Text

License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function
	ML15021A127
Person / Time
Site:	Cooper
Issue date:	01/15/2015
From:	Limpias O; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2014087
	Download: ML15021A127 (69)
	v • d • e

N Nebraska Public Power District Always there when you need us 50.90 NLS2014087 January 15, 2015 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function Cooper Nuclear Station, Docket No. 50-298, License No. DPR-46

Dear Sir or Madam:

The purpose of this letter is for the Nebraska Public Power District (NPPD) to request an amendment to Facility Operating License DPR-46 in accordance with the provisions of 10 CFR 50.4 and 10 CFR 50.90 to revise the Cooper Nuclear Station (CNS) Technical Specifications (TS). The proposed amendment will add new section, TS 3.6.1.9, Residual Heat Removal (RHR) Containment Spray and will add related drywell pressure switches to TS 3.3.5.1, Emergency Core Cooling System Instrumentation. The Containment Spray requirements are currently located in the Technical Requirements Manual. The RHR Containment Spray function is necessary to maintain the drywell within design temperature limits during a small steam line break accident.

NPPD requests approval of the proposed amendment by January 19, 2016. This allows one year for Nuclear Regulatory Commission (NRC) review. Once approved, the amendment will be implemented within 60 days.

Attachment I provides a description of the TS changes, the basis for the amendment, the no significant hazards consideration evaluation pursuant to 10 CFR 50.91(a)(1), and the environmental consideration pursuant to 10 CFR 51.22. Attachment 2 provides the marked up TS pages. Attachment 3 provides the final typed format TS pages to be issued with the amendment. Attachment 4 provides conforming additions to the TS Bases for NRC information.

No formal licensee commitments are being made for this proposed amendment.

This proposed TS change has been reviewed by the necessary safety review committees (Station Operations Review Committee and Safety Review and Audit Board). Amendments to the CNS Facility Operating License through Amendment 249, issued December 12, 2014, have been incorporated into this request.

COOPER NUCLEAR STATION PO. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2014087 Page 2 of 2 By copy of this letter and its attachments, the appropriate State of Nebraska official is notified in accordance with 10 CFR 50.91 (b)(1). Copies are also provided to the NRC Region IV office and the Senior Resident Inspector in accordance with 10 CFR 50.4(b)(1).

Should you have any question concerning this matter, please contact Jim Shaw, Licensing Manager, at (402) 825-2788.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on ,\ *

(Date) 0.*iN. Limpias ' /

Vice President - Nuclear and Chief Nuclear Officer

/dv Attachments: 1. License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function

2. Proposed Technical Specification Revision (Markup)

3. Proposed Technical Specification Revision (Final Typed Format)

4. Proposed Technical Specification Bases Revision (Information Only) cc: Regional Administrator w/attachments USNRC - Region IV Senior Resident Inspector w/attachments USNRC - CNS Nebraska Health and Human Services w/attachments Department of Regulation and Licensure Cooper Project Manager w/attachments USNRC - NRR Project Directorate IV- l NPG Distribution w/o attachments CNS Records w/attachments

NLS2014087 Attachment I Page 1 of 14 Attachment 1 License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function Cooper Nuclear Station, NRC Docket No. 50-298, License No. DPR-46 Revised Pages 3.3-32, 3.3-39, 3.6-25 thru 3.6-42 (Page 3.6-25 and 3.6.26 reflect new Technical Specifications (TS) section 3.6.1.9.

Pages 3.6-27 thru 3.6-42 are due to repagination of subsequent sections.)

1.0 Summary Description 2.0 Detailed Description 2.1 Proposed Change 2.2 Need for Change 2.3 Bases Changes 3.0 Technical Evaluation 3.1 System Description 3.2 Updated Safety Analysis Report (USAR) Safety Design Basis 3.3 TS Bases Safety Analysis 3.4 Technical Justification of Proposed Changes 3.5 USAR Accident Analysis Impact 3.6 Conclusion 4.0 Regulatory Safety Analysis 4.1 Applicable Regulatory Requirements 4.2 Precedent 4.3 No Significant Hazards Consideration 4.4 Conclusion 5.0 Environmental Consideration 6.0 References

NLS2014087 Attachment I Page 2 of 14 1.0

SUMMARY

DESCRIPTION This is a request to amend the Cooper Nuclear Station (CNS) Facility Operating License DPR-46 Technical Specifications (TS). The proposed change would move the Residual Heat Removal (RHR) Containment Spray system requirements from the Technical Requirements Manual (TRM) to TS.

Nebraska Public Power District requests approval of the proposed amendment by January 19, 2016 which allows one year for Nuclear Regulatory Commission (NRC) review. Upon receipt of the approved amendment, CNS will implement the change within 60 days.

2.0 DETAILED DESCRIPTION 2.1 Proposed Change The proposed change would revise the CNS Operating License to add a Limiting Condition for Operation (LCO), Applicability, Required Actions, Completion Times and Surveillance Requirements for the RHR Containment Spray system consistent with the guidance in NUREG-1433, Revision 4, "Standard Technical Specifications General Electric BWR/4 Plants" (Ref. 5). New TS Section 3.6.1.9 will be added with the title RHR Containment Spray. In addition, the Drywell Pressure - High function that supports RHR Containment Spray will be relocated from the TRM to TS 3.3.5.1, Emergency Core Cooling System (ECCS) Instrumentation.

The requirements for the RHR Containment Spray function are currently contained in TRM Section T3.6.1, RHR Containment Spray. The requirements for the Drywell Pressure - High function are currently contained in TRM Section T3.3.2, ECCS and Reactor Core Isolation Cooling Instrumentation. These TRM sections established specific guidance and criteria related to the applicability, operation, and testing for the RHR Containment Spray system. The TRM requirements for the RHR Containment Spray system will be removed once the TS requirements are approved.

2.2 Need for Change This change is being proposed because the RHR Containment Spray function is necessary to maintain the drywell within design temperature limits during a small steam line break (SSLB).

In 1998, CNS converted from custom TS to Standard TS (NUREG-1433). At that time, it was believed that the Containment Spray system did not have a safety function. The conversion document stated, "Neither drywell spray nor suppression pool spray is credited in any DBA [Design Basis Accident] (i.e., they are not needed to function to mitigate the consequences of any design basis accident). They are considered secondary actions in the emergency procedures. Therefore, the drywell and torus sprays are not risk significant. As such, this requirement is not required to be in the

NLS2014087 Attachment I Page 3 of 14 Improved Technical Specifications (ITS) to provide adequate protection of the public health and safety."

In 2000, a concern was entered into the corrective action program that identified a discrepancy between the containment peak temperature utilized by the Environmental Qualification (EQ) program and the SSLB peak temperature documented in the Plant Unique Analysis Report. This root cause determined that in 1985 the EQ program owner made a technical error in utilizing the DBA Loss of Coolant Accident (LOCA) for the most severe design basis event in the drywell. The root cause initiated an action to develop Engineering Evaluation (EE)01-035 (Ref. 1) which determined that the Containment Spray function of RHR was necessary for limiting drywell temperature following a design basis SSLB. EE 01-035 determined that Containment Spray would be added to the TRM based on 10 CFR 50.36(c)(2)(iii) which states, "A licensee is not required to propose to modify technical specifications that are included in any license issued before August 18, 1995, to satisfy the criteria in paragraph (c)(2)(ii) of this section." Since CNS' Operating License was issued January 18, 1974 it was believed that this paragraph provided an exemption from adding RHR Containment Spray to the TS.

In 2014, during a review of external operating experience, it was noted that a utility had identified the same issue of mitigating a small break LOCA at one of their nuclear facilities and was pursuing a license amendment to move Drywell Spray from the TRM to TS. This operating experience was placed in the CNS corrective action program for evaluation. As part of this evaluation, a conference call with the Nuclear Reactor Regulation TS Branch was conducted. The discussion determined that CNS was misapplying the requirement of 10 CFR 50.36(c)(2)(iii). It did not provide an exemption as CNS had thought and compliance with 10 CFR 50.36(c)(2)(ii) was necessary.

10 CFR 50.36(c)(2)(ii) states, "A technical specification limiting condition for operation of a nuclear reactor must be established for each item meeting one or more of the following criteria:

(A) Criterion 1. Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary.

(B) Criterion2. A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

(C) Criterion3. A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or

NLS2014087 Page 4 of 14 transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

(D) Criterion 4. A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety."

RHR Containment Spray meets the requirements of Criterion 3 as it is needed to maintain the drywell within design temperature limits during a SSLB.

2.3 Bases Changes TS Bases for the new TS Section 3.6.1.9 and for the revision to the existing TS 3.3.5.1 are provided in Attachment 4 for the NRCs information. These Bases revisions will be made as an implementing action pursuant to TS 5.5.10, TS Bases Control Program, following issuance of the approved amendment.

3.0 TECHNICAL EVALUATION

3.1 System Description

CNS is a boiling water reactor (BWR) of General Electric design BWR4, with a Mark I containment. Following a DBA, the RHR Containment Spray System removes heat from the drywell and suppression chamber airspace. The drywell is designed to absorb the sudden input of heat from a DBA. The heat addition results in increased steam in the drywell, which increases primary containment temperature and pressure. Steam blowdown from a DBA can also bypass the suppression pool and end up in the suppression chamber airspace. Removal of heat from the suppression chamber and the drywell so that the pressure and temperature inside primary containment remain within analyzed design limits, is provided by two redundant RHR Containment Spray subsystems.

Each of the two RHR Containment Spray subsystems contain two pumps (one divisionally powered and one non-divisionally powered pump) and one heat exchanger, which are manually initiated and independently controlled. The two subsystems perform the Containment Spray function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the drywell and suppression pool spray spargers. Thus, both suppression pool cooling and containment spray functions are performed when the RHR Containment Spray System is initiated. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR Containment Spray subsystem is sufficient to condense the steam in both the drywell and the suppression chamber airspace during the postulated DBA.

The Drywell Pressure-High function serves as an interlock permissive to allow the RHR system to be manually aligned from the Low Pressure Coolant Injection (LPCI)

NLS2014087 Page 5 of 14 mode to the Containment Spray mode after containment pressure has increased above the trip setting. The permissive ensures that containment pressure is elevated before the manual transfer is allowed. This ensures that LPCI is available to prevent or minimize fuel damage until such time that the operator determines that containment pressure control is needed. The pressure switches associated with the Drywell Pressure-High function also provide an isolation of the Containment Spray mode of RHR on decreasing containment pressure following manual actuation of the system. This isolation function is not credited in accident analysis for mitigating excessive depressurization of the containment, therefore is not a TS function.

3.2 Updated Safety Analysis Report (USAR) Safety Design Basis Primary Containment has the capability of withstanding the conditions which could result from any of the postulated design basis accidents for which Primary Containment is assumed to be functional, including the largest amount of energy release and mass flow associated with the accident.

Primary Containment has a margin for metal-water reactions and other chemical reactions subsequent to any postulated design basis accident for which Primary Containment is assumed to be functional, consistent with the performance objectives of the nuclear safety systems and engineered safeguards.

Primary Containment has the capability to maintain its functional integrity during any postulated external or environmental event.

Primary Containment has the capability to be filled with water as an accident recovery method for any postulated design basis accident in which a breach of the Reactor Coolant Pressure Boundary cannot be sealed.

Primary Containment, in conjunction with other nuclear safety systems and engineered safeguards, has the capability to limit leakage during any of the postulated design basis accidents for which it is assumed to be functional such that offsite doses do not exceed the guideline values set forth in 10 CFR 100 (or 10 CFR 50.67 for a LOCA).

Primary Containment has the capability to rapidly isolate pipes or ducts necessary to establish the primary containment barrier.

Primary Containment has the capability to store sufficient water to supply the ECCS requirements.

Primary Containment has the capability to be maintained during normal operation within the range of initial conditions assumed in the "Station Safety Analysis."

NLS2014087 Page 6 of 14 3.3 TS Bases Safety Analysis Reference I contains the results of analyses used to predict primary containment pressure and temperature following the design basis loss of coolant accident. The analyses demonstrate that the temperature and pressure reduction capacity of the RHR Containment Spray System is adequate to maintain the primary containment conditions within design limits. The RHR Containment Spray system satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

3.4 Technical Justification of Proposed Changes The EQ program was utilizing the DBA LOCA profile for qualification of equipment to satisfy 10 CFR 50.49. Subsequently, it has been determined that the limiting primary containment temperature response occurs during a SSLB. A SSLB results in the limiting temperature response due to the superheating of steam as it exits the break, causing the drywell airspace temperature to rise above the saturation temperature. This superheated condition is only applicable to SSLB, since other break scenarios result in a liquid-steam mixture exiting the break and heat-up of the containment is limited to the saturation temperature and therefore is less restrictive than a SSLB. Break sizes larger than one square foot result in vessel swell and a two phase mixture that results in less limiting temperature profiles than the smaller steam line breaks that don't result in rapid reactor pressure vessel (RPV) depressurization and vessel swell.

General Electric (GE) report NEDO-24573, "Mark I Containment Program Plant Unique Load Definition - Cooper Nuclear Station," (Ref. 6) shows a constant 340°F drywell air space temperature response for a small break accident. This 340TF is a bounding assumption based upon constant enthalpy expansion of steam exiting a break.

This represents the maximum superheated condition possible for expansion from saturated steam at RPV pressure to containment pressure. A plant specific realistic model was developed to determine drywell airspace temperature response. It was also necessary to determine the drywell liner temperature response for these elevated containment atmospheric temperatures. The drywell liner design temperature is 281 F and it is necessary to show that this design temperature would not be exceeded.

Nebraska Public Power District (NPPD) calculation NEDC 94-034D (Ref. 2) documents the acceptance of GE report GE-NE-T23-00786-00-02, "Cooper Nuclear Station Containment Analysis Project - Small Steam Line Break Analysis" (Ref. 7).

This calculation was completed to provide a bounding drywell air temperature profile for response of SSLB for EQ qualification and determine the effects on drywell liner temperature. From this report it is evident that Containment Spray is required to mitigate the effects of a SSLB to ensure the drywell liner design temperature is not exceeded. The report shows that given the licensing basis ten minute delay time for operator manual action and conditions requiring containment spray per the Emergency Operating Procedures guidance being met, the drywell liner design temperature is not

NLS2014087 Attachment I Page 7 of 14 exceeded for a SSLB. It also shows that as soon as containment spray is initiated, the drywell air space temperature rapidly returns to the saturation temperature.

NPPD calculation NEDC 00-49 determined the minimum and maximum containment spray flow rates of the RHR system with one pump operation. With concurrent drywell and suppression pool spray operation, the calculation shows the minimum total containment spray flow rate will be 7177 gallons per minute (gpm), with 6480 gpm drywell spray and 697 gpm for suppression pool spray. The minimum total spray flow to mitigate the SSLB was calculated to be 6500 gpm, 6100 gpm for the drywell and 400 gpm for the suppression pool. The new Surveillance Requirement (SR), SR 3.6.1.9.2, will verify each required RHR pump will develop the minimum flow rate needed for the SSLB. A flow rate of >7700 gpm was selected for the SR to bound the analytical minimum of 6500 gpm and be consistent with the flow requirements of SR 3.6.2.3.2 for RHR Suppression Pool Cooling. It is not feasible to validate actual flowrate through the drywell or suppression spray nozzles since this would cause flooding of plant equipment.

The Conditions, Required Actions and Completion Times being used in LCO 3.6.1.9 are consistent with those previously used in the TRM. The TRM contained one Surveillance Requirement for verifying system valves are in the correct position. This SR is moved to the TS as SR 3.6.1.9.1. Two additional SRs that are deemed necessary are SR 3.6.1.9.2 which verifies the RHR pumps can develop the necessary flow rate and SR 3.6.1.9.3 which verifies each spray nozzle is unobstructed. The Frequency requirements for SR 3.6.1.9.1 and SR 3.6.1.9.2 are consistent with similar TS SR Frequency requirements. The Frequency requirement for SR 3.6.1.9.3 is consistent with the requirements of the CNS USAR.

The Conditions, Required Actions, Completion Times and Surveillances being used for LCO 3.3.5.1, function 2.h, Containment Pressure - High are consistent with other instrumentation that use a one-out-of-two taken twice logic and is consistent with the Fitzpatrick precedence with one exception. CNS has an additional surveillance for performing a channel functional test that is a carryover from the TRM requirements.

3.5 USAR Accident Analysis Impact A postulated condition where containment spray may be desirable is in the case of a small steam line break in the drywell. The consequence of such an occurrence, assuming no containment spray action is taken, is the possibility of the containment atmosphere temperature rising due to superheating, thus presenting the potential to exceed the design temperature of the drywell vessel.

When a postulated leak occurs inside the drywell, the pressure and temperature rise, but the time response is different for every postulated steam or liquid leak depending on leak size, reactor pressure, heat transfer to the containment structure, etc.

NLS2014087 Attachment I Page 8 of 14 If the leak is large enough such that the pressure in the drywell rises above that necessary to clear the wetwell downcomers, venting from the drywell to wetwell will result. As the mixture of noncondensibles and steam is purged to the wetwell gas volume, the steam is condensed in the pool and the noncondensibles accumulate in the wetwell gas volume. The containment pressure will continue to increase to the point where essentially all of the noncondensibles in the drywell are "forced" over to the wetwell. The larger the leak, the more rapid the pressure rise. However, the maximum pressure will occur at the time when all of the noncondensibles initially in the drywell are purged to the wetwell gas volume.

The containment atmosphere temperature response is largely a function of this containment pressure. In the case of liquid or mixture leaks, the maximum temperature at any time has an upper bound due to the saturation temperature corresponding to the containment pressure at that time. The peak atmosphere temperature corresponds to the containment pressure when all the drywell noncondensibles are purged to the wetwell.

In the case of a steam leak, the peak atmosphere temperature has an upper bound due to the maximum superheat temperature. This temperature is a function of both the source pressure (reactor pressure vessel) and the receiver pressure (drywell). Since the containment pressure and temperature response will vary with the postulated steam leak size, a spectrum of leak sizes was analyzed to determine the time temperature response of the drywell wall.

This analysis assumes the reactor initially at rated conditions. The leak occurs and high pressure coolant injection is available to add water to the reactor vessel. A simultaneous loss of offsite AC power is also assumed.

Containment pressure and temperature increase at a rate dependent on the size of the steam leak and the reactor pressure. The containment shell temperature rises as steam condenses on the relatively cool wall. The containment pressure also rises, and the peak pressure occurs at a value corresponding to all the noncondensible gases initially in the drywell being purged over to the wetwell. When the drywell shell temperature reaches the saturated temperature dictated by this containment pressure, steam condensation ceases, and the only energy available to further increase the wall temperature is the superheat energy. The result is a decrease in the rate of temperature rise in the containment wall and an increase in the bulk atmosphere temperature of the drywell.

The activation of one of the two containment sprays any time before the wall temperature reaches 281 'F will be effective in terminating the temperature rise because the superheat energy will be quickly removed from the atmosphere. The spray nozzles are designed to give a small particle size, and the heat transfer to the subcooled spray is very effective. To terminate the wall temperature increase, it is necessary to remove only the superheat energy.

NLS2014087 Attachment I Page 9 of 14 An analysis was performed for SSLB over a spectrum of break sizes from 0.01 ft 2 up to 1.0 ft2 . The analysis cases also studied the sensitivity of the resulting conditions with the use of containment spray and with suppression pool cooling without containment spray. In the comparative cases in which suppression pool cooling was used, instead of containment spray, the resulting drywell peak shell temperature was greater than the design limit. Therefore using the containment spray mode, rather than the suppression pool cooling mode, is required to mitigate the effects of a small steam line break. The results of this analysis indicated that the containment shell temperature did not exceed the design temperature of 281 'F when drywell spray was used to control peak drywell temperature.

3.6 Conclusion In summary, the requirements for the RHR Containment Spray function will be established in TS to ensure that this function is provided by two redundant Containment Spray subsystems and that both subsystems are operable in applicable modes. The proposed change is technically sound and continues to maintain the same level of safety as the current licensing basis.

4.0 REGULATORY SAFETY ANALYSIS 4.1 Applicable Regulatory Requirements 10 CFR 50.36(c)(2)(i) provides that TS will include LCOs which are "...the lowest functional capability or performance levels of equipment required for safe operation of the facility. When a limiting condition for operation of a nuclear reactor is not met, the licensee shall shut down the reactor or follow any remedial action permitted by the technical specifications until the condition can be met."

10 CFR 50.36(c)(2)(ii) specifies, "A technical specification limiting condition for operation of a nuclear reactor must be established for each item meeting one or more of the following criteria:

(A) Criterion 1, Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary.

(B) Criterion 2, A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

(C) Criterion 3, A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis

NLS2014087 Page 10 of 14 accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

(D) Criterion 4, A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety."

The proposed change is consistent with current regulations and satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

The proposed surveillance requirements assure the necessary quality of systems and components is maintained, that facility operations will be maintained within safety limits, and that the limiting conditions for operations will be met consistent with current regulations and satisfies 10 CFR 50.36(c)(3), Surveillance Requirements.

NUREG-1433, "Standard Technical Specifications General Electric BWR/4 Plants,"

contain criteria and guidance for ITS for GE BWR/4 plants. The improved ITS were developed based on the criteria in the Final Commission Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors, dated July 22, 1993 which was subsequently codified by changes contained in 10 CFR 50.36. Licensees are encouraged to upgrade their TS consistent with those criteria and conforming, to the extent practical, to ITS.

The proposed changes conform to the guidance provided in NUREG-1433. The evaluations documented above confirm that NPPD will continue to comply with all applicable regulatory requirements.

4.2 Precedent On August 29, 2012, Peach Bottom Atomic Power Station (PBAPS), Units 2 and 3 (NRC Docket Nos. 50-277 and 50-278) submitted a License Amendment Request (Ref.

3) to re-establish Residual Heat Removal System Drywell Spray function requirements (ML12243A497). This request was for relocating the RHR Drywell Spray function, which was contained in the TRM, to the TS. This license amendment request was approved by the NRC with issuance of a safety evaluation on June 18, 2013 (TAC Nos.

ME9445 and ME9446) (Ref. 4). These were license amendments 288 and 291 respectfully for PBAPS Units 2 and 3.

The basis for NPPD's request to relocate the Containment Spray function from the TRM to the TS is the same as PBAPS's request for relocating their Drywell Spray function from the TRM to TS. The difference between the two requests is that NPPD is relocating the Containment Spray function which includes the drywell spray and suppression pool spray functions. The calculations and engineering evaluation performed for the SSLB included the suppression pool spray function along with the drywell spray function as needed for mitigating the SSLB. Even with this difference,

NLS2014087 Attachment I Page 11 of 14 the precedent is still applicable and does not impact the acceptability of the proposed amendment.

In addition, CNS used the Fitzpatrick Nuclear Power Plant TS as an example for the location of the Containment Pressure - High function in the ECCS instrumentation section.

4.3 No Significant Hazards Consideration 10 CFR 50.91 (a)(1) requires that licensee requests for operating license amendments be accompanied by an evaluation of no significant hazard posed by issuance of the amendment. Nebraska Public Power District (NPPD) has evaluated this proposed amendment with respect to the criteria given in 10 CFR 50.92(c). The following is the evaluation required by 10 CFR 50.91 (a)(1).

NPPD is requesting an amendment of the Operating License for the Cooper Nuclear Station to revise the Technical Specification (TS) to add Section 3.6.1.9 Residual Heat Removal (RHR) Containment Spray.

1. Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change to establish the RHR Containment Spray requirement in TS does not introduce new equipment or new equipment operating modes, nor do the proposed changes alter existing system relationships. The proposed change does not affect plant operation, design function, or any analysis that verifies the capability of a structure, system, or component (SSC) to perform a design function.

There are no changes or modifications to the RHR system. The RHR system will continue to function as designed in all modes of operation, including the Containment Spray function. There are no significant changes to procedures or training related to the operation of the Containment Spray function. Primary containment integrity is not adversely impacted and radiological consequences from the accidents analyzed in the Updated Safety Analysis Report (USAR) are not increased. Containment parameters are not increased beyond those previously evaluated and the potential for failure of the containment is not increased.

There is no adverse impact on systems designed to mitigate the consequences of accidents. The proposed change does not increase system or component pressures, temperatures, and flowrates for systems designed to prevent accidents or mitigate the consequences of an accident. Since these conditions do not change, the likelihood of failure of SSC is not increased.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

NLS2014087 Page 12 of 14

2. Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed change to establish the RHR Containment Spray requirement in TS does not alter the design function or operation of any SSC. The Containment system will continue to function as designed in all modes of operation, including RHR Containment Spray function. There is no new system component being installed, no new construction, and no performance of a new test or maintenance function. The proposed TS change does not create the possibility of a new credible failure mechanism or malfunction. The proposed change does not modify the design function or operation of any SSC. The proposed change does not introduce new accident initiators. Primary containment integrity is not adversely impacted and radiological consequences from the accident analyzed in the USAR are not increased. Containment parameters are not increased beyond those previously evaluated and the potential for failure of the containment is not increased. The proposed change does not increase system or component pressures, temperatures, and flowrates for systems designed to prevent accidents or mitigate the consequences of an accident. Since these conditions do not change, the likelihood of failure of an SSC is not increased.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3. Do the proposed changes involve a significant reduction in a margin of safety?

Response: No.

The proposed change does not increase system or component pressures, temperatures, and flowrates for systems designed to prevent accidents or mitigate the consequences of an accident. Containment parameters are not increased beyond those previously evaluated and the potential for failure of the containment is not increased.

The proposed change to establish the RHR Containment Spray requirement in TS is needed in order to reflect the current safety function of Containment Spray related to the small steam line break accident. The proposed change does not exceed or alter a design basis or a safety limit parameter that is described in the USAR.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

NLS2014087 Page 13 of 14 Based on the responses to the above questions, NPPD concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and, accordingly, a finding of "no significant hazards consideration" is justified.

4.4 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.0 ENVIRONMENTAL CONSIDERATION

10 CFR 51.22 provides criteria for, and identification of, licensing and regulatory actions eligible for categorical exclusion from performing an environmental assessment or environmental impact statement. 10 CFR 51.22(c)(9) identifies an amendment to an operating license for a reactor which changes an inspection or a surveillance requirement as a categorical exclusion provided that operation of the facility in accordance with the proposed amendment would not: (1) involve a significant hazards consideration, (2) result in a significant change in the types or significant increase in the amount of any effluents that may be released offsite, or (3) result in a significant increase in individual or cumulative occupational radiation exposure.

CNS review has determined that the proposed amendment, which would change a Technical Specification, does not involve (1) a significant hazards consideration, (2) a significant change in the types or significant increase in the amounts of any effluent that might be released offsite, or (3) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51,22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 REFERENCES

1) Cooper Station Engineering Evaluation 01-035, "EQ Temperature Profile in Containment Based on Small Steam Line Break and DBA-LOCA"

2) Cooper Station Calculation NEDC 94-034D, "Small Steam Line Break Analysis"

3) Peach Bottom Atomic Power Station License Amendment Request of August 29, 2012

4) NRC Issuance of Amendments RE: Revise Technical Specifications to add Residual Heat Removal System Drywell Spray Function Requirements dated June 18, 2013

NLS2014087 Attachment I Page 14 of 14

5) NUREG-1433, Revision 4, "Standard Technical Specifications General Electric BWR/4 Plants"

6) GE Report NEDO-24573, "Mark I Containment Program Plant Unique Load Definition -

Cooper Nuclear Station,"

7) GE report GE-NE-T23-00786-00-02, "Cooper Nuclear Station Containment Analysis Project - Small Steam Line Break Analysis."

NLS2014087 Page 1 of 21 Attachment 2 Proposed Technical Specification Revision (Markup)

Cooper Nuclear Station, Docket No. 50-298, DPR-46 Revised Technical Specification Pages 3.3-31, 3.3-39, 3.6-25 thru 3.6-42 (Pages 3.3-31 and 3.3-39 are revised pages, pages 3.6-25 and 3.6.26 reflect new TS section 3.6.1.9, pages 3.6-27 thru 3.6-42 are due to repagination of subsequent sections)

ECCS Instrumentation 3.3.5.1 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation LCO 3.3.5.1 The ECCS instrumentation for each Function in Table 3.3.5.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.5.1-1.

ACTIONS

NOTE .............................

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.5.1-1 for the channel.

B. As required by 8.1 ---- NOTES --------

Required Action A.1 1. Only applicable and referenced in in MODES 1, 2, Table 3.3.5.1-1. and 3.

2. Only applicable for Functions l.a, 1.b, 2.

aM 2.b. and 2.h Declare supported 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from feature(s) inoperable discovery of when its redundant loss of feature ECCS initiation initiation capability capability for is inoperable, feature(s) in both divisions AND (continued)

Cooper 3.3-31 Amendment No. 178

ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 6)

Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIEO PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE

2. LPCI System (continued) 1,2, 3. I per E SR 3.3 > *'1N7 nnm h.h.C ntaiment C

ntime t Low Pressure

g. Coolant Injection 4a 4(a). subsystem SR 3.3 5 (a) SR 3.3 .5.1.5 3.5.1.> 2 psigI Pressure - High Pump Discharge Flow - Low (Bypass) l ,2 3 SR 3.3.5.1.2

3. High Pressure Coolant SR 3.3.5.1.4 (c)(d)

Injection (HPCI) System SR 3.3.5.1.5

a. Reactor Vessel 1, 4 B SR 3.3.5.1.1 > -42 inches Water Level - Low SR 3.3.5.1.2 Low (Level 2) 2(0), 3(') SR 3 .3.5.1. 4 (c)(d)

SR 3.3.5.1.5

b. Drywell Pressure - 1. 4 B SR 3-3.5-1.2

1.84 psig High SR 3 .3 .5.1.4(C)(d) 2(f) 3() SR 3.3.5.1.5

54 inches

c. Reactor Vessel Water Level - High Z(f), 30*

2 C SR SR 3.3.5.1.1 3.3.5.1.2 I (Level 8) SR 3.3.5.1.4 SR 3.3.5.1.5 1.

d. Emergency 2 o SR 3.3.5.1.2

23 inches Condensate 2(n. 3(f) SR 3.3.5.1.3 Storage Tank SR 3.3.5.1.5 (ECST) Level -

Low 1,

e. Suppression Pool 2 o SR 3.3.5.12 4 inches Water Level - High 2(0, 3 (0 SR 3.3.5.1.4 SR 3.3.5 1.5 (continued)

(a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2. ECCS - Shutdown.

(c) If the as-found channel setpoint is outside Its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(d) The instrument channel selpoint shall be reset to a value that is witNn the as-eft tolerance around the Lmiti Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Se.points more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual selpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to conf'rm channel peiformnarne The Limiting Trip Selpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(f) With reactor steam dome pressure > 150 psig.

Cooper 3.3-39 Amendment No.-242-

RHR Containment Spray 3.6.1.9 I 3.6 CONTAINMENT SPRAY 3.6.1.9 Residual Heat Removal (RHR) Containment Spray LCO 3.6.1.9 Two RHR containment spray subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR containment A.1 Restore RHR 7 days spray subsystem inoperable, containment spray subsystem to OPERABLE status.

B. Two RHR containment B.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months spray subsystems containment spray inoperable. subsystem to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE 4, 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.6-25 Amendment No.

RHR Containment spray 3.6.1.9 SURVEILLANCE REQUIREMENTS II SURVEILLANCE FREQUENCY SR 3.6.1.9.1 Verify each RHR containment spray subsystem 31 days manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

SR 3.6.1.9.2 Verify each required RHR pump develops a flow rate In accordance with of > 7700 gpm through the associated heat the Inservice exchanger while operating in the suppression pool Testing Program cooling mode.

SR 3.6.1.9.3 Verify each spray nozzle is unobstructed. Following maintenance which could result in nozzle blockage Cooper 3.6-26 Amendment No.

Suppression Pool Average Temperature 3.6.2.1 3.6 CONTAINMENT SYSTEMS 3.6.2.1 Suppression Pool Average Temperature LCO 3.6.2.1 Suppression pool average temperature shall be:

a. < 95"F when THERMAL POWER is > 1% RTP and no testing that adds heat to the suppression pool is being performed;

b. < 105°F when THERMAL POWER is > 1% RTP and testing that adds heat to the suppression pool is being performed; and C. < 110°F when THERMAL POWER is < 1% RTP.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool A.1 Verify suppression Once per hour average temperature pool average

> 95°F but < 11O°F. temperature < 110]F.

AND AND THERMAL POWER is > 1% A.2 Restore suppression 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months RTP. pool average temperature to AND < 95:F.

Not performing testing that adds heat to the suppression pool.

(continued)

Cooper 2 Cooper3.6 Amnden No. 1-487 Amendment No. i4ý9

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and 8.1 Reduce THERMAL POWER 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion to < 1% RTP.

Time of Condition A not met.

C. Suppression pool C.1 Suspend all testing Immediately average temperature that adds heat to the

> 105°F. suppression pool.

AND THERMAL POWER is > 1%

RTP.

AND Performing testing that adds heat to the suppression pool.

D. Suppression pool D.1 Place the reactor Immediately average temperature mode switch in the

> 110F but < !20F. shutdown position.

AND D.2 Verify suppression Once per pool average 30 minutes temperature < 120°F.

AND D.3 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

Cooper ;-6 Cooper3 No. +81 Amendment No.

Amendment W-8

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Suppression pool E.1 Depressurize the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months average temperature reactor vessel to

> 120'F. < 200 psig.

AND E.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1.1 Verify suppression pool average 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months temperature is within the applicable limits. AND 5 minutes when performing testing that adds heat to the suppression pool Coopepo 6 2 r COO~~~3 Amnden Amendment No.o.1--

48

Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level LCO 3.6.2.2 Suppression pool water level shall be > 12 ft 7 inches and

< 12 ft 11 inches.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool water A.1 Restore suppression 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months level not within pool water level to limits, within limits.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.2.1 Verify suppression pool water level is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months within limits.

Coop*er je Coor 3.5~8 No. 48 Amendment No. 1-7.8

RHR Suppression Pool Cool i ng 3.6.2.3 3.6 CONTAINMENT SYSTEMS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression A.1 Restore RHR 7 days pool cooling subsystem suppression pool inoperable, cooling subsystem to OPERABLE status.

B. Two RHR suppression B.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months pool cooling suppression pool subsystems inoperable, cooling subsystem to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.629 Coo}per No. W-8 Amendment No. 1~7-8

RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.3.1 Verify each RHR suppression pool cooling 31 days subsystem manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

SR 3.6.2.3.2 Verify each RHR pump develops a flow rate In accordance

> 7700 gpm through the associated heat with the exchanger while operating in the Inservice suppression pool cooling mode. Testing Program Cooper Cooper 32-] Amendment No.

Amendent No. 1-7-8

Primary Containment Oxygen Concentration 3.6.3.1 3.6 CCNTAINMENT SYSTEMS 3.6.3.1 Primary Containment Oxygen Concentration LCO 3.6.3.1 The primary containment oxygen concentration shall be

< 4.0 volume percent.

APPLICABILITY: MODE I during the time period:

a. From 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing THERMAL POWER to < 15% RTP prior to a reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment A.1 Restore oxygen 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months oxygen concentration concentration to not within limit, within limit.

B. Required Action and B.1 Reduce THERMAL POWER 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months associated Completion to < 15% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.1.1 Verify primary containment oxygen 7 days concentration is within limits.

~.~3I Coo er mendmnt No i Coop~er Amendment No. 446

Secondary Containment 3.6.4.1 3.6 CONTAINMENT SYSTEMS 3.6.4.1 Secondary Containment LCO 3.6.4.1 The secondary containment shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary I containment, I During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Secondary containment A. 1 Restore secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable in MODE 1, 2, containment to or 3. OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C. Secondary containment C. 1 --------- NOTE --------

inoperable during LCO 3.0.3 is not movement of recently applicable.

irradiated fuel assem blies -----------------------------------

in the secondary containment, or during Suspend movement of Immediately OPDRVs. recently irradiated fuel assemblies in the secondary containment.

AND (continued)

Amendment 222 3.r. 3 <-ý3.6-ý34 4W06;0

Secondary Containment 3.6-4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 Initiate action to suspend Immediately OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4. 1. 1 Verify secondary containment vacuum is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

> 0.25 inch of vacuum water gauge.

SR 3.6.4.1.2 Verify all secondary containment equipment 31 days hatches are closed and sealed-SR 3.6.4.1.3 Verify one secondary containment access door in 31 days each access opening is closed.

SR 3.6-4.1.4 Verify each SGT subsystem can maintain 24 months on a I

> 0.25 inch of vacuum water gauge in the STAGGERED secondary containment for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate TEST BASIS

<1780 cfm, Cooper Co _pe-r-3.6-35i Amendment No. 242

SCIVs 3.6.4.2 3.6 CONTAINMENT SYSTEMS 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

LCO 3.6.4.2 Each SCIV shall be OPERABLE.

APPLICABILITY: MODES 1,2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS

I141 r- Z" ------ - - - --- - ----- - -------- - --------- --------- - ---

1. Penetration flow paths may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each penetration flow path.

3. Enter applicable Conditions and Required Actions for systems made inoperable by SCIVs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more penetration A. 1 Isolate the affected 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flow paths with one SCIV penetration flow path by inoperable, use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

AND (continued) j~mendet No.J A,m--mCo o p -er 3.6 34 zlýý

SCIVs 3.6.4.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ------ NOTES--------

1. Isolation devices in high radiation areas may be verified by use of administrative means.

2. Isolation devices that I]

are locked, sealed, or Once per 31 days I otherwise secured may I be verified by use of !

administrative means.

Verify the affected penetration flow path is isolated.

B.----------- NOTE------ B.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Only applicable to penetration flow path by penetration flow paths with use of at least one closed two isolation valves, and de-activated automatic valve, closed manual valve, or blind One or more penetration flange.

flow paths with two SClVs inoperable.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A or B AND not met in MODE 1, 2, or 3. C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

C

,ooper jAmendment No.

Amendment 180 3~S-35 a4WO0

SCIVs 3.6.4.2 ACTIC)NS (r.nntini~d~

NS_ ' .- -. . -- ___ __ ___ __ ___ __ ___ __

CONDITION REQUIRED ACTION COMPLETION TIME i i D. Required Action and D.1 ---------- NOTE -....------

associated Completion LCO 3.0.3 is not Time of Condition A or B applicable.

not met during movement of recently irradiated fuel assemblies in the Suspend movement of Immediately secondary containment or recently irradiated fuel during OPDRVs. assemblies in the secondary containment.

AND D.2 Initiate action to suspend Immediately OPDRVs.

I jAmendment No.j Cooper 3.3 6-3 AmeRdFne L 40AO&O

SCIVs 3.6-4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 ----- ~NOTES----

I Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for SCIVs that are open under administrative controls.

Verify each secondary containment isolation 31 days manual valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is dosed.

1~

SR 3.6.4.2.2 Verify the isolation time of each power operated In accordance automatic SCIV is within limits. with the Inservice Testing Program SR 3.8.4.2.3 Verify each automatic SCIV actuates to the 24 months isolation position on an actual or simulated actuation signal.

Cooper Cooper Amendment Amendment No. 242 24~

SGT System 3.6.4.3 3.6 CONTAINMENT SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCO 3.6.4.3 Two SGT subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SGT subsystem A.1 Restore SGT subsystem 7 days inoperable, to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met in MODE 1,2, or 3.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C. Required Action and ----------- NOTE--------

associated Completion LCO 3.0.3 is not applicable.

Time of Condition A not- ---------------------------.....-------

met during movement of recently irradiated fuel C.1 Place OPERABLE SGT Immediately assemblies in the subsystem in operation.

secondary containment or I during OPDRVs. OR (continued)

Cooper 3.6-40 t No.

SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.1 Suspend movement of Immediately recently irradiated fuel assemblies in secondary containment.

AND C.2.2 Initiate action to Immediately suspend OPDRVs.

D. Two SGT subsystems D.1 Enter LCO 3.0.3 Immediately inoperable in MODE 1 2, or 3.

E. Two SGT subsystems E.1 ---------- NOTE------

inoperable during LCO 3.0.3 is not movement of recently applicable.

irradiated fuel assemblies in the secondary Suspend movement of Immediately containment or recently irradiated fuel during OPDRVs. assemblies in secondary containment.

AND (continued)

Amendment No. I Cooper Amendment 2-2!2

.6ý

SGT System 3.6.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for > 10 continuous 31 days hours with heaters operating.

SR 3.6.4.3.2 Perform required SGT fitter testing in accordance In accordance with the Ventilation Fitter Testing Program (VFTP). with the VFTP SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual 24 months or simulated initiation signal.

SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the 24 months correct position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.

Cooper Cooper Amendment No.

Amendment No. 2-42 242

NLS2014087 Page 1 of 21 Attachment 3 Proposed Technical Specification Revision (Final Typed Format)

Cooper Nuclear Station, Docket No. 50-298, DPR-46 Revised Technical Specification Pages 3.3-31, 3.3-39, 3.6-25 thru 3.6-42 (Pages 3.3-31 and 3.3-39 are revised pages, pages 3.6-25 and 3.6.26 reflect new TS section 3.6.1.9, pages 3.6-27 thru 3.6-42 are due to repagination of subsequent sections)

ECCS Instrumentation 3.3.5.1 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation LCO 3.3.5.1 The ECCS instrumentation for each Function in Table 3.3.5. 1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.5.1-1.

ACTIONS llI. JP1

I-11 III' I-..................................--------------------....

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Enter the Condition Immediately inoperable, referenced in Table 3.3.5.1-1 for the channel.

B. As required by Required B.-1 --------- NOTES------

Action A. 1 and referenced in 1. Only applicable in Table 3.3.5.1-1. MODES 1, 2, and 3.

2. Only applicable for Functions 1.a, 1.b, 2.a, 2.b, and 2.h.

Declare supported 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from feature(s) inoperable when discovery of loss of its redundant feature initiation capability ECCS initiation capability for feature(s) in both is inoperable, divisions AND (continued)

Cooper 3.3-31 Amendment No.

ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 6)

Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE

2. LPCI System (continued)

g. Low Pressure Coolant 1,2,3, 1 per subsystem E SR 3.3.5.1.2 > 2107 gpm Injection Pump Discharge SR 3 .3.5.1.4(cxd)

Flow - Low (Bypass) 4(a), 5(a) SR 3.3.5.1.5

h. Containment Pressure - 1,2,3 4 B SR 3.3.5.1.2 ->2 psig High SR 3 .3.5.1. 4 (cxd)

SR 3.3.5.1.5

3. High Pressure Coolant Injection (HPCI) System

a. Reactor Vessel Water Level 1, 4 B SR 3.3.5.1.1 > -42 inches

- Low Low (Level 2) SR 3.3.5.1.2 2(0, 3(f SR 3 .3.5.1.4(cxd)

SR 3.3.5.1.5

b. Drywell Pressure - High 1, 4 B SR 3.3.5.1.2 < 1.84 psig SR 3 .3.5.1. 4 (vXd(

2(0, 3(0 SR 3.3.5.1.5

c. Reactor Vessel Water Level 1, 2 C SR 3.3.5.1.1 <*54 inches

- High (Level 8) SR 3.3.5.1.2 SR 3.3.5.1.4 2(f, 3(S SR 3.3.5.1.5

d. Emergency Condensate 1, 2 D SR 3.3.5.1.2 a 23 inches Storage Tank (ECST) Level - SR 3.3.5.1.3 Low 2(f, 3 (f) SR 3.3.5.1.5

e. Suppression Pool Water 1, 2 D SR 3.3.5.1.2 < 4 inches Level - High SR 3.3.5.1.4 2(0 3(0 SR 3.3.5.1.5 (continued)

(a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.

(c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.

(d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.

(f) With reactor steam dome pressure >150 psig.

Cooper 3.3-39 Amendment No.

RHR Containment Spray 3.6.1.9 3.6 CONTAINMENT SPRAY 3.6.1.9 Residual Heat Removal (RHR) Containment Spray LCO 3.6.1.9 Two RHR containment spray subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR containment A.1 Restore RHR 7 days spray subsystem inoperable, containment spray subsystem to OPERABLE status.

B. Two RHR containment B.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months spray subsystems containment spray inoperable, subsystem to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.6-25 Amendment No.

RHR Containment Spray 3.6.1.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.9.1 Verify each RHR containment spray subsystem 31 days manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

SR 3.6.1.9.2 Verify each required RHR pump develops a flow rate In accordance with of > 7700 gpm through the associated heat the Inservice exchanger while operating in the suppression pool Testing Program cooling mode.

SR 3.6.1.9.3 Verify each spray nozzle is unobstructed. Following maintenance which could result in nozzle blockage Cooper 3.6-26 Amendment No.

Suppression Pool Average Temperature 3.6.2.1 3.6 CONTAINMENT SYSTEMS 3.6.2.1 Suppression Pool Average Temperature LCO 3.6.2.1 Suppression pool average temperature shall be:

a. < 95°F when THERMAL POWER is > 1% RTP and no testing that adds heat to the suppression pool is being performed;

b. < 105'F when THERMAL POWER is > 1% RTP and testing that adds heat to the suppression pool is being performed; and

c. 5 11 0°F when THERMAL POWER is 5 1% RTP.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool average A.1 Verify suppression pool Once per hour temperature > 95 0 F but < average temperature 110 0 F. < 110°F.

AND AND THERMAL POWER is > 1% A.2 Restore suppression pool 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months RTP. average temperature to

< 95 0F.

AND Not performing testing that adds heat to the suppression pool.

(continued)

Cooper 3.6-27 Amendment No.

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Reduce THERMAL 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time POWER to < 1% RTP.

of Condition A not met.

C. Suppression pool average C.1 Suspend all testing that Immediately temperature > 105 0 F. adds heat to the suppression pool.

AND THERMAL POWER is > 1%

RTP.

AND Performing testing that adds heat to the suppression pool.

D. Suppression pool average D.1 Place the reactor mode Immediately temperature > 110 0 F but switch in the shutdown

< 120 0 F. position.

AND D.2 Verify suppression pool Once per 30 minutes average temperature

< 120 0 F.

AND D.3 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

Cooper 3.6-28 Amendment No.

Suppression Pool Average Temperature 3.6.2.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Suppression pool average E.1 Depressurize the reactor 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months temperature > 120 0 F. vessel to < 200 psig.

AND E.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1.1 Verify suppression pool average temperature is within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the applicable limits.

AND 5 minutes when performing testing that adds heat to the suppression pool Cooper 3.6-29 Amendment No.

Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level LCO 3.6.2.2 Suppression pool water level shall be > 12 ft 7 inches and ---12 ft 11 inches.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool water A.1 Restore suppression pool 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months level not within limits, water level to within limits.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.2.1 Verify suppression pool water level is within limits. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Cooper 3.6-30 Amendment No.

RHR Suppression Pool Cooling 3.6.2.3 3.6 CONTAINMENT SYSTEMS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression pool A.1 Restore RHR suppression 7 days cooling subsystem pool cooling subsystem to inoperable. OPERABLE status.

B. Two RHR suppression pool B.1 Restore one RHR 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months cooling subsystems suppression pool cooling inoperable, subsystem to OPERABLE status.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. AND C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Cooper 3.6-31 Amendment No.

RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.3.1 Verify each RHR suppression pool cooling subsystem 31 days manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.

SR 3.6.2.3.2 Verify each RHR pump develops a flow rate > 7700 In accordance gpm through the associated heat exchanger while with the Inservice operating in the suppression pool cooling mode. Testing Program Cooper 3.6-32 Amendment No.

Primary Containment Oxygen Concentration 3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 Primary Containment Oxygen Concentration LCO 3.6.3.1 The primary containment oxygen concentration shall be < 4.0 volume percent.

APPLICABILITY: MODE 1 during the time period:

a. From 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing THERMAL POWER to < 15% RTP prior to a reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment oxygen A.1 Restore oxygen 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months concentration not within concentration to within limit, limit.

B. Required Action and B.1 Reduce THERMAL 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months associated Completion Time POWER to < 15% RTP.

not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.1.1 Verify primary containment oxygen concentration is 7 days within limits.

Cooper 3.6-33 Amendment No.

Secondary Containment 3.6.4.1 3.6 CONTAINMENT SYSTEMS 3.6.4.1 Secondary Containment LCO 3.6.4.1 The secondary containment shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Secondary containment A.1 Restore secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable in MODE 1, 2, or containment to

3. OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not met. AND B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C. Secondary containment C.1 ------------ NOTE -------

inoperable during movement LCO 3.0.3 is not of recently irradiated fuel applicable.

assemblies in the secondary containment or during OPDRVs. Suspend movement of Immediately recently irradiated fuel assemblies in the secondary containment.

AND (continued)

Cooper 3.6-34 Amendment No.

Secondary Containment 3.6.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 Initiate action to suspend Immediately OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is > 0.25 inch 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of vacuum water gauge.

SR 3.6.4.1.2 Verify all secondary containment equipment hatches 31 days are closed and sealed.

SR 3.6.4.1.3 Verify one secondary containment access door in 31 days each access opening is closed.

SR 3.6.4.1.4 Verify each SGT subsystem can maintain > 0.25 inch 24 months on a of vacuum water gauge in the secondary containment STAGGERED for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate < 1780 cfm. TEST BASIS Cooper 3.6-35 Amendment No.

SCIVs 3.6.4.2 3.6 CONTAINMENT SYSTEMS 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

LCO 3.6.4.2 Each SCIV shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS

NOTES ------------------------------

1. Penetration flow paths may be unisolated intermittently under administrative controls.

2. Separate Condition entry is allowed for each penetration flow path.

3. Enter applicable Conditions and Required Actions for systems made inoperable by SCIVs.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more penetration A.1 Isolate the affected 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months flow paths with one SCIV penetration flow path by inoperable, use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange.

AND (continued)

Cooper 3.6-36 Amendment No.

SCIVs 3.6.4.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 ---------- NOTES------

1. Isolation devices in high radiation areas may be verified by use of administrative means.

2. Isolation devices that Once per 31 days are locked, sealed, or otherwise secured may be verified by use of administrative means.

Verify the affected penetration flow path is isolated.

B. --------- NOTE--------- B.1 Isolate the affected 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Only applicable to penetration flow path by penetration flow paths with use of at least one closed two isolation valves, and de-activated automatic valve, closed manual valve, or blind One or more penetration flange.

flow paths with two SCIVs inoperable.

C. Required Action and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A or B not met AND in MODE 1, 2, or 3.

C.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (continued)

Cooper 3.6-37 Amendment No.

SCIVs 3.6.4.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1- ---------- NOTE-------

associated Completion Time LCO 3.0.3 is not of Condition A or B not met applicable.

during movement of recently irradiated fuel assemblies in the secondary containment Suspend movement of Immediately or during OPDRVs. recently irradiated fuel assemblies in the secondary containment.

AND D.2 Initiate action to suspend Immediately OPDRVs.

Cooper 3.6-38 Amendment No.

SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 --------------------- NOTES----------------

1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2. Not required to be met for SCIVs that are open under administrative controls.

Verify each secondary containment isolation manual 31 days valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed.

SR 3.6.4.2.2 Verify the isolation time of each power operated In accordance automatic SCIV is within limits, with the Inservice Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation 24 months position on an actual or simulated actuation signal.

Cooper 3.6-39 Amendment No.

SGT System 3.6.4.3 3.6 CONTAINMENT SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCO 3.6.4.3 Two SGT subsystems shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, During movement of recently irradiated fuel assemblies in the secondary containment, During operations with a potential for draining the reactor vessel (OPDRVs).

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SGT subsystem A.1 Restore SGT subsystem 7 days inoperable, to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not met in AND MODE 1, 2, or 3.

B.2 Be in MODE 4. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C. Required Action and ------------------- NOTE ----------

associated Completion Time LCO 3.0.3 is not applicable.

of Condition A not met during movement of recently irradiated fuel assemblies in C.1 Place OPERABLE SGT Immediately the secondary containment subsystem in operation.

or during OPDRVs.

OR (continued)

Cooper 3.6-40 Amendment No.

SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.1 Suspend movement of Immediately recently irradiated fuel assemblies in secondary containment.

AND C.2.2 Initiate action to suspend Immediately OPDRVs.

D. Two SGT subsystems D.1 Enter LCO 3.0.3 Immediately inoperable in MODE 1, 2, or 3.

E. Two SGT subsystems E.-1 --------- NOTE-------

inoperable during movement LCO 3.0.3 is not of recently irradiated fuel applicable.

assemblies in the secondary containment or during OPDRVs. Suspend movement of Immediately recently irradiated fuel assemblies in secondary containment.

AND (continued)

Cooper 3.6-41 Amendment No.

SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 Initiate action to suspend Immediately OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for ->10 continuous 31 days hours with heaters operating.

SR 3.6.4.3.2 Perform required SGT filter testing in accordance with In accordance with the Ventilation Filter Testing Program (VFTP). the VFTP SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual or 24 months simulated initiation signal.

SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the correct 24 months position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.

Cooper 3.6-42 Amendment No.

NLS2014087 Page 1 of 11 Attachment 4 Proposed Technical Specification Bases Revision (Information Only)

Cooper Nuclear Station Docket No. 50-298, DPR-46 Revised and Added Technical Specification Bases Pages

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)

For most abnormal operational transients and Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored.

The ECCS instrumentation actuates core spray (CS), low pressure coolant injection (LPCI), containment spray, high pressure coolant injection (HPCI), Automatic Depressurization System (ADS), and the diesel generators (DGs). The equipment involved with each of these systems is described in the Bases for LCO 3.5.1, "ECCS-Operating" and LCO 3.6.1.9, "RHR Containment Spray."

Core Spray System The CS System may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) or Drywell Pressure-High. Each of these diverse variables is monitored by four redundant switches, which are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic. Each trip system initiates one of the two CS pumps.

Upon receipt of an initiation signal, if normal AC power is available, both CS pumps start after an approximate 10 second time delay. If a core spray initiation signal is received when normal AC power is not available, the CS pumps start approximately 10 seconds after the bus is energized by the DGs.

The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain primary containment isolated in the event CS is not operating.

The CS pump discharge flow is monitored by a flow transmitter and trip unit. When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the accident analysis (Ref. 2).

The CS System also monitors the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. The variable is monitored by four redundant pressure switches. The outputs of the switches are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

Cooper B 3.3-89 x~x/xx/x

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)

Low reactor water level in the shroud is detected by two additional instruments. When level is greater than the low level setpoint, LPCI may no longer be required, therefore other modes of RHR (e.g., suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoint are provided.

Containment high pressure is detected by four instruments to preclude inadvertent diversion of LPCI flow unless containment overpressurization is indicated. This variable is monitored by four pressure switches, whose contacts provide input to two trip systems. The outputs of the contacts are arranged in a one-out-of-two taken twice logic for each trip system.

Each trip system provides an input to the associated subsystem's containment spray valves. The four instruments also provide an isolation of the containment spray mode of RHR on decreasing containment pressure following manual actuation of the system. This isolation function is not credited in accident analysis for mitigating excessive depressurization of the containment, therefore is not a TS function.

High Pressure Coolant Iniection System The HPCI System may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low (Level 2) or Drywell Pressure-High. Each of these variables is monitored by four redundant switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic for each Function.

The HPCI pump discharge flow is monitored by a flow switch (only one trip system). When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the accident analysis (Ref. 4).

The HPCI test line isolation valves are closed upon receipt of a HPCI initiation signal to allow the full system flow assumed in the accident analysis and maintain primary containment isolated in the event HPCI is not operating.

The HPCI System also monitors the water levels in the emergency condensate storage tanks (ECSTs) and the suppression pool because these are the two sources of water for HPCI operation. Reactor grade water in the ECSTs is the normal source. The ECST suction source consists of two ECSTs connected in parallel to the HPCI pump suction.

Upon receipt of a HPCI initiation signal, the ECST suction valve is automatically signaled to open (it is normally in the open position) unless Cooper B 3.3-91 xx/xx/xx

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the LPCI subsystems.

2.h Containment Pressure - High The Containment Pressure - High Function serves as an interlock permissive to allow the RHR System to be manually aligned from the LPCI mode to the containment spray mode after containment pressure has exceeded the trip setting. The permissive ensures that containment pressure is elevated before the manual transfer is allowed. This ensures that LPCI is available to prevent or minimize fuel damage until such time that the operator determines that containment pressure control is needed.

The Containment Pressure - High Function is implicitly assumed in the analysis of LOCAs inside containment (Ref. 10) since the analysis assumes that containment spray is manually initiated when containment pressure is high. Containment Pressure - High signals are initiated from four pressure switches that sense drywell pressure. The four instruments also provide an isolation of the containment spray mode of RHR on decreasing containment pressure following manual actuation of the system. This isolation function is not credited in accident analysis for mitigating excessive depressurization of the containment, therefore is not a TS function.

Four channels of the Containment Pressure - High Function are only required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, containment spray is not assumed to be initiated.

High Pressure Coolant Iniection (HPCI) System 3.a. Reactor Vessel Water Level-Low Low (Level 2)

Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above fuel zone zero. The Reactor Vessel Water Level-Low Low (Level

2) is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients analyzed in References 6 and 8.

Additionally, the Reactor Vessel Water Level-Low Low (Level 2) Function Cooper B 3.3-101 xx/xx/xx

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) channels associated with CS pump A and four LPCI channels associated with LPCI pumps A and C are required for trip system A. Two CS channels associated with CS pump B and four LPCl channels associated with LPCl pumps B and D are required for trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

ACTIONS A Note has been provided to modify the ACTIONS related to ECCS instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel.

A._1 Required Action A. 1 directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable Condition referenced in the table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.

B.1, B.2, and B.3 Required Actions B.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action B.1 features would be those that are initiated by Functions 1.a, 1.b, 2.a, 2.b, and 2.h (e.g., low pressure I ECCS). The Required Action B.2 system would be HPCI. For Required Action B.1, redundant automatic initiation capability is lost if (a) two or more Function 1.a channels are inoperable and untripped such that both trip systems lose initiation capability, (b) two or more Function 2.a channels are inoperable and untripped such that both trip systems lose initiation capability, (c) two or more Function 1.b channels are inoperable and untripped such that both trip systems lose initiation capability, (d) two or more Function 2.b channels are inoperable and untripped such that Cooper B 3.3-108 xx/xx/xx

ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) both trip systems lose initiation capability, or (e), two or more Function 2.h channels are inoperable and untripped such that both trip systems lose initiation capability. For low pressure ECCS, since each inoperable channel would have Required Action B.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system of low pressure ECCS and DGs to be declared inoperable. However, since channels in both associated low pressure ECCS subsystems (e.g., both CS subsystems) are inoperable and untripped, and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in the associated low pressure ECCS and DGs being concurrently declared inoperable.

For Required Action B.2, automatic initiation capability is lost ifthe combination of Function 3.a or Function 3.b channels that are inoperable and untripped result in the inability to energize the Function's trip relay; i.e., parallel pair logic channels are untrippable. In this situation (loss of automatic initiation capability), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Action B.3 is not appropriate and the HPCI System must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . As noted (Note 1 to Required Action B.1), Required Action B.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the low pressure ECCS is not assumed and the probability of a LOCA is lower. Thus, a total loss of initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action B.3) is allowed during MODES 4 and 5. There is no similar Note provided for Required Action B.2 since HPCI instrumentation is not required in MODES 4 and 5; thus, a Note is not necessary.

Notes are also provided (Note 2 to Required Action B.1 and the Note to Required Action B.2) to delineate which Required Action is applicable for each Function that requires entry into Condition B if an associated channel is inoperable. This ensures that the proper loss of initiation capability check is performed. Required Action B.1 (the Required Action for certain inoperable channels in the low pressure ECCS subsystems) is not applicable to Function 2.e, since this Function provides backup to administrative controls ensuring that operators do not divert LPCI flow from injecting into the core when needed. Thus, a total loss of Function 2.e capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed, since the LPCI subsystems remain capable of performing their intended function.

The Completion Time 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." For Required Action B.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable, untripped channels within the same Function as described Cooper B 3.3-109 xx/xx/xx

ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.5.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic and simulated automatic actuation for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.

2. Amendment No. 7 to Facility License No DPR-46 for the Cooper Nuclear Station, February 6, 1975.

3. Cooper Nuclear Station Design Change 94-332, December 1994.

4. NEDC 97-023, "HPCI Minimum Flow Line Analysis."

5. 10 CFR 50.36(c)(2)(ii).

6. USAR, Section V-2.4.

7. USAR, Section VI-5.0.

8. USAR, Chapter XIV.

9. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.

10. EE 01-035, EQ Temperature Profile in Containment based on Small Steam Line Break and DBA-LOCA Analysis.

Cooper B 3.3-119 xX/xXxx

RHR Containment Spray B 3.6.1.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.9 Residual Heat Removal (RHR) Containment Spray BASES BACKGROUND Following a Design Basis Accident (DBA), the RHR Containment Spray System removes heat from the drywell and suppression chamber airspace. The drywell is designed to absorb the sudden input of heat from the primary system from a DBA. The heat addition results in increased steam in the drywell, which increases primary containment temperature and pressure. Steam blowdown from a DBA can also bypass the suppression pool and end up in the suppression chamber airspace. Removal of heat from the suppression chamber and drywell so that the pressure and temperature inside primary containment remain within analyzed design limits is provided by two redundant RHR containment spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES.

Each of the two RHR containment spray subsystems contain two pumps, (one divisionally powered pump and one non-divisionally powered pump) and one heat exchanger, which are manually initiated and independently controlled. The two subsystems perform the containment spray function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the drywell and suppression pool spray spargers. Thus, both suppression pool cooling and containment spray functions are performed when the RHR Containment Spray System is initiated. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR containment spray subsystem is sufficient to condense the steam in both the drywell and the suppression chamber airspace during the postulated DBA.

APPLICABLE SAFETY ANALYSES References 1 and 2 contain the results of analyses used to predict primary containment pressure and temperature following the design basis loss of coolant accident. The analyses demonstrate that the temperature and pressure reduction capacity of the RHR Containment Spray System is adequate to maintain the primary containment conditions within design limits. The time history for primary containment pressure is calculated to demonstrate that the maximum pressure remains below the design limit.

Cooper B 3.6-51 xxlxxlxx

RHR Containment Spray B 3.6.1.9 BASES (continued)

APPLICABLE SAFETY ANALYSES The RHR Containment Spray System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO In the event of a small break loss of coolant accident, a minimum of one RHR containment spray subsystem is required to maintain the primary containment peak temperature and pressure below the design limits (Ref.

1). To ensure that these requirements are met, two RHR containment spray subsystems must be OPERABLE. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR containment spray subsystem is OPERABLE when the divisionally associated RHR pump, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a DBA could cause pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining RHR containment spray subsystems OPERABLE is not required in MODE 4 or 5.

ACTIONS A. 1 With one RHR containment spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR containment spray subsystem is adequate to perform the primary containment temperature and pressure mitigation function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment temperature and pressure mitigation capability. The 7 day Completion Time was chosen in light of the redundant RHR containment spray capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.

Cooper B 3.6-52 xx/xx/xx

RHR Containment Spray B 3.6.1.9 BASES (continued)

ACTIONS B. 1 With both RHR containment spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this Condition, there is a substantial loss of the primary containment temperature and pressure mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to remove heat from primary containment are available.

C.1 and C.2 If the inoperable RHR containment spray subsystem cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.6.1.9.1 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR containment spray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR containment cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

Cooper B 3.6-53 xx/xx/xx

RHR Containment Spray B 3.6.1.9 BASES SURVEILLANCE REQUIREMENTS SR 3.6.1.9.1 (continued)

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

SR 3.6.1.9.2 Verifying each required RHR pump develops a flow rate > 7700 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in the drywell. Flow is a normal test of centrifugal pump performance required by the ASME Code, Section Xl (Ref. 4). This test confirms one point on the pump performance curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

SR 3.6.1.9.3 This Surveillance is performed following maintenance which could result in nozzle blockage by introduction of air to verify that the spray nozzles are not obstructed and that flow will be provided when required. The Frequency is adequate to detect degradation in performance due to the passive nozzle design and its normally dry state and has been shown to be acceptable through operating experience.

REFERENCES 1. USAR, Chapter XIV, Section 6.3.

2. USAR, Chapter V, Section 2.

3. EE 01-035, EQ Temperature Profile in Containment based on Small Steam Line Break and DBA-LOCA Analysis.

4. ASME, Boiler and Pressure Vessel Code,Section XI.

Cooper B 3.6-54 x~x/xx/x

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NLS2014087, License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function

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NLS2014087, License Amendment Request to Revise Technical Specifications to Add Residual Heat Removal System Containment Spray Function

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Subject:

Dear Sir or Madam:

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3.0 TECHNICAL EVALUATION

3.1 System Description

5.0 ENVIRONMENTAL CONSIDERATION

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