 1 B 3.3.1-31 Revision 0

n RTS Instrumentation B 3.3.1 BASES ACTIONS C.1. C.2.1 and C.2.2 (continued)

This action addresses the train orientation of the SSPS for these Functions. With one channel or train inoperable, the inoperable channel or train must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . If the affected Function(s) cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time, the unit must be placed in a MODE in which the requirement does not apply. To achieve this status, action must be initiated within the same 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to fully insert all rods and the Rod Control System must be rendered incapable of rod withdrawal within the next hour (e.g., by de-energizing all CRDMs, by opening the RTBs, or de-energizing the motor generator (MG) sets). The additional hour for the latter provides sufficient time to accomplish the action in an orderly manner. With the rods fully inserted and Rod Control System incapable of rod withdrawal, these Functions are no longer required.

The Completion Time is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function, and given the low probability of an event occurring during this interval.

Risk assessments performed pursuant to LCO 3.0.4.b should consider the desirability of enabling the Rod Control System or allowing one or more rods to be other than fully inserted in MODES 3, 4, or 5 while one train of Function 19 (one RTB train), Function 20 (one trip mechanism for one RTB), or Function 21 (one SSPS logic train) is inoperable and the Reactor Trip System is degraded. The risk assessment should assure that, prior to enabling the Rod Control System or allowing one or more rods to be other than fully inserted in MODES 3, 4, 04 5, procedural controls have been implemented to maintain the RCS boron concentration sufficient to preclude criticality with all control rods fully withdrawn. The administrative controls apply prior to making this Applicability change, however, if the Applicability change took place, these controls include immediate actions to borate or insert all rods and disable rod control whenever RCS temperature is below 500 0F. This would mitigate any inadvertent rod withdrawal from subcritical transient.

D.1.1. D.1.2. D.2.1. D.2.2. and D.3 Condition D applies to the Power Range Neutron Flux- High Function.

The NIS power range detectors provide input to the Rod Control System and, therefore, have a two-out-of-four trip logic. A known inoperable channel must be placed in the tripped condition. This results in a partial trip condition requiring only one-out-of-three logic for actuation. The 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowed to place the inoperable channel in the tripped condition is justified in WCAP-10271-P-A (Ref. 6).

Revision 19 B 3.3.1-32 Wolf Creek - Unit I1 Creek - Unit B 3.3.1-32 Revision 19

RTS Instrumentation B 3.3.1 BASES ACTIONS D.1.1. D.1.2. D.2.1. D.2.2. and D.3 (continued)

In addition to placing the inoperable channel in the tripped condition, THERMAL POWER must be reduced to S 75% RTP within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Reducing the power level prevents operation of the core with radial power distributions beyond the design limits at a power level where DNB conditions may exist. With one of the NIS power range detectors inoperable, 1/4 of the radial power distribution monitoring capability is lost.

As an alternative to the above actions, the inoperable channel can be placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and the QPTR monitored once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months as per SR 3.2.4.2 (including the SR 3.2.4.2 Note),

QPTR verification. Calculating QPTR every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months compensates for the lost monitoring capability due to the inoperable NIS power range channel and allows continued unit operation at power levels > 75% RTP.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time and the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency are consistent with LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR).'

As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. Twelve hours are allowed to place the plant in MODE 3. This is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems. If Required Actions cannot be completed within their allowed Completion Times, LCO 3.0.3 must be entered.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypass condition for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months while performing routine surveillance testing of other channels. The Note also allows placing the inoperable channel in the bypass condition to allow setpoint adjustments of other channels when required to reduce the setpoint in accordance with other Technical Specifications. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months time limit is justified in Reference 6.

Required Action D.2.2 has been modified by a Note which only requires

-SR 3.2.4.2 to be performed if the Power Range Neutron Flux input to QPTR becomes inoperable. Failure of a component in the Power Range Neutron Flux Channel which renders the High Flux Trip Function inoperable may not affect the capability to monitor QPTR. As such, determining QPTR using the movable incore detectors once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months may not be necessary.

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

Power Range Neutron Flux- Low, Wolf Creek - Unit 1 B 3.3.1-33 Revision 19 1

RTS Instrumentation B 3.3.1 BASES ACTIONS E.1 and E.2 (continued) a Overtemperature AT;

Overpower AT;

Power Range Neutron Flux- High Positive Rate;

Power Range Neutron Flux- High Negative Rate;

Pressurizer Pressure- High; and

SG Water Level - Low Low.

A known inoperable channel must be placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . Placing the channel in the tripped condition results in a partial trip condition requiring only one-out-of-three logic for actuation of the two-out-of-four trip logic. The 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowed to place the inoperable channel in the tripped condition is justified in Reference 6.

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

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months while performing routine surveillance testing of the other channels. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months time limit is justified in Reference 6.

F.1 and F.2 Condition F applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint and one channel is inoperable. Above the P-6 setpoint and below the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. If THERMAL POWER is greater than the P-6 setpoint but less than the P-10 setpoint, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed to reduce THERMAL POWER below the P-6 setpoint or to increase THERMAL POWER above the P-10 setpoint. The NIS Intermediate Range Neutron Flux channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capability of the power range, P-10. If THERMAL POWER is greater than the P-10 setpoint, the NIS power range detectors perform the monitoring and protection Wolf Creek - Unit 1 B 3.3.1-34 Revision 19 1

RTS Instrumentation B 3.3.1 BASES ACTIONS F.1 and F.2 (continued) functions and the intermediate range is not required. The Completion Times allow for a slow and controlled power adjustment above P-1 0 or below P-6 and take into account the redundant capability afforded by the redundant OPERABLE channel, the overlap of the Power Range detectors, and the low probability of its failure during this period. This action does not require the inoperable channel to be tripped because the Function uses one-out-of-two logic. Tripping one channel would trip the reactor. Thus, the Required Actions specified in this Condition are only applicable when channel failure does not result in reactor trip.

GI and G.2 Condition G applies to two inoperable Intermediate Range Neutron Flux trip channels in MODE 2 when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint. Required Actions specified in this Condition are only applicable when channel failures do not result in reactor trip. Above the P-6 setpoint and below the P-1 0 setpoint, the NIS intermediate range detector performs the monitoring Functions. With no intermediate range channels OPERABLE, the Required Actions are to suspend operations involving positive reactivity additions immediately.

This will preclude any power level increase since there are no OPERABLE Intermediate Range Neutron Flux channels. The operator must also reduce THERMAL POWER below the P-6 setpoint within two hours. Below P-6, the Source Range Neutron Flux channels will be able to monitor the core power level. The Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months will allow a controlled power reduction to less than the P-6 setpoint and takes into account the low probability of occurrence'of an event during this period that may require the protection afforded by the NIS Intermediate Range Neutron Flux trip.!'

Required Action G.1 is modified by a Note to indicate that normal plant control operations that individually add limited positive reactivity (i.e.,

temperature or boron concentration fluctuations associated with RCS inventory management or temperature control)'are not precluded by this Action, provided the SDM limits of LCOs 3.1.1, 3.1.5, 3.1.6, and 3.4.2 are met.

H.1 Not Used.

Condition I applies to one inoperable Source Range Neutron Flux trip Wolf Creek - Unit 1 B 3.3.1-35 ..Revision:19 I

RTS Instrumentation B 3.3.1 BASES ACTIONS L (continued) channel when in MODE 2, below the P-6 setpoint. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the two channels inoperable, operations involving positive reactivity additions shall be suspended immediately.

This will preclude any power escalation. With only one source range channel OPERABLE, core protection is severely reduced and any actions that add positive reactivity to the core must be suspended immediately.

Required Action 1.1 is modified by a Note to indicate that normal plant control operations that individually add limited positive reactivity (i.e.,

temperature or boron concentration fluctuations associated with RCS inventory management or temperature control) are not precluded by this Action, provided the SDM limits of LCOs 3.1.1, 3.1.5, 3.1.6, and 3.4.2 are met.

Condition J applies to two inoperable Source Range Neutron Flux trip channels when in MODE 2, below the P-6 setpoint, or in MODE 3, 4, or 5 with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With both source range channels inoperable, the RTBs must be opened immediately. With the RTBs open, the core is in a more stable condition.

KA. K.2.1. and K.2.2 Condition K applies to one inoperable source range channel in MODE 3, 4, or 5 with the Rod Control System capable of rod withdrawal or one or more rods not fully inserted. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the source range channels inoperable, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is allowed to restore it to an OPERABLE status. If the channel cannot be returned to an OPERABLE status action must be initiated within the same 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to fully insert all rods, 1 additional hour is allowed to place the Rod Control System in a condition incapable of rod withdrawal (e.g., by de-energizing all CRDMs, by opening the RTBs, or de-energizing the motor generator (MG) sets). Once the ACTIONS are completed, the core is in a more stable condition and outside the Applicability of the Condition. The allowance of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months to restore the channel to OPERABLE status or fully insert all rods, and the additional hour to place the Rod Control System in a condition incapable of rod withdrawal are justified in Reference 6.

Wolf Creek - Unit 1 B 3.3.1-36 Revision 19 l

PAM Instrumentation B 3.3.3 BASES LCO 14,15,16,17. Core Exit TemDerature (continued) trend the ensuing core heatup. The evaluations account for core nonuniformities, including incore effects of the radial decay power distribution, excore effects of condensate runback in the hot legs, and nonuniform inlet temperatures. Based on these evaluations, adequate core cooling is ensured with two valid core exit temperature channels per quadrant with two CETs per required channel. The CET pairs are oriented radially to permit evaluation of core radial decay power distribution. Core exit temperature is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped. Core exit temperature is also used for unit stabilization and cooldown control.

Two OPERABLE channels of core exit temperature are required in each quadrant to provide indication of radial distribution of the coolant temperature rise across representative regions of the core.

-Reference 6 discusses the conformance of the thermocouple/core cooling monitoring system to NUREG-0737, Section ll.F.2, approved by the NRC in Reference 7. Two sets of two thermocouples ensure a single failure will not disable the ability to determine the radial temperature gradient.

18. Auxiliary Feedwater Flow Rate AFW Flow Rate is a Category 2 variable provided to monitor operation of decay heat removal via the SGs. The AFW Flow rate indicator for each SG is located in the main control room. Each of the four flow indicators is powered by a different separation group.

Since only two of four SGs are required to establish a heat sink for the RCS, flow indication to at least two intact SGs is assured even if a single failure is assumed. AFW flow rate indication is not a Type A variable nor is it Regulatory Guide 1.97 Category 1.

.(Reference 9). -

The AFW Flow to each SG is determined from a differential pressure measurement calibrated for a range of 0 gpm to 400 gpm. Each differential pressure transmitter provides an input to a control room indicator and the unit computer. Since the primary indication used by the operator during an accident is the control room indicator, the PAM specification deals specifically with this portion of the instrument channel.

AFW flow is used three ways:

Wolf Creek - Unit 1 B 3.3.3-9 Revision 8 l

n-p PAM Instrumentation B 3.3.3 BASES LCO 18. Auxiliary Feedwater Flow Rate (continued)

to verify delivery of AFW flow to the SGs;

to determine whether to terminate SI if still in progress, in conjunction with SG water level (narrow range); and

to regulate AFW flow so that the SG tubes remain covered.

AFW flow is also used by the operator to verify that the AFW System is delivering the correct flow to each SG. However, the primary indication used by the operator to ensure an adequate inventory is SG level.

19. Refueling Water Storaae Tank (RWST) Level Refueling Water Storage Tank Level is a Type A, Category 2 variable for determining switchover of containment spray to the containment recirculation sumps. This level indication is provided for the operators to assist in monitoring and ensuring an adequate supply of water for safety injection and containment spray. Table 2 of Reference 2 requires all plant-specific Type A variables to meet Category 1 design and qualification criteria; however, RWST Level is specifically identified in that same table as a Type D Category 2 variable. In this specific case, as discussed in Sections 7.A.3.1 and 7A.3.6 of Reference 1, the requirements of Category 1 are met.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2 and 3. These variables are related to the diagnosis and pre-planned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2 and 3. In MODES 4, 5 and 6, unit conditions are such that the likelihood of an event that would require PAM instrumentation is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.

ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.3-1. The Completion Time(s) of the inoperable channel(s) of a Function will be Revision 19 B 3.3.3-10 Wolf Creek - Unit I1 Creek - Unit B 3.3.3-1 0 Revision 19

PAM Instrumentation B 3.3.3 BASES ACTIONS tracked separately for each Function starting from the time the Condition (continued) was entered for that Function. When the Required Channels in Table 3.3.3-1 are specified on a per SG basis, then the Condition may be entered separately for each SG.

Condition A applies when one or more Functions have one required channel that is inoperable. Required Action A.1 requires restoring the inoperable channel to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.

Condition B applies when the Required Action and associated Completion Time for Condition A are not met. This Required Action specifies initiation of actions in Specification 5.6.8, which requires a written report to be submitted to the NRC within the following 14 days. This action is appropriate in lieu of a-shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.

Condition C applies when one or more Functions have two or more inoperable required channels (i.e., two or more channels inoperable in the same Function). Required Action C.1 requires restoring all but one channel in the Function(s) to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two or more required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance Revision 19 I B 3.3.3-11 Unit I1 Creek - Unit Wolf Creek B 3.3.3-11 Revision 19 l

__ a PAM Instrumentation B 3.3.3 BASES ACTIONS C.1 (continued)

(continued) qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of all but one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur. Condition C is modified by a Note that excludes hydrogen analyzer channels.

D.1 Condition D applies when two hydrogen analyzer channels are inoperable. Required Action D.1 requires restoring one hydrogen analyzer channel to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable based on the unlikely event that a LOCA (which would cause core damage) would occur during this time.

E.1 Condition E applies when the Required Action and associated Completion Time of Condition C or D are not met. Required Action E.1 requires entering the appropriate Condition referenced in Table 3.3.3-1 for the channel immediately. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met any Required Action of Condition C or D, and the associated Completion Time has expired, Condition E is entered for that channel and provides for transfer to the appropriate subsequent Condition.

F.1 and F.2 If the Required Action and associated Completion Time of Conditions C or D are not met and Table 3.3.3-1 directs entry into Condition F, the unit must be brought to a MODE where the requirements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and 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.

Wolf Creek - Unit 1 B 3.3.3-12 Revision 8 l

Remote Shutdown System B 3.3.4 BASES APPLICABLE The Remote Shutdown System is required to provide equipment SAFETYANALYSES. at appropriate locations outside the control room with a capability to promptly shut down and maintain the unit in a safe condition in MODE 3.

The criteria governing the design and specific system requirements of the Remote Shutdown System are located in 10 CFR 50, Appendix A, GDC 19 (Ref. 1).

The Remote Shutdown System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

LCO The Remote Shutdown System LCO provides the OPERABILITY requirements of the functions and ASP controls necessary to place and maintain the unit in MODE 3 from a location other than the control room.

The functions required are listed in Table 3.3.4-1 in the accompanying LCO.

The required ASP controls are listed above and described in USAR Table 7.4-1.1. The remote shutdown panel controls not located at the ASP are described in USAR Table 7.4-1.2 and are excluded from the requirements of this LCO.

The controls, instrumentation, and transfer switches are required for:

. Core reactivity control (initial and long term);

RCS pressure control;

Decay heat removal via the SGs; and

RCS inventory control.

A Function of a Remote Shutdown System is OPERABLE if the required number of channels needed to support the Remote Shutdown System Function identified in Table 3.3.4-1 are OPERABLE.

The remote shutdown instruments and required ASP controls covered by this LCO do not need to be energized to be considered OPERABLE. This LCO is intended to ensure the instruments and controls will be OPERABLE if unit conditions require that the Remote Shutdown System be placed in operation.

Wolf Creek - Unit 1 B 3.3.4-3

Revision 15

Remote Shutdown System B 3.3.4 BASES APPLICABILITY The Remote Shutdown System LCO is applicable in MODES 1, 2, and 3.

This is required so that the unit can be placed and maintained in MODE 3 for an extended period of time from a location other than the control room.

This LCO is not applicable in MODE 4, 5, or 6. In these MODES, the facility is already subcritical and in a condition of reduced RCS energy.

Under these conditions, considerable time is available to restore the remote shutdown instruments and required ASP controls if control room instruments or controls become unavailable.

ACTIONS A Note has been added to the ACTIONS to clarify the application of I Completion Time rules. Separate Condition entry is allowed for each Function listed on Table 3.3.4-1 and for each required ASP control. The Completion Time(s) of the inoperable channel(s)/train(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

When the Required Channels in Table 3.3.4-1 are specified on a per trip breaker, per SG, or per pump basis, the Condition may be entered separately for each trip breaker, SG, or pump, as appropriate.

Condition A addresses the situation where one or more required Functions of the Remote Shutdown System in Table 3.3.4-1, or one or more required ASP controls are inoperable.

The Required Action is to restore the required Function and ASP control to OPERABLE status within 30 days. The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the control room.

Wolf Creek - Unit 1 B 3.3.4-4 Revision 19

RCS Loops - MODE 3 B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Loops - MODE 3 BASES BACKGROUND In MODE 3,the primary function of the reactor coolant is removal of decay heat and transfer of this heat, via the steam generator (SG), to the secondary plant fluid. The secondary function of the reactor coolant is to act as a carrier for soluble neutron poison, boric acid.

The reactor coolant is circulated through four RCS loops, connected in parallel to the reactor vessel, each containing an SG, a reactor coolant pump (RCP), and appropriate flow, pressure, level, and temperature instrumentation for control, protection, and indication. The reactor vessel contains the clad fuel. The SGs provide the heat sink. The RCPs circulate the water through the reactor vessel and SGs at a sufficient rate to ensure proper heat transfer and prevent fuel damage.

In MODE 3, RCPs are used to provide forced circulation for heat removal during heatup and cooldown. The MODE 3 decay heat removal requirements are low enough that a single RCS loop with one RCP running is sufficient to remove core decay heat. However, two RCS loops are required to be OPERABLE to ensure redundant capability for decay heat removal.

APPLICABLE Whenever the reactor trip breakers (RTBs) are in the closed position and SAFETY ANALYSES the control rod drive mechanisms (CRDMs) are energized, an inadvertent rod withdrawal from subcritical, resulting in a power excursion, is possible.

Such a transient could be caused by a malfunction of the Rod Control System. In addition, the possibility of a power excursion due to the ejection of an inserted control rod is possible with the breakers closed or open. Such a transient could be caused by the mechanical failure of a CRDM.

Therefore, in MODE 3 with the Rod Control System capable of rod withdrawal, accidental control rod withdrawal from subcritical is postulated and requires at least two RCS loops to be OPERABLE and in operation to ensure that the accident analyses limits are met. For those conditions when the Rod Control System is not capable of rod withdrawal, two RCS loops are required to be OPERABLE, but only one RCS loop is required to be in operation to be consistent with MODE 3 accident analyses.

Wolf Creek - Unit 1 B 3.4.5-1 I:Revision 0

RCS Loops - MODE 3 B 3.4.5 BASES APPLICABLE The operation of one RCP in MODES 3, 4, and 5 provides adequate flow SAFETY ANALYSES to ensure mixing, prevent stratification, and produce gradual reactivity (continued) changes during RCS boron concentration reductions. With no reactor coolant loop in operation in either MODES 3, 4, or 5, dilution sources must be isolated and administratively controlled. The boron dilution analysis in these MODES take credit for the mixing volume associated with having at least one reactor coolant loop in operation (Ref. 1).

Failure to provide decay heat removal may result in challenges to a fission product barrier. The RCS loops are part of the primary success path that functions or actuates to prevent or mitigate a Design Basis Accident or transient that either assumes the failure of, or presents a challenge to, the integrity of a fission product barrier.

RCS Loops-MODE 3 satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require that at least two RCS loops be OPERABLE. In MODE 3 with the Rod Control System capable of rod withdrawal, two RCS loops must be in operation. Two RCS loops are required to be in operation in MODE 3 with the Rod Control System capable of rod withdrawal due to the postulation of a power excursion because of an inadvertent control rod withdrawal. The required number of RCS loops in operation ensures that the Safety Limit criteria will be met for all of the postulated accidents.

When the Rod Control System is not capable of rod withdrawal only one RCS loop in operation is necessary to ensure removal of decay heat from the core and homogenous boron concentration throughout the RCS. An additional RCS loop is required to be OPERABLE to ensure that redundancy for heat removal is maintained.

Note 1 permits all RCPs to be removed from operation for

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. The purpose of the Note is to perform tests that are required to be performed without flow or pump noise. One of these tests is validation of the pump coastdown curve used as input to a number of accident analyses including a loss of flow accident. This test is generally performed in MODE 3 during the initial startup testing program, and as such should only be performed once. If, however, changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values of the coastdown curve must be revalidated by conducting the test again.

Utilization of Note 1 is permitted provided the following conditions are met, along with any other conditions imposed by test procedures:

Wolf Creek - Unit 1 B 3.4.5-2 Revision 17

RCS Loops - MODE 4 B 3.4.6 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.6 RCS Loops - MODE 4 BASES BACKGROUND In MODE 4, the primary function of the reactor coolant is the removal of decay heat and the transfer of this heat to either the steam generator (SG) secondary side coolant or the component cooling water via the residual heat removal (RHR) heat exchangers. The secondary function of the reactor coolant is to act as a carrier for soluble neutron poison, boric acid.

The reactor coolant is circulated through four RCS loops connected in parallel to the reactor vessel, each loop containing an SG, a reactor coolant pump (RCP), and appropriate flow, pressure, level, and temperature instrumentation for control, protection, and indication. The RCPs circulate the coolant through the reactor vessel and SGs at a sufficient rate to ensure proper heat transfer and to prevent boric acid stratification.

In MODE 4k either RCPs or RHR loops can be used to provide forced circulation. The intent of this LCO is to provide forced flow from at least one RCP or one RHR loop for decay heat removal and transport. The flow provided by one RCP loop or RHR loop is adequate for decay heat removal. The other intent of this LCO is to require that two paths be available to provide redundancy for decay heat removal.

APPLICABLE In MODE 4, RCS circulation is considered in the determination of the time SAFETY ANALYSES available for mitigation of the accidental boron dilution event.

The operation of one RCP in MODES 3, 4, and 5 provides adequate flow to ensure mixing, prevent stratification, and produce gradual reactivity changes during RCS boron concentration reductions. With no reactor coolant loop in operation in either MODES 3,4, or 5, dilution sources must be isolated and administratively controlled. The boron dilution analysis in these MODES take credit for the mixing volume associated with having at least one reactor coolant loop in operation (Ref. 1).

RCS Loops - MODE 4 satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

Wolf Creek - Unit 1 B 3.4.6-1 Revision 17

RCS Loops-MODE 4 B 3.4.6 BASES LCO The purpose of this LCO is to require that at least two loops be OPERABLE in MODE 4 and that one of these loops be in operation. The LCO allows the two loops that are required to be OPERABLE to consist of any combination of RCS loops and RHR loops. Any one loop in operation provides enough flow to remove the decay heat from the core with forced circulation. An additional loop is required to be OPERABLE to provide redundancy for heat removal.

Note 1 permits all RCPs or RHR pumps to be removed from operation for

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. The purpose of the Note is to permit tests that are required to be performed without flow or pump noise. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is adequate to perform the necessary testing, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of Note 1 is permitted provided the following conditions are met along with any other conditions imposed by test procedures:

a. No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1, thereby maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure the SDM is maintained is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and

b. Core outlet temperature is maintained at least 10OF below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 requires that the secondary side water temperature of each SG be

50IF above each of the RCS cold leg temperatures before the start of an RCP with any RCS cold leg temperature s 3680 F. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS loop is comprised of an OPERABLE RCP and an OPERABLE SG in accordance with the Steam Generator Tube Surveillance Program, which has the minimum water level specified in SR 3.4.6.2.

Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.

Wolf Creek - Unit 1 B 3.4.6-2 Revision 12

RCS Loops - MODE 5, Loops Filled B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.7 RCS Loops - MODE 5, Loops Filled '-'

BASES BACKGROUND In MODE 5 with the RCS loops filled, the primary function of the reactor coolant is the removal of decay heat and transfer of this heat either to the steam generator (SG) secondary side coolant via natural circulation (Ref. 3) or the component cooling water via the residual heat removal (RHR) heat exchangers. While the principal means for decay heat removal is via the RHR System, the SGs are specified as a backup means for redundancy. Even though the SGs cannot produce steam in this MODE, they are capable of being a heat sink due to their large contained volume of secondary water. As long as the SG secondary side water is at a lower temperature than the reactor coolant, heat transfer will occur.' The rate of heat transfer is directly proportional to the temperature' difference. The secondary function of the reactor coolant is to act as a carrier for soluble neutron poison, boric acid.

In MODE 5 with RCS loops filled, the reactor coolant is circulated by means of two RHR loops connected to the RCS, each loop containing an RHR heat exchanger, an RHR pump, and appropriate flow and temperature instrumentation for control, protection,' and indication. One RHR pump circulates the water through the RCS at a sufficient rate to prevent boric acid stratification, but is not sufficient for the boron dilution analysis discussed below.

The number of loops in operation can vary to suit the operational needs.

The intent of this LCO is to provide forced flow from at least one RHR loop for decay heat removal and transport. The flow provided by one RHR loop is adequate for decay heat removal.' The other intent of this LCO is to require that a second path be available to provide redundancy for heat removal.

The LCO provides for redundant paths of decay heat removal capability.

The first path can be an RHR loop that must be OPERABLE and in operation. The second path can be another OPERABLE RHR loop or maintaining two SGs with secondary side wide range water levels above 66%'to'provide an alternate method for decay heat removal via natural circulation (Ref. 2). I Wolf Creek - Unit I B 3.4.7-1 Revision 12

a RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES APPLICABLE In MODE 5, RCS circulation is considered in the determination of the time SAFETY ANALYSES available for mitigation of the accidental boron dilution event.

The operation of one RCP in MODES 3, 4, and 5 provides adequate flow to ensure mixing, prevent stratification, and produce gradual reactivity changes during RCS boron concentration reductions. With no reactor coolant loop in operation in either MODES 3, 4, or 5, dilution sources must be isolated or administratively controlled. The boron dilution analysis in these MODES take credit for the mixing volume associated with having at least one reactor coolant loop in operation (Ref.1).

RCS Loops -MODE 5 (Loops Filled) satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require that at least one of the RHR loops be OPERABLE and in operation with an additional RHR loop OPERABLE or two SGs with secondary side wide range water level 2 66%. One RHR loop provides sufficient forced circulation to perform the safety functions of the reactor coolant under these conditions. An additional RHR loop is required to be OPERABLE to meet single failure considerations.

However, if the standby RHR loop is not OPERABLE, an acceptable alternate method is two SGs with their secondary side wide range water levels 2 66%. Should the operating RHR loop fail, the SGs could be used to remove the decay heat via natural circulation.

Note 1 permits all RHR pumps to be removed from operation for

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. The purpose of the Note is to permit tests that are required to be performed without flow or pump noise. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is adequate to perform the necessary testing, and operating experience has shown that boron stratification is not likely during this short period with no forced flow.

Utilization of Note 1 is permitted provided the following conditions are met, along with any other conditions imposed by test procedures:

a. No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1, thereby maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure the SDM is maintained is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and Wolf Creek - Unit 1 B 3.4.7-2 Revision 17

RCS Loops - MODE 5, Loops Not Filled B 3.4.8 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.8 RCS Loops -:MODE 5, Loops Not Filled BASES BACKGROUND In MODE 5 with the RCS loops not filled, the primary function of the reactor coolant is the removal of decay heat generated in the fuel, and the transfer of this heat to the component cooling watervia the residual heat removal (RHR) heat exchangers. The steam generators (SGs) are not available as a heat sink when the loops are not filled. The secondary function of the reactor coolant is to act as a carrier for the soluble neutron poison, boric acid.

In MODE 5 with loops not filled, only RHR pumps can be used for coolant circulation. The number of pumps in operation can vary to suit the operational needs. The intent of this LCO is to provide forced flow from at least one RHR pump for decay heat removal and transport and to require that two paths be available to provide redundancy for heat removal.

APPLICABLE In MODE 5, RCS circulation is considered in the determination of the SAFETY ANALYSES time available for mitigation of the accidental boron dilution event. The flow provided by one RHR loop is adequate for decay heat removal.-

The operation of one RCP in MODES 3, 4, and 5 provides adequate flow to ensure mixing, prevent stratification, and produce gradual reactivity changes during RCS boron concentration reductions. With no reactor coolant loop in operation in either MODES 3, 4, or 5, dilution sources must be isolated and administratively controlled. The boron dilution analysis in these MODES take credit for the mixing volume associated with having at I

least one reactor coolant loop in operation (Ref. 1).

RCS loops in MODE 5 (loops not filled) satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require that at least two RHR loops be OPERABLE arid one of these'loops be in operation. An OPERABLE loop is one that has the capability of transferring heat from the reactor coolant at a controlled rate. Heat cannot be removed via the RHR System unless forced flow is used. A minimum of one running RHR pump meets the LCO requirement for one loop in operation. An additional RHR loop is required to be OPERABLE to meet single failure considerations.

Wolf Creek - Unit 1 B 3.4.8-1 Revision 17.

RCS Loops - MODE 5, Loops Not Filled B 3.4.8 BASES LCO Note 1 permits all RHR pumps to be removed from operation for

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

(continued) The circumstances for stopping both RHR pumps are to be limited to situations when the outage time is short and core outlet temperature is maintained at least 10F below saturation temperature. The Note prohibits boron dilution with coolant at boron concentrations less than required to assure the SDM of LCO 3.1.1 is maintained or draining operations when RHR forced flow is stopped. The Note requires reactor vessel water level be above the vessel flange to ensure the operating RHR pump will not be intentionally deenergized during mid-loop operations.

Note 2 allows one RHR loop to be inoperable for a period of < 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , provided that the other loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when these tests are safe and possible.

An OPERABLE RHR loop is comprised of an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger.

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required.

APPLICABILITY In MODE 5 with loops not filled, this LCO requires core heat removal and coolant circulation by the RHR System. One RHR loop provides sufficient capability for this purpose. However, one additional RHR loop is required to be OPERABLE to meet single failure considerations.

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops - MODES 1 and 2";

LCO 3.4.5, "RCS Loops - MODE 3";

LCO 3.4.6, "RCS Loops - MODE 4";

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled";

LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation - High Water Level" (MODE 6); and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level" (MODE 6).

Since LCO 3.4.8 contains Required Actions with immediate Completion Times, it is not permitted to enter LCO 3.4.8 from either LCO 3.4.7, RCS Loops - MODE 5, Loops Filled," or from MODE 6, unless the requirements of LCO 3.4.8 are met. This precludes removing the heat removal path afforded by the steam generators with the RHR System is degraded.

Wolf Creek - Unit 1 B 3.4.8-2 Revision 19

Pressurizer PORVs B 3.4.1 1 BASES LCO exists when conditions dictate closure of the block valve to limit leakage (continued) Satisfying the LCO helps minimize challenges to fission product barriers.

APPLICABILITY In MODES 1, 2, and 3 (with all RCS cold leg temperatures above 368 0F),

the PORVs are required to be OPERABLE to limit the potential for a small break LOCA through the flow path. The most likely cause for a PORV small break LOCA is a result of a pressure increase transient that causes the PORV to open. Imbalances in the energy output of the core and heat removal by the secondary system can cause the RCS pressure to increase to the PORV opening setpoint. -The most rapid increases will occur at the higher operating power and pressure conditions of MODES I and 2. Although not a required function, the PORVs OPERABILITY in MODES 1, 2, and 3 (with all RCS cold leg temperatures above 368 0 F) also serves the desired function of minimizing challenges to the pressurizer safety valves. The PORVs are also required to be OPERABLE in MODES 1, 2, and 3 (with all RCS cold leg temperatures above 3680 F) for manual actuation to mitigate a Steam Generator Tube

-Rupture event.

Pressure increases are less prominent in MODE 3 because the core input energy is reduced, but the RCS pressure is high. Therefore, the LCO is applicable in MODES 1, 2, and 3 (with all RCS cold leg temperatures above 3680F). The LCO is not applicable in MODES 3 (with any RCS cold leg temperature

368 0 F) 4. 5, and 6 (with the reactor vessel head in place) when both pressure and core energy are decreased and the pressure surges become much less significant. LCO 3.4.12 addresses the PORV requirements in these MODES.'

ACTIONS A Note has been added to clarify that all pressurizer PORVs are treated I as separate entities, each with separate Completion Times (i.e., the Completion Time is on a component basis).; I A.1 --

PORVs may be inoperable and capable of being manually cycled (e.g.,

excessive seat leakage). In this condition, either the PORVs must be Wolf~~~~

I~ ~~ ~ Cre .13 Uni. eiin1 Wolf Creek - Unit 1 B 3.4.1 1-3 Revision 19

Pressurizer PORVs B 3.4.11 BASES ACTIONS A. 1 (continued) restored or the flow path isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The associated block valve is required to be closed, but power must be maintained to the associated block valve, since removal of power would render the block valve inoperable. Although a PORV may be designated inoperable, it may be able to be manually opened and closed, and therefore, able to perform its function. PORV inoperability may be due to excessive seat leakage or other causes that do not prevent manual use and do not create a possibility for a small break LOCA. For these reasons, the block valve may be closed but the Action requires power be maintained to the valve.

This Condition is only intended to permit operation of the plant for a limited period of time not to exceed the next refueling outage (MODE 6) so that maintenance can be performed on the PORVs to eliminate the problem condition. Normally, the PORVs should be available for automatic mitigation of overpressure events and should be returned to OPERABLE and automatic actuation status prior to entering startup (MODE 2).

Quick access to the PORV for pressure control can be made when power remains on the closed block valve. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on plant operating experience that has shown that minor problems can be corrected or closure accomplished in this time period.

B.1. B.2, and B.3 If one PORV is inoperable and not capable of being manually cycled, it must be either restored or isolated by closing the associated block valve and removing the power to the associated block valve. The Completion Times of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months are reasonable, based on challenges to the PORVs during this time period, and provide the operator adequate time to correct the situation. If the inoperable valve cannot be restored to OPERABLE status, it must be isolated within the specified time. Because there is at least one PORV that remains OPERABLE, an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore the inoperable PORV to OPERABLE status. If the PORV cannot be restored within this additional time, the plant must be brought to a MODE in which the LCO does not apply, as required by Condition D.

C.1 and C.2 If one block valve is inoperable, then it is necessary to either restore the block valve to OPERABLE status within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or Wolf Creek - Unit 1 B 3.4.1 1-4 Revision 0

LTOP System B 3.4.12 BASES LCO Each of these methods of overpressure prevention is capable of (continued) mitigating the limiting LTOP transient.

APPLICABILITY This LCO is applicable in MODE 3 when any RCS cold leg temperature is

-53680F, in MODE 4, in MODE 5 and in MODE 6 when the reactor vessel head is on. The pressurizer safety valves provide overpressure protection that meets the Reference 1 P/T limits in MODES 1, 2, and 3.

When the reactor vessel head is off, overpressurization cannot occur.

LCO 3.4.3 provides the operational P/T limits for all MODES. LCO 3.4.10, "Pressurizer Safety Valves," requires the OPERABILITY of the pressurizer safety valves that provide overpressure protection during MODES 1, 2, and 3.

Low temperature overpressure prevention is most critical during shutdown when the RCS is water solid, and a mass or heat input transient can cause a very rapid increase in RCS pressure when little or no time allows operator action to mitigate the event.

ACTIONS A Note prohibits the application of LCO 3.0.4b. to an inoperable LTOP System. There is an increased risk associated with entering MODE 3 from MODE 4 and MODE 4 from MODE 5 with LTOP inoperable and the provisions of LCO 3.0.4b., which allow entry Into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing'inoperable systems and components, should not be applied in this circumstance.

A.1 and B.1 With one or more safety injection pumps or two centrifugal charging pumps capable of injecting into the RCS, RCS overpressurization is possible.'

To immediately initiate action to restore restricted coolant input capability to the RCS reflects the urgency of removing the RCS from this condition.

C.1. D.1. and D.2 An unisolated accumulator requires isolation within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This is only required when the accumulator pressure isat or more than the maximum RCS pressure for the existing temperature allowed by the P/T limit curves.

Wolf Creek - Unit 1 B 3.4.12-9 Revision 19

-_lo LTOP System B 3.4.12 BASES ACTIONS C.1. D.1, and D.2 (continued)

If isolation is needed and cannot be accomplished in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , Required Action D.1 and Required Action D.2 provide two options, either of which must be performed in the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . By increasing the RCS temperature to > 3680 F, an accumulator pressure of 648 psig cannot exceed the LTOP limits if the accumulators are fully injected.

Depressurizing the accumulators below the LTOP limit from the PTLR also gives this protection.

The Completion Times are based on operating experience that these activities can be accomplished in these time periods and on engineering evaluations indicating that an event requiring LTOP is not likely in the allowed times.

E.1 In MODE 3 with any RCS cold leg temperature < 3680 F or MODE 4, with one required RCS relief valve inoperable, the RCS relief valve must be restored to OPERABLE status within a Completion Time of 7 days. Two RCS relief valves in any combination of the PORVS and the RHR suction relief valves are required to provide low temperature overpressure mitigation while withstanding a single failure of an active component.

The Completion Time considers the facts that only one of the RCS relief valves is required to mitigate an overpressure transient and that the likelihood of an active failure of the remaining valve path during this time period is very low.

F.1 The consequences of operational events that will overpressurize the RCS are more severe at lower temperature (Ref. 7). Thus, with one of the two RCS relief valves inoperable in MODE 5 or in MODE 6 with the head on, the Completion Time to restore two valves to OPERABLE status is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The Completion Time represents a reasonable time to investigate and repair several types of relief valve failures without exposure to a lengthy period with only one OPERABLE RCS relief valve to protect against overpressure events.

Wolf Creek - Unit 1 B 3.4.12-1 0 Revision 0

RCS Leakage Detection Instrumentation B 3.4.15 BASES APPLICABLE locations are utilized, if needed, to ensure that the transport delay time of SAFETY ANALYSES the leakage from its source to an instrument location yields an acceptable (continued) overall response time.

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting and monitoring RCS LEAKAGE into the containment area is necessary. Quickly separating the identified LEAKAGE from the unidentified LEAKAGE provides quantitative information to the operators, allowing them to take corrective action should a leak occur detrimental to the safety of the unit and the public.

RCS leakage detection instrumentation satisfies Criterion I of 10 CFR 50.36(c)(2)(ii).

LCO - One method of protecting against large RCS leakage derives from the ability of instruments to rapidly detect extremely small leaks. This LCO requires instruments of diverse monitoring principles to be OPERABLE to provide a high degree of confidence that extremely small leaks are detected in time to allow actions to place the plant in a safe condition, when RCS LEAKAGE indicates possible RCPB degradation.

The LCO is satisfied when monitors of diverse measurement means are available. Thus, the Containment Sump Level and Flow Monitoring System, one containment atmosphere particulate radioactivity monitor and either the Containment Cooler Condensate Flow Monitoring System or one containment atmosphere gaseous radioactivity monitor provide an acceptable minimum.

For containment atmosphere gaseous and particulate radioactivity monitor instrumentation, OPERABILITY involves more than OPERABILITY of the channel electronics. OPERABILITY also requires correct valve lineups, sample pump operation, and, for particulate monitors, sample line insulation and heat tracing, as well as detector OPERABILITY, since

'these supporting features are necessary for the monitors to rapidly detect RCS LEAKAGE.

APPLICABILITY Because of elevated RCS temperature and pressure in MODES 1, 2, 3, and 4, RCS leakage detection instrumentation is required to be OPERABLE.

In MODE 5 or 6, the temperature is required to be

200OF and pressure is maintained low or at atmospheric pressure. Since the temperatures and pressures are far lower than those for MODES 1, 2, 3, and 4, the likelihood of leakage and crack propagation are much smaller. Therefore, the requirements of this LCO are not applicable in MODES 5 and 6.

Wolf Creek - Unit 1 B 3.4.15-3 Revision 9

11IL-RCS Leakage Detection Instrumentation B 3.4.15 BASES ACTIONS A.1 and A.2 A primary system leak would result in reactor coolant flowing into the containment normal sumps or into the instrument tunnel sump. Indication of increasing sump level is transmitted to the control room by means of individual sump level transmitters. This information is used to provide measurement of low leakage by monitoring level increase versus time.

With the required Containment Sump Level and Flow Monitoring System inoperable, no other form of sampling can provide the equivalent information; however, the containment atmosphere particulate radioactivity monitor will provide indications of changes in leakage.

Together with the atmosphere monitor, the periodic surveillance for RCS water inventory balance, SR 3.4.13.1, must be performed at an increased frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to provide information that is adequate to detect leakage. A Note is added allowing that SR 3.4.13.1 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 (near operating rated operating pressure with stable RCS pressure, temperature, power level, pressurizer and makeup tank level, makeup and letdown, and RCP seal injection and return flows). 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.

Restoration of the required Containment Sump Level and Flow Monitoring System to OPERABLE status within a Completion Time of 30 days is required to regain the function after the system's failure. This time is acceptable, considering the Frequency and adequacy of the RCS water inventory balance required by Required Action A.1.

B.1.1. B.1.2. and B.2 With the containment atmosphere particulate radioactivity monitoring instrumentation channel inoperable, alternative action is required. Either samples of the containment atmosphere must be taken and analyzed for gaseous and particulate radioactivity or water inventory balances, in accordance with SR 3.4.13.1, must be performed to provide alternate periodic information.

Wolf Creek - Unit 1 B 3.4.1 5-4 Revision 19

RCS Specific Activity B 3.4.16 BASES LCO The specific iodine activity is limited to 1.0 ttCi/gm DOSE EQUIVALENT; 1-131, and the gross specific activity in the reactor coolant is limited to the

- number of IiCi/gm equal to 100 divided by E (average disintegration energy of the sum of the average beta and gamma energies of the coolant nuclides). The limit on DOSE EQUIVALENT 1-131 ensures the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thyroid dose to an individual at the site boundary during the Design Basis Accident (DBA) will be a small fraction of the allowed thyroid dose.

The limit on gross specific activity ensures the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months whole body dose to an individual at the site boundary during the DBA will be a small fraction of the allowed whole body dose.

The SGTR accident analysis (Ref. 2) shows that the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months site boundary dose levels are within acceptable limits. Violation of the LCO may result in reactor coolant radioactivity levels that could, in the event of an SGTR, lead to site boundary doses that exceed the 10 CFR 100 dose guideline limits.

APPLICABILITY In MODES 1 and 2, and in MODE 3 with RCS average temperature 2 500 0F, operation within the LCO limits for DOSE EQUIVALENT 1-131 and gross specific activity are necessary to contain the potential consequences of an SGTR to within the acceptable site boundary dose values.

For operation in MODE 3 with RCS average temperature < 500 0F, and in MODES 4 and 5, the offsite release of radioactivity.in the event of a SGTR is unlikely since the saturation pressure of the reactor coolant is below the lift pressure settings of the main steam safety and atmospheric relief valves.

ACTIONS A.1 and A.2 -

With the DOSE EQUIVALENT 1-131 greater than the LCO limit, samples at intervals of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months must be taken to demonstrate that the limits of Figure 3.4.16-1 are not exceeded. The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is required to obtain and analyze a sample. Sampling is done to continue to provide a trend.

The DOSE EQUIVALENT 1-131 must be restored to within limits within

- 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is required, if the limit violation resulted from normal iodine spiking and is acceptable because of the low probability of an SGTR occuring during this period.

Wolf Creek - Unit 1 B 3.4.16-3 Revision 0

RCS Specific Activity B 3.4.16 BASES ACTIONS A.1 and A.2 (continued)

A Note permits the use of the provisions of LCO 3.0.4c. This allowance permits entry into the applicable MODE(s) while relying on the ACTIONS.

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

B.1 With the gross specific activity in excess of the allowed limit, the unit must be placed in a MODE in which the requirement does not apply.

The change within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to MODE 3 and RCS average temperature

< 500OF lowers the saturation pressure of the reactor coolant below the setpoints of the main steam safety and atmospheric relief valves and prevents venting the SG to the environment in an SGTR event. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 below 5000 F from full power conditions in an orderly manner and without challenging plant systems.

C.1 If a Required Action and the associated Completion Time of Condition A is not met or if the DOSE EQUIVALENT 1-131 is in the unacceptable region of Figure 3.4.16-1, the reactor must be brought to MODE 3 with RCS average temperature < 5000 F within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 below 500OF from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.16.1 REQUIREMENTS SR 3.4.16.1 requires performing a gamma isotopic analysis as a measure of the gross specific activity of the reactor coolant at least once every 7 days. While basically a quantitative measure of radionuclides with half lives longer than 15 minutes, excluding iodines, this measurement is the Wolf Creek - Unit 1 B 3.4.16-4 Revision 19

ECCS - Shutdown B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.3 ECCS - Shutdown BASES BACKGROUND The Background section for Bases 3.5.2, "ECCS - Operating," is applicable to these Bases, with the following modifications.

In MODE 4, the required ECCS train consists of two separate subsystems: centrifugal charging (high head) and residual heat removal (RHR) (low head).

The ECCS flow paths consist of piping, valves, heat exchangers, and pumps such that water from the refueling water storage tank (RWST) can be injected into the Reactor Coolant System (RCS) following the accidents described in Bases 3.5.2.

APPLICABLE The Applicable Safety Analyses section of Bases 3.5.2 also applies SAFETY ANALYSES to this Bases section.

Due to the stable conditions associated with operation in MODE 4 and the reduced probability of occurrence of a Design Basis Accident (DBA), the ECCS operational requirements are reduced. It is understood in these reductions that certain automatic safety injection (SI) actuation is not available. In this MODE, sufficient time exists for manual actuation of the required ECCS to mitigate the consequences of a DBA.

.d th an MOD 4. the For MODE 3, with the accumulators blocked, and MODE 4, the parameters assumed in the generic bounding thermal hydraulic analysis for the limiting DBA (Reference 1)are based on a combination of limiting parameters for MODE 3, with the accumulators blocked, and parameters for MODE 4. However, assumed ECCS availability is based on MODE 4 conditions; the minimum available ECCS flow is calculated assuming only one OPERABLE ECCS train.

Only one train of.ECCS is required for MODE 4. This requirement dictates that single failures are not considered during this MODE of operation. The ECCS trains satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO In MODE 4, one of the two independent (and redundant) ECCS trains is required to be OPERABLE to ensure that sufficient ECCS flow is available to the core following a DBA.

Wolf Creek - Unit I B 3.5.3-1 'Revision 16

ECCS - Shutdown B 3.5.3 BASES LCO In MODE 4, an ECCS train consists of a centrifugal charging subsystem (continued) and an RHR subsystem. Each train includes the piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST and transferring suction to the containment sump.

During an event requiring ECCS actuation, a flow path is required to provide an abundant supply of water from the RWST to the RCS via the ECCS pumps and their respective supply headers to two cold leg injection nozzles. In the long term, this flow path may be switched to take its supply from the containment sump and to deliver its flow to the RCS hot and cold legs.

This LCO is modified by a Note that allows an RHR train to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the ECCS mode of operation and not otherwise inoperable. This allows operation in the RHR mode during MODE 4.

APPLICABILITY In MODES 1, 2, and 3, the OPERABILITY requirements for ECCS are covered by LCO 3.5.2.

In MODE 4 with RCS temperature below 3500 F, one OPERABLE ECCS train is acceptable without single failure consideration, on the basis of the stable reactivity of the reactor and the limited core cooling requirements.

In MODES 5 and 6, plant conditions are such that the probability of an event requiring ECCS injection is extremely low. Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, "RCS Loops -

MODE 5, Loops Filled," and LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled." MODE 6 core cooling requirements are addressed by LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation - High Water Level," and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level."

ACTIONS A Note prohibits the application of LCO 3.0.4b. to an inoperable ECCS centrifugal charging pump subsystem when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable ECCS centrifugal charging pump subsystem and the provisions of LCO 3.0.4b. which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

Wolf Creek - Unit 1 B 3.5.3-2 Revision 19

ECCS - Shutdown B 3.5.3 BASES ACTIONS A.1 (continued)

With no ECCS RHR subsystem OPERABLE, the plant is not prepared to respond to a loss of coolant accident or to continue a cooldown using the RHR pumps and heat exchangers. The Completion Time of immediately to initiate actions that would restore at least one ECCS RHR subsystem to OPERABLE status ensures that prompt action is taken to restore the required cooling capacity. Normally, in MODE 4, reactor decay heat is removed from the RCS by an RHR loop. If no RHR loop is OPERABLE for this function, reactor decay heat must be removed by some alternate method, such as use of the steam generators. The alternate means of heat removal must continue until the inoperable RHR loop components can be restored to operation so that decay heat removal is continuous.

With both RHR pumps and heat exchangers inoperable, it would be unwise to require the plant to go to MODE 5, where the only available heat removal system is the RHR. Therefore, the appropriate action is to initiate measures to restore one ECCS RHR subsystem and to continue the actions until the subsystem is restored to OPERABLE status.

B.1 With no ECCS high head subsystem OPERABLE, due to the inoperability of the centrifugal charging pump or flow path from the RWST, the plant is not prepared to provide high pressure response to Design Basis Events requiring Si. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time to restore at least one ECCS high head subsystem to OPERABLE status ensures that prompt action is taken to provide the required cooling capacity or to initiate actions to place the plant in MODE 5, where an ECCS train is not required.

C.1 When the Required Actions of Condition B cannot be completed within the required Completion Time, a controlled shutdown should be initiated.

Twenty-four hours is a reasonable time, based on operating experience, to reach MODE 5 in an orderly manner and without challenging plant systems or operators.

SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The applicable Surveillance descriptions from Bases 3.5.2 apply.

Wolf Creek - Unit 1 B 3.5.3-3 Revision 19 1

- -- - -a-ECCS - Shutdown B 3.5.3 BASES REFERENCES The applicable references from Bases 3.5.2 apply.

1. WCAP-12476, Revision 1, "Evaluation of LOCA During Mode 3 and Mode 4 Operation for Westinghouse NSSS," November 2000. I Wolf Creek - Unit 1 B 3.5.3-4 Revision 16

Containment B 3.6.1 BASES LCO Leakage Rate Testing Program leakage test. At this time, the applicable (continued) leakage limits must be met.

Compliance with this LCO will ensure a containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analysis.

Individual leakage rates for the containment air lock (LCO 3.6.2) and containment purge valves with resilient seals (LCO 3.6.3) are not specifically part of the acceptance criteria of 10 CFR 50, Appendix J, Option B. Therefore, leakage rates exceeding these individual limits only result in the containment being inoperable when the leakage results in exceeding the overall acceptance criteria of 1.0 La.

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

ACTIONS A.1 In the event containment is inoperable, containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining containment during MODES 1, 2, 3, and 4. This time period also ensures that the probability of an accident (requiring containment OPERABILITY) occurring during periods when containment is inoperable is minimal.

B.1 and B.2 If containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which.

the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 'and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Wolf Creek - Unit 1 B 3.6.1-3

Revision 0

Containment B 3.6.1 BASES SURVEILLANCE SR 3.6.1.1 REQUIREMENTS Maintaining the containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Containment Leakage Rate Testing Program. The containment concrete visual examinations may be performed during either power operation, e.g.,

performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance/refueling outage. The visual examinations of the steel liner plate inside containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.

Failure to meet air lock and purge valve with resilient seal leakage limits specified in LCO 3.6.2 and LCO 3.6.3 does not invalidate the acceptability of these overall leakage determinations unless their contribution to overall Type A, B, and C leakage causes that to exceed limits. As left leakage prior to the first startup after performing a required Containment Leakage Rate Testing Program leakage test is required to be < 0.6 La for combined Type B and C leakage, and

0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of < 1.0 La. At

1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis.

SR Frequencies are as required by the Containment Leakage Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

SR 3.6.1.2 This SR ensures that the structural integrity of the containment will be maintained in accordance with the provisions of the Containment Tendon Surveillance Program. Testing and Frequency are in accordance with ASME Code Section Xl, Subsection IWL (Ref. 4), and applicable addenda as required by 10 CFR 50.55a, except where an exemption or relief has been authorized by the NRC.

REFERENCES 1. 10 CFR 50, Appendix J, Option B.

2. USAR, Chapter 15.

3. USAR, Section 6.2.

4. ASME Code Section Xl, Subsection IWL.

Wolf Creek - Unit 1 B 3.6.1-4 Revision 17

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

With one of the containment cooling trains inoperable, the inoperable containment cooling train must be restored to OPERABLE status within 7 days.. The components in this degraded condition provide iodine removal capabilities and are capable of providing at least 100% of the heat removal needs. The 7 day Completion Time was developed taking into account the redundant heat removal capabilities afforded by combinations of the Containment Spray System and Containment Cooling System and the low probability of DBA occurring during this period...

The 10 day portion of the Completion Time for Required Action C.1 is based upon engineering judgment. It takes into account the low probability of coincident entry into two Conditions in this Specification coupled with the low probability of an accident occurring during this time.

Refer to Section 1.3 for a more detailed discussion of the purpose of the "from discovery of failure to meet the LCO" portion of the Completion Time.

D.1 With two containment cooling trains inoperable, one of the containment cooling trains must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

The components in this degraded condition provide iodine removal capabilities and are capable of providing significant heat removal needs I after an accident. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time was developed taking into account the heat removal function by both the Containment Spray I System and Containment Cooling System, the iodine removal function of the Containment Spray System, and the low probability of DBA occurring during this period.

E.1 and E.2 If the Required Action and associated Completion Time of Condition C or D of this LCO are not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Wolf Creek - Unit I B 3.6.6-6 Revision 18

_ _ _ _ _ _ - a1 -

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 2 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

Hydrogen Recombiners B 3.6.8 BASES APPLICABILITY In MODES 5 and 6, the probability and consequences of a LOCA are low, (continued) due to the pressure and temperature limitations in these MODES.

Therefore, hydrogen recombiners are not required in these MODES.

ACTIONS A.1 With one containment hydrogen recombiner inoperable, the inoperable recombiner must be restored to OPERABLE status within 30 days. In this condition, the remaining OPERABLE hydrogen recombiner is adequate to perform the hydrogen control function. However, the overall reliability is reduced because a single failure in the OPERABLE recombiner could result in reduced hydrogen control capability. The 30 day Completion Time is based on the availability of the other hydrogen recombiner, the low probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.

B.1 and B.2.

With two hydrogen recombiners inoperable, the ability to perform the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The alternate hydrogen control capabilities are provided by the containment Hydrogen Purge System.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable period of time to verify that a loss of hydrogen' control function does not exist. Both the initial verification and all subsequent verifications may be performed as an administrative check by examining logs or other information to determine the availability of the alternate hydrogen control system. It does not mean to perform the Surveillances needed to demonstrate OPERABILITY of the alternate hydrogen control system. If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two hydrogen recombiners inoperable for up to 7 days. Seven days is a reasonable time to allow two hydrogen recombiners to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of a LOCA that would generate hydrogen in the amounts capable of exceeding the flammability limit.

Wolf Creek - Unit I B 3.6.8-3 Revision 19

Hydrogen Recombiners B 3.6.8 BASES ACTIONS C.1 (continued)

If the inoperable hydrogen recombiner(s) cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.8.1 REQUIREMENTS Performance of a system functional test for each hydrogen recombiner ensures the recombiners are operational and can attain and sustain the temperature necessary for hydrogen recombination. In particular, this SR verifies that the minimum heater sheath temperature increases to 2 11 50 °F in < 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months .

Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.8.2 This SR ensures there are no physical problems that could affect recombiner operation. Since the recombiners are mechanically passive, they are not subject to mechanical failure. The only credible failure involves loss of power, blockage of the internal flow, missile impact, etc.

A visual inspection is sufficient to determine abnormal conditions (i.e.,

loose wiring or structural connections, deposits of foreign materials, etc.)

that could cause such failures. The 18 month Frequency for this SR was developed considering the incidence of hydrogen recombiners failing the SR in the past is low.

SR 3.6.8.3 This SR, which is performed following the functional test of SR 3.6.8.1, requires performance of a resistance to ground test for each heater phase to ensure that there are no detectable grounds in any heater phase. This is accomplished by verifying that the resistance to ground for any heater phase is> 10,000 ohms.

The 18 month Frequency for this Surveillance was developed considering the incidence of hydrogen recombiners failing the SR in the past is low.

Wolf Creek - Unit 1 B 3.6.8-4 Revision 0

ARVs B 3.7.4 BASES LCO acceptance criterion, exists when conditions dictate closure of the block' (continued) valve to limit leakage.

The nitrogen accumulator tanks supplying the turbine driven AFW pump control valves and the steam generator atmospheric relief valves ensure an eight hour supply for the pump and valves.

APPLICABILITY In MODES 1, 2, and 3, the ARV lines are required to be OPERABLE.

In MODE 4, the' pressure and temperature limitations are such that the probability of a SGTR event requiring ARV operation is low. In addition, the RHR System is available to provide the decay heat removal function in MODE 4. Therefore, the ARV lines are not required to be OPERABLE in MODE 4.

In MODE 5 or 6, an SGTR is not a credible event.

ACTIONS A.1 With one ARV line inoperable for reasons other than excessive leakage, action must be taken to restore the ARV line to OPERABLE status within 7 days. The 7 day Completion Time allows for the redundant capability afforded by the remaining OPERABLE ARV lines, a nonsafety grade backup in the Turbine Bypass System, and MSSVs.

B.1 With two ARV lines inoperable for reasons other than excessive ARV seat leakage, action must be taken to restore all but one ARV line to OPERABLE status. Since the block valve can be closed to isolate an ARV, some repairs may be possible with the unit at power. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable to repair inoperable ARV lines,' based on the availability of the Turbine Bypass System and/or MSSVs, and the'low probability of an event occurring during the restoration period that would require the ARV lines.

Wolf Creek - Unit 1 B 3.7.4-3 Revision 19

ARVs B 3.7.4 BASES ACTIONS C.1 (continued)

With three or more ARV lines inoperable for reasons other than excessive leakage, action must be taken to restore all but two ARV lines to OPERABLE status. Since the block valve can be closed to isolate an ARV, some repairs may be possible with the unit at power. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable to repair inoperable ARV lines, based on the availability of the Turbine Bypass System and MSSVs, and the low probability of an event occurring during this period that would require the ARV lines.

D.1 and D.2 Requiring a 30 day limit for restoring an ARV valve to OPERABLE status from inoperable, due to excessive seat leakage from the valve, provides assurance that the required number of ARVs will be available for plant cooldown. This action limits the period in which a block valve is closed due to excessive seat leakage of the ARV and minimizes the delay associated with manually opening a closed manual isolation valve (due to excessive seat leakage of the ARV).

E.1 and E.2 If the ARV lines cannot be restored to OPERABLE status 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 3.7.4.1 REQUIREMENTS To perform a controlled cooldown of the RCS, the ARVs must be able to be opened remotely and throttled through their full range. This SR ensures that the ARVs are tested through a full control cycle at least once per fuel cycle. Performance of inservice testing satisfies this requirement, and use of an ARV during a unit cooldown may satisfy this requirement.

Operating experience has shown that these components usually pass the Surveillance when performed at the required Inservice Testing Program Frequency. The Frequency is acceptable from a reliability standpoint.

Wolf Creek - Unit 1 B 3.7.4-4 Revision 19

AFW System B 3.7.5 BASES APPLICABILITY In MODE 5 or 6, the steam generators are not normally used for heat (continued) removal, and the AFW System is not required.

ACTIONS A Note prohibits the application of LCO 3.0.4b. to an inoperable AFW train when entering MODE 1. There is an increased risk associated with entering MODE 1 with an AFW train inoperable and the provisions of LCO 3.0.4b., which allow entry into a MODE, or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A.1 If one of the two steam supplies to the turbine driven AFW train is inoperable, action must be taken to restore OPERABLE status within 7 days. The 7 day Completion Time is reasonable, based on the following reasons:

a. The redundant OPERABLE steam supply to the turbine driven AFW pump; X

b. The availability of redundant OPERABLE motor driven AFW pumps; and

c. The low probability of an event occurring that requires the inoperable steam supply to the turbine driven AFW pump.

The second Completion Time for Required Action A.1 establishes a limit on the maximum time allowed for any combination of Conditions to be inoperable during any continuous failure to meet this LCO.

The 10 day Completion Time provides a limitation time allowed in this specified Condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which multiple Conditions are entered concurrently. The AND connector between 7 days and 10 days dictates that both Completion Times apply simultaneously, and the more restrictive must be met.

B.1 With one of the required AFW trains (pump or flow path) inoperable for reasons other than Condition A, action must be taken to restore OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This Condition includes the loss of Wolf Creek - Unit I B 3.7.5-5 Revision 19

AFW System B 3.7.5 BASES ACTIONS B.1 (continued) two steam supply lines to the turbine driven AFW pump. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on redundant capabilities afforded by the AFW System, time needed for repairs, and the low probability of a DBA occurring during this time period.

The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of Conditions to be inoperable during any continuous failure to meet this LCO.

The 10 day Completion Time provides a limitation time allowed in this specified Condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The AND connector between 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 10 days dictates that both Completion Times apply simultaneously, and the more restrictive must be met.

C.1 and C.2 When Required Action A.1 or B.1 cannot be completed within the required Completion Time, or if two AFW trains are inoperable, 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.

D.1 If all three AFW trains are inoperable, the unit is in a seriously degraded condition with no safety related means for conducting a cooldown, and only limited means for conducting a cooldown with nonsafety related equipment. In such a condition, the unit should not be perturbed by any action, including a power change, that might result in a trip. The seriousness of this condition requires that action be started immediately to restore one AFW train to OPERABLE status.

Required Action D.1 is modified by a Note indicating that all required MODE changes or power reductions are suspended until one AFW train is restored to OPERABLE status. In this case, LCO 3.0.3 is not applicable because it could force the unit into a less safe condition.

Wolf Creek - Unit 1 B 3.7.5-6 Revision 19 1

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 Section Xl of 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, Section Xl (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 19 1

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 2 1514 psid at a nominal flow of 110 gpm Turbine Driven Pump 2 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 if the 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

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

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

b. A worst case single failure.

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

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

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

One offsite circuit consists of the #7 transformer feeding through the 13-48 breaker power the ESF transformer XNBOI, which, in turn powers the NBO1 bus through its normal feeder breaker. Transformer XNBQ1 may also be powered from the SL-7 supply through the 13-8 breaker provided the offsite 69 KV line is not connected to the 345 kV system.

Another offsite circuit consists of the startup transformer feeding through breaker PA201 powering the ESF transformer XNBO2, which, in turn powers the NBO2 bus through its normal feeder breaker.

Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 12 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence Intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be -

met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions.

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

Upon failure of the DG lube oil keep warm system, the DG remains OPERABLE until the applicable low temperature alarm condition is Wolf Creek - Unit I B 3.8.1-3 Revision 6

AC Sources - Operating B 3.8.1 BASES LCO achieved. Upon failure of the DG jacket water keep warm system, the DG (continued) remains OPERABLE as long as jacket water temperature is 2 105 OF (Ref. 13).

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

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

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

APPLICABILITY The AC sources and LSELS are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

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

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

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

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

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

Wolf Creek - Unit 1 B 3.8.1-4 Revision 19

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

To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if the second required circuit falls SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

- A.2 Required Action A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features.

These features are powered from the redundant AC electrical power train.

This includes motor driven auxiliary feedwater pumps and the turbine driven auxiliary feedwater pump which must be available for mitigation of a feedwater line break. Single train systems, other than the turbine driven auxiliary feedwater pump, are not included in this Condition. A Note is added to this Required Action stating that in MODES 1, 2, and 3, the turbine driven auxiliary feedwater pump is considered a required redundant feature. The reason for the Note is to confirm the OPERABILITY of the turbine driven auxiliary feedwater pump in this Condition, since the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action A.2 is intended to allow the operator time either to evaluate and repair any discovered inoperabilities, or to supply the train without offsite power from the alternate offsite power circuit. Supplying both trains of the Class 1E AC electrical power distribution system from one offsite power source (either XNB01 or XNB02) is acceptable.' This 'Completion Time also allows for an exception to the normal "tiriie zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. The'train has' no offsite power supplying its loads; and

b. A required feature on the other train is inoperable and not in the safeguards position. -

If at any time during the existence of Condition A (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Wolf Creek - Unit 1 B 3.8.1-5 . Revision 19 1

-U-AC Sources - Operating B 3.8.1 BASES ACTIONS A2 (continued)

Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

A.3 According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified Wolf Creek - Unit 1 B 3.8.1-6 Revision 0

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

REQUIREMENTS 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 2 0.8 and s 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.

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)

Wolf Creek - Unit 1 B 3.8.1-19 . Revision 18

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

REQUIREMENTS 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, 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.

Wolf Creek - Unit 1 B 3.8.1-20 Revision 18

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.12 REQUIREMENTS (continued) 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 2 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 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 isverified.

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 I 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-Wolf Creek - Unit 1 B 3.8.1-21 Revision 18

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

REQUIREMENTS 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 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 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.

Wolf Creek - Unit 1 B 3.8.1 -22 Revision 18

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

REQUIREMENTS In order 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 2 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.

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

Wolf Creek - Unit I B 3.8.1-23 -:Revision 18

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.15 (continued)

REQUIREMENTS 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 changing bus 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.

SR 3.8.1.16 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 Wolf Creek - Unit 1 B 3.8.1-24 Revision 18

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.16 (continued)

REQUIREMENTS 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).

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.

Wolf Creek - Unit I B 3.8.1a-25 Revision118

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

REQUIREMENTS 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 1 or 2. Risk insights or deterministic methods may be used for this assessment.

SR 3.8.1.18 Under accident and loss of offsite power 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 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. 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 the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following Wolf Creek - Unit 1 B 3.8.1-26 Revision 18

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

REQUIREMENTS 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 3.8.1.1 1, 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.

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 I 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.

Wolf Creek - Unit I B 3.8.1-27 Revision 18

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

REQUIREMENTS The Note 2 restriction from normally performing the Surveillance in MODE I 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 reason for 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.

SR 3.8.1.21 SR 3.8.1.21 is the performance of an ACTUATION LOGIC TEST 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.

Wolf Creek - Unit 1 B 3.8.1-28 Revision 18

AC Sources - Operating B 3.8.1 BASES 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. ASME, Boiler and Pressure Vessel Code, Section Xi.

12. IEEE Standard 308-1978.

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

Wolf Creek - Unit I B 3.8.1-29 Revisin 18

Boron Concentration B 3.9.1 B 3.9 REFUELING OPERATIONS B 3.9.1 Boron Concentration BASES BACKGROUND The limit on the boron concentration of filled portions of the Reactor Coolant System (RCS) and the refueling canal, that have direct access to the reactor vessel, during refueling ensures that the reactor remains subcritical during MODE 6. The refueling canal is defined as the refueling pool in containment, the spent fuel pool, the transfer canal, and the cask loading pool. Refueling boron concentration is the soluble boron concentration in the coolant in each of these volumes having direct access to the reactor vessel during refueling.

The soluble boron concentration offsets the core reactivity and is measured by chemical analysis of a representative sample of the coolant in each of the volumes. The refueling boron concentration limit is specified in the COLR. Plant procedures ensure the specified boron concentration in order to maintain an overall core reactivity of kff

0.95 during fuel handling, with control rods and fuel assemblies assumed to be in the most adverse configuration (least negative reactivity) allowed by plant procedures.

GDC 26 of 10 CFR 50, Appendix A, requires that two independent reactivity control systems of different design principles be provided (Ref. 1). One of these systems must be capable of holding the reactor core subcritical under cold conditions. The Chemical and Volume Control System (CVCS) is the main system capable of maintaining the reactor subcritical in cold conditions by maintaining the boron concentration.

The reactor is brought to shutdown conditions before beginning operations to open the reactor-vessel for refueling. After the RCS is cooled and depressurized and the vessel head is unbolted, the head is slowly removed. Typically, the refueling pool is then flooded with borated water from the refueling water storage tank through the open reactor vessel by the use of the Residual Heat Removal (RHR) System pumps or by gravity feeding.

The pumping action of the RHR System in the RCS and the natural circulation due to thermal driving heads in the reactor vessel and refueling pool mix the added concentrated boric acid with the water in the refueling pool. The RHR System is in operation during refueling (see LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation - High Water Level," and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Wolf Creek - Unit 1 B 3.9. 1-1 .Revision 0

Boron Concentration B 3.9.1 BASES BACKGROUND Circulation - Low Water Level") to provide forced circulation in the RCS (continued) and assist in maintaining the boron concentrations in the RCS and the refueling pool above the COLR limit.

APPLICABLE The boron concentration limit specified in the COLR is based on the core SAFETY ANALYSES reactivity at the beginning of each fuel cycle (the end of refueling) and includes an uncertainty allowance.

The required boron concentration and the plant refueling procedures that verify the correct fuel loading plan (including full core mapping) ensure that the keff of the core will remain < 0.95 during the refueling operation.

Hence, at least a 5% Ak/k margin of safety is established during refueling.

During refueling, the water volume in the spent fuel pool, the transfer canal, the refueling pool, cask loading pool, and the reactor vessel form a single mass. As a result, the soluble boron concentration is relatively the same in each of these connected volumes having direct access to the reactor vessel.

Boron dilution accidents are precluded in MODE 6 by isolating potential dilution flow paths. See LCO 3.9.2, "Unborated Water Source Isolation Valves."

The RCS boron concentration satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that a minimum boron concentration be maintained in the filled portions of the RCS and the refueling canal, that have direct access to the reactor vessel while in MODE 6. The boron concentration limit specified in the COLR ensures that a core kff of < 0.95 is maintained during fuel handling operations. Violation of the LCO could lead to an inadvertent criticality during MODE 6.

APPLICABILITY This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical. The required boron concentration ensures a keff < 0.95. Above MODE 6, LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," LCO 3.1.5, 'Shutdown Bank Insertion Limits" and LCO 3.1.6, "Control Bank Insertion Limits," ensure that an adequate amount of negative reactivity is available to shut down the reactor and maintain it subcritical.

This Specification has no LCO 3.0.4c. exception and LCO 3.0.4 places no restrictions on MODE changes that are part of the shutdown of the unit. I Wolf Creek - Unit 1 B 3.9.1-2 Revision 19

Boron Concentration B 3.9.1 BASES APPLICABILITY However, since this Specification has Required Actions with immediate (continued) Completions Times, entering MODE 6 will not be permitted unless the boron concentration limits of this LCO are met. This will assure that the core reactivity is maintained within limits during fuel handling operations.

The risk assessments for LCO 3.0.4b. may only be utilized for systems and components, not Criterion' 2 values or parameters such as MODE 6 boron concentration. Therefore, a risk assessment per LCO 3.0.4b. to allow MODE changes with single or multiple system/equipment inoperabilities may not be used to allow a MODE change into this LCO

- while not meeting the MODE 6 boron concentration limits, even if the risk assessment specifically includes consideration of the MODE 6 boron concentration.

ACTIONS A.1 and A.2 Continuation of CORE ALTERATIONS or positive reactivity additions (including actions'to'rieduce boron c6ncentration)'is contingent upo'n maintaining the unit in compliance with.the LCO. If the boron concentration of any coolant volume in the filled portions of the RCS, and the refueling canal, that have direct access to the reactor vessel,' is less than its limit, all operations involving CORE ALTERATIONS or positive reactivity additions must be suspended immediately.

Suspension of CORE ALTERATIONS and positive reactivity additions shall not preclude moving a component to a safe position. Operations that individually add limited positive reactivity (e.g., temperature fluctuations, inventory addition, or temperature control fluctuations), but when combined with all other operations affecting core reactivity (e.g.,

intentional boration) result in overall net negative reactivity addition, are not precluded by this action.

A.3 In addition to immediately suspending CORE ALTERATIONS and positive reactivity additions, boration to restore the concentration must be initiated immediately.

In determining the required combination of boration flow rate and concentration, no unique Design Basis Event must be satisfied. The only requirement is to restore the boron concentration to its required value as soon as possible. In order to raise the boron concentration as soon as possible, the operator should begin boration with the best source available for unit conditions.

Wolf Creek - Unit I B 3.9.1-3 Revision 19

Boron Concentration B 3.9.1 BASES ACTIONS A.3 (continued)

Once actions have been initiated, they must be continued until the boron concentration is restored. The restoration time depends on the amount of boron that must be injected to reach the required concentration.

SURVEILLANCE SR 3.9.1.1 REQUIREMENTS This SR ensures that the coolant boron concentration in the filled portions of the RCS and the refueling canal, that have direct access to the reactor vessel, is within the COLR limits. The boron concentration of the coolant in each required volume is determined periodically by chemical analysis.

A minimum Frequency of once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable amount of time to verify the boron concentration of representative sample(s). The Frequency is based on operating experience, which has shown 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to be adequate.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

Wolf Creek - Unit 1 B 3.9.1-4 Revision 19 1

RHR and Coolant Circulation - Low Water Level B 3.9.6 B 3.9 REFUELING OPERATIONS B 3.9.6 Residual Heat Removal (RHR) and Coolant Circulation - Low 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 exchangers 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 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 2000F, 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 will eventually challenge the integrity of the fuel cladding, which is a fission product barrier. Two trains of the RHR System are required to be OPERABLE, and one train in operation, in order to prevent this challenge.

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 In MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, both RHR loops must be OPERABLE.

Additionally, one loop of RHR must be in operation in order to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and Wolf Creek - Unit 1 B 3.9.6-1 Revision 0.

RHR and Coolant Circulation - Low Water Level B 3.9.6 BASES LCO c. Indication of reactor coolant temperature.

(continued)

An OPERABLE RHR loop consists of 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. An OPERABLE RHR loop must be capable of being realigned to provide an OPERABLE flow path.

APPLICABILITY Two RHR loops are required to be OPERABLE, and one RHR loop must be in operation in MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, to provide decay heat removal.

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 2 23 ft are located in LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation -High Water Level."

Since LCO 3.9.6 contains Required Actions with immediate Completion Times related to the restoration of the degraded decay heat removal function, it is not permitted to enter this LCO from either MODE 5 or from LCO 3.9.5, 'RHR and Coolant Circulation - High Water Level,"

unless the requirements of LCO 3.9.6 are met. This precludes diminishing the backup decay heat removal capability when the RHR System is degraded.

ACTIONS A.1 and A.2 If less than the required number of RHR loops are OPERABLE, action shall be immediately initiated and continued until the RHR loop is restored to OPERABLE status and to operation in accordance with the LCO or until Ž 23 ft of water level is established above the reactor vessel flange. When the water level is 2 23 ft above the reactor vessel flange, the Applicability changes to that of LCO 3.9.5, and only one RHR loop is required to be OPERABLE and in operation. An immediate Completion Time is necessary for an operator to initiate corrective actions.

B.1 If no RHR loop is in operation, 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 Wolf Creek - Unit 1 B 3.9.6-2 Revision 19

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TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents i 0 Amend. No. 123 12/18/99 ii 0 Amend. No. 123 12118/99 iii 2 DRR 00-0147 4/24100 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 12118/99 B 2.1.2-2 12 DRR 02-1062 9/26/02 B 2.1.2-3 0 Amend. No. 123 12118/99 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY B 3.0-1 0 Amend. No. 123 12118/99 B 3.0-2 0 Amend. No. 123 12118/99 B 3.0-3 0 Amend. No. 123 12118/99 B 3.0-4 19 DRR 04-1414 10/12104 B 3.0-5 19 DRR 04-1414 10/12104 B 3.0-6 19 DRR 04-1414 10/12104 B 3.0-7 19 DRR 04-1414 10/12104 B 3.0-8 19 DRR 04-1414 10/12104 B 3.0-9 19 DRR 04-1414 10/12104 B 3.0-10 19 DRR 04-1414 10/12104 B 3.0-11 19 DRR 04-1414 10112104 B 3.0-12 19 DRR 04-1414 10/12104 B 3.0-13 19 DRR 04-1414 10/12104 B 3.0-14 19 DRR 04-1414 10/12104 B3.0-15 19 DRR04-1414 . -10/12/04 TAB - B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1-1 0. : Amend. No. 123 12118/99 B 3.1.1-2 0. Amend. No. 123 12118/99 B 3.1.1-3 O Amend. No. 123 12118/99 B 3.1.1-4 .19 DRR 04-1414 10/12/04 I B 3.1.1-5 0 Amend. No. 123 12118/99 B 3.1.2-1 Amend. No. 123 12118/99 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 Amend. No. 123 12118/99 B 3.1.2-5 I 0 Amend. No. 123 12118/99 B 3.1.3-1 I 0 Amend. No. 123 12118/99 B 3.1.3-2 0. Amend. No. 123 12118/99 B 3.1.3-3 0- Amend. No. 123 12118/99 B 3.1.3-4 : 0 Amend. No. 123 12118/99 B 3.1.3-5 ~0 Amend. No. 123 12/18/99 I

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TAB - B 3.1 REACTIVITY CONTROL SYSTEMS (continued)

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 B 3.2.1-1 0 Amend. No. 123 12/18/99 B 3.2.1-2 0 Amend. No. 123 12118/99 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 02-1062 9/26/02 B 3.2.1-7 0 Amend. No. 123 12/18/99 B 3.2.1-8 0 Amend. No. 123 12/18/99 B 3.2.1-9 4 DRR 00-1365 9/28/00 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 B 3.2.3-1 0 Amend. No. 123 12/18/99 B 3.2.3-2 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 ii Revision 19

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TAB - B 3.2 POWER DISTRIBUTION LIMITS (continued)

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 12/18199, 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 3.31-1 - 0 Amend. No. 123 12/18/99 B 3.3.1-2 0 A m.e.

Amend. No.-.-_-.

No. 1-123 1218/99 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 B 3.3.1-8 0 Amend. No. 123 12/18/99 B 3.3.1-9 0 Amend. No. 123 1218/99 B 3.3.1-10 : 0 Amend. No. 123 12/18/99 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 12/8/02 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 19 DRR 04-1414 10/12/04 B 3.3.1-33 19 DRR 04-1414 10/12/04 B 3.3.1-34 19 DRR 04-1414 10/12/04 B 3.3.1-35 19 DRR 04-1414 10/12/04 B 3.3.1-36 19 DRR 04-1414 10/12/04 B 3.3.1-37 12 DRR 02-1062 9/26/02 B 3.3.1-38 . 12 DRR 02-1062 9/26/02 B 3.3.1-39 0 Amend. No. 123 12/18/99 B 3.3.1-40 0 Amend. No. 123 12/18/99 I

Wolf Creek - UnIt I ...

.Revison 19

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.1-41 0 Amend. No. 123 12/18/99 B 3.3.1-42 13 DRR 02-1458 12/03/02 B 3.3.1-43 13 DRR 02-1458 12/03/02 B 3.3.1-44 13 DRR 02-1458 12/03/02 B 3.3.1-45 13 DRR 02-1458 12/03/02 B 3.3.1-46 13 DRR 02-1458 12/03/02 B 3.3.1-47 13 DRR 02-1458 12/03/02 B 3.3.1-48 13 DRR 02-1458 12/03/02 B 3.3.1-49 13 DRR 02-1458 12/03/02 B 3.3.1-50 13 DRR 02-1458 12/03/02 B 3.3.1-51 13 DRR 02-1458 12/03/02 B 3.3.1-52 13 DRR 02-1458 12/03/02 B 3.3.1-53 13 DRR 02-1458 12/03/02 B 3.3.1-54 13 DRR 02-1458 12/03/02 B 3.3.1-55 13 DRR 02-1458 12/03/02 B 3.3.1-56 13 DRR 02-1458 12/03/02 B 3.3.2-1 0 Amend. No. 123 12/18/99 B 3.3.2-2 0 Amend. No. 123 12118/99 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 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 0 Amend. No. 123 12/18/99 Wolf Creek - UnIt 1 iv Revision 19

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-36 0 Amend. No. 123 12/18/99 B 3.3.2-37 0 Amend. No. 123 12/18/99 B 3.3.2-38 0 Amend. No. 123 12/18/99 B 3.3.2-39 0 Amend. No. 123 12/18/99 B 3.3.2-40 0 Amend. No. 123 12/18/99 B 3.3.2-41 12 DRR 02-1062 9/26/02 B 3.3.2-42 0 Amend. No. 123 12/18/99 B 3.3.2-43 12 DRR 02-1062 9/26/02 B 3.3.2-44 0 Amend. No. 123 12/18/99.

B 3.3.2-45 0 Amend. No. 123 12/18/99 B 3.3.2-46 0 Amend. No. 123 12/18/99 B 3.3.2-47 6 DRR 00-1541 3/13/01 B 3.3.2-48 6 DRR 00-1 541 3/13/01 B 3.3.2-49 0 Amend. No. 123 12/18/99 B 3.3.2-50 2 DRR 00-0147 4/24/00 B 3.3.2-51 1 DRR 99-1624 12/18/99 B 3.3.2-52 0 Amend. No. 123 12/18/99 B 3.3.2-53 0 Amend. No. 123 12/18/99 B 3.3.2-54 6 DRR 00-1541 3/13/01-B 3.3.2-55 6 DRR 00-1541 3/13/01 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 8 DRR 01-1235 9/19/01 B 3.3.3-8 8 DRR 01-1235 9/19/01 B 3.3.3-9 8 DRR 01-1235 9/19/01 B 3.3.3-10 19 DRR 04-1414 10/12/04 B 3.3.3-11 19 DRR 04-1414 10/12/04 B 3.3.3-12 8 DRR 01 -1235 9/19/01 B 3.3.3-13 8 DRR 01 -1235 9/19/01 B 3.3.3-14 8 DRR 01-1235 9/19/01 B 3.3.3-15 8 DRR 01-1 235 9/19/01 I 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 B 3.3.54 1 DRR 99-1624 12/18/99 B 3.3.5-5 0 Amend. No. 123 12/18/99 B 3.3.5-6 0 Amend. No. 123 12/18/99 B 3.3.5-7 0 Amend. No. 123 12/18/99 B 3.3.6-1 0 Amend. No. 123 12/18/99 B 3.3.6-2 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 v Revision 19

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TAB - B 3.3 INSTRUMENTATION (continued)

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 3.3.74 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 3.3.84 0 Amend. No. 123 12/18/99 B 3.3.8-5 0 Amend. No. 123 12/18/99 B 3.3.8-6 0 Amend. No. 123 12/18/99 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 3.4.14 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 3.4.34 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 0 Amend. No. 123 12/18/99 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 12 DRR 02-1062 9/26/02 B 3.4.54 0 Amend. No. 123 12/18/99 B 3.4.5-5 12 DRR 02-1062 9/26/02 B 3.4.5-6 12 DRR 02-1062 9/26/02 B 3.4.6-1 17 DRR 04-0453 5/26/04 B 3.4.6-2 12 DRR 02-1062 9/26/02 Wolf Creek - UnIt 1 vi Revision 19

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

B 3.4.6-3 12 DRR 02-1062 9/26/02 B 3.4.6-4 12 DRR 02-1062 9/26/02 B 3.4.6-5 12 DRR 02-1062 9/26/02 B 3.4.7-1 .12 DRR 02-1062 9/26/02 B 3.4.7-2 17 DRR 04-0453 5/26/04 B 3.4.7-3 0. Amend. No. 123 12118/99 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 Amend. No. 123 12/18/99 B 3.4.9-3 Amend. No. 123 12/18/99 B 3.4.9-4 o0 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 O Amend. No. 123 12/18/99 B 3.4.10-4 4 5 DRR 00-1427 10/12/00 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 DRR 99-1624 12/18/99 B 3.4.11-6 0 Amend. No. 123 .12/18/99

.1 B 3.4.11-7 0. Amend. No. 123 12118/99 B 3.4.12-1 DRR 99-1624 12118/99 B 3.4.12-2 DRR 99-1624 12118/99 B 3.4.12-3 0 Amend. No. 123 12/18/99 B 3.4.12-4 I DRR 99-1624 12/18/99 B 3.4.12-5 I 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 I 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 0 Amend. No. 123 12/18/99 B 3.4.12-13 0 Amend. No. 123 12/18/99 B 3.4.12-14 0 Amend. No. 123 12/18/99 B 3.4.13-1 0 Amend. No. 123 12/18/99 B 3.4.13-2 0. Amend. No. 123 12/18/99 B 3.4.13-3 0 Amend. No. 123 12/18/99 B 3.4.13-4 0 Amend. No. 123 12/18199 B 3.4.13-5 12 DRR 02-1062 9/26/02 B 3.4.13-6 0, Amend. No. 123 12/18/99 B 3.4.14-1 Amend. No. 123 12/18/99 B 3.4.14-2 0 Amend. No. 123 12/18/99 B 3.4.14-3 0 Amend. No. 123 12/18/99 B 3.4.14-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit I vii Revision 19

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

B 3.4.14-5 16 DRR 03-1497 11/4/03 B 3.4.14-6 16 DRR 03-1497 11/4/03 B 3.4.15-1 2 DRR 00-0147 4/24/00 B 3.4.15-2 0 Amend. No. 123 12/18/00 B 3.4.15-3 9 DRR 02-0123 2/28/02 B 3.4.15-4 19 DRR 04-1414 10/12/04 B 3.4.15-5 9 DRR 02-1023 2/28/02 B 3.4.15-6 0 Amend. No. 123 12/18/99 B 3.4.15-7 0 Amend. No. 123 12/18/99 B 3.4.16-1 0 Amend. No. 123 12/18/99 B 3.4.16-2 1 DRR 99-1624 12/18/99 B 3.4.16-3 0 Amend. No. 123 12/18/99 B 3.4.16-4 19 DRR 04-1414 10/12/04 B 3.4.16-5 0 Amend. No. 123 12/18/99 B 3.4.16-6 0 Amend. No. 123 12/18/99 TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1-1 0 Amend. No. 123 12/18/99 B 3.5.1-2 0 Amend. No. 123 12/18/99 B 3.5.1-3 0 Amend. No. 123 12/18/99 B 3.5.1-4 0 Amend. No. 123 12/18/99 B 3.5.1-5 1 DRR 99-1624 12/18/99 B 3.5.1-6 1 DRR 99-1624 12/18/99 B 3.5.1-7 16 DRR 03-1497 11/4/03 B 3.5.1-8 1 DRR 99-1624 12/18/99 B 3.5.2-1 0 Amend. No. 123 12/18/99 B 3.5.2-2 0 Amend. No. 123 12/18/99 B 3.5.2-3 0 Amend. No. 123 12/18/99 B 3.5.2-4 0 Amend. No. 123 12/18/99 B 3.5.2-5 0 Amend. No. 123 12/18/99 B 3.5.2-6 0 Amend. No. 123 12/18/99 B 3.5.2-7 0 Amend. No. 123 12/18/99 B 3.5.2-8 0 Amend. No. 123 12/18/99 B 3.5.2-9 12 DRR 02-1062 9/26/02 B 3.5.2-10 0 Amend. No. 123 12/18/99 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 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 0 Amend. No. 123 12/18/99 B 3.5.5-1 2 Amend. No. 132 4/24/00 B 3.5.5-2 2 Amend. No. 132 4/24/00 B 3.5.5-3 2 Amend. No. 132 4/24/00 B 3.5.5-4 2 Amend. No. 132 4/24/00 Wolf Creek - UnIt 1 viii Revision 19

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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 9119/01 B 3.6.3-11 -9 DRR 02-0123 2128/02 B 3.6.3-12 9 DRR 02-0123 2/28/02 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 13 DRR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12118/99 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 911/04 B 3.6.6-7 0 Amend. No. 123 12/18/99 B 3.6.6-8 14 DRR 03-0102 2/12/03 B 3.6.6-9 13 DRR 02-1458 12/03/02 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 2 DRR 00-0147 4/24/00 B 3.6.7-5 0 Amend. No. 123 12/18/99 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 I B 3.6.8-4 0 Amend. No. 123 12/18/99 B 3.6.8-5 0 Amend. No. 123 12/18/99 Wolf Creek - Unit I ix .. : Revision 19

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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 0 Amend. No. 123 12/18/99 B 3.7.1-6 0 Amend. No. 123 12/18/99 B 3.7.2-1 0 Amend. No. 123 12/18/99 B 3.7.2-2 0 Amend. No. 123 12/18/99 B 3.7.2-3 0 Amend. No. 123 12/18/99 B 3.7.24 0 Amend. No. 123 12/18/99 B 3.7.2-5 0 Amend. No. 123 12/18/99 B 3.7.2-6 0 Amend. No. 123 12/18/99 B 3.7.3-1 0 Amend. No. 123 12/18/99 B 3.7.3-2 0 Amend. No. 123 12/18/99 B 3.7.3-3 0 Amend. No. 123 12/18/99 B 3.7.3-4 0 Amend. No. 123 12/18/99 B 3.7.3-5 0 Amend. No. 123 12/18/99 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 10/12104 B 3.7.4-4 19 DRR 04-1414 10/12104 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 16 DRR 03-1497 11/4/03 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 19 DRR 04-1414 10/12/04 B 3.7.5-8 14 DRR 03-0102 2/12/03 B 3.7.5-9 13 DRR 02-1458 12/03/02 B 3.7.6-1 0 Amend. No. 123 12/18/99 B 3.7.6-2 0 Amend. No. 123 12/18/99 B 3.7.6-3 0 Amend. No. 123 12/18/99 B 3.7.7-1 0 Amend. No. 123 12/18/99 B 3.7.7-2 0 Amend. No. 123 12/18/99 B 3.7.7-3 0 Amend. No. 123 12/18/99 B 3.7.7-4 1 DRR 99-1624 12/18/99 B 3.7.8-1 0 Amend. No. 123 12/18/99 B 3.7.8-2 0 Amend. No. 123 12/18/99 B 3.7.8-3 0 Amend. No. 123 12/18/99 B 3.7.8-4 0 Amend. No. 123 12/18/99 B 3.7.8-5 0 Amend. No. 123 12/18/99 B 3.7.9-1 3 Amend. No. 134 7/14/00 B 3.7.9-2 3 Amend. No. 134 7/14/00 B 3.7.9-3 3 Amend. No. 134 7/14/00 B 3.7.9-4 3 Amend. No. 134 7/14/00 B 3.7.10-1 0 Amend. No. 123 12/18/99 B 3.7.10-2 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 Wolf Creek - Unit 1 x Revision 19

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TAB - B 3.7 PLANT SYSTEMS (continued)

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 1 DRR 99-1624 12/18/99 B 3.7.13-2 1 DRR 99-1624 12/18/99 B 3.7.13-3 1 DRR 99-1624 12/18/99 B 3.7.13-4 1 DRR 99-1624 12/18/99 B 3.7.13-5 1 DRR 99-1624 12118/99 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 1 DRR 99-1624 12/18/99 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 12/18199 B 3.7.18-2 0 Amend. No. 123 12/18199 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 6 DRR 00-1541 3/13101 B3.8.1-4 19 DRR 04-1414 10/12/04 B 3.8.1-5 B 3.8.1-6 19 0

DRR 04-1414 Amend. No. 123 10/12/04 12/18/99 I

B 3.8.1-7 0 Amend. No: 123 12/18/99 B 3.8.1-8 0 Amend. No. 123 12/18/99 B 3.8.1-9' 0 Amend. No. 123 12/18/99 B 3.8.1-10 0 Amend. No. 123 12/18/99 B 3.8.1-11 0 Amend. No. 123 12/18/99 B 3.8.1-12 o Amend. No. 123 12/18/99 B 3.8.1-13 0 Amend. No. 123 12/18/99 B 3.8.1-14 0 Amend. No. 123 12/18/99 B 3.8.1-15 0 Amend. No. 123 12/18/99 B 3.8.1-16 9 DRR 02-0123 2/28/02 B 3.8.1-17 7 DRR 01-0474 5/1/01 B 3.8.1-18 - 0 Amend. No. 123 12/18/99 B 3.8.1-19 18 DRR 04-1018 9/1/04 B 3.8.1-20 . 18 DRR 04-1018 911104 Wolf Creek - Unit 1 xi Revision 19

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.1-21 18 DRR 04-1018 9/1/04 B 3.8.1-22 18 DRR 04-1018 9/1/04 B 3.8.1-23 18 DRR 04-1018 9/1/04 B 3.8.1-24 18 DRR 04-1018 9/1/04 B 3.8.1-25 18 DRR 04-1018 9/1/04 B 3.8.1-26 18 DRR 04-1018 9/1/04 B 3.8.1-27 18 DRR 04-1018 9/1/04 B 3.8.1-28 18 DRR 04-1018 9/1/04 B 3.8.1-29 18 DRR 04-1018 9/1/04 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 0 Amend. No. 123 12/18/99 B 3.8.4-1 0 Amend. No. 123 12/18/99 B 3.8.4-2 0 Amend. No. 123 12/18/99 B 3.8.4-3 0 Amend. No. 123 12/18/99 B 3.8.4-4 0 Amend. No. 123 12/18/99 B 3.8.4-5 0 Amend. No. 123 12/18/99 B 3.8.4-6 0 Amend. No. 123 12/18/99 B 3.8.4-7 6 DRR 00-1541 3/13/01 B 3.8.4-8 0 Amend. No. 123 12/18/99 B 3.8.4-9 2 DRR 00-0147 4/24/00 B 3.8.5-1 0 Amend. No. 123 12/18/99 B 3.8.5-2 0 Amend. No. 123 12/18/99 B 3.8.5-3 0 Amend. No. 123 12/18/99 B 3.8.5-4 12 DRR 02-1062 9/26/02 B 3.8.5-5 12 DRR 02-1062 9/26/02 B 3.8.6-1 0 Amend. No. 123 12/18/99 B 3.8.6-2 0 Amend. No. 123 12/18/99 B 3.8.6-3 0 Amend. No. 123 12/18/99 B 3.8.6-4 0 Amend. No. 123 12/18/99 B 3.8.6-5 0 Amend. No. 123 12/18/99 B 3.8.6-6 0 Amend. No. 123 12/18/99 B 3.8.7-1 0 Amend. No. 123 12/18/99 B 3.8.7-2 5 DRR 00-1427 10/12/00 B 3.8.7-3 0 Amend. No. 123 12/18/99 B 3.8.7-4 0 Amend. No. 123 12/18/99 B 3.8.8-1 0 Amend. No. 123 12/18/99 B 3.8.8-2 0 Amend. No. 123 12/18/99 Wolf Creek - UnIt 1 xii Revision 19

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.8-3 0 Amend. No. 123 - 12118/99 B 3.8.84 12 DRR 02-1062 9/26/02 B 3.8.8-5 - 12 DRR 02-1062 - 9/26/02 B 3.8.9-1 0 Amend. No. 123 12/18/99 B 3.8.9-2 0 Amend. No. 123 12/18/99 B 3.8.9-3 0 Amend. No. 123 12/18199 B 3.8.94 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 12/18199 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 12118/99 B 3.9.1-2 19 DRR 04-1414 10/12104 B 3.9.1-3 19 DRR 04-1414 10/12104 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 12118/99 B 3.9.3-1 12 DRR 02-1062 9/26/02 B 3.9.3-2 12 DRR 02-1062 9/26/02 B 3.9.3-3 12 DRR 02-1062 9/26/02 B 3.9.4-1 14 DRR 03-0102 2/12/03 B 3.9.4-2 13 DRR 02-1458 12/03/02 B 3.9.4-3 13 DRR 02-1458 12/03/02 B 3.9.4-4 13 DRR 02-1458 12/03/02 B 3.9.4-5 13 DRR 02-1458 12/03/02 B 3.9.4-6 13 DRR 02-1458 12/03/02 B 3.9.5-1 0 Amend. No. 123 12/18/99 B 3.9.5-2 12 DRR 02-1062 9/26/02 B 3.9.5-3 12 DRR 02-1062 9/26102 B 3.9.5-4 12 DRR 02-1062 9/26/02 B 3.9.6-1 0 Amend. No. 123 12/18/99 B 3.9.6-2 19 DRR 04-1414 10/12/04 I B 3.9.6-3 12 DRR 02-1062 9/26/02 B 3.9.64 '12 DRR 02-1062 9/26/02 B 3.9.7-1 0 Amend. No. 123 12/18/99 B 3.9.7-2 0 Amend. No. 123 12/18/99 B 3.9.7-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit I MUl : -. : -,ReVisi 19

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IMPLEMENTED (4)

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

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

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

123 issued the improved Technical Specifications and associated Bases which affected each page. The NRC has indicated that Bases changes will not be issued with License Amendments. Therefore, the change document should be a DRR number in accordance with AP 26A-002.

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

Wolf Creek - Unit 1 xiv Revision 19

ML050770415

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