View source for NLS2020057, 10 CFR 50.59(d)(2) and 10 CFR 72.48(d)(2) Summary Report for August 2018 to July 2020

{{Adams
| number = ML20304A157
| issue date = 10/08/2020
| title = 10 CFR 50.59(d)(2) and 10 CFR 72.48(d)(2) Summary Report for August 2018 to July 2020
| author name = Dewhirst L
| author affiliation = Nebraska Public Power District (NPPD)
| addressee name = 
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000298
| license number = DPR-046
| contact person = 
| case reference number = NLS2020057
| document type = Letter type:NLS
| page count = 10
}}

=Text=
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50.59(d)(2) 72.48(d)(2)
NLS2020057 October 8, 2020 U.S Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

==Subject:==
10 CPR 50.59(d)(2) and 10 CPR 72.48(d)(2) Summary Report Cooper Nuclear Station, Docket No. 50-298, License No. DPR-46

==Dear Sir or Madam:==

The purpose ofthis letter is for the Nebraska Public Power District to provide the summary report of evaluations that have been performed for Cooper Nuclear Station, in accordance with the requirements of 10 CPR 50.59(d)(2) and 10 CPR 72.48(d)(2). This report covers the time period from August 1, 2018, to July 31, 2020. Summaries of applicable facility changes are discussed in Attachment 1. Summaries of applicable other changes are discussed in Attachment
: 2. There were no 72.48 evaluations performed during the specified time period.
There are no commitments contained in this letter.
Should ou have any questions concerning this matter, please contact me at (402) 825-5416.
/dv Attachments: 1. Facility Changes
: 2. Other Changes cc:     Regional Administrator w/ attachments USNRC - Region IV Senior Resident Inspector w/ attachments USNRC-CNS COOPER NUCLEAR STATION 72676 648A Ave/ P O Box 98 / Brownville, NE 68321 http://www nppd com

NLS2020057 Page 2 of2 Cooper Project Manager w/ attachments USNRC - NRR Plant Licensing Branch IV NPG Distribution w/ attachments CNS Records w/ attachments

NLS2020057 Page 1 of 4 Attachment 1 Facility Changes The following list provides a summary of 50.59 evaluations that were prepared to support facility changes that were implemented at Cooper Nuclear Station (CNS) during the time period from August 1, 2018 to July 31, 2020.
Change Evaluation Document (CED) 6028320 (Evaluation 2015-5, Revision 2)

==Title:==
RCIC (Reactor Core Isolation Cooling) Turbine Governor Control System Replacement

==
Description:==
The new RCIC digital governor control system installed by CED 6028320 consists of two digital devices in the new control cabinet; the Woodward 505 turbine controller and the Io.trol positioner. CED 6028320 only affects the RCIC turbine governor control system that positions ):he previous governor valve to control the speed of the RCIC pump by controlling steam flow to the turbine. The RCIC initiation logic, and control and isolation logic, are not affected by this modification.
The existing RCIC turbine hydraulic control system and valve actuator are removed. The new system contains a Woodward 505 digital speed controller (RCIC-C-505), digital positioner (RCIC-POS-505), power supplies and associated indications in a new governor control panel (RCIC-PNL-0505). Redundant speed sensor probes (RCIC-SE-3067A & B replacing RCIC-SE-3067) are installed at the RCIC turbine. The governor valve is now driven by the servo actuator instead of hydraulically driven. The new system is configured to accept the existing 4-20 mA flow controller input signal from RCIC-FIC-91. The new system is powered from the existing 125 volt direct current (DC) source.
Due to the environmental conditions adjacent to the RCIC turbine during normal operations, the control panel is relocated from the Reactor Building-North East quad, elevation 859 ft, to the Reactor Building elevation 903 ft - 6 in, in the North East comer, in new panel RCIC-PNL-0505. The existing Main Steam Sample local rack LR-108 is removed and the new RCIC control panel is installed in its place. Reactor Equipment Cooling (REC) water piping to 1-CP-R-lA & 2A seal leak off coolers are rerouted above local rack LR-108 and valves REC 468 & 469 are moved to beside the seal leak off cooler. Other plant modifications have already removed and capped most of the lines to LR-108 due to valve leakage.
This CED removes and caps the remaining lines and removes the local rack.
The new governor valve actuator RCIC-MOT-MOl 1 is an Exlar SR 31 series linear electromechanical reversible servo actuator. Unlike a typical motor

NLS2020057 Page2 of4 operated valve, the SR series linear actuators do not have separate opening and closing motor windings or control circuits. The Introl positioner in the RCIC control panel (also referred to as a servo amplifier) generates a variable frequency alternate current (AC) output based on a position demand signal from the Woodward 505 controller to rotate the SR servo actuator at a controlled speed, torque, and for controlled numbers of revolutions to place the actuator in the desired position. When the desired actuator position is sensed (based on an actuator position feedback signal to the positioner), the positioner output AC frequency is set to zero to hold the positioner in place. As the position demand signal to the positioner changes to maintain RCIC flow, the positioner generates a positive or negative AC signal to open or close the actuator as required.
The scope of the modification also includes data acquisition signals from RCIC system pressure transmitters located on local panel 25-58. The existing obsolete transmitters for pump discharge pressure (RCIC-PT-60), pump suction pressure (RCIC-PT-65), turbine steam inlet pressure (RCIC-PT-68) and turbine steam exhaust pressure (RCIC-PT-70) will be replaced with new 4-20 mA output transmitters. To support the instnnnent loop conversion to a 4-20 mA signal the pressure indicators on panel 9-4 are replaced with new 4-20 mA indicators RCIC-Pl-93, 94, 95, and 96. The instrument loop GEMAC power supply (RCIC-ES-1392) in panel 9-19 is replaced with four new 24 volt DC power supplies (RCIC-ES-1392A, B, C and D).
Revision 1: This change eliminates time delays in the ramp rate on a RCIC initiation signal. The vendor originally proposed these delays to avoid overshoot during startup of the turbine. However, based on operating experience it has been found this time delay is not required. Elimination of the time delays will add margin to the response time especially during the 150 pounds per square inch test.
The 50.59 evaluation had originally included the details and time frames of the delays that were a level of detail not required for the evaluation.
Revision 2: This modification was installed in Refuel Outage 30 (October 2018) and during the modification close out it was noticed some of the specific document updates noted in the original modification included updates beyond the scope of the modification and these updates would be submitted on their own.
The specificity of these updates was also included in the original 50.59 evaluation. As such, revision 2 of the 50.59 evaluation was submitted that eliminated this level of detail. The deletion did not result in a change to the evaluation.
10 CFR 59    This evaluation has determined that the RCIC System will continue to meet its Evaluation:  design and licensing bases requirements following the implementation of the modification that converts to a digital governor control method for the system.

NLS2020057 Page 3 of 4 The new RCIC turbine skid mounted components can satisfy the existing 148&deg;F temperature for the North East quad as described in the Updated Safety Analysis 1Report (USAR). The new RCIC control panel, RCIC-PNL-0505, components on the 903 ft elevation level are qualified to l39&deg;F for a 24-hour period. The new transmitters (RCIC-PT-60/65/68/70) are rated for operation up to 220&deg;F and 100% relative humidity. The system remains capable of operating during a 24-hour FLEX event for expected environmental temperatures.
Since the new RCIC System components are more reliable than the existing components and no new system level failure mode effects are introduced, the modification does not result in more than a minimum increase in the frequency of occurrence of an accident previously evaluated in the CNS USAR.
The new equipment being installed will not initiate any new system level malfunctions. No credit is taken for the RCIC System for the successful mitigation of any USAR postulated design basis transient or accident. Credit is taken for the RCIC System to provide core cooling following two postulated beyond design basis special events (Anticipated Transient Without Scram and Station Blackout). Credit is also taken for RCIC for various Fire scenarios. RCIC is credited for an Extended Loss of AC Power (ELAP) in the CNS Diverse and Flexible Coping Strategies (FLEX) in the CNS response to Nuclear Regulatory Commission (NRC) Order EA-12-049. The RCIC System will not adversely impact any of the systems that have a dynamic interface with the RCIC System; namely, Emergency Condensate Storage Tanks, Suppression Pool, Main Steam, Feedwater, and 125/250 volt DC Power Systems. Therefore, the modification does not result in more than a minimum increase in the likelihood of occurrence of a malfunction of a system, structure, or component (SSC) important to safety previously evaluated in the USAR.
Performance requirements associated with core cooling are unaltered such that fuel integrity will be maintained and the USAR analysis of radiological consequences remains bounding. The RCIC System is not utilized to mitigate any postulated transients or design basis accidents. The new equipment will not initiate any new accidents. The modification will not impair or prevent the Emergency Core Cooling Systems from mitigating the consequences of any design basis accidents. Therefore, this activity does not result in more than a minimum increase in the consequence of an accident previously evaluated in the USAR.
Failure or malfunction of the new equipment will not prevent or affect the ability of safety related systems or systems important to safety to respond to the accidents described in the USAR. Therefore, implementation of the proposed modification does not result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the USAR.
The potential malfunctions of the modified equipment are bounded at a system

NLS2020057 Page 4 of 4 level in the USAR. Therefore, the possibility for an unanalyzed malfunction of an SSC important to safety or an accident of a different type than any previously evaluated in the USAR are not created.
As described in the USAR transient analysis, no malfunction of the RCIC System can cause a transient sufficient to damage the fuel barrier or exceed the nuclear limits as required by the safety design basis. For the 'Inadvertent Start of the High Pressure Coolant Injection (HPCI) Pump' transient, the HPCI System scenario bounds an inadvertent start of the RCIC System. The proposed modification does not adversely impact the technical attributes supporting this conclusion. Therefore, the modification does not result in the design basis limits for fission product barriers, as described in the USAR, being exceeded or altered.
The new digital equipment does not necessitate a revision or replacement of any currently used evaluation methodology for the RCIC System. The modification does not result in a departure from the method of evaluation described in the USAR in establishing the design bases or in the safety analyses.
It is concluded that implementation of the modification does not require a Technical Specification change, does not require a License Amendment, and therefore may proceed without NRC approval.

NLS2020057 Page 1 of 4 Attachment 2 Other Changes The following list provides a summary of 50.59 evaluations that were prepared to support other changes that were implemented at Cooper Nuclear Station (CNS) during the time period from August 1, 2018, to July 31, 2020.
Engineering Change (EC) 18-012 (Evaluation 2018-2, Revision 1)

==Title:==
Extending Inspection Duration of Underwater Torus Region

==
Description:==
EC 18-012, Revision 0, provides the technical basis for extending the American Society of Mechanical Engineers (ASME) Section XI VT-1, visual examination and desludging frequency on 100% of the wetted portion of the Torus from one refueling cycle (2 years) to two refueling cycles (4 years). Conclusions of this evaluation determined it is acceptable to extend the visual/desludging/recoating activities to two refueling cycles conditional on the performance of supplemental volumetric examinations of select test evaluation locations every refueling outage in order to monitor/trend corrosion degradation without entering containment.
The Primary Containment has the following design function for accident mitigation: Primary Containment 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 Loss of Coolant Accident). The Suppression Chamber, in turn, supports this design function by condensing steam discharged to the Suppression Pool during a design basis accident loss of coolant accident (DBA LOCA).
The Containment Inservice Inspection (CISI) Program is credited in the Updated Safety Analysis Report (USAR) as being the Aging Management Program that manages the loss of material aging effect due to general corrosion. The USAR also credits the Suppression Chamber (Torus) coating as a design feature that supports aging management of the Suppression Chamber from general corrosion.
The coating also has the design function of satisfactorily withstanding the temperatures and pressures of the steam environment during a DBA LOCA.
Extending the duration of the visual torus inspections will allow corrosion sites to continue to grow deeper for two additional years before mitigating actions such as recoating the deeper pit like locations can be performed. This change, to extend the mitigation efforts to deal with corrosion from two years to four years, is considered adverse and therefore this activity screens in under 10 CFR 50.59.
The Nuclear Regulatory Commission (NRC) approved the CNS License Renewal

NLS2020057 Page 2 of 4 application originally based on CNS performing visual underwater inspections every outage until the Torus was to be recoated during the period of extended operation (post January 2014). CNS subsequently revised Commitment NLS2010050-02 to remove the full recoating requirement (wetted surface only) but maintain a conservative inspection program every outage cycle until the end of plant life to manage the effects of aging due to corrosion. Under this evaluation, CNS relaxes the visual inspection/desludging/recoating requirements by extending the frequency from two to four years but monitor wall thickness via ultrasonic testing methods in spot locations every outage.
Revision 1: This 50.59 evaluation was developed to extend the frequency of Torus inspection and cleaning and was originally reviewed by Station Operation Review Committee in 2018. As part of a quality review during a program self-assessment, comments on the evaluation were identified and Revision 1 was generated to incorporate the comments. This revision added clarification to questions 2, 3, and 4 but did not change the conclusions of the evaluation.
10 CFR 50.59 This evaluation has concluded that revising the USAR to extend the ASME Evaluation:   Section XI Torus inspection, desludging and spot recoating frequency from two years to four years is acceptable and can be implemented without prior NRC approval.
Technical Requirements Manual (TRM) 3.7.1, River Level (Evaluation 2019-2, Revision 0)

==Title:==
Revise Shutdown Criteria for High River Level

==
Description:==
The shutdown criteria in Condition B ofTRM 3.7.1 is being changed. The current criteria calls for a plant shutdown if "River level is 2:: 902 ft mean sea level (MSL) or forecast to be 2:: 902 ft MSL within the next 36 hours." The forecast relied upon to make TRM 3.7.1 decisions becomes unreliable for Missouri River levels less than 902 ft MSL, therefore a new means of measuring river level and criteria are required.
The new criteria will call for a plant shutdown if the "River level is 2:: 901 '-8" MSL" as measured in the CNS intake structure per current guidance,in Emergency Procedure 5.lFLOOD, Attachment 1. The TRM 3.7.1 Bases, Emergency Procedure 5. lFLOOD, and USAR II-4.2.2 will be updated consistent with the new shutdown criteria of 2: 901 '-8" (901.67 ft) MSL. As a consequence of removing the forecast element of"2:: 902 ft MSL within the next 36 hours" from the shutdown criteria of Condition B, the required action B.1 related to entering Procedure 5. lFLOOD and associated completion time of immediately can be removed. The required action B.1 and completion time of entering the procedure is redundant to the required action A.1 and completion time. It is not plausible to measure a river level of 2: 901 '-8" (901.67 ft) MSL prior to measuring

NLS2020057 Page 3 of 4 a river level of 895 ft MSL, therefore required action B. l is unnecessary. The numbering of required actions B.2 and B.3 will change to B.1 and B.2 respectively as a result ofremoving required action B.1.
The plant design and licensing basis for other flood events evaluated in USAR II-4, "Hydrology," at river levels of 902 ft MSL and above, such as, shutdown without offsite power, local levee failures, and upstream dam failures are not affected by this change to shutdown criteria in TRM 3.7.1, Condition B.
A second change will be to add dam failure criteria as an "or'' statement to TRM
: 3. 7 .1, Condition A. This addition will bring Condition A and Required Actions in line with the existing Procedure 5.lFLOOD entry conditions and TRM 3.7.1 Bases which states, "However, should a dam break or in case of a river level of 895 ft. MSL, the CNS Site Flood Procedure will be put into effect." Condition A will state, "River Level is::: 895 ft MSL or notification of upstream system dam failure." The required actions and completion times associated with Condition A are unaffected by this change.
10 CFR 50.59 Supporting analysis shows that a river level of::: 901 '-8" (901.67 ft) MSL can be Evaluation:  used as the trigger point in TRM 3. 7 .1, Condition B criteria, for initiating a plant shutdown.
The new river level criteria provides the same level of protection against reaching 902 ft MSL as the original forecast criteria with the additional benefit of removing the significant inaccuracies that come with the forecast at higher levels.
Additionally, the guidance for taking the river level measurement in the CNS intake structure already exists in Emergency Procedure 5.lFLOOD, Attachment 1.
The 36 hours operator response time provided by the old forecast method to "Be in MODE 4, with the reactor vessel vented to atmosphere" is unchanged by the new criteria Supporting analysis shows a peak river level of 901.9 ft MSL at CNS, which is less than the USAR described value of 902 ft MSL associated with the CNS levee. The analysis used as input, the Probable Maximum Flood Hydrograph documented in FSAR Question No. 2.1 in support of Amendment No. 9. This hydro graph peaks at a total discharge of 590,000 cubic feet per second (cfs) which exceeds all previously documented peak totals discharged for the Missouri River through Brownville. It is estimated that the peak of the March 2019 flood event was around 345,000 cfs at CNS based on provisional data from the United States Geological Survey gage for the Missouri River at Nebraska City, Nebraska Aerial photos of CNS during the peak of the March 2019 flood (345,000 cfs) were compared to the TUFLOW FV Model at the same flow rate.
The comparison shows good correlation between the aerial photos and the simulation with the footprint of site (dry) and the inundation (wet) around the site.
Since the peak never reaches 902 ft MSL for this hydrograph, the completion

.' '\
NLS2020057 Attachment 2 Page 4 of 4 times of achieving Mode 3 (12 hours) and Mode 4 (36 hours) are guaranteed for the new criteria of~ 901 '-8" (901.67 ft) MSL.
The hydraulic model accepted by Engineering Report 2019-009 shows that the peak water elevation in the 161 kV switchyard is 899.42 ft MSL. The lowest elevation of control circuits supporting the T6 transformer offsite power supply is 899.73 ft MSL. The equipment related to offsite power supply is never impacted per the supporting analysis from which the new shutdown criteria of~ 901 '-8" (901.67 ft) MSL was derived. Therefore, utilizing the new shutdown criteria will provide adequate protection to the T6 transformer offsite power supply.
This first change does not result in a more than minimal increase in any of the 50.59 evaluation questions.
Adding criteria related to notification of upstream system dam failure to TRM 3.7.1, Condition A, does not change any USAR described response or completion time to "notification of upstream system dam failure." This change will bring the TRM 3. 7 .1, Condition A, in line with the existing TRM 3. 7 .1 Bases, actions described in USAR II-4.2.2.2, and the entry conditions for Emergency Procedure 5.lFLOOD. USAR II-4.2.2.2 currently states a plant shutdown is initiated if "Flood waters either reach 902 feet MSL, or are forecast to reach 902 feet MSL within the next 36 hours (as from the 10,000 year flood, or an upstream dam failure)." One of the entry conditions into Emergency Procedure 5.lFLOOD is
                   ''Notification of an upstream dam failure."
This second change does not result in a more than minimal increase in any of the 50.59 evaluation questions.
These changes do not result in a more than minimal increase in any of the 50.59 evaluation questions and the activities may be implemented without prior NRC approval.}}