Text

Submittal of Changes to Technical Specification Bases - Revisions 36 Through 40
	ML090750624
Person / Time
Site:	Wolf Creek
Issue date:	03/11/2009
From:	Flannigan R; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 09-0053
	Download: ML090750624 (93)
	v • d • e

W F CREEK NUCLEAR OPERATING CORPORATION Richard D. Flannigan Manager Regulatory Affairs March 11, 2009 RA 09-0053 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 36 through 40 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 36 through 40) under the provisions of TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2008 through December 31, 2008.

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

Sincerely, Richard D. Flann~iga RDF/rlt cc: E. E. Collins (NRC), w/e, V. G. Gaddy (NRC), w/e B. K. Singal (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET

Enclosure to RA 09-0053 Wolf Creek Generating Station Changes to the Technical Specification Bases

TABLE OF CONTENTS B 3.7 PLA NT SYSTEM S .................................................................................... B 3.7.1-1 B 3.7.1 Main Steam Safety Valves (MSSVs) ................................................ B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs) .............................................. B 3.7.2-1 B 3.7.3 Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulating Valves (MFRVs) and MFRV Bypass Valves ............ B 3.7.3-1 B 3.7.4 Atmospheric Relief Valves (ARVs) ................................................... B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System .................................................. B 3.7.5-1 B 3.7.6 Condensate Storage Tank (CST) ..................................................... B 3.7.6-1 B 3.7.7 Component Cooling Water (CCW) System ...................................... B 3.7.7-1 B 3.7.8 Essential Service Water System (ESW) ........................................... B 3.7.8-1 B 3.7.9 Ultimate Heat Sink (UHS) ................................................................. B 3.7.9-1 B 3.7.10 Control Room Emergency Ventilation System (CREVS) ............... B 3.7.10-1 B 3.7.11 Control Room Air Conditioning System (CRACS) .......................... B 3.7.11-1 B 3.7.12 Emergency Core Cooling System (ECCS) Pump Room Exhaust Air Cleanup System - Not Used ............................................... B 3.7.12-1 B 3.7.13 Emergency Exhaust System (EES) ................................................ B 3.7.13-1 B 3.7.14 Penetration Room Exhaust Air Cleanup System (PREACS)

Not Used ................................................................................... B 3.7.14-1 B 3.7.15 Fuel Storage Pool Water Level ....................................................... B 3.7.15-1 B 3.7.16 Fuel Storage Pool Boron Concentration ......................................... B 3.7.16-1 B 3.7.17 Spent Fuel Assembly Storage ........................................................ B 3.7.17-1 B 3.7.18 Secondary Specific Activity ............................................................. B 3.7.18-1 B 3.8 ELECTRICAL POWER SYSTEMS ........................................................... B 3.8.1-1 B 3.8.1 AC Sources - Operating .................................................................... B 3.8.1-1 B 3.8.2 AC Sources - Shutdown .................................................................... B 3.8.2-1 B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ........................................ B 3.8.3-1 B 3.8.4 DC Sources - Operating .................................................................... B 3.8.4-1 B 3.8.5 DC Sources - Shutdown ................................................................... B 3.8.5-1 B 3.8.6 Battery Cell Parameters .................................................................... B 3.8.6-1 B 3.8.7 Inverters - O perating ......................................................................... B 3.8.7-1 B 3.8.8 Inverters - Shutdown ......................................................................... B 3.8.8-1 B 3.8.9 Distribution Systems - Operating ....................... B 3.8.9-1 B 3.8.10 Distribution Systems - Shutdown .................................................... B 3.8.10-1 B 3.9 REFUELING OPERATIONS ..................................................................... B 3.9.1-1 B 3.9.1 Boron C oncentration ......................................................................... B 3.9.1-1 B 3.9.2 Unborated Water Source Isolation Valves ....................................... B 3.9.2-1 B 3.9.3 Nuclear Instrumentation .................................................................... B 3.9.3-1 B 3.9.4 Containment Penetrations ................................................................ B 3.9.4-1 B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation - High Water Level .................................................... B 3.9.5-1 B 3.9.6 Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level ..................................................... B 3.9.6-1 B 3.9.7 Refueling Pool Water Level .............................................................. B 3.9.7-1 Wolf Creek - Unit 1 iii Revision 37

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE (3) Phase B Isolation - Containment Pressure SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY The basis for containment pressure MODE applicability and the Trip Setpoint are as discussed for ESFAS Function 2.c above.

4. Steam Line Isolation Isolation of the main steam lines provides protection in the event of an SLB inside or outside containment. Rapid isolation of the steam lines will limit the steam break accident to the blowdown from one SG, at most. For an SLB upstream of the main steam isolation valves (MSIVs), inside or outside of containment, closure of the MSIVs limits the accident to the blowdown from only the affected SG. For an SLB downstream of the MSIVs, closure of the MSIVs terminates the accident as soon as the steam lines depressurize. Steam Line Isolation also mitigates the effects of a feed line break and ensures a source of steam for the turbine driven AFW pump during a feed line break.

a. Steam Line Isolation - Manual Initiation Manual initiation of Steam Line Isolation (fast close) can be accomplished from the control room. There are two push buttons in the control room and either push button can initiate action to immediately close all MSIVs. The LCO requires two channels to be OPERABLE.

b. Steam Line Isolation -Automatic Actuation Logic and Actuation Relays (SSPS)

Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.

c. Steam Line Isolation -Automatic Actuation Logic (MSFIS)

The LCO requires two trains to be OPERABLE. The Steam Line Isolation signal from SSPS is provided to the Main Steam and Feedwater Isolation System (MSFIS) by four actuation signals per group. The Steam Line Isolation signals are provided by SSPS slave relays K634A and K634B. Actuation logic consists of the circuitry housed within the MSFIS cabinets and extends to the solenoids at the valves responsible for actuating the MSIVs.

Wolf Creek - Unit 1 B 3.3.2-19 Revision 37

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE 4. Steam Line Isolation (continued)

SAFETY ANALYSES, LCO, and Manual and automatic initiation of steam line isolation must be APPLICABILITY OPERABLE in MODES 1, 2, and 3 when there is sufficient energy in the RCS and SGs to have an SLB or other accident. This could result in the release of significant quantities of energy and cause a cooldown of the primary system. The Steam Line Isolation Function is required in MODES 2 and 3 unless all MSIVs are closed. In MODES 4, 5, and 6, there is insufficient energy in the RCS and SGs to experience an SLB or other accident releasing significant quantities of energy.

d. Steam Line Isolation - Containment Pressure - High 2 This Function actuates closure of the MSIVs in the event of a LOCA or an SLB inside containment to maintain at least one unfaulted SG as a heat sink for the reactor, and to limit the mass and energy release to containment. The transmitters (d/p cells) are located outside containment with the sensing line (high pressure side of the transmitter) located inside containment. Containment Pressure -

High 2 provides no input to any control functions. Thus, three OPERABLE channels are sufficient to satisfy protective requirements with two-out-of-three logic. The transmitters and electronics are located outside of containment. Thus, they will not experience any adverse environmental conditions, and the Trip Setpoint reflects only steady state instrument uncertainties. The Trip Setpoint is < 17.0 psig.

Containment Pressure - High 2 must be OPERABLE in MODES 1, 2, and 3, when there is sufficient energy in the primary and secondary side to pressurize the containment following a pipe break. This would cause a significant increase in the containment pressure, thus allowing detection and closure of the MSIVs. The Steam Line Isolation Function remains OPERABLE in MODES 2 and 3 unless all MSIVs are closed. In MODE 4, the increase in containment pressure following a pipe break would occur over a relatively long time period such that manual actions could reasonably be expected to provide protection. In MODES 5, and 6, there is not enough energy in the primary and secondary sides to pressurize the containment to the Containment Pressure - High 2 setpoint.

Wolf Creek - Unit 1 B 3.3.2-20 Revision 37

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE e. Steam Line Isolation - Steam Line Pressure SAFETY ANALYSES, LCO, and (1) Steam Line Pressure - Low APPLICABILITY (continued) Steam Line Pressure - Low provides closure of the MSIVs in the event of an SLB to maintain at least one unfaulted SG as a heat sink for the reactor, and to limit the mass and energy release to containment. This Function provides closure of the MSIVs in the event of a feed line break to ensure a supply of steam for the turbine driven AFW pump.

Steam Line Pressure - Low was discussed previously under SI Function 1.e and the Trip Setpoint is the same.

Steam Line Pressure - Low Function must be OPERABLE in MODES 1,2, and 3 (above P-11 and below P-11 unless blocked), with any main steam valve open, when a secondary side break or stuck open valve could result in the rapid depressurization of the steam lines. This signal may be manually blocked by the operator below the P-11 setpoint. If not blocked below P-11, the Steam Line Pressure - Low Function must be OPERABLE. When blocked, an inside containment SLB will be terminated by automatic actuation via Containment Pressure - High 2. Stuck valve transients and outside containment SLBs will be terminated by the Steam Line Pressure - Negative Rate - High signal for Steam Line Isolation below P-11 when SI has been manually blocked. The Steam Line Isolation Function is required in MODES 2 and 3 unless all MSIVs are closed and de-activated. This Function is not required to be OPERABLE in MODES 4, 5, and 6 because there is insufficient energy in the secondary side of the unit to have a significant effect on required plant equipment.

(2) Steam Line Pressure - Negative Rate - High Steam Line Pressure - Negative Rate - High provides closure of the MSIVs for an SLB when less than the P-11 setpoint, to maintain at least one unfaulted SG as a heat sink for the reactor, and to Wolf Creek - Unit 1 B 3.3.2-21 Revision 37

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE (2) Steam Line Pressure - Negative Rate - High SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY limit the mass and energy release to containment.

When the operator manually blocks the Steam Line Pressure - Low main steam isolation signal when less than the P-11 setpoint, the Steam Line Pressure - Negative Rate - High signal is automatically enabled. Steam Line Pressure - Negative Rate - High control functions are isolated from the protective functions. Thus, three OPERABLE channels on each steam line are sufficient to satisfy requirements with a two-out-of-three logic.

Steam Line Pressure - Negative Rate - High must be OPERABLE in MODE 3 when the Steam Line Pressure - Low signal is blocked, when a secondary side break or stuck open valve could result in the rapid depressurization of the steam line(s). In MODES 1 and 2, and in MODE 3, when above the P-11 setpoint, this signal is automatically disabled and the Steam Line Pressure - Low signal is automatically enabled. The Steam Line Isolation Function is required to be OPERABLE in MODE 3 unless all MSIVs are closed. In MODES 4, 5, and 6, there is insufficient energy in the primary and secondary sides to have an SLB or other accident that would result in a release of significant enough quantities of energy to cause a cooldown of the RCS.

While the transmitters may experience elevated ambient temperatures due to an SLB, the trip function is based on rate of change, not the absolute accuracy of the indicated steam pressure.

Therefore, the Trip Setpoint reflects only steady state instrument uncertainties. The Trip Setpoint is

<100 psi with a rate /lag controller time constant

> 50 seconds.

Wolf Creek - Unit 1 B 3.3.2-22 Revision 37 1

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE 5. Turbine Trip and Feedwater Isolation SAFETY ANALYSES, LCO, and The primary functions of the Turbine Trip and Feedwater Isolation APPLICABILITY signals are to prevent damage to the turbine due to water in the (continued) steam lines and to stop the excessive flow of feedwater into the SGs. These Functions are necessary to mitigate the effects of a high water level in the SGs, which could result in carryover of water into the steam lines and excessive cooldown of the primary system. The SG high water level is due to excessive feedwater flows.

The Function is actuated when the level in any SG exceeds the high high setpoint and performs the following functions:

Trips the main turbine;

Trips the MFW pumps;

Initiates feedwater isolation; and 0 Shuts the MFW regulating valves and the bypass feedwater regulating valves.

This Function is actuated by SG Water Level - High High, or by an SI signal. The RTS also initiates a turbine trip signal whenever a reactor trip (P-4) is generated. In the event of SI, the unit is taken off line and the turbine generator must be tripped. The MFW System is also taken out of operation and the AFW System is automatically started. The SI signal was previously discussed.

a. Turbine Trip and Feedwater Isolation - Automatic Actuation Logic and Actuation Relays (SSPS)

Automatic Actuation Logic and Actuation Relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.

b. Feedwater Isolation -Automatic Actuation Logic (MSFIS)

Automatic Actuation Logic in the MSFIS consists of the same features and operates in the same manner as described for ESFAS Function 4.c. The Feedwater Line Isolation signals are provided by SSPS slave relays K743A/B, K744A/B, and K745A/B.

Wolf Creek - Unit 1 B 3.3.2-23 Revision 37

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE c. Turbine Trip and Feedwater Isolation - Steam SAFETY ANALYSES, Generator Water Level - High High (P-14)

LCO, and APPLICABILITY This signal provides protection against excessive (continued) feedwater flow. The ESFAS SG water level instruments provide input to the SG Water Level Control System.

Therefore, the actuation logic must be able to withstand both an input failure to the control system (which may then require the protection function actuation) and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with a two-out-of-four logic.

The transmitters (d/p cells) are located inside containment.

However, the events that this Function protects against cannot cause a severe environment in containment.

Therefore, the Trip Setpoint reflects only steady state instrument uncertainties. The Trip Setpoint is _< 78% of narrow range span.

d. Turbine Trip and Feedwater Isolation - Safety Injection Turbine Trip and Feedwater Isolation are also initiated by all Functions that initiate SI. The Feedwater Isolation Function requirements for these initiation Functions are the same as the requirements for their SI function. Therefore, the requirements are not repeated in Table 3.3.2-1.

Instead Function 1, SI, is referenced for all initiating functions and requirements.

Turbine Trip and Feedwater Isolation Function 5.c, SG Water Level - High High must be OPERABLE in MODES 1 and 2 except when all MFIVs are closed and de-activated; and all MFRVs are closed and de-activated or closed and isolated by a closed manual valve; and all MFRV bypass valves are closed and de-activated, or closed and isolated by a closed manual valve, or isolated by two closed manual valves. In MODES 3, 4, 5, and 6, Function 5.c is not required to be OPERABLE. The Automatic Actuation Logic and Actuation Relays (SSPS) Function must be OPERABLE in MODE 1, MODE 2 (except when all MFIVs are closed and de-activated; and all MFRVs are closed and de-activated or closed and isolated by a closed manual valve; and all MFRV bypass valves are closed and de-activated, or closed and isolated by a closed manual valve, or isolated by two closed manual valves) and Wolf Creek - Unit 1 B 3.3.2-24 Revision 39

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE 5. Turbine Trip and Feedwater Isolation (continued)

SAFETY ANALYSES, LCO, and MODE 3 (except when all MFIVs are closed and de-activated; and APPLICABILITY all MFRVs are closed and de-activated or closed and isolated by a closed manual valve; and all MFRV bypass valves are closed and deactivated, or closed and isolated by a closed manual valve, or isolated by two closed manual valves). The Automatic Actuation Logic (MSFIS) Function must be OPERABLE in MODE 1, MODE 2 (except when all MFIVs are closed and de-activated), and MODE 3 (except when all MFIVs are closed and de-activated). In MODES 4, 5, and 6, the Automatic Actuation Logic (SSPS) and the Automatic Actuation Logic (MSFIS) are not required to be OPERABLE.

6. Auxiliary Feedwater The AFW System is designed to provide a secondary side heat sink for the reactor in the event that the MFW System is not available when reactor power is less than 2% power. The system has two motor driven pumps and a turbine driven pump, making it available during normal unit operation during a loss of AC power, a loss of MFW, and during a Feedwater System pipe break. The normal source of water for the AFW System is the condensate storage tank (CST). A loss of suction pressure will automatically realign the pump suctions to the safety related Essential Service Water (ESW) System. The AFW System is aligned so that upon a pump start, flow is initiated to the respective SGs immediately.

a. Auxiliary Feedwater- Manual Initiation Manual initiation of Auxiliary Feedwater can be accomplished from the control room. Each of the three AFW pumps has a pushbutton for manual AFAS initiation.

The LCO requires three channels to be OPERABLE.

b. Auxiliary Feedwater - Automatic Actuation Logic and Actuation Relays (SSPS)

Automatic actuation logic and acutation relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.

c. Auxiliary Feedwater - Automatic Actuation Logic and Actuation Relays (BOP ESFAS)

Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for BOP ESFAS in the Bases Background for 3.3.2.

Wolf Creek - Unit 1 B 3.3.2-25 Revision 39

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE d. Auxiliary Feedwater - Steam Generator Water level - Low SAFETY ANALYSES, Low LCO, and APPLICABILITY SG Water Level - Low Low provides protection against a (continued) loss of heat sink. A feed line break, inside or outside of containment, or a loss of MFW, would result in a loss of SG water level. SG Water Level - Low Low provides input to the SG Level Control System. Therefore, the actuation logic must be able to withstand both an input failure to the control system which may then require a protection function actuation and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with two-out-of-four logic.

With the transmitters (d/p cells) located inside containment and thus possibly experiencing adverse environmental conditions (feed line break), the Trip Setpoint reflects the inclusion of both steady state and adverse environment instrument uncertainties. The Trip Setpoint for the Start Motor-Driven Pumps and the Start Turbine-Driven Pumps is > 23.5% of narrow range instrumentation span.

e. Auxiliary Feedwater - Safety Iniection An SI signal also starts the motor driven AFW pumps via the LOCA sequencer. The AFW initiation functions are the same as the requirements for their SI function.

Therefore, the requirements are not repeated in Table 3.3.2-1. Function 1, SI, is referenced for all initiating functions and requirements.

f. Auxiliary Feedwater - Loss of Offsite Power A loss of offsite power (LOP) to the safeguard buses will be accompanied by a loss of reactor coolant pumping power and the subsequent need for some method of decay heat removal. The loss of offsite power (LOP) is detected by a voltage drop on each safeguard bus. The LOP is sensed and processed by the circuitry for LOP DG start (load shedder and emergency load sequencer) and fed to the BOP ESFAS by the relay actuation. Loss of power to either safeguard bus will start the turbine driven AFW pump to ensure that at least one SG contains enough water to serve as the heat sink for reactor decay heat and sensible heat removal following the reactor trip and automatically isolate the SG blowdown and sample lines.

Wolf Creek - Unit 1 B 3.3.2-26 Revision 39

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE f. Auxiliary Feedwater - Loss of Offsite Power (continued)

SAFETY ANALYSES, LCO, and In addition, once the diesel generators are started and up APPLICABILITY to speed, the motor driven AFW pumps will be sequentially driven loaded onto the diesel generator busses.

Functions 6.a through 6.f must be OPERABLE in MODES 1, 2, and 3 to ensure that the SGs remain the heat sink for the reactor. SG Water Level - Low Low in any operating SG will cause the motor AFW pumps to start.

The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water Level - Low Low in any two operating SGs will cause the turbine driven pump to start. These Functions do not have to be OPERABLE in MODES 5 and 6 because there is not enough heat being generated in the reactor to require the SGs as a heat sink. In MODE 4, AFW actuation does not need to be OPERABLE because either AFW or residual heat removal (RHR) will already be in operation to remove decay heat or sufficient time is available to manually place either system in operation.

g. Auxiliary Feedwater - Trip of All Main Feedwater Pumps A Trip of all MFW pumps is an indication of a loss of MFW and the subsequent need for some method of decay heat and sensible heat removal to bring the reactor back to no load temperature and pressure. Each turbine driven MFW pump is equipped with two pressure switches (one in separation group 1 and one in separation group 4) on the oil line for the speed control system. A low pressure signal from either of these pressure switches indicates a trip of that pump. Two OPERABLE channels per pump satisfy redundancy requirements with one-out-of-two logic on both pumps required for signal activation. A trip of all MFW pumps starts the motor driven AFW pumps to ensure that at least one SG is available with water to act as the heat sink for the reactor.

Function 6.g must be OPERABLE in MODE 1. This ensures that at least one SG is provided with water to serve as the heat sink to remove reactor decay heat and sensible heat in the event of an accident. In MODE 2, AFW actuation due to a trip of all MFW pumps is normally blocked. Blocking of this trip function is permitted just before shutdown of the last operating main feedwater pump and the restoration of this trip function just after the first main feedwater pump is put into service following Wolf Creek - Unit 1 B 3.3.2-27 Revision 37 1

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE 6. Auxiliary Feedwater (continued)

SAFETY ANALYSES, LCO, and SR 3.3.2.8. This limits the potential for inadvertent AFW APPLICABILITY actuations during normal startups and shutdowns. In MODES 3, 4, and 5, the MFW pumps may be normally shut down, and thus pump trip is not indicative of a condition requiring automatic AFW initiation.

h. Auxiliary Feedwater - Pump Suction Transfer on Suction Pressure - Low A low pressure signal in the AFW pump suction line protects the AFW pumps against a loss of the normal supply of water for the pumps, the CST. Three pressure switches are located on the AFW pump suction line from the CST. A low pressure signal sensed by any two of the three switches coincident with an auxiliary feedwater actuation signal will cause the emergency supply of water for both pumps to be aligned. ESW (safety grade) is automatically lined up to supply the AFW pumps to ensure an adequate supply of water for the AFW System to maintain at least one of the SGs as the heat sink for reactor decay heat and sensible heat removal.

Since the detectors are located in an area not affected by HELBs or high radiation, they will not experience any adverse environmental conditions and the Trip Setpoint reflects only steady state instrument uncertainties. The Trip Setpoint is _>21.60 psia.

This Function must be OPERABLE in MODES 1, 2, and 3 to ensure a safety grade supply of water for the AFW System to maintain the SGs as the heat sink for the reactor. This Function does not have to be OPERABLE in MODES 5 and 6 because there is not enough heat being generated in the reactor to require the SGs as a heat sink.

In MODE 4, AFW automatic suction transfer does not need to be OPERABLE because RHR will already be in operation, or sufficient time is available to place RHR in operation, to remove decay heat.

Wolf Creek - Unit 1 B 3.3.2-28 Revision 37 1

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

(continued) 1.1 and 1.2 Condition I applies to:

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

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

Wolf Creek - Unit 1 B 3.3.2-41 Revision 37

ESFAS Instrumentation B 3.3.2 BASES ACTIONS 1.1 and 1.2 (continued)

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

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

J.1 and J.2 Condition J applies to the AFW pump start on trip of all MFW pumps.

This action addresses the train orientation of the BOP ESFAS for the auto start function of the AFW System on loss of all MFW pumps. The OPERABILITY of the AFW System must be assured by allowing automatic start of the AFW System pumps. If a channel is inoperable, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to place the channel in the tripped condition. If the channel cannot be tripped in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , 6 additional hours are allowed to place the unit in MODE 3. The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, the unit does not have any analyzed transients or conditions that require the explicit use of the protection function noted above. The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing of other channels.

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

RWST Level - Low Low Coincident with SI provides actuation of switchover to the containment recirculation sumps. Note that this Function requires the bistables to energize to perform their required Wolf Creek - Unit 1 B 3.3.2-42 Revision 20

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.4 (continued)

REQUIREMENTS large enough to demonstrate signal path continuity. This test is performed every 92 days on a STAGGERED TEST BASIS. The time allowed for the testing (4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ) is justified in Reference 7. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.

A COT is performed on each required channel to ensure the channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3.2-1.

The setpoint shall be left set consistent with the assumptions of the current unit specific setpoint methodology.

The Frequency of 184 days is justified in Reference 13.

SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the slave relay blocking circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay. This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data. The SR is modified by a Note that excludes slave relays K602, K620, K622, K624, K630, K740, and K741 which are included in testing required by SR 3.3.2.13 and SR 3.3.2.14.

For Function 4.c (Steam Line Isolation -Automatic Actuation Logic (MSFIS)) and Function 5.b (Turbine Trip and Feedwater Isolation -

Automatic Actuation Logic (MSFIS)), SR 3.3.2.6 is performed on the associated slave relays in the SSPS cabinets and includes verification that the slave relays are energized at the MSFIS cabinets.

Wolf Creek - Unit 1 B 3.3.2-47 Revision 37

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.7 REQUIREMENTS (continued) SR 3.3.2.7 is the performance of a TADOT every 18 months. This test is a check of the Loss of Offsite Power function. The trip actuating devices tested within the scope of SR 3.3.2.7 are the LSELS output relays and BOP ESFAS separation groups logic associated with the auto-start of the turbine driven AFW pump upon an ESF bus undervoltage condition.

The SR is modified by a Note that excludes verification of setpoints for relays. The Frequency is adequate. It is based on industry operating experience, considering instrument reliability and operating history data and is consistent with the typical refueling cycle. The trip actuating devices tested have no associated setpoint.

SR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions (SSPS) and AFW pump start on trip of all MFW pumps BOP ESFAS. The Manual Safety Injection TADOT shall independently verify OPERABILITY of the handswitch undervoltage and shunt trip contacts for both the Reactor Trip Breakers and Reactor Trip Bypass Breakers as well as the contacts for safety injection actuation. It is performed every 18 months. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.).

The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle. The SR is modified by a Note that excludes verification of setpoints during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints.

SIR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION.

A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.

Wolf Creek - Unit I B 3.3.2-48 Revision 37 1

ESFAS Instrumentation B 3.3.2 BASES REFERENCES 9. SLNRC 84-0038 dated February 27, 1984.

(continued)

10. "Wolf Creek Setpoint Methodology Report," SNP (KG)-492, August 29, 1984.

11. Amendment No. 43 to Facility Operating License No. NPF-42, March 29,1991.

12. WCAP-14333-P-A, Revision 1, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," October 1998.

13. WCAP-1 5376-P-A, Revision 1, "Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times," March 2003.

14. 10 CFR 50.55a(b)(3)(iii), Code Case OMN-1.

15. Performance Improvement Request (PRI) 2005-2067.

Wolf Creek - Unit 1 B 3.3.2-53 Revision 25

ESFAS Instrumentation B 3.3.2 TABLE B 3.3.2-1 (Page 1 of 2)

FUNCTION TRIP SETPOINT(a)

1. Safety Injection

a. Manual Initiation N.A.

b. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

C. Containment Pressure - High-1 *3.5 psig

d. Pressurizer Pressure - Low >_1830 psig

e. Steam Line Pressure - Low >_615 psig

2. Containment Spray N.A.

a. Manual Initiation

b. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

c. Containment Pressure - High-3 < 27.0 psig

3. Containment Isolation

a. Phase A Isolation (1) Manual Initiation N.A.

(2) Automatic Actuation Logic and N.A.

Actuation Relays (SSPS)

(3) Safety Injection See Function 1 (Safety Injection)

b. Phase B Isolation (1) Manual Initiation N.A.

(2) Automatic Actuation Logic and N.A.

Actuation Relays (SSPS)

(3) Containment Pressure - High-3 < 27.0 psig

4. Steam Line Isolation

a. Manual Initiation N.A.

b. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

c. Automatic Actuation Logic (MSFIS) N.A.

d. Containment Pressure - High-2 < 17.0 psig

e. Steam Line Pressure (1) Low > 615 psig (2) Negative Rate - High < 100 psi Wolf Creek - Unit 1 B 3.3.2-54 Revision 37

ESFAS Instrumentation B 3.3.2 TABLE B 3.3.2-1 (Page 2 of 2)

FUNCTION TRIP SETPOINT(a)

5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

b. Automatic Actuation Logic (MSFIS) N.A.

c. SG Water Level - High High < 78% of narrow range instrument span

d. Safety Injection See Function 1 (Safety Injection)

6. Auxiliary Feedwater N.A.

a. Manual Initiation

b. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

c. Automatic Actuation Logic and Actuation N.A.

Relays (BOP ESFAS)

d. SG Water Level - Low-Low >_23.5% of narrow range instrument span

e. Safety Injection See Function 1 (Safety Injection)

f. Loss of Offsite Power N.A.

g. Trip of all Main Feedwater Pumps N.A.

h. Auxiliary Feedwater Pump Suction >_21.60 psia Transfer on Suction Pressure - Low

7. Automatic Switchover to Containment Sump

a. Automatic Actuation Logic and Actuation N.A.

Relays (SSPS)

b. Refueling Water Storage Tank (RWST) > 36% of instrument span Level - Low Low Coincident with Safety Injection See Function 1 (Safety Injection)

8. ESFAS Interlocks

a. Reactor Trip, P-4 N.A.

b. Pressurizer Pressure, P-i 1 *1970 psig (a) The inequality sign only indicates conservative direction. The as-left value will be within a two-sided calibration tolerance band on either side of the nominal value.

Wolf Creek - Unit 1 B 3.3.2-55 Revision 37

ESFAS Instrumentation B 3.3.2 Table B 3.3.2-2 (Page 1 of 3)

INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS

1. Manual Initiation

a. Safety Injection (ECCS) N.A.

b. Containment Spray N.A.

c. Phase "A" Isolation N.A.

d. Phase "B" Isolation N.A.

e. Containment Purge Isolation N.A.

f. Steam Line Isolation N.A.

g. Feedwater Isolation N.A.

h. Auxiliary Feedwater N.A.

I. Essential Service Water N.A.

j Containment Cooling N.A.

k. Control Room Isolation N.A.

I. Reactor Trip N.A.

m. Emergency Diesel Generators N.A.

n. Component Cooling Water N.A.

o. Turbine Trip N.A.

2. Containment Pressure - High-1

a. Safety Injection (ECCS) <29(7)/27(4)

1) Reactor Trip *2

<2(!)

2) Feedwater Isolation

3) Phase "A" Isolation <1.5(5)

4) Auxiliary Feedwater

60

5) Essential Service Water - 60(1)

6) Containment Cooling - 60(1)

7) Component Cooling Water N.A.

8) Emergency Diesel Generators _<14(6)

9) Turbine Trip N.A.

3. Pressurizer Pressure - Low

a. Safety Injection (ECCS) < 29(7)/27(4)

1) Reactor Trip *2

2) Feedwater Isolation 2 (5)

3) Phase "A" Isolation < 2(5)

4) Auxiliary Feedwater _<60

5) Essential Service Water < 60(1)

6) Containment Cooling - 60(1)

7) Component Cooling Water N.A.

8) Emergency Diesel Generators _<14(6)

9) Turbine Trip N.A.

Wolf Creek - Unit 1 B 3.3.2-56 Revision 37

ESFAS Instrumentation B 3.3.2 Table B 3.3.2-2 (Page 2 of 3)

INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS

4. Steam Line Pressure - Low

a. Safety Injection (ECCS)

39(3)/27(4)

1) Reactor Trip *2

<2(5)

2) Feedwater Isolation

<2(5)

3) Phase "A" Isolation

4) Auxiliary Feedwater < 60

5) Essential Service Water *60(1)

6) Containment Cooling *60(1)

7) Component Cooling Water N.A.

8) Emergency Diesel Generators

14(6)

9) Turbine Trip N.A.

b. Steam Line Isolation 2 (5)

5. Containment Pressure - Hiqh-3

a. Containment Spray < 32(1)/20(2)

b. Phase "B" Isolation <31.5

6. Containment Pressure - Higqh-2 Steam Line Isolation <52(5)

7. Steam Line Pressure - Negative Rate-Hiqh

<52(5)

Steam Line Isolation

8. Steam Generator Water Level - High-High

a. Turbine Trip

2.5 2 (5)

<5

b. Feedwater Isolation

9. Steam Generator Water Level - Low-Low

a. Start Motor Driven Auxiliary Feedwater Pumps <60

60

b. Start Turbine Driven Auxiliary Feedwater Pumps

10. Loss-of-Offsite Power _ 60 Start Turbine Driven Auxiliary Feedwater Pumps

11. Trip of All Main Feedwater Pumps Start Motor Driven Auxiliary Feedwater Pumps N.A.

Wolf Creek - Unit 1 B 3.3.2-57 Revision 37

ESFAS Instrumentation B 3.3.2 Table B 3.3.2-2 (Page 3 of 3)

INITIATING SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS

12. Auxiliary Feedwater Pump Suction Pressure-Low Transfer to Essential Service Water <60(1)

13. RWST Level-Low-Low Coincident with Safety Iniection Automatic Switchover to Containment Sump <60 TABLE NOTATIONS (1) Diesel generator starting and sequence loading delays included.

(2) Diesel generator starting delay noj included. Offsite power available.

(3) Diesel generator starting and sequence loading delay included. RHR pumps not included.

Sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is included.

(4) Diesel generator starting and sequence loading delays not included. Offsite power available.

RHR pumps not included. Sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is included.

(5) Does not include valve closure time.

(6) Includes time for diesel to reach full speed.

(7) Diesel generator starting and sequence loading delays included. Sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is not included. Response time assumes only opening of RWST valves.

Wolf Creek - Unit 1 B 3.3.2-58 Revision 20 1

SG Tube Integrity B 3.4.17 1 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.17 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions. Steam generator tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG. The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODES 1 and 2," LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops - MODE 4," and LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled."

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

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

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

Wolf Creek - Unit 1 B 3.4.17-1 Revision 29

SG Tube Integrity B 3.4.17 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of an SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for an SGTR assumes the contaminated secondary fluid is released to the atmosphere via SG atmospheric relief valves and safety valves.

The analysis for design basis accidents and transients other than an SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute or is assumed to increase to 1 gallon per minute as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

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

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

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.

For Refueling Outage 16 and the subsequent operating cycle, an interim alternate repair criterion for the portion of the tube below 17 inches from the top of the tubesheet is specified in TS 5.5.9c.1. (Ref. 7) The tube-to-tubesheet weld is not considered part of the tube.

Wolf Creek - Unit 1 B 3.4.17-2 Revision 37

SG Tube Integrity B 3.4.17 BASES REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

5. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

7. License Amendment No. 178, April 4, 2008.

Wolf Creek - Unit 1 B 3.4.17-7 Revision 37

ECCS - Operating B 3.5.2 BASES ACTIONS A.1 (continued) the ECCS flow equivalent to a single OPERABLE ECCS train remains available. This allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

An event accompanied by a loss of offsite power and the failure of an EDG can disable one ECCS train until power is restored. A reliability analysis (Ref. 5) has shown that the impact of having one full ECCS train inoperable is sufficiently small to justify continued operation for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Reference 6 describes situations in which one component, such as an RHR crossover valve, can disable both ECCS trains. With one or more component(s) inoperable such that 100% of the flow equivalent to a single OPERABLE ECCS train is not available, the facility is in a condition outside the accident analysis. Therefore, LCO 3.0.3 must be immediately entered.

B.1 and B.2 If the inoperable trains cannot be returned to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to 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 plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.5.2.1 REQUIREMENTS Verification of proper valve position ensures that the flow path from the ECCS pumps to the RCS is maintained. Misalignment of these valves could render both ECCS trains inoperable. Securing these valves in position by removal of power or by key locking the control in the correct position ensures that they cannot change position as a result of an active failure or be inadvertently misaligned. These valves are of the type, described in References 6 and 7, that can disable the function of both ECCS trains and invalidate the accident analyses. A 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered reasonable in view of other administrative controls that will ensure a mispositioned valve is unlikely.

Wolf Creek - Unit 1 B 3.5.2-7 Revision 0

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.2 REQUIREMENTS (continued) Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. 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 apply to manual vent/drain valves, and to valves that cannot be inadvertently misaligned such as check valves. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve will automatically reposition within the proper stroke time. 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 is appropriate because the valves are operated under administrative control, and an improper valve position would only affect a single train. This Frequency has been shown to be acceptable through operating experience.

SR 3.5.2.3 The ECCS pumps are normally in a standby, nonoperating mode. As such, flow path piping has the potential to develop voids and pockets of entrained gases. It is important that the ECCS is sufficiently filled with water to ensure that the subsystems can reliably perform their intended function under all LOCA and non-LOCA conditions that require makeup to the RCS. Maintaining the piping from the ECCS pumps to the RCS sufficiently full of water ensures that the system will perform properly, injecting its full capacity into the RCS upon demand. This SR is satisfied by verifying that RHR and SI pump casings and accessible ECCS suction and discharge piping high point vents are sufficiently full of water by venting and/or ultrasonic testing (UT). The design of the centrifugal charging pump is such that significant noncondensible gases do not collect in the pump. Therefore, it is unnecessary to require periodic pump casing venting to ensure the centrifugal charging pump will remain OPERABLE. Accessible high point vents are those that can be reached without hazard or high radiation dose to personnel. This will also prevent water hammer, pump cavitation, and pumping of noncondensible gas (e.g., air, nitrogen, or hydrogen) into the reactor vessel following an SI signal or during shutdown cooling. The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the ECCS piping and the procedural controls governing system operation.

Wolf Creek - Unit 1 B 3.5.2-8 Revision 38

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 REQUIREMENTS (continued) Periodic surveillance testing of ECCS pumps to detect gross degradation caused by impeller structural damage or other hydraulic component problems is required by the ASME Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. The following ECCS pumps are required to develop the indicated differential pressure on recirculation flow:

Centrifugal Charging Pump 2!2490 psid Safety Injection Pump _ 1468.9 psid RHR Pump > 183.6 psid This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the plant safety analysis. SRs are specified in the applicable portions of the Inservice Testing Program, which encompasses the ASME Code. The ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

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

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

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

Wolf Creek - Unit 1 B 3.5.2-9 Revision 38 1

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

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

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

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

2. 10 CFR 50.46.

3. USAR, Sections 6.3 and 15.6.

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

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

December 1, 1975.

6. IE Information Notice No. 87-01.

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

Revision 33 Wolf -

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

Containment Isolation Valves B 3.6.3 BASES ACTIONS In the event the containment isolation valve leakage results in exceeding (continued) the overall containment leakage rate acceptance criteria, Note 4 directs entry into the applicable Conditions and Required Actions of LCO 3.6.1.

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

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

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

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

Condition A is applicable to those penetration flow paths with two containment isolation valves and penetration flow paths with only one containment isolation valve and a closed system. The closed system Wolf Creek - Unit 1 B 3.6.3-5 Revision 36

Containment Isolation Valves B 3.6.3 BASES ACTIONS A.1 and A.2 (continued) must meet the requirement of Reference 5. The Containment Spray System and ECCS are closed ESF-grade systems outside containment, which meet the requirements of Reference 5, and serve as the second containment isolation barrier (Ref. 6).

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

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

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves. I Wolf Creek - Unit 1 B 3.6.3-6 Revision 36

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

In the event one containment isolation valve in two or more penetration flow paths is inoperable, except for purge valve leakage not within limit, all but one of the affected penetration flow path(s) must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic containment isolation valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For a penetration flow path isolated in accordance with C.1, the device used to isolate the penetration should be the closest available one to containment. Required Action C.1 must be completed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . For the penetration flow paths isolated in accordance with Required Action C.1, the affected penetration(s) must be verified to be isolated on a periodic basis per Required Action A.2, which remains in effect. This periodic verification is necessary to assure that the penetrations requiring isolation following an accident are isolated. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the time required to isolate the penetration and the relative importance of supporting Containment OPERABILITY during MODES 1, 2, 3, and 4. For subsequent containment isolation valve inoperabilities, the Required Action and Completion Time continue to apply to each additional containment isolation valve inoperability, with the Completion Time based on each subsequent entry into the Condition consistent with Note 2 to the ACTIONS Table (e.g., for each entry into the Condition).

The containment isolation valve(s) inoperable as a result of that entry shall meet the Required Action and Completion Time.

D.1, D.2, and D.3 In the event one or more containment shutdown or mini-purge valves in one or more penetration flow paths are not within the leakage limits, leakage must be restored to within limits, or the affected penetration flow path must be isolated. The method of isolation must be by the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, closed manual valve (this includes power operated valves with power removed), or blind flange. A containment shutdown purge or mini-purge valve with resilient seals utilized to satisfy Required Action D.1 must have been demonstrated to meet the leakage requirements of SR 3.6.3.6 or SR 3.6.3.7. The specified Completion Time is reasonable, considering that one containment purge valve remains closed so that a gross breach of containment does not exist.

Wolf Creek - Unit 1 B 3.6.3-7 Revision 36

Containment Isolation Valves B 3.6.3 BASES ACTIONS D.1, D.2, and D.3 (continued)

In accordance with Required Action D.2, this penetration flow path must be verified to be isolated on a periodic basis. The periodic verification is necessary to ensure that containment penetrations required to be isolated following an accident, which are no longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or valve manipulation.

Rather, it involves verification, through a system walkdown (which may include the use of local or remote indicators), that those isolation devices outside containment capable of being mispositioned are in the correct position. For the isolation devices inside containment, the time period specified as "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.

For the containment purge valve with resilient seal that is isolated in accordance with Required Action D.1, SR 3.6.3.6 or SR 3.6.3.7 must be performed at least once every 92 days. This assures that degradation of the resilient seal is detected and confirms that the leakage rate of the containment purge valve does not increase during the time the penetration is isolated. The normal Frequency for SR 3.6.3.7, 184 days, is based on an NRC initiative, Multi-Plant Action No. B-20 (Ref. 3). Since more reliance is placed on a single valve while in this Condition, it is prudent to perform the SR more often. Therefore, a Frequency of once per 92 days was chosen and has been shown to be acceptable based on operating experience.

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

Wolf Creek - Unit 1 B 3.6.3-8 Revision 36 1

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

Ifthe Required Actions and associated Completion Times 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.

SURVEILLANCE SR 3.6.3.1 REQUIREMENTS Each 36 inch containment shutdown purge supply and exhaust valve is required to be verified sealed closed or closed and blind flange installed at 31 day intervals. Each 36 inch containment shutdown purge supply and exhaust valve inside containment must be verified sealed closed or blind flange installed prior to entering MODE 4 from MODE 5, ifthe surveillance has not been performed in the previous 92 days. This Surveillance is designed to ensure that a gross breach of containment is not caused by an inadvertent or spurious opening of a containment shutdown purge valve. Detailed analysis of these valves failed to conclusively demonstrate their ability to close during a LOCA in time to limit offsite doses. Therefore, these valves are required to be in the sealed closed position or closed and blind flange installed during MODES 1, 2, 3, and 4.

A containment shutdown purge valve that is sealed closed must have motive power to the valve operator removed. This can be accomplished by de-energizing the source of electric power or by removing the air supply to the valve operator. In this application, the term "sealed" has no connotation of leak tightness. The Frequency is a result of an NRC initiative, Multi-Plant Action No. B-24 (Ref. 4), related to containment purge valve use during plant operations. In the event valve leakage requires entry into Condition D,the Surveillance permits opening one purge valve in a penetration flow path to perform repairs.

SR 3.6.3.2 This SR ensures that the mini-purge valves are closed as required or, if open, open for an allowable reason. Ifa mini-purge valve is open in violation of this SR, the valve is considered inoperable. Ifthe inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The SR is not required to be met when the mini-purge valves are open for the reasons stated.

The valves may be opened for pressure control, ALARA or air quality Wolf Creek - Unit 1 B 3.6.3-9 Revision 36 1

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.2 (continued)

REQUIREMENTS considerations for personnel entry, or for Surveillances that require the valves to be open. The mini-purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The 31 day Frequency is consistent with other containment isolation valve requirements discussed in SR 3.6.3.3.

SR 3.6.3.3 This SR requires verification that each containment isolation manual valve and blind flange located outside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the containment boundary is within design limits.

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 containment isolation valves outside containment and capable of being mispositioned are in the correct position. Since verification of valve position for containment isolation valves outside containment is relatively easy, the 31 day Frequency is based on engineering judgment and was chosen to provide added assurance of the correct positions. The SR specifies that containment isolation valves that are open under administrative controls are not required to meet the SR during the time the valves are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing or securing.

The Note applies to valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3 and 4 for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in the proper position, is small.

SR 3.6.3.4 This SR requires verification that each containment isolation manual valve and blind flange located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive Wolf Creek - Unit 1 B 3.6.3-10 Revision 8 1

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.4 (continued)

REQUIREMENTS fluids or gases outside of the containment boundary is within design limits.

For containment isolation valves inside containment, the Frequency of "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is appropriate since these containment isolation valves are operated under administrative controls and the probability of their misalignment is low. The SR specifies that containment isolation valves that are open under administrative controls are not required to meet the SR during the time they are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing or securing.

A Note has been added that allows valves and blind flanges located in high radiation areas to be verified closed by use of administrative means.

Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3, and 4, for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in their proper position is small.

SR 3.6.3.5 Verifying that the isolation time of each automatic power operated containment isolation valve is within limits is required to demonstrate OPERABILITY. The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analyses.

Isolation times are provided in USAR Figure 6.2.4-1 (Ref. 2). The Frequency of this SR is in accordance with the Inservice Testing Program.

The Inservice Testing Program uses ASME Code Case OMN-1, "Alternative Rules for Preservice and Inservice Testing of Certain Electric Motor-Operated Valve Assemblies in Light-Water Reactor Plants," in lieu of stroke time testing for motor operated valves (Ref. 7). The parameters that must be present to achieve the analyzed isolation time under design basis conditions are measured. This process verifies design basis capability, including isolation time, and is a significant improvement over simple stroke time measurement. The Frequency of this Surveillance is determined through a mix of risk informed and performance based means in accordance with the Inservice Testing Program.

Wolf Creek - Unit 1 B 3.6.3-11 Revision 36 1

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.6 REQUIREMENTS (continued) Leakage integrity tests with a maximum allowable leakage rate for containment shutdown purge supply and exhaust isolation valves will provide early indication of resilient material seal degradation and will allow opportunity for repair before gross leakage failures could develop.

This SR is modified by a Note indicting that the SR is only required to be performed when the containment shutdown purge valves blind flanges are installed.

If the blind flange is installed, leakage rate testing of the valve and its associated blind flange must be performed every 24 months and following each reinstallation of the blind flange. Operating experience has demonstrated that this testing frequency is adequate to assure this penetration is leak tight.

The combined leakage rate for the containment shutdown purge supply and exhaust isolation valves, when pressurized to Pa, and included with all Type B and C penetrations is less than .60 La.

SR 3.6.3.7 For containment mini-purge and shutdown purge valves with resilient seals, additional leakage rate testing beyond the test requirements of 10 CFR 50, Appendix J, Option B is required to ensure OPERABILITY.

Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than do other seal types.

Based on this observation and the importance of maintaining this penetration leak tight (due to the direct path between containment and the environment), a Frequency of 184 days was established as part of the NRC resolution of Multi-Plant Action No. B-20, "Containment Leakage Due to Seal Deterioration" (Ref. 3).

Additionally, this SR must be performed within 92 days after opening the valve. The 92 day Frequency was chosen recognizing that cycling the valve could introduce additional seal degradation (beyond that occurring to a valve that has not been opened). Thus, decreasing the interval (from 184 days) is a prudent measure after a valve has been opened.

The SR is modified by a Note indicating that the SR is only required to be performed for the containment shutdown purge valves when the associated blind flange is removed.

Wolf Creek - Unit 1 B 3.6.3-12 Revision 36 1

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.7 (continued)

REQUIREMENTS The measured leakage rate for each containment mini-purge supply and exhaust isolation valve with resilient seals is less than 0.05 La when pressurized to Pa. The combined leakage rate for the containment shutdown purge supply and exhaust isolation valves, when pressurized to Pa, and included with all Type B and C penetrations is less than .60 La.

SR 3.6.3.8 Automatic containment isolation valves close on a containment isolation signal to prevent leakage of radioactive material from containment following a DBA. This SR ensures that each automatic containment isolation valve will actuate to its isolation position on a containment isolation 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 plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass this Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section 15.

2. USAR, Figure 6.2.4-1.

3. Multi-Plant Action MPA-B020, "Containment Leakage Due to Seal Deterioration."

4. Multi-Plant Action MPA-B024, "Venting and Purging Containment's While at Full Power and Effect of LOCA."

5. USAR, Section 6.2.4.

6. NUREG-0881, "Safety Evaluation Report related to the operation of Wolf Creek Generating Station, Unit No. 1," Section 6.2.3, April 1982.

7. NRC letter dated March 29, 2001, "Relief Request from the Requirements of ASME Code,Section XI, Related to Code Case OMN-1 for Wolf Creek Generating Station (TAC NO. MB0982)."

8. WCAP-1 5791 -P, Rev. 1, "Risk-Informed Evaluation of Extensions to Containment Isolation Valve Completion Times," April 2004.

Wolf Creek - Unit 1 B 3.6.3-13 Revision 36

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 1 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORY/COMPLETION TIME BBHV-8026 P-62 Category 7 7 days BBHV-8027 P-62 Category 7 7 days BBHV-8351A P-41 Category 7 7 days BBHV-8351 B P-22 Category 7 7 days BBHV-8351C P-39 Category 7 7 days BBHV-8351 D P-40 Category 7 7 days BBV-1 18 P-41 Category 7 7 days BBV-148 P-22 Category 7 7 days BBV-178 P-39 Category 7 7 days BBV-208 P-40 Category 7 7 days BBV-245 P-41 Category 7 7 days BBV-246 P-22 Category 7 7 days BBV-247 P-39 Category 7 7 days BBV-248 P-40 Category 7 7 days BBV-352 P-41 Category 7 7 days BBV-354 P-22 Category 7 7 days BBV-356 P-39 Category 7 7 days BBV-358 P-40 Category 7 7 days BG-8381 P-80 Category 7 7 days BGHV-81 00 P-24 Category 7 7 days BGHV-8105 P-80 Category 7 7 days BGHV-8112 P-24 Category 7 7 days BGHV-8152 P-23 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months BGHV-8160 P-23 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months BGV-135 P-24 Category 7 7 days BGV-342 P-80 Category 7 7 days BGV-363 P-23 Category 7 7 days BGV-457 P-24 Category 7 7 days BL-8046 P-25 Category 7 7 days BLHV-8047 P-25 Category 7 7 days BLV-054 P-25 Category 7 7 days BMV-045 P-78 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months BMV-046 P-78 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months BMV-302 P-78 Category 7 7 days ECV-083 P-53 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ECV-084 P-53 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ECV-085 P-53 Category 7 7 days ECV-086 P-54 Category 7 7 days ECV-087 P-54 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ECV-088 P-54 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ECV-094 P-55 Category 7 7 days ECV-095 P-55 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ECV-096 P-55 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Wolf Creek - Unit 1 B 3.6.3-14 Revision 36

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 2 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORY/COMPLETION TIME EFHV-31 P-71 Category 7 7 days EFHV-32 P-28 Category 7 7 days EFHV-33 P-71 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EFHV-34 P-28 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EFHV-45 P-73 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EFHV-46 P-29 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EFHV-49 P-73 Category 7 7 days EFHV-50 P-29 Category 7 7 days EFV-276 P-71 Category 7 7 days EFV-277 P-73 Category 7 7 days EFV-278 P-28 Category 7 7 days EFV-279 P-29 Category 7 7 days EGHV-1 27 P-74 Category 7 7 days EGHV-130 P-75 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months EGHV-131 P-75 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EGHV-132 P-76 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months EGHV-133 P-76 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EGHV-58 P-74 Category 7 7 days EGHV-59 P-75 Category 7 7 days EGHV-60 P-75 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EGHV-61 P-76 Category 7 7 days EGHV-62 P-76 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EGV-090 P-74 Category 7 7 days EGV-204 P-74 Category 7 7 days EGV-371 P-76 Category 7 7 days EGV-372 P-75 Category 7 7 days EJ-8708A P-79 Category 2 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months EJ-8708B P-52 Category 2 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months EJ-8841 A P-21 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EJ-8841 B P-21 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EJHCV-8825 P-21 Category 7 7 days EJHCV-8890A P-82 Category 7 7 days EJHCV-8890B P-27 Category 7 7 days EJ HV-8701A P-79 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJHV-8701 B P-52 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJHV-8809A P-82 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJHV-8809B P-27 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJHV-881 1A P-15 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Wolf Creek - Unit 1 B 3.6.3-15 Revision 39

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 3 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORYICOMPLETION TIME EJHV-8811B P-14 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJHV-8840 P-21 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EJV-054 P-82 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJV-056 P-21 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EJV-058 P-27 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EJV-086 P-27 Category 7 7 days EJV-088, -090 P-27 Category 7 7 days EJV-118, 120 P-21 Category 7 7 days EJV-122 P-21 Category 7 7 days EJV-1 24 P-21 Category 7 7 days EJV-1 32 P-82 Category 7 7 days EJV-1 34, -136 P-82 Category 7 7 days EJV-1 54 P-79 Category 7 7 days EJV-1 66 P-27 Category 7 7 days EJV-1 71, -172, -173, -174 P-82 Category 7 7 days EJV-1 75, -176, -177, -178 P-21 Category 7 7 days EJV-179, -180, -181, -182 P-27 Category 7 7 days EJV-218 P-21 Category 7 7 days EMHV-8801A P-88 Category 7 7 days EMHV-8801 B P-88 Category 7 7 days EMHV-8802A P-87 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMHV-8802B P-48 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMHV-8823 P-49 Category 7 7 days EMHV-8824 P-48 Category 7 7 days EMHV-8835 P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EMHV-8843 P-88 Category 7 7 days EMHV-8871 P-92 Category 7 7 days EMHV-8881 P-87 Category 7 7 days EMHV-8888 P-58 Category 7 7 days EMHV-8964 P-92 Category 7 7 days EMV-001 P-87 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-002 P-87 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-003 P-48 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-004 P-48 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-006 P-58 Category 7 7 days EMV-038 P-92 Category 7 7 days EMV-051 P-87 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-052, -053, -055, -056, P-87 Category 7 7 days

-184, -185 EMV-059 P-48 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months EMV-060, -061, -063, -064, P-48 Category 7 7 days EMV-067 P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Wolf Creek - Unit 1 B 3.6.3-16 Revision 39

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 4 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORY/COMPLETION TIME EMV-068, -069, -070, -071, P-49 Category 7 7 days

-072, -073, -074, -075 EMV-077 P-88 Category 7 7 days EMV-123 P-58 Category 7 7 days EMV-1 51 P-88 Category 7 7 days EMV-153 P-92 Category 7 7 days EMV-162, -163, -164, -165, P-49 Category 7 7 days

-166, -167, -168 EMV-1 69, -217 P-48 Category 7 7 days EMV-170, -172 P-48 Category 7 7 days EMV-182 P-58 Category 7 7 days EMV-186, -187 P-87 Category 7 7 days EMV-218 P-49 Category 7 7 days EMV-8815 P-88 Category 7 7 days ENHV-06 P-89 Category 7 7 days ENHV-01 P-16 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ENHV-07 P-13 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ENHV-12 P-66 Category 7 7 days ENV-013 P-89 Category 7 7 days ENV-017 P-66 Category 7 7 days ENV-076 P-89 Category 7 7 days ENV-080 P-66 Category 7 7 days EP-8818A P-82 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EP-8818B P-82 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EP-8818C P-27 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EP-8818D P-27 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EPHV-8880 P-45 Category 7 7 days EPV-010. P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EPV-020 P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EPV-030 P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EPV-040 P-49 Category 1 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months EPV-043 P-45 Category 7 7 days EPV-046 P-45 Category 7 7 days GPV-010 P-34 Category 7 7 days GPV-01 1 P-51 Category 7 7 days GPV-012 P-51 Category 7 7 days GSHV-12 P-101 Category 7 7 days GSHV-13 P-101 Category 7 7 days GSHV-14 P-101 Category 7 7 days GSHV-17 P-97 Category 7 7 days GSHV-18 P-97 Category 7 7 days GSHV-20 P-65 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Wolf Creek - Unit 1 B 3.6.3-17 Revision 36

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 5 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORY/COMPLETION TIME GSHV-21 P-65 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months GSHV-3 P-99 Category 7 7 days GSHV-31 P-101 Category 7 7 days GSHV-32 P-101 Category 7 7 days GSHV-33 P-97 Category 7 7 days GSHV-34 P-97 Category 7 7 days GSHV-36 P-99 Category 7 7 days GSHV-37 P-99 Category 7 7 days GSHV-38 P-56 Category 7 7 days GSHV-39 P-56 Category 7 7 days GSHV-4 P-99 Category 7 7 days GSHV-5 P-99 Category 7 7 days GSHV-8 P-56 Category 7 7 days GSHV-9 P-56 Category 7 -7 days GSV-029 P-99 Category 7 7 days GSV-032 P-56 Category 7 7 days GSV-033 P-99 Category 7 7 days GSV-036 P-97 Category 7 7 days GSV-041 P-65 Category 7 7 days GSV-050 P-101 Category 7 7 days GSV-052 P-97 Category 7 7 days GSV-056 P-101 Category 7 7 days GSV-058 P-56 Category 7 7 days GTHZ-1 1 V-160 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-12 V-160 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-4 V-161 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-5 V-161 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-6 V-161 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-7 V-161 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-8 V-160 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTHZ-9 V-160 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months GTV-222 V-161 Category 7 7 days GTV-223 V-160 Category 7 7 days HBHV-7126 P-44 Category 7 7 days HBHV-7136 P-26 Category 6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months HBHV-7150 P-44 Category 7 7 days HBHV-7176 P-26 Category 5 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months HBV-419 P-26 Category 7 7 days HBV-420 P-44 Category 7 7 days HDV-016 P-43 Category 7 7 days HDV-017 P-43 Category 7 7 days HDV-023 P-43 Category 7 7 days Wolf Creek - Unit 1 B 3.6.3-18 Revision 36

Containment Isolation Valves B 3.6.3 TABLE B 3.6.3-1 (Page 6 of 6)

CONTAINMENT ISOLATION VALVES - COMPLETION TIMES VALVE PENETRATION NO. CATEGORY/COMPLETION TIME KAFV-29 P-30 Category 7 7 days KAV-039 P-63 Category 7 7 days KAV-118 P-63 Category 7 7 days KAV-1 63 P-63 Category 7 7 days KAV-204 P-30 Category 7 7 days KAV-218 P-30 Category 7 7 days KBV-001 P-98 Category 7 7 days KBV-002 P-98 Category 7 7 days KCHV-253 P-67 Category 7 7 days KCV-431 P-67 Category 7 7 days KCV-478 P-67 Category 7 7 days LFFV-95 P-32 Category 7 7 days LFFV-96 P-32 Category 7 7 days LFV-093 P-32 Category 7 7 days SJHV-12 P-69 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SJHV-127 P-93 Category 7 7 days SJHV-128 P-64 Category 3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SJHV-129 P-64 Category 7 7 days SJHV-13 P-69 Category 4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SJHV-130 P-64 Category 7 7 days SJHV-131 P-57 Category 7 7 days SJHV-132 P-57 Category 7 7 days SJHV-18 P-95 Category 7 7 days SJHV-19 P-95 Category 7 7 days SJHV-5 P-93 Category 5 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months SJHV-6 P-93 Category 5 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months SJV-066 P-95 Category 7 7 days SJV-069 P-93 Category 7 7 days SJV-071 P-69 Category 7 7 days SJV-1 06 P-64 Category 7 7 days SJV-111 P-57 Category 7 7 days SJV-1 14 P-57 Category 7 7 days Wolf Creek - Unit 1 B 3.6.3-19 Revision 36

Containment Pressure B 3.6.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.4 Containment Pressure BASES BACKGROUND The containment pressure is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a loss of coolant accident (LOCA) or steam line break (SLB). These limits also prevent the containment pressure from exceeding the containment design negative pressure differential with respect to the outside atmosphere in the event of inadvertent actuation of the Containment Spray System.

Containment pressure is a process variable that is monitored and controlled. The containment pressure limits are derived from the input conditions used in the containment functional analyses and the containment structure external pressure analysis. Should operation occur outside these limits coincident with a Design Basis Accident (DBA), post accident containment pressures could exceed calculated values.

APPLICABLE Containment internal pressure is an initial condition used in the DBA SAFETY ANALYSES analyses to establish the maximum peak containment internal pressure.

The initial containment conditions are relatively unimportant parameters with respect to the containment pressure temperature analysis. The limiting DBAs considered, relative to containment pressure, are the LOCA and SLB, which are analyzed using computer codes developed to predict the containment pressure transients. The worst case LOCA generates larger mass and energy release than the worst case SLB. However, the SLB event bounds the LOCA event from the containment peak pressure standpoint (Ref. 1).

The initial pressure condition used in the containment analysis was 14.7 psia (0 psig). The containment analysis (Ref. 1) shows that the maximum peak calculated containment pressure results from a MSLB.

The maximum containment pressure resulting from the worst case MSLB, 51.5 psig, does not exceed the containment design pressure, 60 psig.

The containment was also designed for an external pressure load equivalent to -3.0 psig. The inadvertent actuation of the Containment Spray System was analyzed to determine the resulting reduction in containment pressure. The initial pressure condition used in this analysis was 0 psig. This resulted in a minimum pressure inside containment of

-2.72 psig, which is less than the design pressure.

For certain aspects of transient accident analyses, maximizing the calculated containment pressure is not conservative. In particular, the cooling effectiveness of the Emergency Core Cooling System during the Wolf Creek - Unit I B 3.6.4-1 Revision 39

Containment Pressure B 3.6.4 BASES APPLICABLE core reflood phase of a LOCA analysis increases with increasing SAFETY ANALYSES containment backpressure. Therefore, for the reflood phase, the (continued) containment backpressure is calculated in a manner designed to conservatively minimize, rather than maximize, the containment pressure response in accordance with 10 CFR 50, Appendix K (Ref. 2).

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

LCO Maintaining containment pressure at less than or equal to the LCO upper pressure limit ensures that, in the event of a DBA, the resultant peak containment accident pressure will remain below the containment design pressure. Maintaining containment pressure at greater than or equal to the LCO lower pressure limit ensures that the containment will not exceed the design negative differential pressure following the inadvertent actuation of the Containment Spray System.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. Since maintaining containment pressure within limits is essential to ensure initial conditions assumed in the accident analyses are maintained, the LCO is applicable in MODES 1, 2, 3 and 4.

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, maintaining containment pressure within the limits of the LCO is not required in MODE 5 or 6.

ACTIONS A. 1 When containment pressure is not within the limits of the LCO, it must be restored to within these limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Required Action is necessary to return operation to within the bounds of the containment analysis. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1, "Containment," which requires that containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

B.1 and B.2 If containment pressure cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 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 Wolf Creek - Unit 1 B 3.6.4-2 Revision 0

Containment Air Temperature B 3.6.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.5 Containment Air Temperature BASES BACKGROUND The containment structure serves to contain radioactive material that may be released from the reactor core following a Design Basis Accident (DBA). The containment average air temperature is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a loss of coolant accident (LOCA) or steam line break (SLB).

The containment average air temperature limit is derived from the input conditions used in the containment functional analyses and the containment structure external pressure analyses. This LCO ensures that initial conditions assumed in the analysis of containment response to a DBA are not violated during unit operations. The total amount of energy to be removed from containment by the Containment Spray and Cooling systems during post accident conditions is dependent upon the energy released to the containment due to the event, as well as the initial containment temperature and pressure. The higher the initial temperature, the more energy that must be removed, resulting in higher peak containment pressure and temperature. Exceeding containment design pressure may result in leakage greater than that assumed in the accident analysis. Operation with containment temperature in excess of the LCO limit violates an initial condition assumed in the accident analysis.

APPLICABLE Containment average air temperature is an initial condition used in the SAFETY ANALYSES DBA analyses that establishes the containment environmental qualification operating envelope for both pressure and temperature. The limit for containment average air temperature ensures that operation is maintained within the assumptions used in the DBA analyses for containment (Ref. 1).

The limiting DBAs considered relative to containment OPERABILITY are the LOCA and SLB. The DBA LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure transients. No two DBAs are assumed to occur simultaneously or consecutively. The postulated DBAs are analyzed with regard to Engineered Safety Feature (ESF) systems, assuming the loss of one ESF bus, which is the worst case single active failure, resulting in one train each of the Containment Spray System, Residual Heat Removal System, and Containment Cooling System being rendered inoperable.

The limiting DBA for the maximum peak containment air temperature is an SLB. The initial containment average air temperature assumed in the Wolf Creek - Unit 1 B 3.6.5-1 Revision 0

Containment Air Temperature B 3.6.5 BASES APPLICABLE design basis analyses (Ref. 1) is 120'F. This resulted in a maximum SAFETY ANALYSES containment air temperature of 360.0°F. The design temperature is (continued) 320 0 F.

The spectrum of SLBs cases are used to establish the environmental qualification operating envelope for containment. The performance of required safety related equipment, including the containment structure itself, is evaluated against this operating envelope to ensure the equipment can perform its safety function. The maximum peak containment air temperature was calculated to exceed the containment design temperature for only a few seconds during the transient. The basis of the containment design temperature, however, is to ensure the performance of safety related equipment inside containment (Ref. 2).

Thermal analyses showed that the time interval during which the containment air temperature exceeded the containment design temperature was short enough that the equipment surface temperatures remained below the design temperature. Therefore, it is concluded that the calculated transient containment air temperature is acceptable for the DBA SLB.

The temperature limit is also used in the containment external pressure analyses to ensure that the minimum pressure limit is maintained following an inadvertent actuation of the Containment Spray System (Ref. 1).

The containment pressure transient is sensitive to the initial air mass in containment and, therefore, to the initial containment air temperature.

The limiting DBA for establishing the maximum peak containment internal pressure is a MSLB. The temperature limit is used in this analysis to ensure that in the event of an accident the maximum containment internal pressure will not be exceeded.

Containment average air temperature satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO During a DBA, with an initial containment average air temperature less than or equal to the LCO temperature limit, the resultant accident temperature profile assures that the containment structural temperature will be maintained below the containment design temperature and that required safety related equipment within containment will continue to perform its function.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining Wolf Creek - Unit 1 B 3.6.5-2 Revision 37

Containment Spray and Cooling Systems B 3.6.6 BASES BACKGROUND Containment Cooling System (continued)

In post accident operation following an actuation signal, the Containment Cooling System fans are designed to start automatically in slow speed if not already running. If running in high (normal) speed, the fans automatically shift to slow speed. The fans are operated at the lower speed during accident conditions to prevent motor overload from the higher mass atmosphere. The temperature of the ESW is an important factor in the heat removal capability of the fan units.

APPLICABLE The Containment Spray System and Containment Cooling System limits SAFETY ANALYSES the temperature and pressure that could be experienced following a DBA.

The limiting DBAs considered are the loss of coolant accident (LOCA) and the steam line break (SLB). The LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. No DBAs are assumed to occur simultaneously or consecutively. The postulated DBAs are analyzed with regards to containment ESF systems, assuming the loss of one ESF bus, which is the worst case single active failure and results in one train of the Containment Spray System and Containment Cooling System being rendered inoperable.

The analysis and evaluation show that under the worst case scenario, the highest peak containment pressure is 51.5 psig and the peak containment temperature is 360.0°F (experienced during an SLB). Both results meet the intent of the design basis. (See the Bases for LCO 3.6.4, "Containment Pressure," and LCO 3.6.5 for a detailed discussion.) The analyses and evaluations assume a unit specific power level ranging to 102%, one containment spray train and one containment cooling train operating, and initial (pre-accident) containment conditions of 120OF and 0 psig. The analyses also assume a response time delayed initiation to provide conservative peak calculated containment pressure and temperature responses.

For certain aspects of transient accident analyses, maximizing the calculated containment pressure is not conservative. In particular, the effectiveness of the Emergency Core Cooling System during the core reflood phase of a LOCA analysis increases with increasing containment backpressure. For these calculations, the containment backpressure is calculated in a manner designed to conservatively minimize, rather than maximize, the calculated transient containment pressures in accordance with 10 CFR 50, Appendix K (Ref. 2).

The effect of an inadvertent containment spray actuation has been analyzed. An inadvertent spray actuation results in a -2.72 psig containment pressure and is associated with the sudden cooling effect in the interior of the leak tight containment. Additional discussion is provided in the Bases for LCO 3.6.4.

Wolf Creek - Unit 1 B 3.6.6-3 Revision 37

Containment Spray and Cooling Systems B 3.6.6 BASES APPLICABLE The modeled Containment Spray System actuation from the containment SAFETY ANALYSES analysis is based on a response time associated with exceeding the (continued) containment High-3 pressure setpoint to achieving full flow through the containment spray nozzles.

The Containment Spray System total response time includes diesel generator (DG) startup (for loss of offsite power), sequenced loading of equipment, containment spray pump startup, and spray line filling (Ref. 4).

Containment cooling train performance for post accident conditions is given in Reference 4. The result of the analysis is that each train can provide 100% of the required peak cooling capacity during the post accident condition. The train post accident cooling capacity under varying containment ambient conditions, required to perform the accident analyses, is also shown in Reference 4.

The modeled Containment Cooling System actuation from the containment analysis is based upon a response time associated with receipt of an SI signal to achieving full Containment Cooling System air and safety grade cooling water flow. The Containment Cooling System total response time of 70 seconds, includes signal delay, DG startup (for loss of offsite power), and Essential Service Water pump startup times and line refill (Ref. 4).

The Containment Spray System and the Containment Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO During a DBA, a minimum of one containment cooling train and one containment spray train is required to maintain the containment peak pressure and temperature below the design limits (Ref. 3). Additionally, one containment spray train is also required to remove iodine from the containment atmosphere and maintain concentrations below those assumed in the safety analysis. To ensure that these requirements are met, two containment spray trains and two containment cooling trains must be OPERABLE. Therefore, in the event of an accident, at least one train in each system operates, assuming the worst case single active failure occurs.

Each Containment Spray System typically includes a spray pump, spray headers, eductor, nozzles, valves, piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST upon an ESF actuation signal and manually transferring to the containment sump.

A containment cooling train typically includes cooling coils, dampers, two fans, instruments, and controls to ensure an OPERABLE flow path.

Wolf Creek - Unit 1 B 3.6.6-4 Revision 0

MSIVs B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Main Steam Isolation Valves (MSIVs)

BASES BACKGROUND The MSIVs isolate steam flow from the secondary side of the steam generators following a high energy line break (HELB). MSIV closure terminates flow from the unaffected (intact) steam generators to the break.

One MSIV is located in each main steam line outside, but close to, containment. The MSIVs are downstream from the main steam safety valves (MSSVs) and auxiliary feedwater (AFW) pump turbine steam supply, to prevent MSSV and AFW isolation from the steam generators by MSIV closure. Closing the MSIVs isolates each steam generator from the others, and isolates the turbine, Turbine Bypass System, and other auxiliary steam supplies from the steam generators.

The MSIV is a 28-inch gate valve with system-medium actuation trains.

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

The MSIVs close on a main steam isolation signal generated by low steam line pressure, high steam line negative pressure rate or High-2 containment pressure. The MSIVs fail as is on loss of control or actuation power.

Each MSIV has~an MSIV bypass valve. Although these bypass valves are normally closed, they receive the same emergency closure signal as do their associated MSIVs. The MSIVs may also be actuated manually.

A description of the MSIVs is found in the USAR, Section 10.3 (Ref. 1).

APPLICABLE The design basis of the MSIVs is established by the containment analysis SAFETY ANALYSES for the large steam line break (SLB) inside containment, discussed in the USAR, Section 6.2.1.4 (Ref. 2). It is also affected by the accident analysis of the SLB events presented in the USAR, Section 15.1.5 (Ref. 3). The design precludes the blowdown of more than one steam generator, assuming a single active component failure (e.g., the failure of one MSIV to close on demand).

Wolf Creek - Unit 1 B 3.7.2-1 Revision 37

MSIVs B 3.7.2 BASES APPLICABLE The limiting case for the containment pressure analysis is the SLB inside SAFETY ANALYSES containment, with initial reactor power at approximately 0% with loss of (continued) offsite power and the failure of one emergency diesel generator. At lower powers, the steam generator inventory and temperature are at their maximum, maximizing the analyzed mass and energy release to the containment. Due to reverse flow and failure of the MSIV to close,the additional mass and energy in the steam headers downstream from the other MSIV contribute to the total release. With the most reactive rod cluster control assembly assumed stuck in the fully withdrawn position, there is an increased possibility that the core will become critical and return to power. The core is ultimately shut down by the boric acid injection delivered by the Emergency Core Cooling System.

The accident analysis compares several different SLB events against different acceptance criteria. The large SLB outside containment upstream of the MSIV is limiting for offsite dose, although a break in this short section of main steam header has a very low probability. The large SLB inside containment at hot zero power is the limiting case for a post trip return to power. The analysis includes scenarios with offsite power available, and with a loss of offsite power following turbine trip. With offsite power available, the reactor coolant pumps continue to circulate coolant through the steam generators, maximizing the Reactor Coolant System cooldown. With a loss of offsite power, the response of mitigating systems is delayed. Significant single failures considered include failure of an MSIV to close.

The MSIVs serve only a safety function and remain open during power operation. These valves operate under the following situations:

a. An HELB inside containment. In order to maximize the mass and energy release into containment, the analysis assumes that the MSIV in the affected steam generator remains open. For this accident scenario, steam is discharged into containment from all steam generators until the remaining MSIVs close. After MSIV closure, steam is discharged into containment only from the affected steam generator and from the residual steam in the main steam header downstream of the closed MSIVs in the unaffected loops. Closure of the MSVIs isolates the break from the unaffected steam generators.

b. A break outside of containment and upstream from the MSIVs is not a containment pressurization concern. The uncontrolled blowdown of more than one steam generator must be prevented to limit the potential for uncontrolled RCS cooldown and positive reactivity addition. Closure of the MSIVs isolates the break and limits the blowdown to a single steam generator.

Wolf Creek - Unit 1 B 3.7.2-2 Revision 37

MSIVs B 3.7.2 BASES APPLICABLE c. A break downstream of the MSIVs will be isolated by the closure SAFETY ANALYSES of the MSIVs.

(continued)

d. Following a steam generator tube rupture, closure of the MSIVs isolates the ruptured steam generator from the intact steam generators to minimize radiological releases.

e. The MSIVs are also utilized during other events such as a feedwater line break. This event is less limiting as far as MSIV OPERABILITY is concerned.

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

LCO This LCO requires that four MSIVs and their associated actuator trains be OPERABLE. The MSIVs are considered OPERABLE when the isolation times are within limits, and they close on an isolation actuation signal.

An MSIV actuator train is considered OPERABLE when it is capable of closing the associated MSIV on demand and within the required isolation time. The MSIVs are considered OPERABLE when isolation times are within limits of Figure B 3.7.2-1 when given a close signal and they are capable of closing on an isolation actuation signal.

This LCO provides assurance that the MSIVs will perform their design safety function to mitigate the consequences of accidents that could result in offsite exposures comparable to the 10 CFR 100 (Ref. 4) limits or the NRC staff approved licensing basis.

APPLICABILITY The MSIVs must be OPERABLE in MODE 1, and in MODES 2 and 3 due to significant mass and energy in the RCS and steam generators. When the MSIVs are closed, they are already performing the safety function.

The MSIV actuator trains must be OPERABLE in MODES 1, 2, and 3 to support operation of the MSIV.

In MODE 4, the steam generator energy is low.

In MODE 5 or 6, the steam generators do not contain much energy because their temperature is below the boiling point of water; therefore, the MSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

Wolf Creek - Unit 1 B 3.7.2-3 Revision 37

MSIVs B 3.7.2 BASES ACTIONS The LCO specifies OPERABILITY requirements for the MSIVs as well as for their associated actuator trains. The Conditions and Required Actions for TS 3.7.2 separately address inoperability of the MSIV actuator trains and inoperability of the MSIVs themselves.

A.1 With a single actuator train inoperable on one MSIV, action must be taken to restore the inoperable actuator train to OPERABLE status within 7 days. The 7-day Completion Time is reasonable in light of the dual-redundant actuator train design such that with one actuator train inoperable, the affected MSIV is still capable of closing on demand via the remaining OPERABLE actuator train. The 7-day Completion Time takes into account the redundant OPERABLE actuator train to the MSIV, reasonable time for repairs, and the low probability of an event occurring that requires the inoperable actuator train to the affected MSIV.

B.1 With an actuator train on one MSIV inoperable and an actuator train on an additional MSIV inoperable, such that the inoperable actuator trains are not in the same separation group, action must be taken to restore one of the inoperable actuator trains to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With two actuator trains inoperable on two MSIVs, there is an increased likelihood that an additional failure (such as the failure of an actuation logic train) could cause one MSIV to fail to close. The 72-hour Completion Time is reasonable since the dual-redundant actuator train design ensures that with only one actuator train on each of two affected MSIVs inoperable, each MSIV is still capable of closing on demand.

C.1 With an actuator train on one MSIV inoperable and an actuator train on an additional MSIV inoperable, but with both inoperable actuator trains in the same separation group, action must be taken to restore one of the inoperable actuator trains to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24-hour Completion Time provides a reasonable amount of time for restoring at least one actuator train since the dual-redundant actuator train design for each MSIV ensures that a single inoperable actuator train cannot prevent the affected MSIV(s) from closing on demand. With two actuator trains inoperable in the same separation group, an additional failure (such as the failure of an actuation logic train in the other separation group) could cause both affected MSIVs to fail to close on demand. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Wolf Creek - Unit 1 B 3.7.2-4 Revision 30

MSIVs B 3.7.2 BASES ACTIONS H.1 and H.2 (continued)

The 7 day Completion Time is reasonable, based on engineering judgment, in view of MSIV status indications available in the control room, and other administrative controls, to ensure that these valves are in the closed position.

1.1 and 1.2 If the MSIVs cannot be restored to OPERABLE status or are not closed within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed at least in 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 MODE 2 conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS This SR verifies that the closure time of each MSIV is within the limits of Figure B 3.7.2-1 from each actuator train when tested pursuant to the Inservice Testing Program. The MSIV isolation time is explicitly assumed in the accident analyses that credit the Steam Line Isolation. Figure B 3.2.7-1 is a curve of the MSIV isolation time limit as a function of steam generator pressure. The acceptance curve for the MSIV stroke time conservatively accounts for potential pressure differential between the steam generator pressure indication and the pressure at the MSIV. This Surveillance is normally performed upon returning the unit to operation following a refueling outage.

The Frequency is in accordance with the Inservice Testing Program.

This test can be conducted in MODE 3 with the unit at operating temperature and pressure. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

SR 3.7.2.2 This SR verifies that each actuator train can close its respective MSIV on an actual or simulated actuation signal. The manual fast close hand switch in the control room provides an acceptable actuation signal. This Surveillance is normally performed upon returning the plant to operation Wolf Creek - Unit 1 B 3.7.2-7 Revision 37

MSIVs B 3.7.2 BASES SURVEILLANCE SR 3.7.2.2 (continued)

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

The frequency of MSIV testing is every 18 months. The 18 month Frequency for testing is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section 10.3.

2. USAR, Section 6.2.

3. USAR, Section 15.1.5.

4. 10 CFR 100.11.

Wolf Creek - Unit 1 B 3.7.2-8 Revision 37 1

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Figure B 3.7.2-1 MSIV Isolation Time vs. Steam Generator Pressure Wolf Creek - Unit 1 B 3.7.2-9 Revision 37

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Wolf Creek - Unit 1 B 3.7.3-2 Revision 38

MFIVs and MFRVs and MFRV Bypass Valves I B 3.7.3 BASES APPLICABLE Criterion 3 of 10 CFR 50.36(c)(2)(ii) indicates that components that are SAFETY ANALYSIS part of the primary success path and that actuate to mitigate an event that (continued) presents a challenge to a fission product barrier should be in Technical Specifications. The primary success path of a safety sequence analysis consists of the combination and sequences of equipment needed to operate (including consideration of the single failure criteria) so that the plant response to the event remains within appropriate acceptance criteria. The primary success path does not include backup and diverse equipment. The MFIVs, with their dual-redundant actuators, are the primary success path for feedwater isolation; the MFRVs, MFRV bypass valves, and the SGFP trip are backup and diverse equipment. The MFIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). The MFRVs and MFRV bypass valves satisfy Criterion 4 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO ensures that the MFIVs and associated actuator trains, MFRVs and MFRV bypass valves will isolate MFW flow to the steam generators, following an FWLB or main steam line break. The MFIVs and associated actuator trains will also isolate the nonsafety related portions from the safety related portions of the system.

This LCO requires that each MFIV and its associated actuator trains, MFRV and MFRV bypass valve for the four main feedwater lines be OPERABLE. An MFIV actuator train is considered OPERABLE when it is capable of closing the associated MFIV on demand and within the required isolation time. The MFIVs are considered OPERABLE when isolation times are within the limits of Figure B 3.7.3-1 when given a fast close signal and they are capable of closing on an isolation actuation signal. The MFRVs and MFRV bypass valves are considered OPERABLE when isolation times are < 15 seconds when given an isolation actuation signal and they are capable of closing on an isolation actuation signal. For the MFRVs and the MFRV bypass valves, the LCO requires only that the trip close function is OPERABLE.

Failure to meet the LCO requirements can result in additional mass and energy being released to containment following an SLB or FWLB inside containment. A feedwater isolation signal on high steam generator level is relied on to terminate an excess feedwater flow event, and failure to meet the LCO may result in the introduction of water into the main steam lines.

APPLICABILITY The MFIVs, MFRVs and MFRV bypass valves must be OPERABLE whenever there is significant mass and energy in the Reactor Coolant System and steam generators. In MODES 1, 2, and 3, the MFIVs, MFRVs and MFRV bypass valves are required to be OPERABLE to Wolf Creek - Unit 1 B 3.7.3-3 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES APPLICABILITY perform their isolation function and limit the amount of available fluid that (continued) could be added to containment in the case of a secondary system pipe break inside containment. When the valves are closed, they are already performing their safety function. The MFIV actuator trains must be OPERABLE in MODES 1, 2, and 3 to support operation of the MFIV.

Exceptions to the Applicability are allowed where the valve is assured of performing its safety function as follows:

a. When the MFIV is closed and de-activated, it is performing is safety function. Requiring the valve closed and de-activated provides dual assurance that it is performing its safety function.

When the valve is de-activated, power is removed from the actuation solenoids on the valves.

b. When the MFRV is closed and de-activated or is closed and isolated by a closed manual valve, it is performing its safety function. Requiring the valve closed and de-activated provides dual assurance that it is performing its safety function. When the valve is de-activated, power is removed from the actuation solenoids on the valves. Requiring the valve closed and isolated by a closed manual valve also provides dual assurance that it is performing its safety function.

c. When the MFRV bypass valve is closed and de-activated, or is closed and isolated by a closed manual valve, or is isolated by two closed manual valves, it is performing its safety function.

Requiring the valve closed and de-activated provides dual assurance that it is performing its safety function. When the valve is de-activated, power is removed from the actuation solenoids on the valves. Requiring the valve closed and isolated by a closed manual valve also provides dual assurance that it is performing its safety function. Finally, there is dual assurance that the safety function is being performed when the MFRV bypass valve is isolated by two closed manual valves.

In MODES 4, 5, and 6, steam generator energy is low. Therefore, the MFIVs can be closed since MFW is not required.

ACTIONS The LCO specifies OPERABILITY requirements for the MFIVs as well as for their associated actuator trains, MFRVs and MFRV bypass valves.

The Conditions and Required Actions for TS 3.7.3 separately address inoperability of the MFIV actuator trains and inoperability of the MFIVs themselves.

Wolf Creek - Unit 1 B 3.7.3-4 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES ACTIONS A.1 (continued)

With a single actuator train inoperable on one MFIV, action must be taken to restore the inoperable actuator train to OPERABLE status within 7 days. The 7-day Completion Time is reasonable in light of the dual-redundant actuator train design such that with one actuator train inoperable, the affected MFIV is still capable of closing on demand via the remaining OPERABLE actuator train. The 7-day Completion Time takes into account the redundant OPERABLE actuator train to the MFIV, reasonable time for repairs, and the low probability of an event occurring that requires the inoperable actuator train to the affected MFIV.

B..1 With an actuator train on one MFIV inoperable and an actuator train on an additional MFIV inoperable, such that the inoperable actuator trains are not in the same separation group, action must be taken to restore one of the inoperable actuator trains to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With two actuator trains inoperable on two MFIVs, there is an increased likelihood that an additional failure (such as the failure of an actuation logic train) could cause one MFIV to fail to close. The 72-hour Completion Time is reasonable since the dual-redundant actuator train design ensures that with only one actuator train on each of two affected MFIVs inoperable, each MFIV is still capable of closing on demand.

C.1 With an actuator train on one MFIV inoperable and an actuator train on an additional MFIV inoperable, but with both inoperable actuator trains in the same separation group, action must be taken to restore one of the inoperable actuator trains to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24-hour Completion Time provides a reasonable amount of time for restoring at least one actuator train since the dual-redundant actuator train design for each MFIV ensures that a single inoperable actuator train cannot prevent the affected MFIV(s) from closing on demand. With two actuator trains inoperable in the same separation group, an additional failure (such as the failure of an actuation logic train in the other separation group) could cause both affected MFIVs to fail to close on demand. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into the redundant OPERABLE actuator trains to the affected MFIVs and the low probability of an event occurring that requires the inoperable actuator trains to the affected MFIVs.

Wolf Creek - Unit 1 B 3.7.3-5 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves I B 3.7.3 BASES ACTIONS D.1 (continued)

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

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

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

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

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

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

With one MFIV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed, they are performing their required safety function. Condition F is entered when one or more MFIV is inoperable, including when both actuator trains for one MFIV are inoperable. When only one actuator train is inoperable on one MFIV, Condition A applies.

Wolf Creek - Unit 1 B 3.7.3-6 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES ACTIONS F.1 and F.2 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the dual-redundant actuators on the MFIVs, the redundancy afforded by the remaining OPERABLE valves, and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

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

G.1 and G.2 With one MFRV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

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

H.1 and H.2 With one MFRV bypass valve in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . When these valves are closed or isolated, they are performing their required safety function.

Wolf Creek - Unit 1 B 3.7.3-7 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves I B 3.7.3 BASES ACTIONS H.1 and H.2 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

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

1.1 and 1.2 Two inoperable valves in the-same flow path is treated the same as a loss of the isolation capability of this flow path. For each feedwater line there are two flow paths, defined as flow through the MFRV/MFIV and flow through the MFRV bypass valves/MFIV. Because the MFIV, MFRV, and MFRV bypass valve are of different designs, a common mode failure of the valves in the same flow path is not likely. However, under these conditions, affected valves in each flow path must be restored to OPERABLE status, or the affected flow path isolated with 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This action returns the system to the condition where at least one valve in each flow path is performing the required safety function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to complete the actions required to close the MFIV or MFRV and MFRV bypass valve, or otherwise isolate the affected flow path.

J.1 and J.2 If the MFIV(s) and MFRVs and MFRV bypass valves cannot be restored to OPERABLE status, or closed, within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

Wolf Creek - Unit 1 B 3.7.3-8 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that the closure time of each MFIV, MFRV, and MFRV bypass valve is within limits (Figure B 3.7.3-1 for the MFIVs and < 15 seconds for the MFRV and MFRV bypass valves) when tested pursuant to the Inservice Testing Program. The MFIV, MFRV, and MFRV bypass valve closure time is assumed in the accident and containment analyses.

This Surveillance is normally performed upon returning the unit to operation following a refueling outage. This is consistent with Regulatory Guide 1.22 (Ref. 3). The Surveillance may be performed as required for post-maintenance testing of the MFRVs and MFRV bypass valves under appropriate conditions during applicable MODES. In particular, the MFRVs should normally not be tested at power since even a partial stroke exercise increases the risk of a valve closure with the unit generating power. However, when the plant is operating using the MFRV bypass valves (at low power levels during MODE 1), the surveillance for the MFRVs may be performed for post-maintenance testing during such conditions without increasing plant risk.

If it is necessary to adjust stem packing to stop packing leakage and ifa required stroke test is not practical in the current plant MODE, it should be shown by analysis that the packing adjustment is within torque limits specified by the manufacturer for the existing configuration of packing, and that the performance parameters of the valve are not adversely affected. A confirmatory test must be performed at the first available opportunity when plant conditions allow testing. Packing adjustments beyond the manufacturer's limits may not be performed without (1) an engineering analysis and (2) input from the manufacturer, unless tests can be performed after the adjustments. (Reference 4)

The Frequency for this SR is in accordance with the Inservice Testing Program. Operating experience has shown that these components usually pass the Surveillance when performed at the Inservice Testing Program Frequency. This test is normally conducted in MODE 3 with the unit at nominal operating temperature and pressure, as discussed in Reference 2. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

SR 3.7.3.2 This SR verifies that each actuator train can close its respective MFIV on an actual or simulated actuation signal. The manual close hand switch in the control room provides an acceptable actuation signal. This Wolf Creek - Unit 1 B 3.7.3-9 Revision 37

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 BASES SURVEILLANCE SR 3.7.3.2 (continued)

REQUIREMENTS Surveillance is normally performed upon returning the plant to operation following a refueling outage in conjunction with SR 3.7.3.1. However, it is acceptable to perform this Surveillance individually. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated The Frequency of MFIV testing is every 18 months. The 18 month Frequency for testing is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability standpoint.

SR 3.7.3.3 This SR verifies that each MFRV and MFRV bypass valve is capable of closure on an actual or simulated actuation signal. The actuation of solenoids locally at the MFRVs and MFRV bypass valves constitutes an acceptable simulated actuation signal. This Surveillance is normally performed upon returning the unit to operation following a refueling outage in conjunction with SR 3.7.3.1. However, it is acceptable to perform this Surveillance individually.

The Frequency of MFRV and MFRV bypass valve testing is every 18 months. The 18 month Frequency for testing is based on the refueling cycle. This Frequency is acceptable from a reliability standpoint. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

REFERENCES 1. USAR, Section 10.4.7.

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

3. Regulatory Guide 1.22, Rev. 0.

4. NUREG-1482, Revision 1, "Guidelines for Inservice Testing at Nuclear Power Plants."

Wolf Creek - Unit 1 B 3.7.3-10 Revision 38

MFIVs and MFRVs and MFRV Bypass Valves B 3.7.3 40

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Figure B 3.7.3-1 MFIV Isolation Time Limit vs. Steam Generator Pressure Wolf Creek - Unit 1 B 3.7.3-11 Revision 37

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

The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature on the other train (Train A or Train B) is inoperable and not in the safeguards position.

If at any time during the existence of this Condition (one DG inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-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.

B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DG. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on the other DG, it would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on Wolf Creek - Unit 1 B 3.8.1-9 Revision 26 1

AC Sources - Operating B 3.8.1 BASES ACTIONS B.3.1 and B.3.2 (continued) the remaining DG, performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG. Required Action B.3.2 is modified by a Note stating that it is satisfied by the automatic start and sequence loading of the DG. The Note indicates that an additional start of the DG for test purposes only, is not required if the DG has automatically started and loaded following a loss of the offsite power source to its respective bus (Ref. 18).

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE DG is not affected by the same problem as the inoperable DG.

B.4.1, B.4.2.1, and B.4.2.2 In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. With a DG inoperable, the inoperable DG must be restored to OPERABLE status within the applicable, specified Completion Time.

The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months for Required Action B.4.1 applies when a DG is discovered or determined to be inoperable, such as due to a component or test failure, and requires time to effect repairs, or it may apply when a DG is rendered inoperable for the performance of maintenance during applicable MODES. The 72-hour Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA during this period.

The second Completion Time for Required Action B.4.1 also establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . If the offsite circuit is restored to OPERABLE status within the required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , this could lead to a total of 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 compliance with the LCO (i.e.,

restore the DG). At this time, an offsite circuit could again become inoperable and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months allowed prior to complete Wolf Creek - Unit 1 B 3.8.1 -10 Revision 39

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

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

The Required Actions are modified by a Note that states that Required Actions B.4.2.1 and B.4.2.2 are only applicable for voluntary planned maintenance and may be used once per cycle per DG. Required Actions B.4.2.1 and B.4.2.2 only applies when a DG is declared or rendered inoperable for the performance of voluntary, planned maintenance activities. Required Action B.4.2.1 provides assurance that the required Sharpe Station gensets are available when a DG is out of service for greater than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The availability of the required gensets are verified once perl2 hours by locally monitoring various genset parameters.

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

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

Wolf Creek - Unit 1 B 3.8.1 -11 Revision 36

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

b. The offsite power supply and switchyard condition are conducive to an extended DG Completion Time, which includes ensuring that switchyard access is restricted and no elective maintenance within the switchyard is performed that would challenge offsite power availability.

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

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

Auxiliary Feedwater System (three trains)

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

" Essential Service Water System (both trains)

" Emergency Core Cooling System (two trains).

If, while Required Action B.4.2.2 is being used, one (or more) of the above systems or components is determined or discovered to be inoperable, or if an emergent condition affecting DG OPERABILITY is identified, re-entry into Required Action B.2 and B.3 would be required, as applicable. In addition, the effect on plant risk would be assessed and any additional or compensatory actions taken, in accordance with the plant's program for implementation of 10 CFR 50.65(a)(4). The 7-day Completion Time would remain in effect for the DG if Required Action B.2 and B.3 are satisfied.

Wolf Creek - Unit 1 B 3.8.1-12 Revision 35

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.7 REQUIREMENTS See SR 3.8.1.2.

SR 3.8.1.8 Not Used.

SR 3.8.1.9 Not Used.

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

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

In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, testing must be performed using a power factor _> 0.8 and < 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.

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

Wolf Creek - Unit 1 B 3.8.1-23 Revision 40

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

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

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

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

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

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

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

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

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

2. USAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3.

4. USAR, Chapter 6.

5. USAR, Chapter 15.

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

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

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

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

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

11. ANSI C84.1-1982.

12. IEEE Standard 308-1978.

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

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

15. Performance Improvement Request 2005-3184.

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

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

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

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

(continued)

Wolf Creek - Unit 1 B 3.8.1-34 Revision 39

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

IMPLEMENTED (4)

TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents i 0 Amend. No. 123 12/18/99 ii 29 DRR 06-1984 10/17/06 iii 37 DRR 08-0503 4/8/08 TAB - B 2.0 SAFETY LIMITS (SLs)

B 2.1.1-1 0 Amend. No. 123 12/18/99 B 2.1.1-2 14 DRR 03-0102 2/12/03 B 2.1.1-3 14 DRR 03-0102 2/12/03.

B 2.1.1-4 14 DRR 03-0102 2/12/03 B 2.1.2-1 0 Amend. No. 123 12/18/99 B 2.1.2-2 12 DRR 02-1062 9/26/02 B 2.1.2-3 0 Amend. No. 123 12/18/99 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY B 3.0-1 34 DRR 07-1057 7/10/07 B 3.0-2 0 Amend. No. 123 12/18/99 B 3.0-3 0 Amend. No. 123 12/18/99 B 3.0-4 19 DRR 04-1414 10/12/04 B 3.0-5 19 DRR 04-1414 10/12104 B 3.0-6 19 DRR 04-1414 10/12/04 B 3.0-7 19 DRR 04-1414 10/12/04 B 3.0-8 19 DRR 04-1414 10/12/04 B 3.0-9 34 DRR 07-1057 7/10/07 B 3.0-10 34 DRR 07-1057 7/10/07 B 3.0-11 34 DRR 07-1057 7/10/07 B 3.0-12 34 DRR 07-1057 7/10/07 B 3.0-13 34 DRR 07-1057 7/10/07 B 3.0-14 34 DRR 07-1057 7/10/07 B 3.0-15 34 DRR 07-1057 7/10/07 B 3.0-16 34 DRR 07-1057 7/10/07 TAB - B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1-1 0 Amend. No. 123 12/18/99 B 3.1.1-2 0 Amend. No. 123 12/18/99 B 3.1.1-3 0 Amend. No. 123 12/18/99 B 3.1.1-4 19 DRR 04-1414 10/12/04 B 3.1.1-5 0 Amend. No. 123 12/18/99 B 3.1.2-1 0 Amend. No. 123 12/18/99 B 3.1.2-2 0 Amend. No. 123 12/18/99 B 3.1.2-3 0 Amend. No. 123 12/18/99 B 3.1.2-4 0 Amend. No. 123 12/18/99 B 3.1.2-5 0 Amend. No. 123 12/18/99 B 3.1.3-1 0 Amend. No. 123 12/18/99 B 3.1.3-2 0 Amend. No. 123 12/18/99 B 3.1.3-3 0 Amend. No. 123 12/18/99 B 3.1.3-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 Revision40

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

IMPLEMENTED (4)

TAB - B 3.1 REACTIVITY CONTROL SYSTEMS (continued)

B 3.1.3-5 0 Amend. No. 123 12/18/99 B 3.1.3-6 0 Amend. No. 123 12/18/99 B 3.1.4-1 0 Amend. No. 123 12/18/99 B 3.1.4-2 0 Amend. No. 123 12/18/99 B 3.1.4-3 0 Amend. No. 123 12/18/99 B 31.4-4 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 12/18/99 B 3.2.1-3 0 Amend. No. 123 12/18/99 B 3.2.1-4 0 Amend. No. 123 12/18/99 B 3.2.1-5 1 DRR 99-1624 12/18/99 B 3.2.1-6 12 DRR 02-1062 9/26/02 B 3.2.1-7 0 Amend. No. 123 12/18/99 B 3.2.1-8 29 DRR 06-1984 10/17/06 B 3.2.1-9 29 DRR 06-1984 10/17/06 B 3.2.1-10 29 DRR 06-1984 10/17/06 B 3.2.2-1 0 Amend. No. 123 12/18/99 B 3.2.2-2 0 Amend. No. 123 12/18/99 B 3.2.2-3 0 Amend. No. 123 12/18/99 B 3.2.2-4 0 Amend. No. 123 12/18/99 B 3.2.2-5 0 Amend. No. 123 12/18/99 B 3.2.2-6 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 ii Revision40

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TAB - B 3.2 POWER DISTRIBUTION LIMITS (continued)

B 3.2.3-1 0 Amend. No. 123 12/18/99 B 3.2.3-2 0 Amend. No. 123 12/18/99 B 3.2.3-3 0 Amend. No. 123 12/18/99 B 3.2.4-1 0 Amend. No. 123 12/18/99 B 3.2.4-2 0 Amend. No. 123 12/18/99 B 3.2.4-3 0 Amend. No. 123 12/18/99 B 3.2.4-4 0 Amend. No. 123 12/18/99 B 3.2.4-5 0 Amend. No. 123 12/18/99 B 3.2.4-6 0 Amend. No. 123 12/18/99 B 3.2.4-7 0 Amend. No. 123 12/18/99 TAB - B 3.3 INSTRUMENTATION B 3.3.1-1 0 Amend. No. 123 12/18/99 B 3.3.1-2 0 Amend. No. 123 12/18/99 B 3.3.1-3 0 Amend. No. 123 12/18/99 B 3.3.1-4 0 Amend. No. 123 12/18/99 B 3.3.1-5 0 Amend. No. 123 12/18/99 B 3.3.1-6 0 Amend. No. 123 12/18/99 B 3.3.1-7 5 DRR 00-1427 10/12/00 B 3.3.1-8 0 Amend. No. 123 12/18/99 B 3.3.1-9 0 Amend. No. 123 12/18/99 B 3.3.1-10 29 DRR 06-1984 10/17/06 B 3.3.1-11 0 Amend. No. 123 12/18/99 B 3.3.1-12 0 Amend. No. 123 12/18/99 B 3.3.1-13 0 Amend. No. 123 12/18/99 B 3.3.1-14 0 Amend. No. 123 12/18/99 B 3.3.1-15 0 Amend. No. 123 12/18/99 B 3.3.1-16 0 Amend. No. 123 12/18/99 B 3.3.1-17 0 Amend. No. 123 12/18/99 B 3.3.1-18 0 Amend. No. 123 12/18/99 B 3.3.1-19 0 Amend. No. 123 12/18/99 B 3.3.1-20 0 Amend. No. 123 12/18/99 B 3.3.1-21 0 Amend. No. 123 12/18/99 B 3.3.1-22 0 Amend. No. 123 12/18/99 B 3.3.1-23 9 DRR 02-0123 2/28/02 B 3.3.1-24 0 Amend. No. 123 12/18/99 B 3.3.1-25 0 Amend. No. 123 12/18/99 B 3.3.1-26 0 Amend. No. 123 12/18/99 B 3.3.1-27 0 Amend. No. 123 12/18/99 B 3.3.1-28 2 DRR 00-0147 4/24/00 B 3.3.1-29 1 DRR 99-1624 12/18/99 B 3.3.1-30 1 DRR 99-1624 12/18/99 B 3.3.1-31 0 Amend. No. 123 12/18/99 B 3.3.1-32 20 DRR 04-1533 2/16/05 B 3.3.1-33 20 DRR 04-1533 2/16/05 B 3.3.1-34 20 DRR 04-1533 2/16/05 B 3.3.1-35 20 DRR 04-1533 2/16/05 B 3.3.1-36 20 DRR 04-1533 2/16/05 B 3.3.1-37 20 DRR 04-1533 2/16/05 B 3.3.1-38 20 DRR 04-1533 2/16/05 B 3.3.1-39 25 DRR 06-0800 5/18/06 Wolf Creek - Unit 1 iii Re~vision40)

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.1-40 20 DRR 04-1533 2/16/05 B 3.3.1-41 20 DRR 04-1533 2/16/05 B 3.3.1-42 20 DRR 04-1533 2/16/05 B 3.3.1-43 20 DRR 04-1533 2/16/05 B 3.3.1-44 20 DRR 04-1533 2/16/05 B 3.3.1-45 20 DRR 04-1533 2/16/05 B 3.3.1-46 20 DRR 04-1533 2/16/05 B 3.3.1-47 20 DRR 04-1533 2/16/05 B 3.3.1-48 20 DRR 04-1533 2/16/05 B 3.3.1-49 20 DRR 04-1533 2/16/05 B 3.3.1-50 20 DRR 04-1533 2/16/05 B 3.3.1-51 21 DRR 05-0707 4/20/05 B 3.3.1-52 20 DRR 04-1533 2/16/05 B 3.3.1-53 20 DRR 04-1533 2/16/05 B 3.3.1-54 20 DRR 04-1533 2/16/05 B 3.3.1-55 25 DRR 06-0800 5/18/06 B 3.3.1-56 20 DRR 04-1533 2/16/05 B 3.3.1-57 20 DRR 04-1533 2/16/05 B 3.3.1-58 29 DRR 06-1984 10/17/06 B 3.3.1-59 20 DRR 04-1533 2/16/05 B 3.3.2-1 0 Amend. No. 123 12/18/99 B 3.3.2-2 0 Amend. No. 123 12/18/99 B 3.3.2-3 0 Amend. No. 123 12/18/99 B 3.3.2-4 0 Amend. No. 123 12/18/99 B 3.3.2-5 0 Amend. No. 123 12/18/99 B 3.3.2-6 7 DRR 01-0474 5/1/01 B 3.3.2-7 0 Amend. No. 123 12/18/99 B 3.3.2-8 0 Amend. No. 123 12/18/99 B 3.3.2-9 0 Amend. No. 123 12/18/99 B 3.3.2-10 0 Amend. No. 123 12/18/99 B 3.3.2-11 0 Amend. No. 123 12/18/99 B 3.3.2-12 0 Amend. No. 123 12/18/99 B 3.3.2-13 0 Amend. No. 123 12/18/99 B 3.3.2-14 2 DRR 00-0147 4/24/00 B 3.3.2-15 0 Amend. No. 123 12/18/99 B 3.3.2-16 0 Amend. No. 123 12/18/99 B 3.3.2-17 0 Amend. No. 123 12/18/99 B 3.3.2-18 0 Amend. No. 123 12/18/99 B 3.3.2-19 37 DRR 08-0503 4/8/08 B 3.3.2-20 37 DRR 08-0503 4/8/08 B 3.3.2-21 37 DRR 08-0503 4/8/08 B 3.3.2-22 37 DRR 08-0503 4/8/08 B 3.3.2-23 37 DRR 08-0503 4/8/08 B 3.3.2-24 39 DRR 08-1096 8/28/08 B 3.3.2-25 39 DRR 08-1096 8/28/08 B 3.3.2-26 39 DRR 08-1096 8/28/08 B 3.3.2-27 37 DRR 08-0503 4/8/08 B 3.3.2-28 37 DRR 08-0503 4/8/08 B 3.3.2-29 0 Amend. No. 123 12/18/99 B 3.3.2-30 0 Amend. No. 123 12/18/99 B 3.3.2-31 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 iv Revision40

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-32 0 Amend. No. 123 12/18/99 B 3.3.2-33 0 Amend. No. 123 12/18/99 B 3.3.2-34 0 Amend. No. 123 12/18/99 B 3.3.2-35 20 DRR 04-1533 2/16/05 B 3.3.2-36 20 DRR 04-1533 2/16/05 B 3.3.2-37 20 DRR 04-1533 2/16/05 B 3.3.2-38 20 DRR 04-1533 2/16/05 B 3.3.2-39 25 DRR 06-0800 5/18/06 B 3.3.2-40 20 DRR 04-1533 2/16/05 B 3.3.2-41 37 DRR 08-0503 4/8/08 B 3.3.2-42 20 DRR 04-1533 2/16/05 B 3.3.2-43 20 DRR 04-1533 2/16/05 B 3.3.2-44 20 DRR 04-1533 2/16/05 B 3.3.2-45 20 DRR 04-1533 2/16/05 B 3.3.2-46 20 DRR 04-1533 2/16/05 B 3.3.2-47 37 DRR 08-0503 4/8/08 B 3.3.2-48 37 DRR 08-0503 4/8/08 B 3.3.2-49 20 DRR 04-1533 2/16/05 B 3.3.2-50 20 DRR 04-1533 2/16/05 B 3.3.2-51 20 DRR 04-1533 2/16/05 B 3.3.2-52 20 DRR 04-1533 2/16/05 B 3.3.2-53 25 DRR 06-0800 5/18/06 B 3.3.2-54 37 DRR 08-0503 4/8/08 B 3.3.2-55 37 DRR 08-0503 4/8/08 B 3.3.2-56 37 DRR 08-0503 4/8/08 B 3.3.2-57 37 DRR 08-0503 4/8/08 B 3.3.2-58 20 DRR 04-1533 2/16/05 B 3.3.3-1 0 Amend. No. 123 12/18/99 B 3.3.3-2 5 DRR 00-1427 10/12/00 B 3.3.3-3 0 Amend. No. 123 12/18/99 B 3.3.3-4 0 Amend. No. 123 12/18/99 B 3.3.3-5 0 Amend. No. 123 12/18/99 B 3.3.3-6 8 DRR 01-1235 9/19/01 B 3.3.3-7 21 DRR 05-0707 4/20/05 B 3.3.3-8 8 DRR 01-1235 9/19/01 B 3.3.3-9 8 DRR 01-1235 9/19/01 B 3.3.3-10 19 DRR 04-1414 10/12/04 B 3.3.3-11 19 DRR 04-1414 10/12/04 B 3.3.3-12 21 DRR 05-0707 4/20/05 B 3.3.3-13 21 DRR 05-0707 4/20/05 B 3.3.3-14 8 DRR 01-1235 9/19/01 B 3.3.3-15 8 DRR 01-1235 9/19/01 B 3.3.4-1 0 Amend. No. 123 12/18/99 B 3.3.4-2 9 DRR 02-1023 2/28/02 B 3.3.4-3 15 DRR 03-0860 7/10/03 B 3.3.4-4 19 DRR 04-1414 10/12/04 B 3.3.4-5 1 DRR 99-1624 12/18/99 B 3.3.4-6 9 DRR 02-0123 2/28/02 B 3.3.5-1 0 Amend. No. 123 12/18/99 B 3.3.5-2 1 DRR 99-1624 12/18/99 B 3.3.5-3 1 DRR 99-1624 12/18/99 Wolf Creek - Unit 1 V Revision40

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TAB - B 3.3 INSTRUMENTATION (continued)

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

B 3.4.1-1 0 Amend. No. 123 12/18/99 B 3.4.1-2 10 DRR 02-0411 4/5/02 B 3.4.1-3 10 DRR 02-0411 4/5/02 B 3.4.1-4 0 Amend. No. 123 12/18/99 B 3.4.1-5 0 Amend. No. 123 12/18/99 B 3.4.1-6 0 Amend. No. 123 12/18/99 B 3.4.2-1 0 Amend. No. 123 12/18/99 B 3.4.2-2 0 Amend. No. 123 12/18/99 B 3.4.2-3 0 Amend. No. 123 12/18/99 B 3.4.3-1 0 Amend. No. 123 12/18/99 B 3.4.3-2 0 Amend. No. 123 12/18/99 B 3.4.3-3 0 Amend. No. 123 12/18/99 B 3.4.3-4 0 Amend. No. 123 12/18/99 B 3.4.3-5 0 Amend. No. 123 12/18/99 B 3.4.3-6 0 Amend. No. 123 12/18/99 B 3.4.3-7 0 Amend. No. 123 12/18/99 B 3.4.4-1 0 Amend. No. 123 12/18/99 B 3.4.4-2 29 DRR 06-1984 10/17/06 B 3.4.4-3 0 Amend. No. 123 12/18/99 B 3.4.5-1 0 Amend. No. 123 12/18/99 B 3.4.5-2 17 DRR 04-0453 5/26/04 B 3.4.5-3 29 DRR 06-1984 10/17/06 B 3.4.5-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vi Revision40

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

B 3.4.5-5 12 DRR 02-1062 9/26/02 B 3.4.6-1 17 DRR 04-0453 5/26/04 B 3.4.6-2 29 DRR 06-1984 10/17/06 B 3.4.6-3 12 DRR 02-1062 9/26/02 B 3.4.6-4 12 DRR 02-1062 9/26/02 B 3.4.6-5 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 29 DRR 06-1984 10/17/06 B 3.4.7-4 12 DRR 02-1062 9/26/02 B 3.4.7-5 12 DRR 02-1062 9/26/02 B 3.4.8-1 17 DRR 04-0453 5/26/04 B 3.4.8-2 19 DRR 04-1414 10/12/04 B 3.4.8-3 12 DRR 02-1062 9/26/02 B 3.4.8-4 12 DRR 02-1062 9/26/02 B 3.4.9-1 0 Amend. No. 123 12/18/99 B 3.4.9-2 0 Amend. No. 123 12/18/99 B 3.4.9-3 0 Amend. No. 123 12/18/99 B 3.4.9-4 0 Amend. No. 123 12/18/99 B 3.4.10-1 5 DRR 00-1427 10/12/00 B 3.4.10-2 5 DRR 00-1427 10/12/00 B 3.4.10-3 0 Amend. No. 123 12/18/99 B 3.4.10-4 32 DRR 07-0139 2/7/07 B 3.4.11-1 0 Amend. No. 123 12/18/99 B 3.4.11-2 1 DRR 99-1624 12/18/99 B 3.4.11-3 19 DRR 04-1414 10/12/04 B 3.4.11-4 0 Amend. No. 123 12/18/99 B 3.4.11-5 1 DRR 99-1624 12/18/99 B 3.4.11-6 0 Amend. No. 123 12/18/99 B 3.4.11-7 32 DRR 07-0139 2/7/07 B 3.4.12-1 1 DRR 99-1624 12/18/99 B 3.4.12-2 1 DRR 99-1624 12/18/99 B 3.4.12-3 0 Amend. No. 123 12/18/99 B 3.4.12-4 1 DRR 99-1624 12/18/99 B 3.4.12-5 1 DRR 99-1624 12/18/99 B 3.4.12-6 1 DRR 99-1624 12/18/99 B 3.4.12-7 0 Amend. No. 123 12/18/99 B 3.4.12-8 1 DRR 99-1624 12/18/99 B 3.4.12-9 19 DRR 04-1414 10/12/04 B 3.4.12-10 0 Amend. No. 123 12/18/99 B 3.4.12-11 0 Amend. No. 123 12/18/99 B 3.4.12-12 32 DRR 07-0139 2/7/07 B 3.4.12-13 0 Amend. No. 123 12/18/99 B 3.4.12-14 32 DRR 07-0139 2/7/07 B 3.4.13-1 0 Amend. No. 123 12/18/99 B 3.4.13-2 29 DRR 06-1984 10/17/06 B 3.4.13-3 29 DRR 06-1984 10/17/06 B 3.4.13-4 35 DRR 07-1553 9/28/07 B 3.4.13-5 35 DRR 07-1553 9/28/07 B 3.4.13-6 29 DRR 06-1984 10/17/06 B 3.4.14-1 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vii ReAsion40

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(4)

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

B 3.4.14-2 0 Amend. No. 123 12/18/99 B 3.4.14-3 0 Amend. No. 123 12/18/99 B 3.4.14-4 0 Amend. No. 123 12/18/99 B 3.4.14-5 32 DRR 07-0139 2/7/07 B 3.4.14-6 32 DRR 07-0139 2/7/07 B 3.4.15-1 31 DRR 06-2494 12/13/06 B 3.4.15-2 31 DRR 06-2494 12/13/06 B 3.4.15-3 33 DRR 07-0656 5/1/07 B 3.4.15-4 33 DRR 07-0656 5/1/07 B 3.4.15-5 31 DRR 06-2494 12/13/06 B 3.4.15-6 31 DRR 06-2494 12/13/06 B 3.4.15-7 31 DRR 06-2494 12/13/06 B 3.4.15-8 31 DRR 06-2494 12/13/06 B 3.4.16-1 31 DRR 06-2494 12/13/06 B 3.4.16-2 31 DRR 06-2494 12/13/06 B 3.4.16-3 31 DRR 06-2494 12/13/06 B 3.4.16-4 31 DRR 06-2494 12/13/06 B 3.4.16-5 31 DRR 06-2494 12/13/06 B 3.4.17-1 29 DRR 06-1984 10/17/06 B 3.4.17-2 37 DRR 08-0503 4/8/08 B 3.4.17-3 29 DRR 06-1984 10/17/06 B 3.4.17-4 29 DRR 06-1984 10/17/06 B 3.4.17-5 29 DRR 06-1984 10/17/06 B 3.4.17-6 29 DRR 06-1984 10/17/06 B 3.4.17-7 37 DRR 08-0503 4/8/08 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 38 DRR 08-0624 5/1/08 B 3.5.2-9 38 DRR 08-0624 5/1/08 B 3.5.2-10 33 DRR 07-0656 5/11/07 B 3.5.3-1 16 DRR 03-1497 11/4/03 B 3.5.3-2 19 DRR 04-1414 10/12/04 B 3.5.3-3 19 DRR 04-1414 10/12/04 B 3.5.3-4 16 DRR 03-1497 11/4/03 B 3.5.4-1 0 Amend. No. 123 12/18/99 B 3.5.4-2 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 viii Re\4sion40

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

B 3.5.4-3 0 Amend. No. 123 12/18/99 B 3.5.4-4 0 Amend. No. 123 12/18/99 B 3.5.4-5 0 Amend. No. 123 12/18/99 B 3.5.4-6 26 DRR 06-1350 7/24/06 B 3.5.5-1 21 DRR 05-0707 4/20/05 B 3.5.5-2 21 DRR 05-0707 4/20/05 B 3.5.5-3 2 Amend. No. 132 4/24/00 B 3.5.5-4 21 DRR 05-0707 4/20/05 TAB - B 3.6 CONTAINMENT SYSTEMS B 3.6.1-1 0 Amend. No. 123 12/18/99 B 3.6.1-2 0 Amend. No. 123 12/18/99 B 3.6.1-3 0 Amend. No. 123 12/18/99 B 3.6.1-4 17 DRR 04-0453 5/26/04 B 3.6.2-1 0 Amend. No. 123 12/18/99 B 3.6.2-2 0 Amend. No. 123 12/18/99 B 3.6.2-3 0 Amend. No. 123 12/18/99 B 3.6.2-4 0 Amend. No. 123 12/18/99 B 3.6.2-5 0 Amend. No. 123 12/18/99 B 3.6.2-6 0 Amend. No. 123 12/18/99 B 3.6.2-7 0 Amend. No. 123 12/18/99 B 3.6.3-1 0 Amend. No. 123 12/18/99 B 3.6.3-2 0 Amend. No. 123 12/18/99 B 3.6.3-3 0 Amend. No. 123 12/18/99 B 3.6.3-4 0 Amend. No. 123 12/18/99 B 3.6.3-5 36 DRR 08-0255 3/11/08 B 3.6.3-6 36 DRR 08-0255 3/11/08 B 3.6.3-7 36 DRR 08-0255 3/11/08 B 3.6.3-8 36 DRR 08-0255 3/11/08 B 3.6.3-9 36 DRR 08-0255 3/11/08 B 3.6.3-10 36 DRR 08-0255 3/11/08 B 3.6.3-11 36 DRR 08-0255 3/11/08 B 3.6.3-12 36 DRR 08-0255 3/11/08 B 3.6.3-13 36 DRR 08-0255 3/11/08 B 3.6.3-14 36 DRR 08-0255 3/11/08 B 3.6.3-15 39 DRR 08-1096 8/28/08 B 3.6.3-16 39 DRR 08-1096 8/28/08 B 3.6:3-17 36 DRR 08-0255 3/11/08 B 3.6.3-18 36 DRR 08-0255 3/11/08 B 3.6.3-19 36 DRR 08-0255 3/11/08 B 3.6.4-1 39 DRR 08-1096 8/28/08 B 3.6.4-2 0 Amend. No. 123 12/18/99 B 3.6.4-3 0 Amend. No. 123 12/18/99 B 3.6.5-1 0 Amend. No. 123 12/18/99 B 3.6.5-2 37 DRR 08-0503 4/8/08 B 3.6.5-3 13 DRR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12/18/99 B 3.6.6-1 0 Amend. No. 123 12/18/99 B 3.6.6-2 0 Amend. No. 123 12/18/99 B 3.6.6-3 37 DRR 08-0503 4/8/08 B 3.6.6-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 ix Revision40

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TAB - B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.6-5 0 Amend. No. 123 12/18/99 B 3.6.6-6 18 DRR 04-1018 9/1/04 B 3.6.6-7 0 Amend. No. 123 12/18/99 B 3.6.6-8 32 DRR 07-0139 2/7/07 B 3.6.6-9 32 DRR 07-0139 2/7/07 B 3.6.7-1 0 Amend. No. 123 12/18/99 B 3.6.7-2 0 Amend. No. 123 12/18/99 B 3.6.7-3 0 Amend. No. 123 12/18/99 B 3.6.7-4 29 DRR 06-1984 10/17/06 B 3.6.7-5 29 DRR 06-1984 10/17/06 B 3.6.8-1 0 Amend. No. 123 12/18/99 B 3.6.8-2 0 Amend. No. 123 12/18/99 B 3.6.8-3 19 DRR 04-1414 10/12/04 B 3.6.8-4 0 Amend. No. 123 12/18/99 B 3.6.8-5 0 Amend. No. 123 12118/99 TAB - B 3.7 PLANT SYSTEMS B 3.7.1-1 0 Amend. No. 123 12/18/99 B 3.7.1-2 0 Amend. No. 123 12/18/99 B 3.7.1-3 0 Amend. No. 123 12/18/99 B 3.7.1-4 0 Amend. No. 123 12/18/99 B 3.7.1-5 32 DRR 07-0139 2/7/07 B 3.7.1-6 32 DRR 07-0139 2/7/07 B 3.7.2-1 37 DRR 08-0503 4/8/08 B 3.7.2-2 37 DRR 08-0503 4/8/08 B 3.7.2-3 37 DRR 08-0503 4/8/08 B 3.7.2-4 30 DRR 06-2329 11/8/06 B 3.7.2-5 30 DRR 06-2329 11/8/06 B 3.7.2-6 30 DRR 06-2329 11/8/06 B 3.7.2-7 37 DRR 08-0503 4/8/08 B 3.7.2-8 37 DRR 08-0503 4/8/08 B 3.7.2-9 37 DRR 08-0503 4/8/08 B 3.7.3-1 37 DRR 08-0503 4/8/08 B 3.7.3-2 38 DRR 08-0624 5/1/08 B 3.7.3-3 37 DRR 08-0503 4/8/08 B 3.7.3-4 37 DRR 08-0503 4/8/08 B 3.7.3-5 37 DRR 08-0503 4/8/08 B 3.7.3-6 37 DRR 08-0503 4/8/08 B 3.7.3-7 37 DRR 08-0503 4/8/08 B 3.7.3-8 37 DRR 08-0503 4/8/08 B 3.7.3-9 37 DRR 08-0503 4/8/08 B 3.7.3-10 38 DRR 08-0624 5/11/08 B 3.7.3-11 37 DRR 08-0503 4/8/08 B 3.7.4-1 1 DRR 99-1624 12/18/99 B 3.7.4-2 1 DRR 99-1624 12/18/99 B 3.7.4-3 19 DRR 04-1414 10/12/04 B 3.7.4-4 19 DRR 04-1414 10/12/04 B 3.7.4-5 1 DRR 99-1624 12/18/99 B 3.7.5-1 0 Amend. No. 123 12/18/99 B 3.7.5-2 0 Amend. No. 123 12/18/99 B 3.7.5-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 X Revtision40

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TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.5-4 26 DRR 06-1350 7/24/06 B 3.7.5-5 19 DRR 04-1414 10/12/04 B 3.7.5-6 19 DRR 04-1414 10/12/04 B 3.7.5-7 32 DRR 07-0139 2/7/07 B 3.7.5-8 14 DRR 03-0102 2/12/03 B 3.7.5-9 32 DRR 07-0139 2/7/07 B 3.7.6-1 0 Amend. No. 123 12/18/99 B 3.7.6-2 0 Amend. No. 123 12/18/99 B 3.7.6-3 0 Amend. No. 123 12/18/99 B 3.7.7-1 0 Amend. No. 123 12/18/99 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 B 3.7.10-5 0 Amend. No. 123 12/18/99 B 3.7.10-6 0 Amend. No. 123 12/18/99 B 3.7.10-7 0 Amend. No. 123 12/18/99 B 3.7.11-1 0 Amend. No. 123 12/18/99 B 3.7.11-2 0 Amend. No. 123 12/18/99 B 3.7.11-3 0 Amend. No. 123 12/18/99 B 3.7.11-4 0 Amend. No. 123 12/18/99 B 3.7.12-1 0 Amend. No. 123 12/18/99 B 3.7.13-1 24 DRR 06-0051 2/28/06 B 3.7.13-2 1 DRR 99-1624 12/18/99 B 3.7.13-3 24 DRR 06-0051 2/28/06 B 3.7.13-4 1 DRR 99-1624 12/18/99 B 3.7.13-5 1 DRR 99-1624 12/18/99 B 3.7.13-6 12 DRR 02-1062 9/26/02 B 3.7.13-7 DRR 99-1624 12/18/99 11 B 3.7.13-8 DRR 99-1624 12/18/99 B 3.7.14-1 0 Amend. No. 123 12/18/99 B 3.7.15-1 0 Amend. No. 123 12/18/99 B 3.7.15-2 0 Amend. No. 123 12/18/99 B 3.7.15-3 0 Amend. No. 123 12/18/99 B 3.7.16-1 5 DRR 00-1427 10/12/00 B 3.7.16-2 23 DRR 05-1995 9/28/05 B 3.7.16-3 5 DRR 00-1427 10/12/00 B 3.7.17-1 7 DRR 0 1-0474 5/1/01 B 3.7.17-2 7 DRR 0 1-0474 5/1/01 Wolf Creek - Unit 1 xi Revision40

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TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.17-3 5 DRR 00-1427 10/12/00 B 3.7.18-1 0 Amend. No. 123 12/18/99 B 3.7.18-2 0 Amend. No. 123 12/18/99 B 3.7.18-3 0 Amend. No. 123 12/18/99 TAB - B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1-1 0 Amend. No. 123 12/18/99 B 3.8.1-2 0 Amend. No. 123 12/18/99 B 3.8.1-3 25 DRR 06-0800 5/18/06 B 3.8.1-4 25 DRR 06-0800 5/18/06 B 3.8.1-5 25 DRR 06-0800 5/18/06 B 3.8.1-6 25 DRR 06-0800 5/18/06 B 3.8.1-7 26 DRR 06-1350 7/24/06 B 3.8.1-8 35 DRR 07-1553 9/28/07 B 3.8.1-9 26 DRR 06-1350 7/24/06 B 3.8.1-10 39 DRR 08-1096 8/28/08 B 3.8.1-11 36 DRR 08-0255 3/11/08 B 3.8.1-12 35 DRR 07-1553 9/28/07 B 3.8.1-13 26 DRR 06-1350 7/24/06 B 3.8.1-14 26 DRR 06-1350 7/24/06 B 3.8.1-15 26 DRR 06-1350 7/24/06 B 3.8.1-16 26 DRR 06-1350 7/24/06 B 3.8.1-17 26 DRR 06-1350 7/24106 B 3.8.1-18 26 DRR 06-1350 7/24/06 B 3.8.1-19 26 DRR 06-1350 7/24/06 B 3.8.1-20 26 DRR 06-1350 7/24/06 B 3.8.1-21 33 DRR 07-0656 5/1/07 B 3.8.1-22 33 DRR 07-0656 5/1/07 B 3.8.1-23 40 DRR 08-1846 12/9/08 B 3.8.1-24 33 DRR 07-0656 5/1/07 B 3.8.1-25 33 DRR 07-0656 5/1/07 B 3.8.1-26 33 DRR 07-0656 5/1/07 B 3.8.1-27 33 DRR 07-0656 5/1/07 B 3.8.1-28 33 DRR 07-0656 5/1/07 B 3.8.1-29 33 DRR 07-0656 5/1/07 B 3.8.1-30 33 DRR 07-0656 5/1/07 B 3.8.1-31 33 DRR 07-0656 5/1/07 B 3.8.1-32 33 DRR 07-0656 5/1/07 B 3.8.1-33 39 DRR 08-1096 8/28/08 B 3.8.1-34 39 DRR 08-1096 8/28/08 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 Wolf Creek - Unit 1 xii Revision 40

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

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 00-0 147 4/24/00 B 3.8.5-1 0 Amend. No. 123 12/18/99 B 3.8.5-2 0 Amend. No. 123 12/18/99 B 3.8.5-3 0 Amend. No. 123 12/18/99 B 3.8.5-4 12 DRR 02-1062 9/26/02 B 3.8.5-5 12 DRR 02-1062 9/26/02 B 3.8.6-1 0 Amend. No. 123 12/18/99 B 3.8.6-2 0 Amend. No. 123 12/18/99 B 3.8.6-3 0 Amend. No. 123 12/18/99 B 3.8.6-4 0 Amend. No. 123 12/18/99 B 3.8.6-5 0 Amend. No. 123 12/18/99 B 3.8.6-6 0 Amend. No. 123 12/18/99 B 3.8.7-1 0 Amend. No. 123 12/18/99 B 3.8.7-2 5 DRR 00-1427 10/12/00 B 3.8.7-3 0 Amend. No. 123 12/18/99 B 3.8.7-4 0 Amend. No. 123 12/18/99 B 3.8.8-1 0 Amend. No. 123 12/18/99 B 3.8.8-2 0 Amend. No. 123 12/18/99 B 3.8.8-3 0 Amend. No. 123 12/18/99 B 3.8.8-4 12 DRR 02-1062 9/26/02 B 3.8.8-5 12 DRR 02-1062 9/26/02 B 3.8.9-1 0 Amend. No. 123 12/18/99 B 3.8.9-2 0 Amend. No. 123 12/18/99 B 3.8.9-3 0 Amend. No. 123 12/18/99 B 3.8.9-4 0 Amend. No. 123 12/18/99 B 3.8.9-5 0 Amend. No. 123 12/18/99 B 3.8.9-6 0 Amend. No. 123 12/18/99 B 3.8.9-7 0 Amend. No. 123 12/18/99 B 3.8.9-8 1 DRR 99-1624 12/18/99 B 3.8.9-9 0 Amend. No. 123 12/18/99 B 3.8.10-1 0 Amend. No. 123 12/18/99 B 3.8.10-2 0 Amend. No. 123 12/18/99 B 3.8.10-3 0 Amend. No. 123 12/18/99 B 3.8.10-4 0 Amend. No. 123 12/18/99 B 3.8.10-5 12 DRR 02-1062 9/26/02 B 3.8.10-6 12 DRR 02-1062 9/26/02 Wolf Creek - Unit 1 xiii Revision40

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TAB - B 3.9 REFUELING OPERATIONS B 3.9.1-1 0 Amend. No. 123 12/18/99 B 3.9.1-2 19 DRR 04-1414 10/12/04 B 3.9.1-3 19 DRR 04-1414 10/12/04 B 3.9.1-4 19 DRR 04-1414 10/12/04 B 3.9.2-1 0 Amend. No. 123 12/18/99 B 3.9.2-2 0 Amend. No. 123 12/18/99 B 3.9.2-3 0 Amend. No. 123 12/18/99 B 3.9.3-1 24 DRR 06-0051 2/28/06 B 3.9.3-2 24 DRR 06-0051 2/28/06 B 3.9.3-3 24 DRR 06-0051 2/28/06 B 3.9.3-4 24 DRR 06-0051 2/28/06 B 3.9.4-1 23 DRR 05-1995 9/28/05 B 3.9.4-2 13 DRR 02-1458 12/03/02 B 3.9.4-3 25 DRR 06-0800 5/18/06 B 3.9.4-4 23 DRR 05-1995 9/28/05 B 3.9.4-5 33 DRR 07-0656 5/1/07 B 3.9.4-6 23 DRR 05-1995 9/28/05 B 3.9.5-1 0 Amend. No. 123 12/18/99 B 3.9.5-2 32 DRR 07-0139 2/7/07 B 3.9.5-3 32 DRR 07-0139 2/7/07 B 3.9.5-4 32 DRR 07-0139 2/7/07 B 3.9.6-1 0 Amend. No. 123 12/18/99 B 3.9.6-2 19 DRR 04-1414 10/12/04 B 3.9.6-3 12 DRR 02-1062 9/26/02 B 3.9.6-4 12 DRR 02-1062 9/26/02 B 3.9.7-1 25 DRR 06-0800 5/18/06 B 3.9.7-2 0 Amend. No. 123 12/18/99 B 3.9.7-3 0 Amend. No. 123 12/18/99 Note 1 The page number is listed on the center of the bottom of each page.

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

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

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

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

Wolf Creek - Unit 1 xiv Revision40

ML090750624

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