ML21195A062

Issuance of Amendment No. 319 One-Time Request to Revise Technical Specification Action for Rod Position Indicators

ML21195A062
Person / Time
Site:	Salem
Issue date:	08/03/2021
From:	James Kim Plant Licensing Branch 1
To:	Carr E Public Service Enterprise Group
Kim J
References
EPID L-2021-LLA-0114
Download: ML21195A062 (15)

Text

August 3, 2021 Mr. Eric Carr President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 - ISSUANCE OF AMENDMENT NO. 319 RE: ONE-TIME REQUEST TO REVISE A TECHNICAL SPECIFICATION ACTION FOR ROD POSITION INDICATORS (EPID L-2021-LLA-0114)

Dear Mr. Carr:

The U.S. Nuclear Regulatory Commission (the Commission) has issued the enclosed Amendment No. 319 to Renewed Facility Operating License No. DPR-75 for the Salem Nuclear Generating Station (Salem), Unit No. 2, in response to your application dated June 18, 2021.

The amendment revised a technical specification action for rod position indicators. This is a one-time change during the current operating cycle to support maintenance on the transformer supplying power to all of the Salem, Unit No. 2, rod position indicators.

A copy of the related safety evaluation is also enclosed. Notice of Issuance will be included in the Commissions monthly Federal Register notice.

Sincerely,

/RA/

James S. Kim, Project Manager Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-311

Enclosures:

1. Amendment No. 319 to DPR-75

2. Safety Evaluation cc: Listserv

PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC DOCKET NO. 50-311 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 319 Renewed License No. DPR-75

1. The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment filed by PSEG Nuclear LLC dated June 18, 2021, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance: (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D. The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

Enclosure 1

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and paragraph 2.C.(2) of Renewed Facility Operating License No. DPR-75 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 319, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. The license amendment is effective as of its date of issuance and shall be implemented within 5 days.

FOR THE NUCLEAR REGULATORY COMMISSION Digitally signed by James James G. G. Danna Date: 2021.08.03 Danna 08:42:01 -04'00' James G. Danna, Chief Plant Licensing Branch I Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Renewed Facility Operating License and Technical Specifications Date of Issuance: August 3, 2021

ATTACHMENT TO LICENSE AMENDMENT NO. 319 SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 RENEWED FACILITY OPERATING LICENSE NO. DPR-75 DOCKET NO. 50-311 Replace the following page of the Renewed Facility Operating License with the attached revised page. The revised page is identified by amendment number and contains a marginal line indicating the area of change.

Remove Insert 3 3 Replace the following page of the Appendix A, Technical Specifications, with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.

Remove Insert 3/4 1-16a 3/4 1-16a

(4) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use at any time any byproduct, source or special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration and as fission detectors in amounts as required; (5) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) PSEG Nuclear LLC, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level PSEG Nuclear LLC is authorized to operate the facility at steady state reactor core power levels not in excess of 3459 megawatts (thermal).

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 319, and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. PSEG Nuclear LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Renewed License No. DPR-75 Amendment No. 319

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

3. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

b. With two or more analog rod position indicators per group inoperable:

1. Immediately place the control rods in manual control, and

2. Deleted

3. Verify the position of the rods with inoperable position indicators indirectly using the power distribution monitoring system (if power is above 25% RTP) or using the movable incore detectors (if power is less than 25% RTP or the power distribution monitoring system is inoperable) at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and

4. Within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s* restore the inoperable rod position indicators to OPERABLE status such that a maximum of one rod position indicator per group is inoperable, or

5. Be in HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

c. When one or more rods with inoperable position indicators have been moved in excess of 24 steps in one direction since the last determination of the rods position:

1. Determine the position of the non-indicating rod(s) indirectly using the power distribution monitoring system (if power is above 25% RTP) or using the movable incore detectors (if power is less than 25% RTP or the power distribution monitoring system is inoperable) within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

d. With a maximum of one group demand position indicator per bank inoperable either:

1. Verify that all analog rod position indicators for the affected bank are OPERABLE and that the most withdrawn rod and the least withdrawn rod of the bank are within a maximum of 18 steps when reactor power is 85% RATED THERMAL POWER or if reactor power is > 85% RATED THERMAL POWER, 12 steps of each other at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, or

2. Reduce THERMAL POWER to less than 50% of RATED THERMAL POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

• During the Unit 2 25th operating cycle, a one-time 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> allowed outage time is permitted to allow repair of the rod position indication Solatron transformer. This one-time change will cease to apply if Unit 2 enters Mode 3 prior to the S2R25 refueling outage.

SALEM - UNIT 2 3/4 1-16a Amendment No. 319

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 319 TO RENEWED FACILITY OPERATING LICENSE NO. DPR-75 PSEG NUCLEAR LLC EXELON GENERATION COMPANY, LLC SALEM NUCLEAR GENERATING STATION, UNIT NO. 2 DOCKET NO. 50-311

1.0 INTRODUCTION

By letter dated June 18, 2021 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML21169A004), PSEG Nuclear LLC (the licensee) submitted a license amendment request (LAR) regarding the technical specifications (TSs) for Salem Nuclear Generating Station (Salem), Unit No. 2. The proposed amendment would revise TS limiting condition for operation (LCO) 3.1.3.2.1, Position Indication Systems - Operating, ACTION b.4, to extend the completion time for more than one inoperable analog rod position indicator per group from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> to allow for corrective maintenance and testing on the transformer supplying power to all of the Salem, Unit No. 2, rod position indicators. The proposed extension would be applicable on a one-time basis and would be implemented within 5 days from the date of issuance of the amendment.

2.0 REGULATORY EVALUATION

2.1 Regulations and Guidance In Section 50.36, Technical specifications, of Title 10 of the Code of Federal Regulations (10 CFR), the NRC established its regulatory requirements related to the content of TSs. Pursuant to 10 CFR 50.36, TSs are required to include items in the following categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements; (4) design features; and (5) administrative controls. The rule does not specify the particular requirements to be included in a plants TSs.

The regulation at 10 CFR 50.36(b) states, in part, that:

Each license authorizing operation of a utilization facility will include technical specifications. The technical specifications will be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto, submitted pursuant to [10 CFR] 50.34 [Contents of applications; Enclosure 2

technical information]. The Commission may include such additional technical specifications as the Commission finds appropriate.

The regulation at 10 CFR 50.36(c)(2)(i) states, in part that:

Limiting conditions for operation 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.

Regulatory Guide (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis (ADAMS Accession No. ML17317A256), describes a risk-informed approach acceptable to the NRC for assessing the nature and impact of proposed licensing basis changes by considering engineering issues and applying risk insights.

RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications (ADAMS Accession No. ML100910008), describes an acceptable risk-informed approach to TS changes, specifically for changes to completion times.

Salem was designed and constructed in accordance with Atomic Energy Commission (AEC) proposed General Design Criteria published in July 1967. The AEC proposed criteria, as documented in Salems updated final safety analysis report Section 3.1, were compared to 10 CFR Part 50 Appendix A General Design Criteria (GDC). The GDC criterion applicable to the LAR is GDC 13, which states:

Criterion 13Instrumentation and control. Instrumentation shall be provided to monitor variables and systems over their anticipated ranges for normal operation, for anticipated operational occurrences, and for accident conditions as appropriate to assure adequate safety, including those variables and systems that can affect the fission process, the integrity of the reactor core, the reactor coolant pressure boundary, and the containment and its associated systems. Appropriate controls shall be provided to maintain these variables and systems within prescribed operating ranges.

GDC 13 is similar to AEC Criterion 12.

As discussed below, following implementation of the proposed change, Salem, Unit No. 2, will remain in compliance with AEC Criterion 12.

2.2 System Description The requested change would impact rod position indication. Salem, Unit No. 2, has 53 rod control cluster assemblies (RCCAs) - 24 shutdown and 29 control. Normally, all rods are fully withdrawn at full power. The analog rod position indication (ARPI) senses and displays control rod position. The analog rod position indicators are affected by the capacitor and transformer degradation.

2.3 Proposed Technical Specifications Change The current ACTION b.4 allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of continued plant operation with two or more analog

rod position indicators per group inoperable. Within that time, all but one analog rod position indicator per group must be restored to operable status. If the required analog rod position indicators cant be restored to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, ACTION b.5 requires the licensee to place the plant in HOT STANDBY with the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The proposed amendment would provide the licensee, on a one-time basis, an extra 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to continue plant operation with two or more analog rod position indicators per group inoperable. Specifically, the licensee proposed adding a footnote to the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time in ACTION b.4, which would state:

• During the Unit 2 25th operating cycle, a one-time 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> allowed outage time is permitted to allow repair of the rod position indication Solatron transformer.

This one-time change will cease to apply if Unit 2 enters Mode 3 prior to the S2R25 refueling outage.

3.0 TECHNICAL EVALUATION

3.1 Adverse Condition Description The licensee identified a degraded output voltage on the 5 KVA Solatron transformer that provides conditioned voltage input for the Salem, Unit No. 2, analog rod position indicators.

ARPI is dependent on stable, regulated voltage to provide accurate rod position. A change in Solatron transformer output impacts the rod position indication.

3.2 Repair Plan The Salem, Unit No. 2, 5 KVA Solatron transformer repair plan was informed by a previous Unit No. 1 Solatron transformer repair. The Salem, Unit No. 1, maintenance assessment identified a failed internal capacitor as the cause of the transformers degraded output voltage.

The licensee believes that Unit No. 2 has the same failure and, therefore, based its repair plans on replacing the capacitor.

If the capacitor replacement does not repair the degraded voltage, the licensee has requested enough time in the repair plan to replace the transformer in whole. The licensee provided a table in the LAR with the duration of each repair action, which describes the activities to be accomplished in the requested 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The licensees repair plan will only be entered if the voltage is further degraded or if Salem, Unit No. 2, is required to perform an emergent plant shutdown to Mode 3 or lower prior to the next Unit No. 2 refueling outage (S2R25). If neither of those scenarios present, the transformer will be repaired prior to plant startup from the next Unit No. 2 refueling outage.

The licensee has taken steps to ensure that the repair is completed in a timely manner. The licensee has prepared clearance documents and tested and staged the replacement capacitors pulled from stores. Additionally, the licensee developed guidance to assist in the internal wiring of the capacitors in the transformer housing.

3.3 Regulatory Requirements Evaluation The objective of Salem, Unit No. 2, TS 3.1.3.2.1 is consistent with that of TS 3.1.7 in NUREG-1431, Standard Technical Specifications - Westinghouse Plants (ADAMS Accession No. ML12100A222). This TS ensures operability of the control rod position indicators to determine control rod positions and to ensure compliance with the control rod alignment and

insertion limits. Inability to accurately determine the rod position can directly affect the calculations for shutdown margin and safety analysis that directly affects core power.

When the rod position indication has failed, the Rod Control System is placed in manual to ensure that unplanned rod motion will not occur and indirect position determination can be determined by movable incore detectors. During the proposed maintenance, diverse systems would remain operable to assist in detecting rod misalignment. The systems available would include axial flux differential (AFD) and quadrant power tilt ratio (QPTR) monitor and alarms, power range nuclear instruments (PRNIs), AFD console indication, and plant computer AFD and QPTR indications. Additionally, the group demand counter indication would remain available on the console and plant computer. The operable diverse systems maintain compliance with AEC Criterion 12.

As discussed in Section 2.3, above, the licensee requested a one-time additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of allowed outage time to TS 3.1.3.2.1 ACTION b.4. In Section 3.1 of the LAR, the licensee provided an evaluation and justification for the proposed extra 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of operation while in the condition with two or more analog rod position indicators per group inoperable. The NRC staff determined that while in this condition, diverse systems to detect rod misalignment would remain operable along with remedial actions to: (1) place control rods under manual control (to prevent automatic rod movement) and (2) ensure rod alignment and insertion limit requirements remain met. The staff determined that the one-time additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> beyond the existing outage time is a reasonable request because it is a short amount of additional time during which appropriate remedial actions will be required. The licensee plans to first change the capacitor.

If this repair proves successful, the repair would be completed within the current allowed outage time. Finally, repairs will only be started if the voltage degradation increases. The staff find this proposed change acceptable because, with the addition of the diverse means to ensure that any rod misalignment will be identified, it will provide sufficient time to restore operability while minimizing risk due to a required shutdown transient.

Based on the above, the NRC staff determined that the regulatory requirements of 10 CFR 50.36 will continue to be met because the TSs, as amended, will continue to be derived from the analyses and evaluation included in the safety analysis report, and amendments thereto, in accordance with 10 CFR 50.36(b) and because the TSs, as amended, will continue to require the licensee to shut down the reactor or follow any remedial action permitted by the TSs until the LCO can be met, in accordance with 10 CFR 50.36(c)(2) and that AEC Criterion 12 will continue to be met.

3.4 Risk Insights In Section 3.3 of the LAR, the licensee provided risk insights related to the proposed change.

Because this is not a risk-informed LAR, the NRC staff neither reviewed the licensees probabilistic risk assessment (PRA) models to determine their technical acceptability to support the LAR nor relied on the numerical results provided by the licensee.

In Section 3.3.6 of the LAR, the license stated that, [a]ll [Salem] Unit [No.] 2 work will be re-screened to identify operational or reactivity risk vulnerabilities that could potentially cause a plant or reactivity transient. This work will be re-scheduled accordingly to reduce the likelihood that the control room operators would need to change reactor power while ARPIs are unavailable. In Section 3.3.4 of the LAR, the licensee also stated that, there exists sufficient defense-in-depth with the loss of ARPI, as redundancy and independence exist within reactivity monitoring systems. Therefore, the likelihood of simultaneous maintenance actions is small.

Any maintenance will be evaluated and controlled by the licensee through its Configuration Risk Management Program, and the human performance actions discussed in this safety evaluation.

In the LAR, the licensee provided a risk evaluation considering insights from its full power internal events PRA and provided additional set of stand-alone risk calculations for seismic, fire, and other external events. The licensees analysis evaluated the incremental conditional core damage probability (ICCDP) and the incremental conditional large early release probability (ICLERP) for rod position indication being unavailable for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> instead of the requested 30-hour allowable outage time (AOT), as provided in the summary table below.

ICCDP ICLERP Single 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 5.90E-9 8.74E-10 TS 3.1.3.2.1 Entry Section 2.4 of RG 1.177 states that a one-time TS completion time change impact on plant risk is acceptable when the ICCDP is less than 1.0 x 10-6 and the ICLERP is less than 1.0 x 10-7.

The NRC staff used the Salem, Unit No. 2, SPAR model for reactor protection components to confirm that there are no specific basic events associated with single control rods or control rod position indicators. The SPAR model revealed that the greatest common-cause failure (CCF) contributor for reactor protection components is the CCF of 10 or more control rods inserting into the core followed by the mechanical failure of reactor trip breakers. Based on this insight, the NRC staff believes that the risk contribution from CCF coming from one control rod alone (or an analog rod position indicator) should not be significant. In addition, rod position indication instrumentation is not an accident initiator leading to core damage and providing indication of rod position does not affect the operability of the shutdown or control rods.

The NRC staff also notes that that the delta CDF and delta LERF values of 1.08E-06 and 1.59E-7, respectively, reported in Section 3.3.3 of the LAR are small with respect to the RG 1.174 acceptance risk metrics.

RG 1.177 states that, [t]he licensee should provide the rationale that supports the acceptability of the proposed changes by integrating probabilistic insights with traditional considerations to arrive at a final determination of risk. The NRC staff reviewed the compensatory actions risk management actions (RMAs) discussed in the LAR, which the licensee stated would be implemented for the duration of the proposed one-time rod position indication AOT extension.

The licensee stated that during the proposed AOT extension, the following compensatory measures would be in effect:

Control rods will be maintained in manual per TS 3.1.3.2.1 action b.1 to prevent automatic rod motion.

Reactor engineering will verify rod position in accordance with TS 3.1.3.2.1 action b.3.

Additionally, reactor engineering will perform a rod position verification following plant stabilization from any emergent power maneuver in response to a plant transient.

Main control room operators will perform additional monitoring of diverse parameters that assist in the detection of gross rod misalignment such as hourly monitoring of PRNIs, AFD, QPTR, and group demand counters. An operator will be dedicated to continuously monitoring AFD and QPTR on the plant computer during any power changes.

Control room operators will be briefed on performing reactor trip confirmation according to current training. Operators are trained to verify a reactor trip using multiple and diverse indications which include, PRNIs, intermediate range nuclear instrument power level and startup rate, rod bottom lights, and reactor trip breaker position. Based on the diversity of the remaining available indications, the unavailability of the ARPIs will not impact the operators ability to respond to an anticipated transient without scram event. These established verifications will ensure successful reactor trip confirmation if required.

Reactor engineering will remain on-station, after call-in, to support rod position verifications via flux mapping during the Unit No. 2 ARPI transformer repair window.

This will ensure success in monitoring for proper rod alignment in the event the operating crew is required to change power in response to an event or perform an orderly shutdown.

All Unit No. 2 work will be re-screened to identify operational or reactivity risk vulnerabilities that could potentially cause a plant or reactivity transient. This work will be re-scheduled accordingly to reduce the likelihood that the control room operators would need to change reactor power while ARPIs are unavailable.

The licensee-provided risk insights supported the traditional engineering conclusions associated with the licensees proposed compensatory actions. The risk insights did not challenge the engineering conclusions that the proposed changes are in addition to other defense in depth attributes and are not the sole method of achieving defense in depth.

3.5 Technical Conclusion Based on the technical evaluation discussed above, the NRC staff concludes that the proposed one-time change of the completion time from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> to restore the inoperable rod position indicators to operable status is acceptable.

4.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION

The NRCs regulation at 10 CFR 50.92(c) states that the NRC may make a final determination under the procedures in 10 CFR 50.91 that a license amendment involves no significant hazards consideration if operation of the facility, in accordance with the amendment, would not: (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.

An evaluation of the issue of no significant hazards consideration is presented below:

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

Response: No.

Rod position indication instrumentation is not an accident initiator, providing indication only of the control and shutdown rods positions. Normal operation, abnormal occurrences and accident analyses assume the rods are at certain positions within the reactor core. The proposed one-time change modifies the time that rod position indication may be inoperable. The existing TS Actions and other plant instrumentation provide appropriate compensation for that

inoperability. Thus, this change does not involve a significant increase in the probability of an accident.

Extending the allowed outage time to restore inoperable rod position indicators does not affect the operability of the shutdown or control rods. With rod position indicators inoperable, the position of non-indicating rods is required to be verified by indirect means (i.e., moveable incore detectors). Thus, inoperable rod position indication instrumentation does not involve an increase in the consequences of an accident. The inoperable rod position indication does not have any impact on the ability to trip the reactor in response to analyzed accidents and transients.

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

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

Response: No.

The proposed change does not alter the design, function, or operation of any plant component and does not install any new or different equipment. The proposed change will not impose any new or different requirement or introduce a new accident initiator, accident precursor, or malfunction mechanism.

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

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

Loss of rod position indication does not cause a rod to be misaligned. With rod position indicators inoperable, the control rods are required to be placed in manual control, and the position of non-indicating rods is required to be verified using indirect means. The proposed change will not affect the ability of the shutdown or control rods to perform their required function.

The proposed amendment will not result in a design basis or safety limit being exceeded or altered. Therefore, since the proposed change does not impact the response of the plant to a design basis accident, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above evaluation, the NRC staff concludes that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff has made a final determination that no significant hazards consideration is involved for the proposed amendment and that the amendment should be issued as allowed by the criteria contained in 10 CFR 50.91.

5.0 STATE CONSULTATION

In accordance with the Commissions regulations, the New Jersey State official was notified of the proposed issuance of the amendment on June 28, 2021. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendment changes requirements with respect to the installation or use of facility components located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, as published in the Federal Register (86 FR 34788; June 30, 2021), and there has been no public comment on such finding. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commissions 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.

Principal Contributors: D. Woodyatt K. Tetter M. Hamm Date: August 3, 2021

ML21195A062 OFFICE NRR/DORL/LPL1/PM NRR/DORL/LPL1/LAiT NRR/DORL/LPL3/LA NRR/DSS/SNSB/BC NAME JKim KEntz SRohrer SKrepel DATE 7/14/2021 7/14/2021 7/14/2021 7/13/2021 OFFICE NRR/DSS/STSB/BC (A) NRR/DRA/APLC/BC OGC - NLO NRR/DORL/LPL1/BC NAME NJordan SRosenberg JWachutka JDanna DATE 7/20/2021 7/9/2021 7/20/2021 7/28/2021 OFFICE NRR/DORL/LPL1/PM NAME JKim DATE 8/3/2021