Text

Changes to Technical Specification Bases - Revisions 50 Through 54
	ML12080A216
Person / Time
Site:	Wolf Creek
Issue date:	03/12/2012
From:	Sen G; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 12-0026
	Download: ML12080A216 (61)
	v • d • e

WS.LF CREEK

'NUCLEAR OPERATING CORPORATION Gautam Sen Manager Regulatory Affairs March 12, 2012 RA 12-0026 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 50 through 54 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 Nuclear Regulatory Commission (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 50 through 54) under the provisions to TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2011 through December 31, 2011.

This letter contains no commitments.

contact me at (620) 364-4175.

If you have any questions concerning this matter, please Sincerely, Gautam Sen GS/rlt Enclosure cc: E. E. Collins (NRC), w/e J. R. Hall (NRC), w/e N. F. O'Keefe (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/HC/VET Au~'

Enclosure to RA 12-0026 Wolf Creek Generating Station Changes to the Technical Specification Bases (31 pages)

TS BASES REVISION: 54 TECHNICAL SPECIFICATION BASES Wolf Creek Generating Station, Unit 1 Summary of Revision 54:

Released:

DC12 11/16/2011

1. Technical Specification (TS) Bases page B 3.3.2-46 is revised to provided clarification of the Note to Surveillance Requirement (SR) 3.3.2.3 regarding why the continuity check does not have to be performed. The third sentence is revised from: "This SR is applied to the balance of plant actuation logic." to "This SR is applied to the balance of plant actuation logic and relays that do not have circuits installed to perform the continuity check." (CR 37904)

2.

The TS Bases 3.7.5 Background Section is being revised to provide a description of the turbine driven auxiliary feedwater (AFW) pump standby tanks. Change Package 12957 installed the turbine driven AFW pump standby tanks.

3. Change Package # 013298, Rev. 0, "Issue Revisions to AC System Study Calculations," provides a coordinated and organized means to update the electrical distribution system AC System calculations and their associated Calculation Change Notices (CCNs) that are impacted by the release of Revision 6 to Calculation XX-E-006, "AC System Analysis." The analysis determined that supplying both trains of the Class 1 E AC electrical power distribution system from one offsite power source (either XNB01 or XNB02) is not acceptable.

4.

TS Bases page B 3.8.1-29 is revised to delete the word "automatic" from the phrase "... automatic load transfer." The Bases for SR 3.8.1.16 state, in part: "As required by Regulatory Guide 1.9, Rev. 3 (Ref. 3), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to ready to load status when offsite power is restored. The load transfer that occurs after synchronizing with offsite power is a manual process not an automatic load transfer. The term "automatic load transfer" in not used in the Technical Specification SR itself. Regulatory Guide 1.9, Rev. 3, Section 2.2.11, Synchronizing Test, does not refer to an automatic load transfer. (CR 38701)

5. The TS 3.7.19 Bases are being revised to include the main steam low point drain isolation valves and the steam generator (SG) chemical injection valves as secondary system isolation valves. CR 40975 determined that the main steam low point drain isolation valves and the SG chemical injection valves were implicitly credited in the safety analysis and therefore should be considered as secondary system isolation valves under TS 3.7.19.

ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES LCO, and APPLICABILITY (continued)

a.

Engineered Safety Feature Actuation System Interlocks - Reactor Trip, P-4 The P-4 interlock is enabled when a reactor trip breaker (RTB) and its associated bypass breaker is open. Manual reset of SI following a 60 second time delay, in conjunction with P-4, generates an automatic SI block. This Function allows operators to take manual control of SI systems after the initial phase of injection is complete. Once SI is blocked, automatic actuation of SI cannot occur until the RTBs have been manually closed.

The functions of the P-4 interlock are:

Function Trips the main turbine Isolates MFW with coincident low Tavg Allows manual block of the automatic reactuation of SI after a manual reset of SI; and

" Allows arming of the steam dump valves and transfers the steam dump from the load rejection Tavg controller to the plant trip controller; and Prevents opening of the MFW isolation valves if they were closed on SI or SG Water Level -

High High.

Required MODE 1,2 1,2 1,2,3 None 1,2,3 Each of the above functions is interlocked with P-4 to avert or reduce the continued cooldown of the RCS following a reactor trip. A reactor trip from MODE 1 or 2 could result in an excessive cooldown of the RCS that could cause an insertion of positive reactivity with a subsequent increase in core power. To avoid such a situation, the noted functions have been interlocked with P-4 as part of the design of the unit control and protection system.

Wolf Creek - Unit 1 B 3.3.2-31 Revision 52

ESFAS Instrumentation B 3.3.2 r -

BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY

a.

En-gineered Safety Feature Actuation System Interlocks - Reactor Trip, P-4 (continued)

The turbine trip function, MFW isolation coincident with low Tavg function, arming of the steam dump valves function do not serve a mitigation function in the licensing basis safety analyses. Block of the SI signals is required to support long-term ECCS operation in the post-LOCA recirculation mode. Block of the opening of the MFW isolation valves on SI or SG Water Level - High High prevents reopening the valves for mitigation 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 RTB position switches that provide input to the P-4 interlock (P-4 generated when one train's RTB and the alternate train's Bypass Breaker are both open) only function to energize or de-energize or open or close contacts. Therefore, this Function has no adjustable trip

setpoint with which to associate a Trip Setpoint and Allowable Value.

This Function does not have to be OPERABLE in MODE 4, 5, or 6 because the main turbine, the MFW System, and the Steam Dump System are not in operation.

b.

Engineered Safety Feature Actuation System Interlocks -

Pressurizer Pressure, P-11 The P-11 interlock permits a normal unit cooldown and depressurization without actuation of SI or main steam line isolation. With.two-out-of-three pressurizer pressure channels (discussed previously) less than the P-11 setpoint, the operator can manually block the Pressurizer Pressure - Low and Steam Line Pressure - Low SI signals and the Steam Line Pressure - Low steam line isolation signal (previously discussed). When the Steam Line Pressure - Low steam line isolation signal is manually blocked, a main steam isolation signal on Steam Line Pressure - Negative Rate - High is automatically enabled.

This provides protection for an SLB by closure of the MSIVs. With two-out-of-three pressurizer pressure channels above the P-11 setpoint, the Pressurizer Pressure - Low and Steam Line Pressure -Low SI signals and the Steam Line Pressure - Low steam line isolation signal are automatically enabled. The operator can also Wolf Creek - Unit 1 B 3.3.2-32 Revision 52

ESFAS Instrumentation B 3.3.2 BASES ACTIONS P.1. P.2.1, and P.2.2 (continued) redundancy provided by the motor driven AFW pumps, and the low probability of an event occurring during this interval. If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 4 within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power in an orderly manner and without challenging unit systems. In MODE 4, the unit does not have any analyzed transients or conditions that require the turbine driven AFW pump for mitigation.

SURVEILLANCE The SRs for each ESFAS Function are identified by the SRs column REQUIREMENTS of Table 3.3.2-1.

A Note has been added. to the SR Table to clarify that Table 3.3.2-1 determines which.SRs apply to which ESFAS Functions.

Note that each channel of process protection supplies both trains of the ESFAS. When testing channel I, train A and train B must be examined.

Similarly, train A and train B must be examined when testing channel II, channel III, and channel IV. The CHANNEL CALIBRATION and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

SR 3.3.2.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including indication and reliability. If a channel is outside the criteria, it may be an indication Wolf Creek - Unit 1 B 3.3.2-45 Revision 20 1

ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE SR 3.3.2.1 (continued)

REQUIREMENTS that the sensor or the signal processing equipment has drifted outside its limit.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

SR 3.3.2.2 SR 3.3.2.2'is the performance of an ACTUATION LOGIC TEST. The SSPS is tested every 92 days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypass condition, thus preventing inadvertent actuation. Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity. This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

SR 3.3.2.3 SR 3.3.2.3 is the performance of an ACTUATION LOGIC:TEST using the BOP ESFAS automatic tester. The continuity check does not have to be performed, as explained in the Note. This SR is applied to the balance of plant actuation logic and relays that do not have circuits installed to perform the continuity check. This test is required every 31 days on a STAGGERED TEST BASIS. The Frequency is adequate based on industry operating experience, considering instrument reliability and operating history data.

SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The

.MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but Wolf Creek - Unit 1 B 3.3.2-46 Revision 54

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

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

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

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

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

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

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

Wolf Creek - Unit 1 B 3.4.5-1 Revision 0

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

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

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

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

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

Note 1 permits all RCPs to be removed from operation for _< 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. The purpose of the Note is to perform tests that are required to be performed without flowor pump noise. One of these tests is validation of the pump coastdown curve used as input to a number of accident analyses including a loss of flow accident. This test is generally performed in MODE 3 during the initial startup testing program, and as such should only be performed once. If, however, changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values of the coastdown curve must be revalidated by conducting the test again.

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

Wolf Creek - Unit 1 B 3.4.5-2 Revision 53

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

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

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

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

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

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

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

Wolf Creek - Unit 1 B 3.4.6-1 Revision 53

RCS Loops-MODE 4 B 3.4.6 BASES LCO The purpose of this LCO is to require that at least two loops be.

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

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

_< 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. The purpose of the Note is to permit tests that are required to be performed without flow or pump noise. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months time period is adequate to perform the necessary testing, and operating experience has shown that boron stratification is not a problem during this short period with no forcedflow.

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

a.

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

b.

Core outlet temperature is maintained at least 1 0°F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

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

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

An OPERABLE RCS loop is comprised of an OPERABLE RCP and an OPERABLE SG, which has the minimum water level specified in SR 3.4.6.2.

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

Wolf Creek - Unit 1 B 3.4.6-2 Revision 29

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

B 3.4.8 RCS Loops - MODE 5, Loops Not Filled.

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

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

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

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

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

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

Wolf Creek - Unit 1 B 3.4.8-1 Revision 53

RCS Loops - MODE 5, Loops Not Filled B 3.4.8 BASES LCO (continued)

Note 1 permits all RHR pumps to be removed from operation for < 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

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

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

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

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. When both RHR loops (or trains) are required to be OPERABLE, the associated Component Cooling Water (CCW) train is required to be OPERABLE. The heat sink for the CCW System is normally provided by the Service Water System or Essential Service Water (ESW) System, as determined by system availability. In MODES 5 and 6, one Diesel Generator (DG) is required to be OPERABLE per LCO 3.8.2, "AC Sources - Shutdown." The same ESW train is required to be OPERABLE to support DG OPERABILITY.

Typically, both ESW trains are utilized to support CCW train OPERABILITY. However, a Service Water train can be utilized to support CCW/RHR OPERABILITY if the associated ESW train is inoperable.

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

Operation in other MODES is covered by:

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

LCO 3.4.5, "RCS Loops - MODE 3";

LCO 3.4.6, "RCS Loops - MODE 4";

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

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

Wolf Creek - Unit 1 B 3.4.8-2 Revision 42

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) orthe 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 18 and the subsequent operating cycle, a one-time alternate repair criterion for the portion of the tube below 15.2 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 52

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 thatfeach automatic containment isolation valvewill 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 Xl,. Related to Code Case OMN-1 for:Wolf Creek Generating Station (TAC NO. MB0982)."

8.

WCAP-15791-P, Rev. 1, "Risk-Informed Evaluation of Extensions to Containment Isolation Valve Completion Times," April 2004.

9.

License Amendment No. 190, November 3, 2010.

Wolf Creek - Unit 1 B 3.6.3-13 Revision 50

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-8100 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

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 I

associated with separation group 4 ("yellow"), and one actuator trains is associated with separation group 1 ("red").

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

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

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

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

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

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

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

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 50

AFW System B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Auxiliary Feedwater (AFW) System BASES BACKGROUND The AFW System automatically supplies feedwater to the steam generators toremove decay heat from the Reactor Coolant System upon the loss of normal feedwater supply. The AFW pumps normally take suction through a common suction line from the condensate storage tank (CST) (LCO 3.7.6). Should the CST become unavailable, cooling water is available from the Essential Service Water (ESW) System. Three turbine driven AFW pump standby tanks are provided in the turbine driven AFW pump suction line to ensure an adequate safety grade source of water is available to accomplish an automatic transfer of the suction from the CST to an ESW supply. Each motor driven AFW pump is supplied from its respective ESW train. The steam turbine driven AFW pump is supplied from either ESW train. The AFW pumps discharge to the steam generator secondary side via separate and independent connections to the main feedwater (MFW) piping outside containment. The steam generators function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the steam generators via the main steam safety valves (MSSVs) (LCO 3.7.1) or atmospheric relief valves (LCO 3.7.4). If the main condenser is available, steam may be released via the steam dump valves and pumped back to the CST.

The AFW System consists of two motor driven AFW pumps and one steam turbine driven pump configured into three trains. Each motor driven pump provides 100% of the feedwater flow required for removal of decay heat from the reactor. The turbine driven pump provides 200% of the capacity of a motor driven pump. The pumps are equipped with recirculation lines to prevent pump operation against a closed system.

Each motor driven AFW pump is powered from an independent Class I E power supply and feeds two steam generators, although each pump has the capability to be locally aligned to feed other steam generators. The steam turbine driven AFW pump receives steam from two main steam lines upstream of the main steam isolation valves and water from either the condensate storage tank or redundant ESW supply lines. Each of the steam feed lines will supply.100% of the requirements of the turbine driven AFW pump. In addition, each of the ESW supply lines will supply 100% of the requirements of the turbine driven AFW pump. The three turbine driven AFW pump standby tanks are gravity fed from the CST and maintains adequate level with the CST level maintained in accordance with LCO 3.7.6.

The AFW System is capable of supplying feedwater to the steam generators during normal unit startup, shutdown, and hot standby conditions.

Wolf Creek - Unit 1 B 3.7.5-1 Revision 54

AFW System B 3.7.5 BASES BACKGROUND The turbine driven AFW pump supplies a common header capable of (continued) feeding all steam generators with normally open air operated control valves. The motor driven pumps supply flow to the steam generators through a normally open motor operated valve that automatically throttles flow to prevent pump runout conditions under all steam generator pressure conditions. One pump at full flow is sufficient to remove decay heat and cool the unit to residual heat removal (RHR) entry conditions.

Thus, the requirement for diversity in motive power sources for the AFW System is met.

The AFW System is designed to supply sufficient water to the steam generator(s) to remove decay heat with steam generator pressure at the setpoint of the MSSVs. Subsequently, the AFW System supplies sufficient water to cool the unit to RHR entry conditions, with steam released through the ARVs.

The motor driven AFW pumps start automatically on steam generator water level 'low-low in any steam generator, on trip of both main feedwater pumps, upon actuation of AMSAC, and on actuation by the LOCA sequencer or shutdown sequencer. The turbine driven AFW pump is automatically started by steam generator water level - low-low in any two steam generators, NB01 or NB02 undervoltage, and upon actuation of AMSAC.

The AFW System is discussed in the USAR, Section 10.4.9 (Ref. 1).

APPLICABLE SAFETY ANALYSES The AFW System mitigates the consequences of any event with loss of normal feedwater.

The design basis of the AFW System is to supply water to the steam generator to remove decay heat and other residual heat by delivering at least the minimum required flow rate to the steam generators at pressures corresponding to the lowest steam generator safety valve set pressure plus 3% accumulation.

In addition, the AFW System must supply enough makeup water to replace steam generator secondary inventory lost as the unit cools to MODE 4 conditions. Sufficient AFW flow must also be available to account for flow losses such'as pump recirculation and line breaks.

The limiting Design Basis Accidents (DBAs) and transients for the AFW System are as follows:

Wolf Creek - Unit 1 B 3.7.5-2 Revision 54 1

SSIVs B 3.7.19 B 3.7 PLANT SYSTEMS B 3.7.19 Secondary System Isolation Valves (SSIVs)

BASES BACKGROUND Closure of secondary system isolation valves (SSIVs) ensures that the assumptions used in the plant accident and containment analyses remain valid. In accident conditions, SSIVs close to terminate the blowdown from the faulted steam generator and isolate the intact steam generators, and to isolate the plant secondary side in order to prevent possible diversion of auxiliary feedwater flow.

The accident analyses assume. that the steam generators are isolated after receiving an isolation signal. Following receipt of the steam line isolation signal (SLIS) and auxiliary feedwater actuation signal (AFAS),

the intact steam generators are assumed to be isolated, except for the steam supply valves to the turbine-driven auxiliary feedwater pump (governed by LCO 3.7.5, "Auxiliary Feedwater (AFW) System"). There are also analysis cases that evaluate the single failure of a main steam or main.feedwater isolation valve. In addition to the valves governed by LCO 3.7.2, "Main Steam Isolation Valves (MSIVs) and MSIV Valve Bypass Valves," and LCO 3.7.3, "Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulating Valves (MFRVs) and MFRV Bypass Valves,"

the analysis assumptions require that the steam generator blowdown and sample line isolation valves are closed.

When plant accident conditions require delivery of auxiliary feedwater, the normally closed steam supply isolation valves to the turbine-driven auxiliary feedwater pump (TDAFP) open on an AFAS. This ensures availability of the TDAFP. The AFAS also closes the steam generator blowdown and sample isolation valves in order to isolate the plant's secondary side.

The Steam Generator Blowdown System (SGBS) helps to maintain the steam generator secondary side water within chemical specifications.

Heat is recovered from the blowdown and returned to the feedwater system. Portions of the SGBS are safety related and are required to function following a design basis accident.

One blowdown isolation valve (SGBIV) is installed in each of the four blowdown lines outside the containment. These valves prevent uncontrolled blowdown from more than one steam generator and isolate non-safety related portions from the safety related portions of the system.

These valves are air-operated globe valves which fail closed. For Wolf Creek - Unit 1 B 3.7.19-1 Revision 44

SSIVs B 3.7.19 BASES BACKROUND emergency closure, either of two safety related solenoid valves is de-(continued) energized to dump air supplied to the valve actuator. The electrical solenoid valves are energized from separate Class 1 E sources and are closed upon receipt of an steam generator blowdown and sample isolation (AFAS) signal.

The SGBS also includes safety related steam generator blowdown sample isolation valves (SGBSIVs). Three SGBSIVs are installed in each of the'sample line flow paths for each steam generator. Two valves are located inside the containment (one from each sample point), and one valve is located outside containment. The SGBSIVs prevent uncontrolled blowdown from more than one steam generator and isolate the non-safety related portions from the safety related portions of the system. The SGBSIVs are solenoid-operated globe valves which fail closed. The inside containment solenoid valves are energized from separate Class IE sources from the outside containment solenoid valves. These valves are also closed upon receipt of an steam generator blowdown and sample isolation (AFAS) signal.

On each of the four main steam lines; upstream of the MSIVs, is a 12-inch diameter low point drain line. Each drain line has a level detection system that consists of a level switch that annunciates on a high level. Attached to the 12-inch line is a 1-inch diameter line back to the condenser. One air-operated main steam low point drain isolation valve (MSLPDIV) is installed in each 1-inch drain line. The MSLPDIVs are normally open to allow a steam trap to pass moisture to the main condenser. The MSLPDIVs close upon receipt of an SLIS and function to isolate the plant's secondary side. For emergency closure on receipt of an SLIS, either of two safety related solenoid valves is deenergized to dump air supplied to the valve actuator. The electrical solenoid valves are energized from separate Class 1 E sources. The MSLPDIVs fail in the closed position.

When plant accident conditions require feedline isolation, a feedwater isolation signal (FWIS) trips the main feedwater pumps and closes the MFIVs, the MFRVs, and the MFRV bypass valves. The FWIS also provides a signal to close the air-operated chemical injection isolation valve located in the chemical injection flow path associated with each main feedwater line. The valves automatically fail closed when an FWIS is received.

The Steam Generator Chemical Injection System delivers chemicals to the steam generators via chemical addition through lines that tap directly into the feedwater lines, downstream of the MFIV.

Wolf Creek - Unit 1 B 3.7.19-2 Revision 54

SSIVs B 3.7.19 BASES BACKROUND For each or. any of the four feedwater lines, a positive displacement (continued) metering pump delivers the chemicals from a supply tank into the associated feedwater line.via, an injection flow path that includes an automatic air-operated globe isolation valve, a check valve, and a manual valve prior to entering into the feedwater system.

The Steam Generator Chemical Injection System is used to maintain proper system pH and scavenge oxygen present in the steam generators to minimize corrosion during plant shutdown conditions. The system adds hydrazine and amine mixture to the steam generator and is normally not in use during plant power operation, except during plant conditions in hot standby or cold layup. The Steam Generator Chemical Injection System is infrequently used during the Applicability of this Specification.

The manual valve located in each chemical injection flow path is maintained locked closed until the system is used. When the system is used,ý the manual valve is opened under administrative controls. The controls include the presence of a dedicated operator who has constant communication with the control room while the flow path is open.

Therefore, crediting the locked closed manual valve in the chemical injection flow path for isolation is warranted when it is only opened under administrative controls.

The main steam and related secondary side lines are automatically isolated upon receipt of an SLIS or feedwater isolation signal (FWIS).

The diverse parameters sensed to initiate an SLIS are low steam line pressure, high negative steam pressure rate, and high containment pressure (Hi-2).

A FWIS is generated by a safety injection signal (SIS), reactor trip with low Tave, steam generator water level high-high, or steam generator water level low-low. The diverse parameters sensed to initiate an SIS are low steam line pressure, low pressurizer pressure, and high containment pressure (Hi-i).

The steam generator blowdown and sample isolation (AFAS) isolates the steam generator blowdown and sample lines., A steam generator blowdown and sample isolation (AFAS) is generated by a SIS, motor-driven AFAS, or undervoltage on switchgear 4.16 kV buses NBO1 or NB02.

Descriptions of SSIVs are found in the USAR, Section 10.4.7 (Ref. 1),

Section 10.4.8 (Ref. 2), and Section 10.3 (Ref. 3).

Wolf Creek - Unit 1 B 3.7.19-3

,Revision 54

SSIVs B 3.7.19 BASES APPLICABLE The accident analysis assume that the steam generators are isolated SAFETY ANALYSES after receiving an isolation signal as discussed in the Background section.

Further discussion can be found in the USAR, Chapters 6 and 15.

The SSIVs function to ensure the primary success path for steam line and feed line isolation and for delivery of required auxiliary feedwater flow and, therefore, satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO provides assurance that SSIVs will isolate the plant's secondary side, following a main feed line or main steam line break and ensures the required flow of auxiliary feedwater to the intact steam generators. The automatic secondary system isolation valves are considered OPERABLE when their isolation times are within limits and they are capable of closing on an isolation actuation signal. OPERABILITY of the automatic SSIVs also requires the OPERABILITY of the auxiliary relays downstream of the Balance of Plant Engineered Safety Features Actuation System (ESFAS) cabinets (the auxiliary relays in the system cabinets are considered to be part of the end devices covered by this LCO).

The locked closed manual valves in the chemical injection flow path are considered OPERABLE when they are locked closed. Locked closed manual SSIVs include steam generator chemical injection isolation valves (AEVO128, AEVO129, AEV0130, and AEVO131).

Automatic secondary system isolation valves include the SGBIVs (BMHV0001, BMHV0002, BMHV0003, and BMHV0004) and the SGBSIVs (BMHV0019, BMHV0020, BMHV0021, BMHV0022, BMHV0065, BMHV0066, BMHV0067, BMHV0068, BMHV0035, BMHV0036, BMHV0037, and BMHV0038), and the main steam low point drain isolation valves (ABLVO07, ABLVO08, ABLVO09, and ABLV01 0).

APPLICABILITY The SSIVs must be OPERABLE in MODES 1, 2, and 3, when there is significant mass and energy in the Reactor Coolant System (RCS) and steam generators. When the SSIVs are closed and de-activated, or closed and isolated by a closed manual valve, or the flow path is isolated by a combination of closed manual valve(s) and closed de-activated automatic valve(s), they are performing the specified safety function of isolating the plant's secondary side. An air-operated SSIV is de-activated when power and air are removed from its actuation solenoid valves, and a solenoid-operated SSIV is de-activated when power is removed from its associated solenoid valve.

In MODES 4, 5, and 6, the steam generator energy is low. Therefore, the SSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

Wolf Creek - Unit 1 B 3.7.19-4 Revision 54

SSIVs B 3.7.19 BASES ACTIONS The ACTIONS are modified by a Note to provide clarification that, for this LCO, separate Condition entry is allowed for each SSIV. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SSIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SSIVs are governed by subsequent Condition entry and application of associated Required Actions.

A second Note has been added to allow SSIVs to be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in continuous communication with the control room. In this way, the SSIV can be rapidly isolated when the need for secondary system isolation is indicated.

A.1 and A.2 With one or more SSIVs inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable valves within 7 days. When these valves are closed or isolated, they are performing their specified safety function.,

The 7 day Completion Time takes into account the low probability of an event occurring during this time period that would require isolation of the plant's secondary side. The 7 day Completion Time is reasonable, based on operating experience.

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

If the SSIVs are closed and de-activated, or closed and isolated by a closed manual valve, or the SSIV flow path is isolated by a combination of closed manual valve(s) and closed de-activated automatic valve(s), this LCO does not apply as discussed in the Applicability section.

Wolf Creek - Unit 1 B 3.7.19-5 Revision 54

SSIVs B 3.7.19 BASES ACTIONS B.1 and B.2 (continued)

If the Required Action and associated Completion Time of Condition A is not met, 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 in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.19.1 REQUIREMENTS This SR verifies the proper alignment for required automatic SSIVs in the flow path that are used to isolate the plant's secondary side. The SSIV is allowed to be in a nonaccident position provided the valve will automatically reposition within the proper stroke time. 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 valves capable of being mispositioned are in the correct position. This SR does not apply to the locked closed manual valves in the chemical injection flow path since these valves were verified to be in the correct position upon locking.

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

SR 3.7.19.2 This SR verifies that the isolation time of each required automatic SSIV is within limits when tested pursuant to the Inservice Testing Program. The specific limits are documented in the Inservice Testing Program. The SSIV isolation times are less than or equal to those assumed in the accident and containment analyses. The SR is performed only for required SSIVs. This Surveillance does not include verifying a closure time for the steam generator chemical injection isolation valves. An exception is made for the steam generator chemical addition injection isolation valves which are not included in the Inservice Testing Program.

These valves are passive and contain a locking device and a check valve in their flow path.

Wolf Creek - Unit 1 B 3.7.19-6 Revision 54

SSIVs B 3.7.19 BASES SURVEILLANCE REQUIREMENTS SR 3.7.19.2 (continued)

For the required SSIVs, performance of this Surveillance is routinely done during plant operation (or as required for post-maintenance testing), but it may also be required to be performed upon returning the unit to operation following a refueling outage.

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

SR 3.7.19.3 This SR verifies that each required automatic SSIV in the flow path is capable of closure on an actual or simulated actuation signal. This Surveillance is routinely performed during plant operation, but may also be performed upon returning the unit to operation following a refueling outage.

The Frequency for this SR is 18 months.

REFERENCES

1.

USAR, Section 10.4.7.

2.

USAR, Section 10.4.8.

3.

USAR, Section 10.3.

Wolf Creek - Unit 1 B 3.7.19-7 Revision 54 1

AC Sources - Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND The unit Class 1E AC Electrical Power Distribution System AC sources consist of the offsite power sources (preferred power sources, normal and alternate from the redundant Engineered Safety Feature (ESF) transformers), and the onsite standby power sources (Train A and Train B diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the ESF systems.

The onsite Class 1E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to its preferred offsite power source and a single DG.

Offsite power is supplied to the unit switchyard from the transmission network by three transmission lines. From the switchyard, two electrically and physically separated circuits provide AC power, through the ESF transformers, to the 4.16 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1 E ESF buses is found in the USAR, Chapter 8 (Ref. 2).

An offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1 E ESF bus(es).

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class 1 E Distribution System. Within 1 minute after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service via the load sequencer.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. DGs A and B are dedicated to ESF buses NB01 and NB02, respectively. The DG starts automatically on a safety injection (SI) signal or on an ESF bus undervoltage signal. A degraded voltage signal produces an undervoltage condition by opening the normal and alternate Wolf Creek - Unit 1 B 3.8.1 -1 Revision 54

AC Sources - Operating B 3.8.1 BASES BACKGROUND (continued) feeder breakers to the bus(es) experiencing degraded voltage. Both signals are initiated from the load shedder and emergency load sequencer (LSELS). OPERABILITY of the undervoltage and degraded voltage instrumentation functions are addressed in LCO 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation." After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a LSELS strips non-essential loads from the ESF bus. When the DG is tied to the ESF bus, essential loads are then sequentially connected to its respective ESF bus by the load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.

In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a loss of coolant accident (LOCA).

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the DG in the process. Within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG is 6201 kW with 10% overload permissible for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.

APPLICABLE SAFETY ANALYSES The initial conditions of DBA and transient analyses in the USAR, Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS);

and Section 3.6, Containment Systems.

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the Accident analyses and is based upon Wolf Creek - Unit 1 B 3.8.1-2 Revision 0

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

a.

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

b.

A worst case single failure.

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

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

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

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

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

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

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

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

Wolf Creek - Unit 1 B 3.8.1-3 Revision 47

AC Sources - Operating B 3.8.1 BASES LCO Upon failure of the DG lube oil keep warm system when the DG is in the (continued) standby condition, the DG is considered inoperable due to the inability to maintain engine lubrication (Ref. 15). Upon failure of the DG jacket water keep warm system, the DG remains OPERABLE as long as jacket water temperature is _> 105 OF (Ref. 1.3).

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

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

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

a.

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

b.

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

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

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

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

Wolf Creek - Unit 1 B 3.8.1-4 Revision 54

AC Sources - Operating B 3.8.1 BASES ACTIONS A.1 To ensure a highly; reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if the second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

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

These redundant required features are those that are assumed to function to mitigate an accident, coincident with a loss of offsite power, in the safety analyses, such as the Emergency Core Cooling System and Auxiliary Feedwater System. These redundant features do not include monitoring requirements, such as Post Accident Monitoring and Remote Shutdown. These features are powered from the redundant AC electrical power train. This includes motor driven auxiliary feedwater pumps and the turbine driven auxiliary feedwater pump which must be available for mitigation of a feedwater line break. Single train systems, other than the turbine driven auxiliary feedwater pump, are not included in this Condition.

A Note is added to this Required Action stating that in MODES 1, 2, and 3, the turbine driven auxiliary feedwater pump is considered a required redundant feature. The reason for the Note is to confirm the OPERABILITY of the turbine driven auxiliary feedwater pump in this Condition, since the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action A.2 is intended to allow the operator time 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.

The train has no offsite power supplying its loads; and Wolf Creek - Unit 1 B 3.8.1-5 Revision 54

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

b.

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

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

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

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

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

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

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a Wolf Creek - Unit 1 B 3.8.1-6 Revision 25 1

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

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

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

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

The restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g., post-work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, as a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1, 2, 3 or 4. Risk insights or deterministic methods may be used for this assessment.

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

paragraph 6.2.6(2).

Wolf Creek - Unit 1 B 3.8.1-29 Revision 54

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

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

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

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

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

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

SR 3.8.1.18 Under accident and loss of offsite power conditions loads are sequentially connected. to the bus by the LSELS. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The 10% load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that Wolf Creek - Unit 1 B 3.8.1-30 Revision 33 1

DC Sources - Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.1 (continued)

REQUIREMENTS charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or a battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. The 7 day Frequency is consistent with IEEE-450 (Ref. 9). This SR applies only to those chargers connected to a battery bank and bus. (Ref. 12)

SR 3.8.4.2 Visual inspection to detect corrosion of the battery cells and connections, or measurement of the resistance of each intercell, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The visual inspection is to detect corrosion in cell post connection area; corrosion. outside the connection area is not an OPERABILITY concern and would not require measuring resistance.

The Surveillance Frequency for these inspections, which can detect conditions that can cause power losses due to resistance heating, is 92 days. This Frequency is considered acceptable based on operating experience related to detecting corrosion trends.

SR 3.8.4.3 Visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function.)

The 18 month Frequency for this SR is based on operational experience.

SR 3.8.4.4 and SR 3.8.4.5 Visual inspection and resistance measurements of connections provide an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. The anticorrosion material is used Wolf Creek - Unit 1 B 3.8.4-5 Revision 50

DC Sources - Operating B 3.8.4 BASES SURVEILLANCE SR 3.8.4.4 and SR 3.8.4.5 (continued)

REQUIREMENTS to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection. The removal of visible corrosion is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR provided visible corrosion is removed during performance of SR 3.8.4.4.

The Surveillance Frequencies of 18 months are based on operational experience.

SR 3.8.4.6 This SR requires that each battery charger be capable of supplying 300 amps and 128.4 V for _ 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . These requirements are based on the design rating of the chargers (Ref..4). According to Regulatory Guide 1.32 (Ref. 10), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging' capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensures that these requirements can be satisfied.

The Surveillance Frequency is acceptable, given the unit conditions required to perform the test and the other administrative controls existing to ensure adequate charger performance during these 18 month intervals.

In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

SR 3.8.4.7 A battery service test is a special test of battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length should correspond to the design duty cycle requirements as specified in Reference 4.

The Surveillance Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 10) and Regulatory Guide 1.129 (Ref. 11), which state that the battery service test should be performed during refueling operations or at some other outage, with intervals between tests, not to exceed 18 months.

Wolf Creek - Unit 1 B 3.8.4-6 Revision 50 1

Distribution Systems - Operating B 3.8.9 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.9 Distribution Systems - Operating BASES BACKGROUND The onsite Class 1 E AC, DC, and AC vital bus electrical power distribution systems are divided by train into two redundant and independent AC, DC, and AC vital bus electrical power distribution subsystems as defined in Table B 3.8.9-1. Train A is associated with AC load group 1; Train B, with AC load group 2.

The AC electrical power subsystem for each train consists of an Engineered Safety Feature (ESF) 4.16 kV bus and 480 buses and load centers. Each 4.16 kV ESF bus has one separate and independent offsite source of power as well as a dedicated onsite diesel generator (DG) source. Each 4.16 kV ESF bus is normally connected to a preferred offsite source. After a loss of the preferred offsite power source to a 4.16 kV ESF bus, the onsite emergency DG supplies power to the bus.

Control power for the 4.16 kV breakers is supplied from the Class 1E batteries. Additional description of this system may be found in the Bases for LCO 3.8.1, "AC Sources - Operating," and the Bases for LCO 3.8.4, "DC Sources - Operating."

The 120 VAC vital buses are arranged in two load groups per train and are normally powered through the inverters from the 125 VDC electrical power subsystem. Refer to Bases B 3.8.7 for further information on the 120 VAC vital system.

The 125 VDC electrical power distribution system is arranged into two buses per train. Refer to Bases B 3.8.4 for further information on the 125 VDC electrical power subsystem.

The list of all required distribution buses is presented in Table B 3.8.9-1.

I APPLICABLE SAFETY ANALYSES The initial conditions of Design Basis Accident (DBA) and transient

,analyses in the USAR, Chapter 6 (Ref. 1), and in the USAR, Chapter 15 (Ref. 2), assume ESF systems are OPERABLE. The AC, DC, and AC vital bus electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Wolf Creek - Unit 1 B 3.8.9-1 Revision 54

Distribution Systems - Operating B 3.8.9 BASES APPLICABLE Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and SAFETY ANALYSES Section 3.6, Containment Systems.

(continued)

The OPERABILITY of the AC, DC, and AC vital bus electrical power distribution systems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit.

This includes maintaining power distribution systems OPERABLE during accident conditions in the event of:

a.

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

b.

A worst case single failure.

The distribution systems satisfy Criterion 3 of the 10 CFR 50.36(c)(2)(ii).

LCO The required power distribution subsystems listed in Table B 3.8.9-1 ensure the availability of AC, DC, and AC vital bus electrical power for the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. The AC, DC, and AC vital bus electrical power distribution subsystems are required to be OPERABLE.

Maintaining the Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.

OPERABLE AC electrical power distribution subsystems require the associated buses and load centers to be energized to their proper voltages. OPERABLE DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger. OPERABLE vital bus electrical power distribution subsystems require the associated buses to be energized to their proper voltage from the associated inverter via inverted DC voltage, or Class 1 E constant voltage (Sola) transformer.

In addition, no tie breakers between redundant safety related AC, DC, and AC vital bus power distribution subsystems exist. This prevents any electrical malfunction in any power distribution subsystem from propagating to the redundant subsystem, that could cause the failure of a redundant subsystem and a loss of essential safety function(s).

Wolf Creek - Unit 1 B 3.8.9-2 Revision 54

Distribution Systems - Operating B 3.8.9 BASES APPLICABILITY The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a.

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

b.

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

Electrical power distribution subsystem requirements for MODES 5 and 6 are covered in the Bases for LCO 3.8.10, "Distribution Systems -

Shutdown."

ACTIONS A.1 With either bus NG05E or NG06E inoperable, the Essential Service Water (ESW) train supported by that bus also is inoperable. These buses provide power to ESW equipment only. NG05E provides power to Train A ESW equipment; NG06E, to Train B ESW equipment. With one of these buses inoperable, immediate entry into the applicable Conditions and Required Actions of the LCO 3.7.8, "Essential Service Water (ESW)

System," for the associated ESW train is required. This ensures appropriate limits are placed upon train inoperability as discussed in the Bases for LCO 3.7.8.

B.1 With one or more required AC buses or load centers, other than NG05E or NG06E and AC vital buses, in one train inoperable, the remaining AC electrical power distribution subsystem in the other train is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining.power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required AC buses, and load centers must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

Wolf Creek - Unit I B 3.8.9-3 Revision 54

Distribution Systems - Operating B 3.8.9 BASES ACTIONS B.1 (continued)

Condition B worst scenario is one train without AC power (i.e., no offsite power to the train and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operator's attention be focused on minimizing the potential for loss of power to the remaining train by stabilizing the unit, and on restoring power to the affected train. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months time limit before requiring a unit shutdown in this Condition is acceptable because of:

a.

The potential for decreased safety if the unit operator's attention is diverted from the evaluations and actions necessary to restore power to the affected train, to the actions associated with taking the unit to shutdown within this time limit; and

b.

The potential for an event in conjunction with a single failure of a redundant component in the train with AC power.

The second Completion Time for Required Action B. 1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DC bus is inoperable and subsequently restored OPERABLE, the LCO may already have been not met for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . This could lead to a total of 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , since initial failure of the LCO, to restore the AC distribution system. At this time, a DC circuit could again become inoperable, and AC distribution restored OPERABLE. This could continue indefinitely.

The Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This will result in establishing the "time zero" at the time the LCO was initially not met, instead of the time Condition B was entered. The 16 hour1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months Completion Time is an acceptable limitation on this potential to fail to meet the LCO indefinitely.

C. i1 With one AC vital bus inoperable, the remaining OPERABLE AC vital buses are capable of supporting the minimum safety functions necessary to shut down the unit and maintain it in the safe shutdown condition.

Overall reliability is reduced, however, since an additional single failure could result in the minimum required ESF functions not being supported.

Therefore, the required AC vital bus must be restored to OPERABLE Wolf Creek - Unit 1 B 3.8.9-4 Revision 0

Nuclear Instrumentation B 3.9.3 B 3.9 REFUELING OPERATIONS B 3.9.3 Nuclear Instrumentation BASES BACKGROUND The source range neutron flux monitors are used during refueling operations to monitor the core reactivity condition. The installed source range neutron flux monitors are part of the Nuclear Instrumentation System (NIS). These detectors are located external to the reactor vessel and detect neutrons leaking from the core. There are two sets of source range neutron flux monitors: (1) Westinghouse source range neutron flux monitors and (2) Gamma-Metrics source range neutron flux monitors.

The Westinghouse source range neutron flux monitors (SE-NI-0031 and SE-NI-0032) are BF 3 detectors operating in the proportional region of the gas filled detector characteristic curve. The detectors monitor the neutron flux in counts per second. The instrument range covers six decades of neutron flux (1 to 1 E+6 cps). The detectors also provide continuous visual indication in the control room. The NIS is designed in accordance with the criteria presented in Reference 1.

The Gamma-Metrics source range neutron flux monitors (SE-NI-0060A and SE-NI-0061A) are fission chambers that provide indication of neutron flux from reactor shutdown to reactor full power level (1 E-1 to 1 E+5 cps). The monitors provide continuous visual indication in the control room to allow operators to monitor core flux.

APPLICABLE Two OPERABLE source range neutron flux monitors are required to SAFETY ANALYSES provide a signal to alert the operator to unexpected changes in core reactivity such as an improperly loaded fuel assembly.

The source range neutron flux monitors satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO requires that two source range neutron flux monitors be OPERABLE to ensure that redundant monitoring capability is available to detect changes in core reactivity. To be OPERABLE, each monitor must provide visual indication in thecontrol room.

When any of the safety related busses supplying power to one of the detectors (SE-NI-31 or 32) associated with the Westinghouse source range neutron flux monitors are taken out of service, the corresponding source range neutron flux monitor may be considered OPERABLE when its detector is powered from a temporary nonsafety related source of Wolf Creek - Unit 1 B 3.9.3-1 Revision 24

Nuclear Instrumentation B 3.9.3 BASES LCO (continued) power, provided the detector for the opposite source range neutron flux monitor is powered from its normal source. (Ref. 2) This allowance to power a detector from a temporary non-safety related source of power is also applicable to the Gamma-Metrics source range monitors. (Ref. 3)

The Westinghouse monitors are the normal source range monitors used during refueling activities. The Gamma-Metrics source range monitors provide an acceptable equivalent control room visual indication to the Westinghouse monitors in MODE 6, including CORE ALTERATIONS, with the complete fuel assembly inventory set within the reactor vessel or with the monitor(s) coupled to the core. (Ref. 3) Either the set of two Westinghouse source range neutron flux monitors or the set of two Gamma-Metrics source range monitors may be used to perform this reactivity-monitoring function. The use of one BF3 detector and one Gamma-Metrics detector is not permitted due to the importance of using detectors on opposing sides of the core to effectively monitor the core reactivity.

APPLICABILITY In MODE 6, the source range neutron flux monitors must be OPERABLE to determine changes in core reactivity. There are no other direct means available to check core reactivity levels. In MODES 2, 3, 4, and 5, these same installed source range detectors and circuitry are also required to be OPERABLE by LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation."

ACTIONS A.1 and A.2 With only one source range neutron flux monitor OPERABLE, redundancy has been lost. Since these instruments are the only direct means of monitoring core reactivity conditions, CORE ALTERATIONS and introduction into the RCS, coolant with boron concentration less than required to meet the minimum boron concentration of LCO 3.9.1 must be suspended immediately. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation. Introduction of coolant inventory must be from sources that have a boron concentration greater than that required in the RCS for minimum refueling boron concentration.

This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation.

Performance of Required Action A.1 shall not preclude completion of movement of a component to a safe position.

Wolf Creek - Unit 1 B 3.9.3-2 Revision 51

Nuclear Instrumentation B 3.9.3 BASES ACTIONS B.1 (continued)

With no source range neutron flux monitor OPERABLE action to restore a monitor to OPERABLE status shall be initiated immediately. Once initiated, action shall be continued until a source range neutron flux monitor is restored to OPERABLE status.

B.2 With no source range neutron flux monitor OPERABLE, there are no direct means of detecting changes in core reactivity. However, since CORE ALTERATIONS and boron concentration changes inconsistent with Required Action A.2 are not to be made, the core reactivity condition is stabilized until the source range neutron flux monitors are OPERABLE. This stabilized condition is determined by performing SR 3.9.1.1 to ensure that the required boron concentration exists.

The Completion Time of once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient to obtain and analyze a reactor coolant sample for boron concentration and ensures that unplanned changes in boron concentration would be identified. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable, considering the low probability of a change in core reactivity during this time period.

SURVEILLANCE SR 3.9.3.1 REQUIREMENTS SR 3.9.3.1 is the performance of a CHANNEL CHECK, which is a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that the two indication channels should be consistent with core conditions.

Changes in fuel loading and core geometry can result in significant differences between source range channels, but each channel should be consistent with its local conditions.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is consistent with the CHANNEL CHECK Frequency specified similarly for the same instruments in LCO 3.3.1.

SR 3.9.3.2 SR 3.9.3.2 is the performance of a CHANNEL CALIBRATION every 18 months. This SR is modified by a Note stating that neutron detectors are excluded from the CHANNEL CALIBRATION. The source range neutron detectors are maintained based on manufacturer's Wolf Creek - Unit 1 B 3.9.3-3 Revision 51 1

Nuclear Instrumentation B 3.9.3 BASES TECHNICAL SR 3.9.3.2 (continued)

SURVEILLANCE REQUIREMENTS recommendations. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency.

REFERENCES

1.

10 CFR 50, Appendix A, GDC 13, GDC 26, GDC 28, and GDC 29.

2.

NRC letter (J. Stone to 0. Maynard) dated October 3, 1997:

"Wolf Creek Generating Station - Technical Specification Bases Change, Source Range Nuclear Instruments Power Supply Requirements."

3.

Engineering Disposition for WO 11-339015-002, "Changes to TRM 3.3.15," March 21, 2011.

Wolf Creek - Unit 1 B 3.9.3-4 Revision 53

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TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents i

34 DRR 07-1057 7/10/07 ii 29 DRR 06-1984 10/17/06 iii 44 DRR 09-1744 10/28/09 TAB - B 2.0 SAFETY LIMITS (SLs)

B 2.1.1-1 0

Amend. No. 123 12/18/99 B 2.1.1-2 14 DRR 03-0102 2/12/03 B 2.1.1-3 14 DRR 03-0102 2/12/03 B 2.1.1-4 0

Amend. No. 123 2/12/03 B 2.1.2-1 0

Amend. No. 123 12/18/99 B 2.1.2-2 12 DRR 02-1062 9/26/02 B 2.1.2-3 0

Amend. No. 123 12/18/99 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY B 3.0-1 34 DRR 07-1057 7/10/07 B 3.0-2 0

Amend. No. 123 12/18/99 B 3.0-3 0

Amend. No. 123 12/18/99 B 3.0-4 19 DRR 04-1414 10/12/04 B 3.0-5 19 DRR 04-1414 10/12/04 B 3.0-6 19 DRR 04-1414 10/12/04 B 3.0-7 19 DRR 04-1414 10/12/04 B 3.0-8 19 DRR 04-1414 10/12/04 B 3.0-9 42 DRR 09-1009 7/16/09 B 3.0-10 42 DRR 09-1009 7/16/09 B 3.0-11 34 DRR 07-1057 7/10/07 B 3.0-12 34 DRR 07-1057 7/10/07 B 3.0-13 34 DRR 07-1057 7/10/07 B 3.0-14 34 DRR 07-1057 7/10/07 B 3.0-15 34 DRR 07-1057 7/10/07 B 3.0-16 34 DRR 07-1057 7/10/07 TAB - B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1-1 0

B 3.1.1-2 0

B 3.1.1-3 0

B 3.1.1-4 19 B 3.1.1-5 0

B 3.1.2-1 0

B 3.1.2-2 0

B 3.1.2-3 0

B 3.1.2-4 0

B 3.1.2-5 0

B 3.1.3-1 0

B 3.1.3-2 0

B 3.1.3-3 0

B 3.1.3-4 0

Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 04-1414 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 12/18/99 12/18/99 12/18/99 10/12/04 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 Wolf Creek - Unit 1 Revision 54

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TAB - B 3.1 B 3.1.3-5 B 3.1.3-6 B 3.1.4-1 B 3.1.4-2 B 3.1.4-3 B 3.1.4-4 B 3.1.4-5 B 3.1.4-6 B 3.1.4-7 B 3.1.4-8 B 3.1.4-9 B 3.1.5-1 B 3.1.5-2 B 3.1.5-3 B 3.1.5-4 B 3.1.6-1 B 3.1.6-2 B 3.1.6-3 B 3.1.6-4 B 3.1.6-5 B 3.1.6-6 B 3.1.7-1 B 3.1.7-2 B 3.1.7-3 B 3.1.7-4 B 3.1.7-5 B 3.1.7-6 B 3.1.8-1 B 3.1.8-2 B 3.1.8-3 B 3.1.8-4 B 3.1.8-5 B 3.1.8-6 REACTIVITY CONTROL SYSTEMS 0

0 0

0 48 0

0 0

48 48 48 0

0 0

15 15 0

5 (continued)

Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 10-3740 Amend. No. 123 Amend. No. 123 DRR 10-3740 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 10-3740 DRR 10-3740 DRR 10-3740 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 03-0860 DRR 03-0860 Amend. No. 123 DRR 00-1427 12/18/99 12/18/99 12/18/99 12/18/99 12/28/10 12/18/99 12/18/99 12/28/10 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/28/10 12/28/10 12/28/10 12/18/99 12/18/99 12/18/99 7/10/03 7/10/03 12/18/99 10/12/00 TAB - B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1-1 48 B 3.2.1-2 0

B 3.2.1-3 48 B 3.2.1-4 48 B 3.2.1-5 48 B 3.2.1-6 48 B 3.2.1-7 48 B 3.2.1-8 48 B 3.2.1-9 29 B 3.2.1-10 48 B 3.2.2-1 48 B 3.2.2-2 0

B 3.2.2-3 48 B 3.2.2-4 48 B 3.2.2-5 48 B 3.2.2-6 48 DRR 10-3740 Amend. No. 123 DRR 10-3740 DRR 10-3740 DRR 10-3740 DRR 10-3740 DRR 10-3740 DRR 10-3740 DRR 06-1984 DRR 10-3740 DRR 10-3740 Amend. No. 123 DRR 10-3740 DRR 10-3740 DRR 10-3740 DRR 10-3740 12/28/10 12/18/99 12/28/10 12/28/10 12/28/10 12/28/10 12/28/10 12/28/10 10/17/06 12/28/10 12/28/10 12/18/99 12/28/10 12/28/10 12/28/10 12/28/10 Wolf Creek - Unit 1 ii Revision54

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TAB - B 3.2 POWER DISTRIBUTION LIMITS (continued)

B 3.2.3-1 0

Amend. No. 123 12/18/99 B 3.2.3-2 0

Amend. No. 123 12/18/99 B 3.2.3-3 0

Amend. No. 123 12/18/99 B 3.2.4-1 0

Amend. No. 123 12/18/99 B 3.2.4-2 0

Amend. No. 123 12/18/99 B 3.2.4-3 48 DRR 10-3740 12/28/10 B 3.2.4-4 0

Amend. No. 123 12/18/99 B 3.2.4-5 48 DRR 10-3740 12/28/10 B 3.2.4-6 0

Amend. No. 123 12/18/99 B 3.2.4-7 48 DRR 10-3740 12/28/10 TAB - B 3.3 INSTRUMENTATION B 3.3.1-1 0

B 3.3.1-2 0

B 3.3.1-3 0

B 3.3.1-4 0

B 3.3.1-5 0

B 3.3.1-6 0

B 3.3.1-7 5

B 3.3.1-8 0

B 3.3.1-9 0

B 3.3.1-10 29 B 3.3.1-11 0

B 3.3.1-12 0

B 3.3.1-13 0

B 3.3.1-14 0

B 3.3.1-15 0

B 3.3.1-16 0.

B 3.3.1-17 0

B 3.3.1-18 0

B 3.3.1-19 0

B 3.3.1-20 0

B 3.3.1-21 0

B 3.3.1-22 0

B 3.3.1-23 9

B 3.3.1-24 0

B 3.3.1-25 0

B 3.3.1-26 0

B 3.3.1-27 0

B 3.3.1-28 2

B 3.3.1-29 1

B 3.3.1-30 1

B 3.3.1-31 0

B 3.3.1-32 20 B 3.3.1-33 48 B 3.3.1-34 20 B 3.3.1-35 19 B 3.3.1-36 20 B 3.3.1-37 20 B 3.3.1-38 20 B 3.3.1-39 25 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-1427 Amend. No. 123 Amend. No. 123 DRR 06-1984 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 02-0123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-0147 DRR 99-1624 DRR 99-1624 Amend. No. 123 DRR 04-1533 DRR 10-3740 DRR 04-1533 DRR 04-1414 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 06-0800 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 10/12/00 12/18/99 12/18/99 10/17/06 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 2/28/02 12/18/99 12/18/99 12/18/99 12/18/99 4/24/00 12/18/99 12/18/99 12/18/99 2/16/05 12/28/10 2/16/05 10/13/04 2/16/05 2/16/05 2/16/05 5/18/06 Wolf Creek - Unit 1 iii Revision 54

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.1-40 20 B 3.3.1-41 20 B 3.3.1-42 20 B 3.3.1-43 20 B 3.3.1-44 20 B 3.3.1-45 20 B 3.3.1-46 48 B 3.3.1-47 20 B 3.3.1-48 48 B 3.3.1-49 20 B 3.3.1-50 20 B 3.3.1-51 21 B 3.3.1-52 20 B 3.3.1-53 20 B 3.3.1-54 20 B 3.3.1-55 25 B 3.3.1-56 20 B 3.3.1-57 20 B 3.3.1-58 29 B 3.3.1-59 20 B 3.3.2-1 0

B 3.3.2-2 0

B 3.3.2-3 0

B 3.3.2-4 0

B 3.3.2-5 0

B 3.3.2-6 7

B 3.3.2-7 0

B 3.3.2-8 0

B 3.3.2-9 0

B 3.3.2-10 0

B 3.3.2-11 0

B 3.3.2-12 0

B 3.3.2-13 0

B 3.3.2-14 2

B 3.3.2-15 0

B 3.3.2-16 0

B 3.3.2-17 0

B 3.3.2-18 0

B 3.3.2-19 37 B 3.3.2-20 37 B 3.3.2-21 37 B 3.3.2-22 37 B 3.3.2-23 37 B 3.3.2-24 39 B 3.3.2-25 39 B 3.3.2-26 39 B 3.3.2-27 37 B 3.3.2-28 37 B 3.3.2-29 0

B 3.3.2-30 0

B 3.3.2-31 52 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 10-3740 DRR 04-1533 DRR 10-3740 DRR 04-1533 DRR 04-1533 DRR 05-0707 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 06-0800 DRR 04-1533 DRR 04-1533 DRR 06-1984 DRR 04-1533 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 01-0474 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-0147 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-1096 DRR 08-1096 DRR 08-1096 DRR 08-0503 DRR 08-0503 Amend. No. 123 Amend. No. 123 DRR 11-0724 2/16/05 2/16/05 2/16/05 2/16/05 2/16/05 2/16/05 12/28/10 2/16/05 12/28/10 2/16/05 2/16/05 4/20/05 2/16/05 2/16/05 2/16/05 5/18/06 2/16/05 2/16/05 10/17/06 2/16/05 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 5/1/01 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 4/24/00 12/18/99 12/18/99 12/18/99 12/18/99 4/8/08 4/8/08 4/8/08 4/8/08 4/8/08 8/28/08 8/28/08 8/28/08 4/8/08 4/8/08 12/18/99 12/18/99 4/11/11 Wolf Creek - Unit 1 iv Revision 54

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-32 52 B 3.3.2-33 0

B 3.3.2-34 0

B 3.3.2-35 20 B 3.3.2-36 20 B 3.3.2-37 20 B 3.3.2-38 20 B 3.3.2-39 25 B 3.3.2-40 20 B 3.3.2-41 45 B 3.3.2-42 45 B 3.3.2-43 20 B 3.3.2-44 20 B 3.3.2-45 20 B 3.3.2-46 54 B 3.3.2-47 43 B 3.3.2-48 37 B 3.3.2-49 20 B 3.3.2-50 20 B 3.3.2-51 43 B 3.3.2-52 43 B 3.3.2-53 43 B 3.3.2-54 43 B 3.3.2-55 43 B 3.3.2-56 43 B 3.3.2-57 43, B 3.3.3-1 0,

B 3.3.3-2 5,

B 3.3.3-3 0

B 3.3.3-4 0

B 3.3.3-5 0

B 3.3.3-6 8

B 3.3.3-7 21 B 3.3.3-8 8

B 3.3.3-9 8

B 3.3.3-10 19 B 3.3.3-11 19 B 3.3.3-12 21 B 3.3.3-13 21 B 3.3.3-14 8

B 3.3.3-15 8

B 3.3.4-1 0

B 3.3.4-2 9

B 3.3.4-3 15 B 3.3.4-4 19 B 3.3.4-5 1

B 3.3.4-6 9

B 3.3.5-1 0

B 3.3.5-2 1

B 3.3.5-3 1

DRR 11-0724 Amend. No. 123 Amend. No. 123 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 06-0800 DRR 04-1533 Amend. No. 187 (ETS)

Amend. No. 187 (ETS)

DRR 04-1533 DRR 04-1533 DRR 04-1533 DRR 11-2394 DRR 09-1416 DRR 08-0503 DRR 04-1533 DRR 04-1533 DRR 09-1416 DRR 09-1416 DRR 09-1416 DRR 09-1416 DRR 09-1416 DRR 09-1416 DRR 09-1416 Amend. No. 123 DRR 00-1427 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 01-1235 DRR 05-0707 DRR 01-1235 DRR 01-1235 DRR 04-1414 DRR 04-1414 DRR 05-0707 DRR 05-0707 DRR 01-1235 DRR 01-1235 Amend. No. 123 DRR 02-1023 DRR 03-0860 DRR 04-1414 DRR 99-1624 DRR 02-0123 Amend. No. 123 DRR 99-1624 DRR 99-1624 4/11/11 12/18/99 12/18/99 2/16/05 2/16/05 2/16/05 2/16105 5/18/06 2/16/05 3/5/10 3/5/10 2/16/05 2/16/05 2/16/05 11/16/11 9/2/09 4/8/08 2/16/05 2/16/05 9/2/09 9/2/09 9/2/09 9/2/09 9/2/09 9/2/09 9/2/09 12/18/99 10/12/00 12/18/99 12/18/99 12/18/99 9/19/01 4/20/05 9/19/01 9/19/01 10/12/04 10/12/04 4/20/05 4/20/05 9/19/01 9/19/01 12/18/99 2/28/02 7/10/03 10/12/04 12/18/99 2/28/02 12/18/99 12/18/99 12/18/99 Wolf Creek - Unit 1 V

Re~vision 54

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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

B 3.4.1-2 10 B 3.4.1-3 10 B 3.4.1-4 0

B 3.4.1-5 0

B 3.4.1-6 0

B 3.4.2-1 0

B 3.4.2-2 0

B 3.4.2-3 0

B 3.4.3-1 0

B 3.4.3-2 0

B 3.4.3-3

.0 B 3.4.3-4 0

B 3.4.3-5 0

B 3.4.3-6 0

B 3.4.3-7 0

B 3.4.4-1 0

B 3.4.4-2 29 B 3.4.4-3 0

B 3.4.5-1 0

B 3.4.5-2 53 B 3.4.5-3 29 B 3.4.5-4 0

Amend. No. 123 DRR 02-0411 DRR 02-0411 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 06-1984 Amend. No. 123 Amend. No. 123 DRR 11-1513 DRR 06-1984 Amend. No. 123 12/18/99 4/5/02 4/5/02 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 10/17/06 12/18/99 12/18/99 7/18/11 10/17/06 12/18/99 Wolf Creek - Unit 1 vi Revision 54

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TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5-5 12 B 3.4.5-6 12 B 3.4.6-1 53 B 3.4.6-2 29 B 3.4.6-3 12 B 3.4.6-4 12 B 3.4.6-5 12 B 3.4.7-1 12 B 3.4.7-2 17 B 3.4.7-3 42 B 3.4.7-4 42 B 3.4.7-5 12 B 3.4.8-1 53 B 3.4.8-2 42 B 3.4.8-3 42 B 3.4.8-4 42 B 3.4.9-1 0

B 3.4.9-2 0

B 3.4.9-3 0

B 3.4.9-4 0

B 3.4.10-1 5

B 3.4.10-2 5

B 3.4.10-3 0

B 3.4.10-4 32 B 3.4.11-1 0

B 3.4.11-2 1

B 3.4.11-3 19 B 3.4.11-4 0

B 3.4.11-5 1

B 3.4.11-6 0

B 3.4.11-7 32 B 3.4.12-1 1

B 3.4.12-2 1

B 3.4.12-3 0

B 3.4.12-4 1

B 3.4.12-5 1

B 3.4.12-6 1

B 3.4.12-7 0

B 3.4.12-8 1

B 3.4.12-9 19 B 3.4.12-10 0

B 3.4.12-11 0

B 3.4.12-12 32 B 3.4.12-13 0

B 3.4.12-14 32 B 3.4.13-1 0

B 3.4.13-2 29 B 3.4.13-3 29 B 3.4.13-4 35 B 3.4.13-5 35 B 3.4.13-6 29 (continued)

DRR 02-1062 DRR 02-1062 DRR 11-1513 DRR 06-1984 DRR 02-1062 DRR 02-1062 DRR 02-1062 DRR 02-1062 DRR 04-0453 DRR 09-1009 DRR 09-1009 DRR 02-1062 DRR 11-1513 DRR 09-1009 DRR 09-1009 DRR 09-1009 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-1427 DRR 00-1427 Amend. No. 123 DRR 07-0139 Amend. No. 123 DRR 99-1624 DRR 04-1414 Amend. No. 123 DRR 99-1624 Amend. No. 123 DRR 07-0139 DRR 99-1624 DRR 99-1624 Amend. No. 123 DRR 99-1624 DRR 99-1624 DRR 99-1624 Amend. No. 123 DRR 99-1624 DRR 04-1414 Amend. No. 123 Amend. No. 123 DRR 07-0139 Amend. No. 123 DRR 07-0139 Amend. No. 123 DRR 06-1984 DRR 06-1984 DRR 07-1553 DRR 07-1553 DRR 06-1984 9/26/02 9/26/02 7/18/11 10/17/06 9/26/02 9/26/02 9/26/02 9/26/02 5/26/04 7/16/09 7/16/09 9/26/02 7/18/11 7/16/09 7/16/09 7/16/09 12/18/99 12/18/99 12/18/99 12/18/99 10/12/00 10/12/00 12/18/99 2/7/07 12/18/99 12/18/99 10/12/04 12/18/99 12/18/99 12/18/99 2/7/07 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 10/12/04 12/18/99 12/18/99 2/7/07 12/18/99 2/7107 12/18/99 10/17/06 10/17/06 9/28/07 9/28/07 10/17/06 Wolf Creek - Unit I vii Revision 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES..'.

PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT 13)

DATE EFFECTIVE/

IMPLEMENTED (4)

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

B 3.4.14-1 0

Amend. No. 123 12/18/99 B 3.4.14-2 0

Amend. No. 123 12/18/99 B 3.4.14-3 0

Amend. No. 123 12/18/99 B 3.4.14-4 0

Amend. No. 123 12/18/99 B 3.4.14-5 32 DRR 07-0139 2/7/07 B 3.4.14-6 32 DRR 07-0139 2/7/07 B 3.4.15-1 31 DRR 06-2494 12/13/06 B 3.4.15-2 31 DRR 06-2494 12/13/06, B 3.4.15-3 33 DRR 07-0656 5/1/07 B 3.4.15-4 33 DRR 07-0656 5/1/07 B 3.4.15-5 31 DRR 06-2494 12/13/06 B 3.4.15-6 31 DRR 06-2494 12/13/06 B 3.4.15-7 31 DRR 06-2494 12/13/06 B 3.4.15-8 31 DRR 06-2494 12/13/06 B 3.4.16-1 31 DRR 06-2494 12/13/06 B 3.4.16-2 31 DRR 06-2494 12/13/06 B 3.4.16-3 31 DRR 06-2494 12/13/06 B 3.4.16-4 31 DRR 06-2494 12/13/06 B 3.4.16-5 31 DRR 06-2494 12/13/06 B 3.4.17-1 29 DRR 06-1984 10/17/06 B 3.4.17-2 44 DRR 09-1744 10/28/09 B 3.4.17-3 52 DRR 11-0724 4/11/11 B 3.4.17-4 29 DRR 06-1984 10/17/06 B 3.4.17-5 29 DRR 06-1984 10/17/06 B 3.4.17-6 29 DRR 06-1984 10/17/06 B 3.4.17-7 44 DRR 09-1744 10/28/09 TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1-1 0

Amend. No. 123 12/18/99 B 3.5.1-2 0

Amend. No. 123 12/18/99 B 3.5.1-3 0

Amend. No. 123 12/18/99 B 3.5.1-4 0

Amend. No. 123 12/18/99 B 3.5.1-5 1

DRR 99-1624 12/18/99 B 3.5.1-6 1

DRR 99-1624 12/18/99 B 3.5.1-7 16 DRR 03-1497 11/4/03 B 3.5.1-8 1

DRR 99-1624 12/18/99 B 3.5.2-1 0

Amend. No. 123 12/18/99 B 3.5.2-2 0

Amend. No. 123 12/18/99 B 3.5.2-3 0

Amend. No. 123 12/18/99 B 3.5.2-4 0

Amend. No. 123 12/18/99 B 3.5.2-5 41 DRR 09-0288 3/20/09 B 3.5.2-6 42 DRR 09-1009 7/16/09 B 3.5.2-7 42 DRR 09-1009 7/16/09 B 3.5.2-8 38 DRR 08-0624 5/1/08 B 3.5.2-9 38 DRR 08-0624 5/1/08 B 3.5.2-10 41 DRR 09-0288 3/20/09 B 3.5.2-11 41 DRR 09-0288 3/20/09 B 3.5.3-1 16 DRR 03-1497 11/4/03 B 3.5.3-2 19 DRR 04-1414 10/12/04 B 3.5.3-3 19 DRR 04-1414 10/12/04 B 3.5.3-4 16 DRR 03-1497 11/4/03 Wolf Creek - Unit 1 viii Rev.ision 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

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

B 3.5.4-1 0

Amend. No. 123 12/18/99 B 3.5.4-2 0

Amend. No. 123 12/18/99 B 3.5.4-3 0

Amend. No. 123 12/18/99 B 3.5.4-4 0

Amend. No. 123 12/18/99 B 3.5.4-5 0

Amend. No. 123 12/18/99 B 3.5.4-6 26 DRR 06-1350 7/24/06 B 3.5.5-1 21 DRR 05-0707 4/20/05 B 3.5.5-2 21 DRR 05-0707 4/20/05 B 3.5.5-3 2

Amend. No. 132 4/24/00 B 3.5.5-4 21 DRR 05-0707 4/20/05 TAB - B 3.6 CONTAINMENT SYSTEMS B 3.6.1-1 0

B 3.6.1-2 0

B 3.6.1-3 0

B 3.6.1-4 17 B 3.6.2-1 0

B 3.6.2-2 0

B 3.6.2-3 0

B 3.6.2-4 0

B 3.6.2-5 0

B 3.6.2-6 0

B 3.6.2-7 0

B 3.6.3-1 0

B 3.6.3-2 0

B 3.6.3-3 0

B 3.6.3-4 49 B 3.6.3-5 49 B 3.6.3-6 49 B 3.6.3-7 41 B 3.6.3-8 36 B 3.6.3-9 36 B 3.6.3-10 8

B 3.6.3-11 36 B 3.6.3-12 36 B 3.6.3-13 50 B 3.6.3-14 36 B 3.6.3-15 39 B 3.6.3-16 39 B 3.6.3-17 36 B 3.6.3-18

.36 B 3.6.3-19 36 B 3.6.4-1 39 B 3.6.4-2 0

B 3.6.4-3 0

B 3.6.5-1 0

B 3.6.5-2 37.

B 3.6.5-3 13 B 3.6.5-4 0

B 3.6.6-1 42 B 3.6.6-2 0

Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 04-0453 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 11-0014 DRR 11-0014 -

DRR 11-0014 DRR 09-0288 DRR 08-0255 DRR 08-0255 DRR 01-1235 DRR 08-0255 DRR 08-0255 DRR 11-0449 DRR 08-0255 DRR 08-1096 DRR 08-1096 DRR 08-0255 DRR 08-0255 DRR 08-0255 DRR 08-1096 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 08-0503 DRR 02-1458 Amend. No. 123 DRR 09-1009 Amend. No. 123 12/18/99 12/18/99 12/18/99 5/26/04 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 1/31/11 1/31/11 1/31/11 3/20/09 3/11/08 3/11/08 9/19/01 3/11/08 3/11/08 3/9/11 3/11/08 8/28/08 8/28/08 3/11/08 3/11/08 3/11/08 8/28/08 12/18/99 12/18/99 12/18199 4/8/08 12/03/02 12/18/99 7/16/09 12/18/99 Revision 54 Wolf Creek - Unit 1 ix

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES".'

PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT (3' DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.6-3 37 DRR 08-0503 4/8/08 B 3.6.6-4 42 DRR 09-1009 7/16/09 B 3.6.6-5 0

Amend. No. 123 12/18/99 B 3.6.6-6 18 DRR 04-1018 9/1/04 B 3.6.6-7 0

Amend. No. 123 12/18/99 B 3.6.6-8 32 DRR 07-0139 2/7/07 B 3.6.6-9 32 DRR 07-0139 2/7/07 B 3.6.7-1 0

Amend. No. 123 12/18/99 B 3.6.7-2 42 DRR 09-1009 7/16/09 B 3.6.7-3 0

Amend. No. 123 12/18/99 B 3.6.7-4 29 DRR 06-1984 10/17/06 B 3.6.7-5 42 DRR 09-1009 7/16/09 TAB - B 3.7 PLANT SYSTEMS B 3.7.1-1 B 3.7.1-2 B 3.7.1-3 B 3.7.1-4 B 3.7.1-5 B 3.7.1-6 B 3.7.2-1 B 3.7.2-2 B 3.7.2-3 B 3.7.2-4 B 3.7.2-5 B 3.7.2-6 B 3.7.2-7 B 3.7.2-8 B 3.7.2-9 B 3.7.2-10 B 3.7.2-11 B 3.7.3-1 B 3.7.3-2 B 3.7.3-3 B 3.7.3-4 B 3.7.3-5 B 3.7.3-6 B 3.7.3-7 B 3.7.3-8 B 3.7.3-9 B 3.7.3-10 B 3.7.3-11 B 3.7.4-1 B 3.7.4-2 B 3.7.4-3 B 3.7.4-4 B 3.7.4-5 B 3.7.5-1 0

0 0

0 32 32 44 44 44 44 44 44 44 44 44 44 44 37 50 37 37 37 37 37 37 37 38-37 1

1 19 191 54 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 07-0139 DRR 07-0139 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 08-0503 DRR 11-0449 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0503 DRR 08-0624 DRR 08-0503 DRR 99-1624 DRR 99-1624 DRR 04-1414 DRR 04-1414 DRR 99-1624 DRR 11-2394 12/18/99 12/18/99 12/18/99 12/18/99 2/7/07 2/7/07 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 10/28/09 4/8/08 3/9/11 4/8/08 4/8/08 4/8/08 4/8/08 4/8/08 4/8/08 4/8/08 5/1/08 4/8/08 12/18/99 12118/99 10/1 2/04 10/12/04 12/18/99 11/16/11 Wolf Creek - Unit I X

Revi~sion 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.7 PLANT SYSTEMS B 3.7.5-2 B 3.7.5-3 B 3.7.5-4 B 3.7.5-5 B 3.7.5-6 B 3.7.5-7 B 3.7.5-8 B 3.7.5-9 B 3.7.6-1 B 3.7.6-2 B 3.7.6-3 B 3.7.7-1 B 3.7.7-2 B 3.7.7-3 B 3.7.7-4 B 3.7.8-1 B 3.7.8-2 B 3.7.8-3 B 3.7.8-4 B 3.7.8-5 B 3.7.9-1 B 3.7.9-2 B 3.7.9-3 B 3.7.9-4 B 3.7.10-1 B 3.7.10-2 B 3.7.10-3 B 3.7.10-4 B 3.7.10-5 B 3.7.10-6 B 3.7.10-7 B 3.7.10-8 B 3.7.10-9 B 3.7.11-1 B 3.7.11-2 B 3.7.11-3 B 3.7.11-4 B 3.7.12-1 B 3.7.13-1 B 3.7.13-2 B 3.7.13-3 B 3.7.13-4 B 3.7.13-5 B 3.7.13-6 B 3.7.13-7 B 3.7.13-8 B 3.7.14-1 B 3.7.15-1 B 3.7.15-2 B 3.7.15-3 B 3.7.16-1 (continued) 54 0

44 44 44 32 14 32 0

0 0

0 1

0 0

0 3

3 3

3 41 41 41 41 41 41 41 41 41 0

0 0

24 1

42 1

1 12 1

1 0

0 0

0 5

DRR 11-2394 Amend. No. 123 DRR 09-1744 DRR 09-1744 DRR 09-1744 DRR 07-0139 DRR 03-0102 DRR 07-0139 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 99-1624 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 134 Amend. No. 134 Amend. No. 134 Amend. No. 134 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 DRR 09-0288 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 06-0051 DRR 99-1624 DRR 09-1009 DRR 99-1624 DRR 99-1624 DRR 02-1062 DRR 99-1624 DRR 99-1624 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-1427 11/16/11 12/18/99 10/28/09 10/28/09 10/28/09 2/7/07 2/12/03 2/7/07 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 7/14/00 7/14/00 7/14/00 7/14/00 3/20/09 3/20/09 3/20/09 3/20/09 3/20/09 3/20/09 3/20/09 3/20/09 3/20/09 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 2/28/06 12/18/99 7/16/09 12/18/99 12/18/99 9/26/02 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 10/12/00 Wolf Creek - Unit 1 xi Revision 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.16-2 23 DRR 05-1995 9/28/05 B 3.7.16-3 5

DRR 00-1427 10/12/00 B 3.7.17-1 7

DRR 01-0474 5/1/01 B 3.7.17-2 7

DRR 01-0474 5/1/01 B 3.7.17-3 5

DRR 00-1427 10/12/00 B 3.7.18-1 0

Amend. No. 123 12/18/99 B 3.7.18-2 0

Amend. No. 123 12/18/99 B 3.7.18-3 0

Amend. No. 123 12/18/99 B 3.7.19-1 44 DRR 09-1744 10/28/09 B 3.7.19-2 54 DRR 11-2394 11/16/11 B 3.7.19-3 54 DRR 11-2394 11/16/11 B 3.7.19-4 54 DRR 11-2394 11/16/11 B 3.7.19-5 54 DRR 11-2394 11/16/11 B 3.7.19-6 54 DRR 11-2394 11/16/11 B 3.7.19-7 54 DRR 11-2394 11/16/11 TAB - B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1-1 54 B 3.8.1-2 0

B 3.8.1-3 47 B 3.8.1-4 54 B 3.8.1-5 54 B 3.8.1-6 25 B 3.8.1-7 26 B 3.8.1-8 35 B 3.8.1-9 42 B 3.8.1-10 39 B 3.8.1-11 36 B 3.8.1-12 47 B 3.8.1-13 47 B 3.8.1-14 47 B 3.8.1-15 47 B 3.8.1-16 26 B 3.8.1-17 26 B 3.8.1-18 26 B 3.8.1-19 26 B 3.8.1-20 26 B 3.8.1-21 33 B 3.8.1-22 33 B 3.8.1-23 40 B 3.8.1-24 33 B 3.8.1-25 33 B 3.8.1-26 33 B 3.8.1-27 33 B 3.8.1-28 33 B 3.8.1-29 54 B 3.8.1-30 33 B 3.8.1-31 33 B 3.8.1-32 33 B 3.8.1-33 39 B 3.8.1-34 47 DRR 11-2394 Amend. No. 123 DRR 10-1089 DRR 11-2394 DRR 11-2394 DRR 06-0800 DRR 06-1350 DRR 07-1553 DRR 09-1009 DRR 08-1096 DRR 08-0255 DRR 10-1089 DRR 10-1089 DRR 10-1089 DRR 10-1089 DRR 06-1350 DRR 06-1350 DRR 06-1350 DRR 06-1350 DRR 06-1350 DRR 07-0656 DRR 07-0656 DRR 08-1846 DRR 07-0656 DRR 07-0656 DRR 07-0656 DRR 07-0656 DRR 07-0656 DRR 11-2394 DRR 07-0656 DRR 07-0656 DRR 07-0656 DRR 08-1096 DRR 10-1089 11/16/11 12/18/99 6/16/10 11/16/11 11/16/11 5/18/06 7/24/06 9/28/07 7/16/09 8/28/08 3/11/08 6/16/10 6/16/10 6/16/10 6/16/10 7/24/06 7/24/06 7/24/06 7/24/06 7/24/06 5/1/07 5/1/07 12/9/08 5/1/07 5/1/07 5/1/07 5/1/07 5/1/07 11/16/11 5/1/07 5/1/07 5/1/07 8/28/08 6/16/10 Wolf Creek-Unit 1 xii Revision 54

LIST OF EFFECTIVE PAGES -'TECHNICAL SPECIFICATION BASES PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2-1 0

B 3.8.2-2 0

B 3.8.2-3 0

B 3.8.2-4 0

B 3.8.2-5 12 B 3.8.2-6 12 B 3.8.2-7 12 B 3.8.3-1 1

B 3.8.3-2 0

B 3.8.3-3 0

B 3.8.3-4 1

B 3.8.3-5 0

B 3.8.3-6 0

B 3.8.3-7 12 B 3.8.3-8 1

B 3.8.3-9 0

B 3.8.4-1 0

B 3.8.4-2 0

B 3.8.4-3 0

B 3.8.4-4 0

B 3.8.4-5 50 B 3.8.4-6 50 B 3.8.4-7 6

B 3.8.4-8 0

B 3.8.4-9 2

B 3.8.5-1 0

B 3.8.5-2 0

B 3.8.5-3 0

B 3.8.5-4 12 B 3.8.5-5 12 B 3.8.6-1 0

B 3.8.6-2 0

B 3.8.6-3 0

B 3.8.6-4 0

B 3.8.6-5 0

B 3.8.6-6 0

B 3.8.7-1 0

B 3.8.7-2 5

B 3.8.7-3 0

B 3.8.7-4

.0 B 3.8.8-1 0

B 3.8.8-2 0

B 3.8.8-3 0

B 3.8.8-4 12 B 3.8.8-5 12 B 3.8.9-1 54 B 3.8.9-2 54 B 3.8.9-3 54 B 3.8.9-4 0

B 3.8.9-5 0

B 3.8.9-6 0

(continued)

Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 02-1062 DRR 02-1062 DRR 02-1062 DRR 99-1624 Amend. No. 123 Amend. No. 123 DRR 99-1624 Amend. No. 123 Amend. No. 123 DRR 02-1062 DRR 99-1624 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 11-0449 DRR 11-0449 DRR 00-1541 Amend. No. 123 DRR 00-0147 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 02-1062 DRR 02-1 062 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 00-1427 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 Amend. No. 123 DRR 02-1062 DRR 02-1062 DRR 11-2394 DRR 11-2394 DRR 11-2394 Amend. No. 123 Amend. No. 123 Amend. No. 123 12/18/99 12/18/99 12/18/99 12/18/99 9/26/02 9/26/02 9/26/02 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 9/26/02 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 3/9/11 3/9/11 3/13/01 12/1 /99 4/24/00 12/18/99 12/18/99 12/18/99 9/26/02 9/26/02 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 10/12/00 12/18/99 12/18/99 12/18/99 12/18/99 12/18/99 9/26/02 9/26/02 11/16/11 11/16/11 11/16/11 12/18/99 12/18/99 12/18/99 Wolf Creek - Unit 1 xiii Revision 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (1)

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.9-7 0

Amend. No. 123 12/18/99 B 3.8.9-8 1

DRR 99-1624 12/18/99 B 3.8.9-9 0

Amend. No. 123 12/18/99 B 3.8.10-1 0

Amend. No. 123 12/18/99 B 3.8.10-2 0

Amend. No. 123 12/18/99 B 3.8.10-3 0

Amend. No. 123 12/18/99 B 3.8.10-4 0

Amend. No. 123 12/18/99 B 3.8.10-5 12 DRR 02-1062 9/26/02 B 3.8.10-6 12 DRR 02-1062 9/26/02 TAB - B 3.9 REFUELING OPERATIONS B 3.9.1-1 0

Amend. No. 123 12/18/99 B 3.9.1-2 19 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 51 DRR 11-0664 3/21/11 B 3.9,3-3 51 DRR 11-0664 3/21/11 B 3.9.3-4 53 DRR 11-1513 7/18/11 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 2/7107 B 3.9.6-1 0

Amend. No. 123 12/18/99 B 3.9.6-2 42 DRR 09-1009 7/16/09 B 3.9.6-3 42 DRR 09-1009 7/16/09 B 3.9.6-4 42 DRR 09-1009 7/16/09 B 3.9.7-1 25 DRR 06-0800 5/18/06 B 3.9.7-2 0

Amend. No. 123 12/18/99 B 3.9.7-3 0

Amend. No. 123 12/18/99 Wolf Creek - Unit 1 xiV Revision 54

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE (")

REVISION NO. (2)

CHANGE DOCUMENT (3)

DATE EFFECTIVE/

IMPLEMENTED (4)

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

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

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

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

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

Wolf Creek - Unit 1 XV Revision 54

ML12080A216

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