ML18130A270

Issuance of Amendment No. for Emergency Diesel Generator Surveillance Requirements Regarding Voltage and Frequency Limits and the Voltage Limit for Emergency Diesel Generator Load Rejection

ML18130A270
Person / Time
Site:	Harris
Issue date:	06/20/2018
From:	Martha Barillas Plant Licensing Branch II
To:	Hamilton T Duke Energy Progress
Barillas M DORL/LPL2-2 301-415-2760
References
CAC MF9828, EPID L-2017-LLA-0244
Download: ML18130A270 (24)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 June 20, 2018 Ms. Tanya M. Hamilton Site Vice President Shearon Harris Nuclear Power Plant Duke Energy 5413 Shearon Harris Road M/C HNP01 New Hill, NC 27562-0165

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - ISSUANCE OF AMENDMENT FOR EMERGENCY DIESEL GENERATOR SURVEILLANCE REQUIREMENTS REGARDING VOLTAGE AND FREQUENCY LIMITS AND THE VOLTAGE LIMIT FOR EMERGENCY DIESEL GENERATOR LOAD REJECTION (CAC NO. MF9828; EPID L-2017-LLA-0244)

Dear Ms. Hamilton:

The U.S. Nuclear Regulatory Commission (the Commission) has issued Amendment No. 165 to Renewed Facility Operating License No. NPF-63 for the Shearon Harris Nuclear Power Plant, Unit 1 (HNP). This amendment changes the Technical Specifications (TSs) surveillance requirements established for the Emergency Diesel Generators (EDGs) in response to your application dated June 5, 2017 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML17156A216), as supplemented by letters dated October 30, 2017, November 27, 2017, and January 28, 2018 (ADAMS Accession Nos. ML173038156, ML17331A354 and ML18022A046).

The amendment revises HNP TSs to restrict the steady-state voltage and frequency limits for EOG operation to ensure that accident mitigation equipment can perform as designed. These changes modify the existing non-conservative voltage and frequency limit present in HNP TSs.

In addition, the amendment changes a TS to increase the voltage limits for the EOG full load rejection test to provide additional operating margin to test acceptance criteria.

A copy of our related Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commission's regular biweekly Federal Register notice.

Docket No. 50-400

Enclosures:

1. Amendment No. 165 to NPF-63

2. Safety Evaluation cc: Listserv Sincerely, Martha Barillas, Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 DUKE ENERGY PROGRESS. LLC DOCKET NO. 50-400 SHEARON HARRIS NUCLEAR POWER PLANT. UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 165 Renewed License No. NPF-63

1.

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

A.

The application for amendment by Duke Energy Progress, LLC (the licensee),

dated June 5, 2017, as supplemented by letters dated October 30, 2017, November 27, 2017, and January 28, 2018, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 Commission's 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 Commission's regulations and all applicable requirements have been satisfied.

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. NPF-63 is hereby amended to read as follows:

(2)

Technical Specifications and Environmental Protection Plan The Techni~al Specifications contained in Appendix A, and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, as revised through Amendment No. 165, are hereby incorporated into this license. Duke Energy Progress, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This license amendment is effective as of the date of its issuance and shall be implemented within 60 days of issuance.

Attachment:

Changes to the Renewed License and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION

~~y Booma Venkataraman, Acting Chief Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: June 2 o, 2 o 1 8

ATTACHMENT TO LICENSE AMENDMENT NO. 165 SHEARON HARRIS NUCLEAR POWER PLANT. UNIT 1 RENEWED FACILITY OPERATING LICENSE NO. NPF-63 DOCKET NO. 50-400 Replace the following page of the renewed facility operating license with the revised page. The revised page is identified by amendment number and contains a marginal line indicating the area of change:

Remove Page 4 Insert Page 4 Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove 3/48-4 3/48-5 3/4 8-6 3/4 8-7 3/4 8-8 3/4 8-9 Insert 3/4 8-4 3/4 8-5 3/4 8-6 3/4 8-7 3/4 8-8 3/4 8-9

1 C.

This 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 Duke Energy Progress, LLC, is authorized to operate the facility at reactor Core power levels not in excess of 2948 megawatts thermal (100 percent rated core power) in accordance with the conditions specified herein.

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, as revised through Amendment No. 1 6 5, are hereby incorporated into this license. Duke Energy Progress, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3)

Antitrust Conditions (4)

(5)

Duke Energy Progress, LLC. shall comply with the antitrust conditions delineated in Appendix C to this license.

Initial Startup Test Program (Section 14)1 Any changes to the Initial Test Program described in Section 14 of the FSAR made in accordance with the provisions of 10 CFR 50.59 shall be reported in accordance with 50.59(b) within one month of such change.

Steam Generator Tube Rupture (Section 15.6.3)

Prior to startup following the first refueling outage, Carolina Power & Light Company* shall submit for NRC review and receive approval if a steam generator tube rupture analysis, including the assumed operator actions, which demonstrates that the consequences of the design basis steam generator tube rupture event for the Shearon Harris Nuclear Power Plant are less than the acceptance criteria specified in the Standard Review Plan, NUREG-0800, at 15.6.3 Subparts II (1) and (2) for calculated doses from radiological releases. In preparing their analysis Carolina Power &

Light Company* will not assume that operators will complete corrective actions within the first thirty minutes after a steam generator tube rupture.

The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

• On April 29, 2013, the name "Carolina Power & Light Company" (CP&L) was changed to "Duke Energy Progress, Inc." On August 1, 2015, the name "Duke Energy Progress, Inc." was changed to "Duke Energy Progress, LLC."

Renewed License No. NPF-63 Amendment No. 1 6 5

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING LIMITING CONDITION FOR OPERATION ACTION (Continued):

h.

With one automatic load sequencer inoperable:

1.

Restore the automatic load sequencer to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least 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 /> and COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required physically independent circuits between the offsite transmission network and the onsite Class 1 E distribution system shall be:

a.

Determined OPERABLE at the frequency specified in the Surveillance Frequency Control Program by verifying correct breaker alignment and power availability, and

b.

Demonstrated OPERABLE at the frequency specified in the Surveillance Frequency Control Program by manually transferring the onsite Class 1 E power supply from the unit auxiliary transformer to the startup auxiliary transformer.

4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE:

a.

At the frequency specified in the Surveillance Frequency Control Program by:

1.

Verifying the fuel level in the day tank,

2.

Verifying the fuel level in the main fuel oil storage tank,

3.

Verifying the fuel oil transfer pump can be started and transfers fuel from the storage system to the day tank,

4.

Verifying the diesel generator can start** and accelerate## to synchronous speed (450 rpm) with generator steady-state voltage and frequency 6900 +/-

276 volts and 60 +/- 0.48 Hz,

5.

Verifying the diesel generator is synchronized, gradually loaded** to an indicated 6200-6400 kW*** and operates for at least 60 minutes,

6.

Verifying the pressure in at least one air start receiver to be greater than or equal to 190 psig, and

7.

Verifying the diesel generator is aligned to provide standby power to the associated emergency buses.

• • This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable, regarding loading recommendations.

• • • This band is meant as guidance to avoid routine overloading of the engine. Loads in excess of this band for special testing or momentary variations due to changing bus loads shall not invalidate the test.

1. 1. The voltage and frequency conditions shall be met within 10 seconds or gradual acceleration to no-load conditions per vendor recommendations will be an acceptable alternative.

SHEARON HARRIS - UNIT 1 3/4 8-4 Amendment No. 1 6 5

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING SURVEILLANCE REQUIREMENTS (CONTINUED) 4.8.1.1.2 (Continued)

b.

Check for and remove accumulated water:

1.

From the day tank, at the frequency specified in the Surveillance Frequency Control Program and after each operation of the diesel where the period of operation was greater than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and

2.

From the main fuel oil storage tank, at the frequency specified in the Surveillance Frequency Control Program.

c.

By verifying fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program, at frequencies in accordance with the Diesel Fuel Oil Testing Program.

d.

DELETED.

e.

At the frequency specified in the Surveillance Frequency Control Program, the diesel generators shall be started** and accelerated to at least 450 rpm in less than or equal to 10 seconds. The generator steady-state voltage and frequency shall be 6900 +/- 276 volts and 60 +/- 0.48 Hz in less than or equal to 10 seconds after the start signal.

• • This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading recommendations.

SHEARON HARRIS - UNIT 1 3/4 8-5 Amendment No. 1 6 5

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING SURVEILLANCE REQUIREMENTS (CONTINUED) 4.8.1.1.2 (Continued)

The generator shall be manually synchronized to its appropriate emergency bus, loaded to an indicated 6200-6400***kW, and operate for at least 60 minutes.

The diesel generator shall be started for this test by using one of the following signals on a rotating basis:

1.

Simulated loss of offsite power by itself, and

2.

A Safety Injection test signal by itself.

This test, if it is performed so that it coincides with the testing required by Surveillance Requirement 4.8.1.1.2.a.4, may also serve to concurrently meet those requirements as well.

f.

At the frequency specified in the Surveillance Frequency Control Program by:

1.

DELETED

2.

During shutdown, verifying that, on rejection of a load of greater than or equal to 1078 kW, the voltage and frequency are maintained with 6900 +/- 690 volts and 60 +/- 6. 75 Hz, with voltage stabilizing to 6900 +/- 276 volts and frequency stabilizing to 60 +/- 0.48 Hz within 1 O seconds without any safety-related load tripping out or operating in a degraded condition.

3.

During shutdown, verifying that the load sequencing timer is OPERABLE with the interval between each load block within 10% of its design interval.

4.

During shutdown, simulating a loss of offsite power by itself, and:

• • • This band is meant as guidance to avoid routine overloading of the engine. Loads in excess of this band for special testing or momentary variations due to changing bus loads shall not invalidate the test.

SHEARON HARRIS-UNIT 1 3/4 8-6 Amendment No. 1 6 5

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING SURVEILLANCE REQUIREMENTS (Continued) 4.8.1.1.2 (Continued) a)

Verifying de-energization of the emergency buses and load shedding from the emergency buses.

b)

Verifying the diesel starts** on the auto-start signal, energizing the emergency buses with permanently connected loads in less than or equal to 1 O seconds, energizing the auto-connected shutdown loads through the load sequencer, and operating for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization of these loads, the steady-state voltage and frequency shall be maintained at 6900 +/- 276 volts and 60 +/- 0.48 Hz.

5.

During shutdown, verifying that on a safety injection test signal (without loss of power) the diesel generator starts-on the auto-start signal and operates on standby for greater than or equal to 5 minutes.

6.

During shutdown, simulating a loss of offsite power in conjunction with a safety injection test signal, and a)

Verifying de-energization of the emergency buses and load shedding from the emergency buses.

b)

Verifying the diesel starts** on the auto-start signal, energizing the emergency buses with permanently connected loads in less than or equal to 1 O seconds, energizing the auto-connected emergency (accident) loads through the sequencing timers, and operating for greater than or equal to 5 minutes and maintaining the steady-state voltage and frequency at 6900 +/- 276 volts and 60 +/- 0.48 Hz.

c)

DELETED

• • This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading recommendations.

SHEARON HARRIS - UNIT 1 3/4 8-7 Amendment No. 1 6 s

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING SURVEILLANCE REQUIREMENTS (Continued) 4.8.1.1.2 (Continued)

7.

Verifying the diesel generator operates** for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. During the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of this test, the diesel generator shall be loaded to 6800-7000 kW*** and, during the remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of this test, the diesel generator shall be loaded to an indicated 6200-6400 kW***.

8.

DELETED

9.

During shutdown, verifying the diesel generator's capability to:

a)

Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated restoration of offsite power, b)

Transfer its loads to the offsite power source, and c)

Proceed through its shutdown sequence.

10. DELETED

11. During shutdown, verifying the generator capability to reject a load of between 6200 and 6400 kW without tripping. The generator voltage shall not exceed 8280 volts during and following the load rejection;

12. During shutdown, verifying that, with the diesel generator operating in a test mode and connected to its bus, a simulated Safety Injection signal overrides the test mode by: (1) returning the diesel generator to standby operation and (2) automatically energizing the emergency loads with offsite power.

• • This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading recommendations.

• • • This band is meant as guidance to avoid routine overloading of the engine. Loads in excess of this band for special testing or momentary variations due to changing bus loads shall not invalidate the test.

SHEARON HARRIS - UNIT 1 3/4 8-8 Amendment No. 1 6 5

ELECTRICAL POWER SYSTEMS A.C. SOURCES OPERATING SURVEILLANCE REQUIREMENTS (CONTINUED) 4.8.1.1.2 (Continued)

13. During shutdown, verifying that all diesel generator trips, except engine overspeed, loss of generator potential transformer circuits, generator differential, and emergency bus differential are automatically bypassed on a simulated or actual loss of offsite power signal in conjunction with a safety injection signal.

14. During shutdown, verifying that within 5 minutes of shutting down the EDG, after the EDG has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at an indicated load of 6200-6400 kw, the EDG starts and accelerates to a steady-state voltage and frequency of 6900 +/- 276 volts and 60 +/- 0.48 hz in 10 seconds or less.

g.

At the frequency specified in the Surveillance Frequency Control Program or after any modifications which could affect diesel generator interdependence by starting** both diesel generators simultaneously, during shutdown, and verifying that both diesel generators accelerate to at least 450 rpm in less than or equal to 10 seconds.

h.

At the frequency specified in the Surveillance Frequency Control Program by:

1)

DELETED.

2)

Performing a pressure test, of those isolable portions of the diesel fuel oil piping system designed to Section Ill, subsection ND of the ASME Code, at a test pressure equal to 110% of the system design pressure.

• • This test shall be conducted in accordance with the manufacturer's recommendations regarding engine prelube and warmup procedures, and as applicable regarding loading recommendations.

SHEARON HARRIS - UNIT 1 3/4 8-9 Amendment No. 1 6 5

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 165 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-63 DUKE ENERGY PROGRESS, LLC SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 DOCKET NO. 50-400

1.0 INTRODUCTION

By letter dated June 5, 2017 (Agencywide Documents Access and Management System (ADAMS Accession No. ML17156A216), as supplemented by letters dated October 30, 2017, November 27, 2017, and January 22, 2018 (ADAMS Accession Nos. ML173038156, ML17331A354 and ML18022A046), Duke Energy Progress, LLC (the licensee) submitted a license amendment request (LAR) to revise the Shearon Harris Nuclear Power Plant, Unit 1 (HNP), Technical Specifications (TSs). The requested changes would revise the TS surveillance requirements (SRs) established for the Emergency Diesel Generators (EDGs).

Specifically, the proposed changes restrict the steady-state voltage and frequency limits for EDG operation to ensure that accident mitigation equipment can perform as designed. These changes modify the existing voltage and frequency limits from plus or minus 10 percent (6900 +/- 690 volts) to plus or minus 4 percent of the nominal EDG voltage (6900 +/- 276 volts),

and plus or minus 2 percent of nominal frequency (60 +/- 1.2 hertz (Hz)), to plus or minus 0.8 percent of the nominal frequency (60 +/- 0.48 Hz), respectively. In addition, the licensee proposes to change the HNP TS SR 4.8.1.1.2.f.11 to increase the voltage limit for the EDG full load rejection test from 110 percent of the EDG voltage at the start of the test to 8280 volts at any time during the test, which is 120 percent of the EDG nominal voltage rating of 6900 volts to provide additional operating margin to test acceptance criteria.

The supplements dated October 30, 2017, November 27, 2017, and January 28, 2018, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's initial proposed no significant hazards consideration determination as published in the Federal Register on September 26, 2017 (82 FR 44851).

2.0 REGULATORY EVALUATION

2.1

System Description

The function of the EDG system is to provide a reliable source of alternate power to the emergency 6.9 kilovolt (kV) buses for use in the event that normal sources of offsite power are not available. The EDGs automatically start upon receipt of either an Engineered Safety Feature Actuation Signal or a low bus voltage, as indicated by the bus undervoltage relays, and are automatically connected to the bus through the EOG output breaker upon either a low bus voltage or a loss of bus voltage. The existing onsite power system consists of two EOGs that are rated at nominal 6900 volts alternating current (VAC), 6.5 megawatts (MW), have a machine rated power factor of 0.8, and an apparent power rating of 8.125 megavolt amperes. The EOGs are capable of being ready to load within 10 seconds and being fully loaded within 55 seconds after receipt of a start signal. Each EOG is capable of supplying all power needed for the safe shutdown of the plant under design emergency conditions. Each EOG engine provides a reliable source of driving power to the respective EOG.

2.2 Proposed Technical Specifications Changes The licensee proposed changes to HNP TS SR 4.8.1.1.2.a.4, SR 4.8.1.1.2.e, SR 4.8.1.1.2.f.2, SR 4.8.1.1.2.f.4.b, SR 4.8.1.1.2.f.6.b, and SR 4.8.1.1.2.f.14 in order to restrict the steady-state voltage and frequency limits for EOG operation, to ensure that accident mitigation equipment can perform as designed. These changes modify the existing non-conservative voltage and frequency limits present in HNP TS.

The licensee also requested a revision to HNP TS SR 4.8.1.1.2.f.11 to increase the voltage limit for the EOG full load rejection test. This change provides additional operating margin to test acceptance criteria.

The proposed changes revise the following HNP TS SRs:

SR 4.8.1.1.2.a.4 is being revised to verify that on a slow start from standby conditions, the EOG will come up to a voltage of 6900 +/- 276 volts. The frequency will also be revised to 60 +/- 0.48 Hz, as this SR verifies that the EOG will start in slow speed and will reach steady-state conditions for voltage and frequency.

SR 4.8.1.1.2.e is being revised to verify that the EOG starts from a standby condition and achieves a steady-state voltage of 6900 +/- 276 volts and frequency of 60 +/- 0.48 Hz in less than or equal to 10 seconds following a start signal.

SR 4.8.1.1.2.f.2 verifies that during shutdown, on a rejection of a load of greater than or equal to 1078 kilowatts (kW), the EOG will maintain a voltage of 6900 +/- 690 volts and frequency of 60 +/- 6. 75 Hz, with frequency stabilizing to 60 +/- 1.2 Hz within 10 seconds without any safety-related load tripping out or operating in a degraded condition. This SR is being revised to limit the voltage stabilizing to 6900 +/- 276 volts and frequency stabilizing to 60 +/- 0.48 Hz within 10 seconds without any safety-related load tripping out or operating in a degraded condition.

SR 4.8.1.1.2.f.4.b verifies that during shutdown on a simulated loss of offsite power by itself, the EOG starts on the auto-start signal, energizing the emergency buses with permanently connected loads in less than or equal to 10 seconds, energizing the auto-connected shutdown loads through the load sequencer, and operating for greater than or equal to 5 minutes while the EOG is loaded with the emergency loads. After the energization of these loads, the steady-state voltage and frequency shall be maintained at 6900 +/- 690 volts and 60 +/- 1.2 Hz.

This SR is being revised to verify that the EOG maintains a steady-state voltage of 6900 +/- 276 volts and frequency of 60 +/- 0.48 Hz.

SR 4.8.1.1.2.f.6.b verifies that during shutdown, on a simulated loss of offsite power in conjunction with a safety injection (SI) test signal, the EOG starts on the auto-start signal, energizing the emergency buses with permanently connected loads in less than or equal to 10 seconds, energizing the auto-connected emergency (accident) loads through the sequencing timers, and operates for greater than or equal to 5 minutes and maintains the steady-state voltage and frequency at 6900 +/- 690 volts and 60 +/- 1.2 Hz. This SR is being revised to verify that the EDG maintains a steady-state voltage of 6900 +/- 276 volts and frequency of 60 +/- 0.48 Hz.

SR 4.8.1.1.2.f.14 verifies that during shutdown, within 5 minutes of shutting down the EDG, after the EDG has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at an indicated load of 6200-6400 kW, the EDG starts and accelerates to steady-state conditions of 6900 +/- 690 volts and 60 +/- 1.2 Hz in 10 seconds or less. This SR is being revised to verify that the EDG starts and accelerates to steady-state conditions of 6900 +/- 276 volts and frequency of 60 +/- 0.48 Hz in 10 seconds or less.

In its LAR, the licensee stated the current EDG voltage and frequency range limits of 6900 volts

+/- 10 percent and 60 Hz +/- 2 percent within the HNP TS SR 4.8.1.1.2.a.4, 4.8.1.1.2.e, 4.8.1.1.2.f.2, 4.8.1.1.2.f.4.b, 4.8.1.1.2.f.6.b, and 4.8.1.1.2.f.14, are not appropriate for steady-state voltage and frequency conditions. The reasons provided below illustrate the basis for why the current values are not appropriate.

1. The lower end of the range (6210 VAC) is below the dropout setting of the Degraded Grid Voltage Relay (6420 VAC nominal). The Degraded Grid Voltage Relay reset setting is at 6450 VAC. HNP TS Table 3.3-4, Engineered Safety Features Actuation System Instrumentation Trip Setpoints, Item 9 specifies the Degraded Grid Voltage Relay (DGVR) voltage setpoint to be~ 6420 VAC with an allowable value of

~ 6392 VAC. The nominal dropout setting is 6420 VAC and the maximum expected voltage considering tolerance is 6438 VAC. It should be noted that the breaker tripping function of the DGVR is "blocked" while the EDGs are supplying the emergency buses.

The lower end of the range (6210 VAC) is also below the required voltage to ensure the loads will function and not be damaged. In order to address this issue, surveillance test procedures were revised to control voltage at a tighter band of 6500-7200 volts.

2. The upper end of the range (7590 VAC) is above the maximum allowed operating voltage for the 6.6 kV motors supplied by the 6.9 kV emergency buses (7260 VAC). In order to address this issue, surveillance test procedures were revised to control voltage at a tighter band of 6500-7200 volts.

3. Use of a higher than 60 Hz frequency was not previously considered in the EDG loading analysis, thus fuel consumption, motor-operated valve (MOV) stroke times, pump speed/output or impact on fan operations were not previously evaluated.

Based upon the reasons identified above, HNP determined that the values in the HNP TS SR 4.8.1.1.2.a.4, 4.8.1.1.2.e, 4.8.1.1.2.f.2, 4.8.1.1.2.f.4.b, 4.8.1.1.2.f.6.b, and 4.8.1.1.2.f.14, are non-conservative for steady-state operation. Thus, the TS changes proposed by this LAR are necessary to resolve the non-conservative condition described above.

This LAR also proposed to increase the voltage limit per HNP TS SR 4.8.1.1.2.f.11 for full load rejection testing of the EDGs. This surveillance test demonstrates the EDG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. An EDG may experience a full load rejection because of a system fault or an inadvertent EDG breaker trip during an event. The HNP TSs require testing the EDG performance per SR 4.8.1.1.2.f.11, to demonstrate the capability of the EDG to reject a load equal to the continuous load rating of the EDG without tripping or sustaining damage. This testing ensures that the EDG is immediately available to perform its required functions after the event, including reconnection to the bus if the trip initiator can be corrected or isolated. The load rejection test envelopes the voltage and frequency variations that are observed during a partial or full load rejection event with the EDG connected to the safety buses.

The existing TS voltage limit value is 110 percent of the EDG voltage at the start of the test.

The test requires that the EDG be paralleled to the grid just prior to load rejection. This reduces margin due to the EDG being in the droop mode (EDG in parallel with the offsite power source during testing). Additionally, a technical basis for the specific 110 percent value does not exist in any applicable industry or regulatory standards. Institute of Electrical and Electronics Engineers (IEEE) Standard 387-1977, "IEEE Standard Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations," Section 6.4.5, Load Rejection Tests, specifies that load rejection tests shall demonstrate the capability of rejecting the maximum rated load without exceeding speed or voltage that would cause tripping, mechanical damage, or harmful overstresses. Specific voltage limit values are not provided.

Previous full load rejection test results have shown that inadequate margin exists between the resultant transient peak voltages and the TS voltage limit. Therefore, the proposed increase in the voltage limit will provide adequate test margin.

2.3 Regulatory Requirements Title 10 of the Code of Federal Regulations (10 CFR) Part 50, "Domestic Licensing of Production and Utilization Facilities," Section 50.36, "Technical specifications," establishes the regulatory requirements related to the content of TSs.

Section 50.36(c)(2) to 10 CFR Part 50 states, in part, that the limiting conditions for operation (LCOs) are the lowest functional capability or performance level of equipment required for safe operation of the facility, and when LCOs are not met, the licensee shall shut down the reactor or follow any remedial action permitted by the TSs until the LCO can be met.

Section 50.36(c)(3) to 10 CFR Part 50 requires, in part, that TSs include SRs, which are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met.

Section 50.46, "Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors," to 10 CFR Part 50 requires, in part, that an emergency core cooling system (ECCS) must be designed so that its calculated cooling performance following postulated loss-of-coolant accidents (LOCAs) conform to the criteria set forth in regulations.

Appendix A to 10 CFR Part 50, "General Design Criteria for Nuclear Power Plants" (hereinafter referred to as GDC), establishes the minimum necessary design, fabrication, construction, testing, and performance requirements for structures, systems, and components important to safety; that is, structures, systems, and components that provide reasonable assurance that the facility can be operated without undue risk to the health and safety of the public.

GDC 10, "Reactor design," states the reactor core and associated coolant, control and protection systems shall be designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences.

GDC 15, "Reactor coolant system design," states the reactor coolant system and associated auxiliary, control, and protection systems shall be designed with sufficient margin to assure that the design conditions of the reactor coolant pressure boundary are not exceeded during any condition of normal operation, including anticipated operational occurrences.

GDC 17, "Electric power systems," requires, in part, that an onsite electrical power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences, and (2) the core is cooled, and containment integrity and other vital functions are maintained in the event of postulated accidents. The onsite electric power supplies, including the batteries and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.

GDC 18, "Inspection and testing of electric power systems," requires, in part, that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing of important areas and features to assess the continuity of the systems and the condition of their components. The systems shall be, in part, designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operation sequence that brings the systems into operation.

2.4 Regulatory Guidance The following guidance documents were also considered during this review.

Regulatory Guide 1.9, "Selection, Design, and Qualification of Diesel-Generator Units Used As Standby (Onsite) Electric Power Systems at Nuclear Power Plants," Revision 2, December 1979 (ADAMS Accession No. ML12305A253), which states that "Frequency should be restored to within 2 percent of nominal, and voltage should be restored to within 10 percent of nominal within 60 percent of each load-sequence time interval."

Regulatory Guide 1.108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Revision 1, August 1977 (ADAMS Accession No. ML12216A011) as modified in accordance with the guidance of Information Notice 85-32, dated April 22, 1985.

NRC Technical Report Designation (NUREG) 0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants (initially issued as NUREG 75/087),

Revision 5, May 2010.

3.0 TECHNICAL EVALUATION

3.1 Technical Specifications Surveillance Requirement Changes The proposed TS SR changes would revise the current EDG steady-state voltage limit of plus or minus 10 percent of the nominal EDG voltage (6900 +/- 690 volts) to plus or minus 4 percent of the nominal EDG voltage (6900 +/- 276 volts). The TS SR changes would also revise the current EDG frequency limit of plus or minus 2 percent of the nominal frequency (60 +/- 1.2 Hz) to plus or minus 0.8 percent of the nominal frequency (60 +/- 0.48 Hz) for HNP.

3.2 Impact of the TS SR changes on Final Safety Analysis Report (FSAR) Chapter 15 Analyses 3.2.1 FSAR Chapter 15 Events Credited in Analysis of Record (AOR) Equipment Powered by the EDG In its supplement dated November 27, 2017, the licensee evaluated the assumptions and plant data used in the AOR for all the events discussed in Chapter 15 of the HNP FSAR to determine the events that credited equipment powered by the EDG. The licensee's evaluation identified that the following events credited equipment powered by the EDG:

1. Steam System Piping Failure

2.

Loss of Non-Emergency AC Power to the Station Auxiliaries

3.

Loss of Normal Feedwater Flow

4.

Feedwater System Pipe Break

5.

Inadvertent Operation of the Emergency Core Cooling System During Power Operation

6.

Steam Generator Tube Rupture

7.

Large-Break LOCA (LBLOCA)

8.

Small-Break LOCA (SBLOCA)

The NRC staff finds that the licensee's approach based on the evaluation of the assumptions and plant data used in the AOR is adequate, and its evaluation appropriately identifies the affected events.

3.2.2 Equipment Powered by the EDG and Credited in the AOR In its supplement dated November 27, 2017, the licensee identified that the safety isolation valves, pumps, and fans for SI, auxiliary feedwater (AFW), containment fan coolers (CFC), and containment spray (CT) are the equipment powered by the EDG and credited in the FSAR AOR.

The licensee evaluated the adequacy of the above identified equipment used in the AOR to show acceptable performance characteristics of the safety-grade equipment. The licensee's engineering evaluations showed that induction motors in the safety-related pumps, fans, and valves considered in the FSAR Chapter 15 AOR do not have any significant impact from variations in voltage for the requested EDG voltage tolerance of+/- 4 percent.

The EDG frequency variations could affect pump and fan flow rates, as well as MOV stroke times. The licensee performed engineering evaluations to determine the effect of EDG frequency variations on the performance of the safety-related pumps and fans. The results showed that the safety-related pumps would continue to perform their design functions assumed in the AOR. A summary of the evaluation of the +/- 0.8 percent frequency tolerance on safety-related pumps is provided in Attachment 2 of the Request for Additional Information (RAI) response dated November 27, 2017. The evaluation of the effect of the+/- 0.8 percent frequency tolerance on safety-related fans is discussed in Sections 3.2.4 of this safety evaluation.

The licensee's engineering evaluations also showed that the allowed stroke times of safety-related MOVs are not impacted by the proposed+/- 0.8 percent EDG frequency tolerance.

Specifically, the safety-related pressurizer power-operated relief valves (PORVs) are pneumatically operated valves and the control power for these valves is provided by direct current buses; therefore there is no impact to the operation of these valves with the new EDG voltage and frequency limits. The steam generator (SG) PORVs each have an electro-hydraulic operator and the control power for these valves is provided by alternating current motor control centers. The licensee's engineering evaluations showed that there would be no impact of concern to the SG PORV operation due to the new EDG voltage and frequency limits. In addition, there would be no impact to any automatic actuation delay times with the new EDG voltage and frequency limits.

Based on the above discussion, the NRC concluded that the impact of changing the EDG frequency tolerance to +/- 0.8 percent (60 +/- 0.48 Hz) on the accident analyses in the HNP FSAR Chapter 15, "Accident Analysis," involves the inputs used for pump and fan performance characteristics for SI, AFW, CFC, and CT. The NRC staff reviewed the licensee's engineering evaluations identifying the equipment powered by the EDG and credited in the FSAR Chapter 15 AOR, and finds that: the affected equipment are appropriately identified; the methods used to determine the effects of the EDG voltage and frequency variations on the affected equipment in the areas of the SI and AFW flow rates, and MOV stroke time are adequate; and the impact of the revised EDG voltage and frequency limits on the Chapter 15 AOR is adequately identified. Therefore, the NRC staff finds the proposed frequency change acceptable.

3.2.3 Impact of the Revised EDG Voltage and Frequency Limits on Non-LOCA Analyses As discussed in Sections 3.2.1 and 3.2.2, the following non-LOCA events could potentially be impacted by the EDG frequency tolerance increase due to the impact to SI and/or AFW flow. In the licensee's analyses discussed in the supplement dated November 27, 2017, and Section 3.2.3 below, events that use minimum SI, and AFW flow were evaluated relative to the effect of EDG frequency tolerance on the low side, and events that use maximum SI or AFW flow were evaluated relative to the effect of the high side of the tolerance.

3.2.3.1 Steam System Piping Failure (FSAR Section 15.1.5)

HNP FSAR Section 15.1.5 discusses the steam line break (SLB) analysis. An SLB is defined as the pipe break in the main steam system. The steam release during an SLB causes a decrease in the reactor coolant system (RCS) temperature and the SG pressure. In the presence of a negative moderator temperature coefficient, the RCS temperature decrease results in an addition of positive reactivity. If the added positive reactivity could not be compensated by the negative reactivity added by the control rod insertion resulting from a reactor trip and boron addition, the reactor core might return to power (RTP) after a reactor trip. The following four cases were analyzed: (1) an SLB at hot full power (HFP) with offsite power available; (2) an SLB at HFP with concurrent loss of offsite power; (3) an SLB at hot zero power (HZP) with offsite power available; and ( 4) an SLB at HZP with concurrent loss of offsite power. Since the SLB analysis involves both AFW flow and SI flow, the licensee evaluated both flow rates for the effect of EDG frequency tolerance. The EDG frequency tolerance on the high side may affect maximum AFW flow, while the EDG frequency tolerance on the low side may affect the minimum high head safety injection (HHSI) flow and timing of boron delivery to the core. To maximize the effects of the AFW flow and HHSI flow on the RTP, the SLB analysis assumes maximum AFW flow to the affected SG starting at event initiation and continuing throughout the event, and assumes a minimum SI flow rate to delay boron injection to the core, resulting in a conservative core power response during the RTP.

A maximum AFW flow rate of 3,000 gallons per minute (gpm) is used in the AOR, which bounds the effect of the EDG frequency tolerance on the high side. Therefore, the NRC staff finds that the requested EDG frequency tolerance on the high side for AFW flow has no effect on the SLB analysis.

The minimum HHSI flow rate from the AOR was compared to the minimum HHSI flow rate that includes the effect of the EOG frequency tolerance. This comparison shows that the HHSI flow rate with EDG frequency adjusted low produced only slightly less flow than the HHSI flow used in the SLB AOR, particularly over the range of RCS pressure during a SLB event. The RTP for Case 1, the HFP case with reactor coolant pumps (RCPs) powered by the available offsite power, is mitigated by boron injection. Since the increase in power at the time of boron injection

{which is at or approximately the time of peak power) is very small, a small delay in boron injection as a result of a slightly lower HHSI flow rate would not significantly affect the peak RTP. Similar behavior exists for Case 2, the HFP with RCPs-off case, and Case 3, the HZP with RCPs-on case. For Case 4, the HZP RCPs-off case, the peak RTP occurs well before boron reaches the core. For this case, any minor delay in boron injection would have no effect on the peak RTP.

Based on the above discussion, the NRC staff finds that the EDG frequency tolerance on the high side for AFW flow and low side for HHSI flow would have no significant effect on the FSAR Section 15.1.5, SLB AOR.

3.2.3.2 Loss of Non-Emergency Alternating Current (AC) Power to the Station Auxiliaries (FSAR Section 15.2.6)

HNP FSAR Section 15.2.6 discusses the loss of non-emergency AC power analysis. The event may be caused by a complete loss of the offsite power accompanied by a turbine-generator trip.

The loss of non-emergency AC power AOR assumes a minimum AFW flow rate of 37 4 gpm (total to three SGs) to maximize the peak RCS pressure during the event. This minimum flow rate bounds the effect of the EDG frequency tolerance on the low side. Therefore, the NRC staff finds that the AOR would adequately support an EDG frequency tolerance of+/- 0.8 percent.

3.2.3.3 Loss of Normal Feedwater Flow {LNF) (FSAR Section 15.2. 7)

HNP FSAR Section 15.2.7 discusses the LNF analysis. The LNF event may be caused by feedwater pump failures, valve malfunctions or a loss of AC power sources. The LNF AOR assumes a minimum AFW flow rate of 374 gpm (total to three SGs). This minimum flow rate bounds the effect of the EDG frequency tolerance on the low side. Therefore, the NRC staff finds that the AOR would adequately support an EDG frequency tolerance of+/- 0.8 percent.

3.2.3.4 Feedwater System Pipe Break (FLB) (FSAR Section 15.2.8)

HNP FSAR Section 15.2.8 discusses the FLB analysis. The event is defined as a break in a feedwater line large enough to prevent addition of sufficient feedwater to maintain shell-side water inventory in the SG. The FLB AOR assumes a minimum AFW flow rate of 374 gpm (total to three SGs). This minimum flow rate bounds the effect of the EDG frequency tolerance on the low side.

The FLB AOR limiting case uses a maximum HHSI flow rate. A comparison of the AOR maximum HHSI flow rate to HHSI flow rates adjusted for an EDG frequency tolerance of

+ 0.8 percent shows that the values are equivalent up to an RCS pressure of 1,915 pounds per square inch absolute (psia). Above 1,915 psia, the AOR values are higher than the values adjusted for the requested EDG frequency tolerance. Therefore, the NRC staff finds that the FLB AOR would adequately support an EDG frequency tolerance of+/- 0.8 percent.

3.2.3.5 Inadvertent Operation of the Emergency Core Cooling System (ECCS) During Power Operation (FSAR Section 15.5.1)

HNP FSAR Section 15.5.1 discusses the analysis of the inadvertent operation of the ECCS during power operation. This event is initiated by spurious actuation of SI and assumes continuous SI throughout the event. This event does not involve AFW.

FSAR Section 15.5.1 AOR includes the following three cases: two cases analyze departure from nucleate boiling (DNB) at beginning-of-cycle and end-of-cycle conditions, and a third case addresses pressurizer overfill. The AOR demonstrates that DNB is not challenged for this event, with the DNB ratio generally increasing throughout the transient. Small changes to HHSI from a +/- 0.8 percent EDG frequency tolerance do not affect this conclusion.

For the pressurizer overfill case, the analysis assumes high HHSI flow rates to maximize the potential for the pressurizer to overfill. A comparison of the AOR maximum HHSI flow rates to HHSI flow rates adjusted for an EDG frequency tolerance of+ 0.8 percent shows that the values are equivalent up to an RCS pressure of 1,915 psia. Above 1,915 psia, the AOR values are higher than the values adjusted for the requested EDG frequency tolerance, except for the data point at 2,515 psia. Since the pressure range for this case is between 1,935 psia and 2,250 psia, the data point at 2,515 psia has no significance for the pressurizer overfill analysis that assumes high HHSI flow rates. For the pressurizer overfill case, RCS pressure remains relatively constant near 2,250 psia out to the time that the pressurizer PORVs and safety relief valves (SRVs) open. The AOR maximum HHSI flow rate is slightly higher 2250 psia than the HHSI flow rate that accounts for the requested EDG frequency tolerance. The difference results in the pressurizer to be filled at a slightly later time using the HHSI flow rates adjusted for the EDG frequency tolerance. The temperature of the fluid in the pressurizer when the pressurizer fills and the PORVs and SRVs open will not be significantly different and remains within the acceptable range. Therefore, the NRC staff determined that the AOR remains bounding for the pressurizer overfill case.

3.2.3.6 Steam Generator Tube Rupture (SGTR) (FSAR Section 15.6.3):

HNP FSAR Section 15.6.3 discusses the SGTR margin-to-overfill (MTO) analysis. The SGTR event is defined by a penetration of the barrier between the RCS and the main steam system.

This event may be caused by the failure of an SG U-tube. Since the SGTR MTO analysis credits both HHSI and AFW flow, the licensee addressed the effect of the EDG frequency tolerance on the assumed AFW and HHSI flow rates. The limiting case in the SGTR MTO thermal-hydraulic analysis assumes a maximum AFW flow rate of 1,500 gpm. This maximum flow rate does not account for the effect of the EDG frequency tolerance on the high side or a single failure of the turbine driven AFW speed controller. Accounting for both an increase in EOG frequency and turbine driven FW speed controller failure, the licensee showed that the higher AFW flow rate was offset with a shorter time to isolate a faulted SG.

The AOR limiting case uses maximum HHSI flow. A comparison of the AOR maximum HHSI flow rate curve to HHSI flow rates adjusted for an EOG frequency tolerance of+ 0.8 percent shows that the EOG frequency adjusted flow rates will exceed the AOR values at certain pressure points. The license performed an evaluation and showed that the differences in HHSI flow would have a negligible impact on the MTO analysis. Specifically, the AOR maximum HHSI flow rate curve remains bounding below 1,950 psia, and the EOG-frequency adjusted HHSI flow curve is higher between 2,000 and 2,300 psia. For the limiting SGTR case, RCS pressure remains between 1,900 and 2,100 psia from the time of SI actuation to the time of RCS depressurization. During this time period, the HHSI flow rates remain approximately the same. Therefore, the NRC staff finds that the SGTR MTO analysis would adequately support a

+/- 0.8 percent EOG frequency tolerance.

3.2.4 Impact of the Revised EOG Voltage and Frequency Limits on LOCA Analyses HNP FSAR Section 15.6.3 discusses the LOCA analysis. For the LOCA analysis, the licensee evaluated the assumed pump and fan performance characteristics for SI, AFW, CFC, and CT for the impact of a +/- 0.8 percent EOG frequency tolerance. The NRC reviewed the licensee's evaluation as discussed in the following Sections 3.2.4.1 and 3.2.4.2 for the analyses of LBLOCA and SBLOCA, respectively.

3.2.4.1 Large-Break LOCA (LBLOCA) (FSAR Section 15.6.5.2)

The LBLOCA AOR in FSAR 15.6.5.2 assumes the maximum CFC performance and CT flow in order to minimize containment backpressure, resulting in a maximum break flow rate.

Specifically, the CFC performance in the AOR analysis exceeds the design capability of the fan coolers by a significant margin to accommodate a +/- 0.8 percent change in CFC fan speed due to the proposed variations in EOG frequency, and the maximum two-pump CT flow of 5,000 gpm assumed in the AOR bounds the calculated CT flow rates for the EDGs operating with an increased EOG frequency tolerance of 0.8 percent.

The LBLOCA AOR assumed the minimum SI flow delivery curves to minimize the RCS inventory makeup. The minimum SI flow curves assumed in the AOR were calculated for both HHSI and low head safety injection (LHSI) to account for an increased EOG frequency tolerance of+/- 0.8 percent.

For long-term cooling during a LOCA event, the refueling water storage tank (RWST) is the source for all ECCS pumps. The water source in the RWST is automatically switched to the containment sump when a low-low level in RWST occurs coincident with a SI signal. The low-head residual heat removal (RHR) pumps and CT pumps draw the water from the containment recirculation sump. The minimum RWST low-low allowable value in the TSs is determined to assure that switchover from the RWST (injection mode) to the containment sump (recirculation mode) occurs before the RWST empties to prevent damage due to void cavitation to RHR and CT pumps and maintain cooling capacity. Page 4 of Attachment 2 of the November 27, 2017, supplement indicates that the current available switchover volume margin, that is, the usable water remaining in the RWST following transition from injection to recirculation, is 20,620 gallons. Section 3.4.5 of the LAR indicates that the switchover volume margin of 20,620 gallons was determined based on pump performance at nominal frequency and motor speed. The licensee shows that when the effect of+/- 0.8 percent steady-state frequency tolerance on the pump flow is incorporated in calculating the switchover volume margin, the current margin of 20,620 gallons decreases to 19,316 gallons. Since the available switchover volume margin of 19,316 gallons would provide reasonable assurance that the RWSTwater inventory is sufficient to prevent damage to pumps and maintain long-term cooling capability following transition from the injection to recirculation mode of operation, the NRC staff finds that the AOR of long-term cooling for a LOCA event remains valid.

Since the LBLOCA AOR assumes the maximum CFC performance and CT flow, and minimum SI flow that accounted for an increased EDG frequency tolerance of+/- 0.8 percent, and the long-term cooling calculation shows that sufficient water in the RWST is available to prevent damage to ECCS pumps following transition from injection to recirculation, the NRC staff finds that the LBLOCA AOR would adequately support a +/- 0.8 percent EDG frequency tolerance.

3.2.4.2 Small-Break LOCA (SBLOCA) Analysis (FSAR Section 15.6.5.3)

The SBLOCA AOR in FSAR Section 15.6.5.3 assumes a minimum AFW flow rate of 374 gpm, which remains bounding for the requested EDG frequency tolerance. The AOR also assumes the minimum SI flow delivery curves to minimize the RCS inventory makeup heat removal capacity. The minimum SI flow curves assumed in the AOR were calculated for both HHSI and LHSI to account for an increased EDG frequency tolerance of+/- 0.8 percent.

Since the SBLOCA AOR assumes the minimum AFW and SI flow rates that accounted for an increased EDG frequency tolerance of+/- 0.8 percent, the NRC staff finds that the SBLOCA AOR would adequately support a +/- 0.8 percent EDG frequency tolerance.

3.2.5 Methods for Determination of SI and AFW Flow, and MOV Stroke Time with Respect to Changes of EDG Voltage and Frequency Limits In its supplement dated November 27, 2017, the licensee stated that to account for parallel HHSI pump operation associated with maximum SI flow conditions, the single pump flow rates are doubled. The total dynamic head (TDH) and two pump flow rate values in the bounding pump performance curve are increased using pump affinity laws to account for the increased EDG frequency. The licensee stated that the flow is proportional to shaft speed and pump total head is proportional to the square of the shaft speed. The licensee did not mention a change in the TDH or flow rates due to the variations in EDG voltage.

In its LAR dated June 5, 2017, the licensee stated that for induction motors, motor speed is a direct function of frequency such that relatively small changes in frequency can have a non-trivial effect on equipment performance while comparatively large changes in voltage do not have a similar effect on motor speed. Watts or horsepower are essentially constant in induction motors such that if voltage drops, current will increase to maintain a constant kW rating.

Therefore, pumps, fans, and valves are not significantly impacted from variations in voltage, as long as the manufacturers' minimum voltage requirements are satisfied.

In its review, the NRC staff found that the voltage variations will not affect the SI pumps' flow rates or TDH. The pump motors are National Electrical Manufacturers Association (NEMA) induction motors, and the proposed voltage variation of 4 percent is within the requirements of NEMA MG 1, "Motors and Generators," Section 12.44, "Variation from Rated Voltage and Rated Frequency," Paragraph 12.44.1, "Running," which states, in part, that:

"Alternating-current motors shall operate successfully under running conditions at rated load with a variation in the voltage or the frequency up to the following:

_ a. Plus or minus 10 percent of rated voltage with rated frequency for induction motors.

b. Plus or minus 6 percent of rated voltage with rated frequency for universal motors.

c. Plus or minus 5 percent of rated frequency with rated voltage.

d. A combined variation in voltage and frequency of 10 percent (sum of absolute values) of the rated values, provided the frequency variation does not exceed plus or minus 5 percent of rated frequency, and the voltage variation of universal motors (except fan motors) does not exceed plus or minus 6 percent of rated voltage."

The NRC staff finds that the effects of the revised EOG voltage and frequency limits on the AOR in FSAR Chapter 15 are appropriately identified, and the methods used to determine the SI and AFW flow rates, and MOV stroke time are acceptable. Therefore, the NRC staff finds the proposed change acceptable.

In its LAR dated June 5, 2017, the licensee stated that the engineering evaluatipn and calculations demonstrate that the proposed frequency tolerance of+/- 0.8 percent ensures Safety-related pumps meet their design functions, and the accident analysis inputs and assumptions are maintained. The available net positive suction head (NPSHa) and the required net positive suction head (NPSHr) of the safety-related pumps were considered in this evaluation. In its response to an RAI dated November 27, 2017, the licensee stated that the effects of a +/- 0.8 percent frequency tolerance were incorporated into analyses for the following safety-related pumps:

Auxiliary feedwater motor-driven pumps and turbine-driven pump Component cooling water (CCW) pumps Containment spray (CT) pumps Diesel fuel oil (DFO) transfer pumps Emergency service water (ESW) pumps, booster pumps, and screenwash pumps Essential services chilled water (ESCW) P-4 pump and P-7 pump Residual heat removal / low head safety injection (RHR) pumps Charging and safety injection/ high head safety injection pumps (CSIPs)

Boric acid transfer (BAT) pumps Spent fuel pool cooling (SFPC) pumps The licensee provided a table containing a summary of the evaluation of the+/- 0.8 percent frequency tolerance on the system parameters (flow, pressure and NPSH), the respective system parameter limits, and any low pressure alarms for the pumps listed above. Only the limiting case of either overfrequency or underfrequency was calculated and provided in the table. The NRC staff reviewed the information in the table provided for the pumps listed above and finds that the proposed +/- 0.8 percent frequency tolerance will not have a negative impact on the operation of the pumps, because in each limiting case sufficient margin in flow, pressure, NPSH, and low pressure alarm settings exists.

The licensee evaluated pump discharge relieve valves with the EOG operating at 60.48 Hz.

The evaluation concluded that the relief valves on the affected discharge piping will not lift. The NRC staff reviewed the evaluation results and finds that there is sufficient margin between the pumps' discharge pressures with the EOG operating at 60.48 Hz and the relief valve setpoints so that the relief valves will not lift.

The licensee stated that the proposed steady-state voltage and frequency tolerances resulted in a reduction to the injection and recirculation mode NPSH margin for the CT pumps. In the injection mode, the CT pump NPSHa decreased from 92.3 feet to 92 feet, and the NPSHr increased from 12.5 feet to 13 feet. In the recirculation mode, CT pump NPSHa decreased from 27.1 feet to 25.5 feet, and NPSHr increased from 12 feet to 12.4 feet. In both modes the NPSHa is still greater than the NPSHr. The licensee stated that the reduction in NPSH margin has no impact on the likelihood of a CT pump malfunction. The NRC staff finds that the small change in NPSH margin will not prevent the CT pumps from performing their design function.

The licensee stated that the impact to AFW, ESW, CCW, SFPC, BAT, and ESCW systems have been evaluated and equipment functions and limits are maintained with the +/- 0.8 percent frequency tolerance value. In response to an RAI dated November 27, 2017, the licensee provided a table containing a summary of the evaluation of the +/- 0.8 percent frequency tolerance on the system parameters (flow, pressure, and NPSH), the respective system parameter limits, and any low pressure alarms for the pumps in the systems listed above. Only the limiting case of either overfrequency or underfrequency was calculated and provided in the table. The NRC staff has reviewed the information in the table provided for the pumps listed above and finds that the proposed +/- 0.8 percent frequency tolerance will not have a negative impact on the operation of the pumps, because in each limiting case sufficient margin in flow, pressure, NPSH, and low pressure alarm settings exists.

In its LAR dated June 5, 2017, the licensee stated the DFO Transfer system was evaluated to determine any impact of the proposed frequency limits on the EDG fuel consumption rate. The licensee stated that the plant's fuel consumption rate analysis is based upon the full load rating (nameplate rating) of the EDG, and that an analysis has shown that at the proposed upper frequency limit, the EDG will operate at less than the full load rating. In its supplement dated November 27, 2017, the licensee stated that the EDG fuel oil consumption is driven by engine load, and although the load is increased by a small amount when the frequency increases, the increase in load has a minimum impact on its margin to capacity. The licensee stated that the minimum fuel oil delivered to the EDG at nominal frequency is 25.5 gpm, and the frequency adjusted flow rate is 25.4 gpm. The minimum required flow to the EDG at full load (nameplate) is 7.6 gpm. The fuel oil transfer pump NPSHa at nominal frequency is 34.88 feet, and the frequency adjusted NPSHa is 34.82. The NPSHr for the pump is 4.06 feet. The NRC staff has reviewed the flow rate and NPSH information for the DFO transfer pumps and finds that the proposed+/- 0.8 percent frequency tolerance will not have a negative impact on the operation of the pumps, because there is sufficient margin in the pumps' flow rate and the NPSH.

In response to an RAI dated November 27, 2017, the licensee provided additional information concerning the engine-driven lube oil and jacket water pumps. The NRC staff reviewed the flow rate information and Lube Oil System main header low lube oil pressure alarm and trip setpoint information for the engine driven lube oil pump and finds that the proposed +/- 0.8 percent frequency tolerance will not have a negative impact on the operation of the pump or the EDG, because there is sufficient margin in the pump's flow rate. The pump's flow rate is substantially larger than the EDG's lube oil requirements at rated speed, and the excess oil is diverted to the engine sump by a pressure regulating valve. Also, there is sufficient margin between the pump's discharge pressure and the lube oil system alarm and trip setpoints.

The NRC staff reviewed the additional information provided by the licensee in its supplement dated November 27, 2017, on the engine-driven jacket water pump and the flow rate information. The NRC staff finds that the proposed +/- 0.8 percent frequency tolerance will not have a negative impact on the operation of the pump or the EDG because the small change in flow rate will not affect the temperature differential across the EDG and the small change in pressure(+/- 0.34 psig) still leaves sufficient margin between the pump operating parameters and the setpoints for the jacket water low pressure alarm and the jacket water low pressure trip.

In its LAR, the licensee stated that there are a number of safety-related MOVs in multiple systems that must operate during or after sequencing. A variation in bus voltage and frequency will affect the available valve motor torque and the valve stroke times. The licensee evaluated the motor torque values for the affected valves. Using the proposed EDG voltage and frequency variations, the licensee determined that the minimum and maximum motor torque values calculated did not result in an increase or decrease in MOV motor torque outside the bounds of what was previously determined to be the minimum and maximum motor torque with either "Offsite Power Available" or with current TSs variation limits applied. The licensee concluded that the MOV stroke times are bounded by the more conservative calculated torque values.

The NRC staff finds that the licensee's conclusion that EDG operation at steady-state voltage and frequency within the proposed TS ailowable ranges does not result in an increase or decrease in MOV motor torque outside the bounds of what was previously determined to be the minimum and maximum torque, and that the MOV stroke times are bounded by the more conservative calculated torque values, is acceptable. The lower voltage limit is increased, thus improving the previous calculated margins, and the tighter frequency band will mean a tighter stroke band. The total band difference is negligible on overall MOV stroke time.

3.3 Evaluation of the proposed changes of the EDG Steady-State Voltage Limit The NRC staff reviewed the determination of steady-state voltage limit to verify the methodology followed by the licensee for the proposed changes to the TS SRs related to the EDG steady-state voltage limit. To verify the proposed changes are acceptable, the licensee performed an evaluation to the 6.9 kV emergency bus minimum and maximum allowed steady-state EDG voltages to ensure that electrical equipment supplied from the emergency bus will be operating within the continuous voltage range of this equipment.

The licensee's evaluation to determine the minimum steady-state voltage was to ensure that the voltage supports all downstream emergency 480 volt safety.;related loads, that all emergency power system equipment will be operating within the continuous operating range of the equipment, and that the value selected is within the capability of the EDG voltage regulator ratings. The licensee's assumptions for determining the minimum allowed voltage limit are the EDG operating fully loaded to a 6.5 MW rating, at an assumed 0.8 power factor, and the incorporation of the voltage drop. To determine the minimum steady-state voltage limit, the licensee performed calculations (calculation E-6003, Tables A1 and A2 provided and calculation E-6000 Tables A6-1 and A6-2 in Attachment 3 of the LAR.) Based on the results of the calculations and the assumptions considered, the licensee demonstrated that the minimum EDG steady-state voltage required to support all safety.. related loads is 6511 volts or 94.36 percent of nominal rating. In order to provide conservatism, the licensee chose the minimum EDG steady-state voltage to 96 percent of nominal rating, or 6624 volts. The NRC staff reviewed the calculations in Attachment 3 of the LAR and finds that the licensee's methodology to determine the minimum EDG steady-state voltage is acceptable. The NRC staff finds that the assumptions used in the calculations are conservative and the new value of the minimum EDG steady-state voltage is acceptable. In addition, the new value (6624 volts) of the minimum EDG steady-state voltage is more conservative than the actual value in the TS SRs, since it reduces the EDG steady-state voltage limit from 10 percent to 4 percent of the voltage nominal value.

The NRC staff also reviewed the licensee's evaluation to determine the maximum EDG steady-state voltage limit. In order to determine the maximum allowed EDG steady-state voltage, the licensee established the following criteria: 1) the maximum EDG steady-state voltage must ensure that the electrical equipment supplied from the emergency power system will be operated within the continuous voltage range of the equipment; 2) the voltage value selected must be within the capability of the EDG voltage regulator rating; and 3) the maximum EDG steady-state voltage requires load terminal voltage to be less than the maximum criteria voltage. The licensee performed calculation E-6003, and evaluated the results using the criteria mentioned above and determined the EDG terminal voltage to be 7186 volts. The licensee added additional conservatism and selected 7176 volts (104 percent of nominal) as the upper limit for the EDG steady-state voltage. The NRC staff reviewed the calculations performed by the licensee, the assumptions taken for the voltage required for the most limiting load, and the assumptions in voltage drop and determined the licensee's approach for determining the maximum EDG steady-state voltage limit is acceptable. The value is more conservative than the actual value in the TS SRs since it reduces the EDG steady-state voltage limit from 10 percent to 4 percent of the voltage nominal value.

The NRC staff reviewed Attachment 2 of the LAR to verify the proposed TSs changes were in accordance with the analysis performed in the LAR. The NRC staff noted that the proposed changes to SR 4.8.1.1.2.f.2 only changed the frequency values and not the voltage values.

SR 4.8.1.1.2.f.2 kept plus or minus 10 percent of the nominal voltage (6900 +/- 690 volts) instead of the plus or minus 4 percent of the nominal EDG voltage (6900 +/- 276 volts), as proposed in the LAR Section 3.4.1. In its RAI response dated January 22, 2018, the licensee provided a discussion addressing this discrepancy and a summary of the analysis that demonstrates the steady-state voltage values of plus or minus 10 percent of the nominal voltage (6900 +/- 690 volts). The licensee stated that the current voltage limit of 6900 +/- 690 volts in SR 4.8.1.1.2.f.2 is for the transient EDG voltage response following a rejection of a load of greater than or equal to 1078 kW, and not the steady-state EDG voltage limit. In addition, the licensee proposed to revise SR 4.8.1.1.2.f.2 to include the steady-state voltage limit condition of 6900 +/- 276 volts. The revised SR states, "During Shutdown, verifying that, on rejection of a load of greater than or equal to 1078 KW, the voltage and frequency are maintained with 6900 +/- 690 volts and 60 +/- 6. 75 Hz, with voltage stabilizing to 6900 +/- 276 volts and frequency stabilizing to 60 +/- 0.48 Hz within 10 seconds without any safety-related load tripping out or operating in a degraded condition." The NRC staff finds the response to the RAI acceptable because the licensee has provided clarification in the response RAI and revised to SR 4.8.1.1.2.f.2 to be consistent with the proposed changes in the LAR.

The NRC staff reviewed the proposed revision of the TS SRs with regard to EDG steady-state voltage limit and finds them acceptable. The licensee's evaluation, which includes calculations of the required steady-stated voltage of the safety-related equipment, consideration of the voltage regulator capabilities, voltage drop calculations, etc., provides reasonable assurance that the safety-related equipment supplied by the EDG will function and meets the requirements of GDC 17. In addition, the new EDG steady-state voltage limits are more conservative than the limits in the current TS SRs in reducing the voltage limit from 10 percent to 4 percent of the nominal voltage. Therefore, the NRC staff finds the propose EDG steady-state voltage limits acceptable.

3.4 Evaluation of the proposed changes of the EDG Steady-State Frequency Limit The NRC staff reviewed the licensee's determination of steady-state frequency limit to verify the methodology followed by the licensee to determine the proposed changes to the TS SRs related to the EDG steady-state frequency limit are acceptable. The licensee proposed to revise the TS SRs to change the current steady-state frequency from plus or minus 2 percent (60 +/- 1.2 Hz) to plus or minus 0.8 percent (60 +/- 0.48 Hz). Regulatory Guide 1.9, Revision 2, Section 5.1.2, "Mechanical and Electrical Capabilities," states that the frequency should be restored to within 2 percent of nominal within 60 percent of each load-sequence time interval.

The licensee's approach for evaluating frequency limits is based on performance of safety-related equipment susceptible to variation in frequency, such as induction motors (motor speed is a direct function of frequency). LAR Section 3.4.5, "Safe Shutdown Equipment Evaluation," provides the evaluation of the safety-related equipment susceptible to frequency variations. This evaluation demonstrates that reducing the EDG frequency limits will not affect the performance of the safety-related equipment and the EDG will be able to support the electrical loads. In order to ensure the EDG frequency limits are kept within the 0.8 percent of the nominal frequency at steady-state, the governor specification has a speed band of

+/- 0.25 percent, which results in a frequency band of+/- 0.15 Hz nominal. This frequency is less than the frequency tolerance of+/- 0.8 percent of the nominal frequency (60 +/- 0.48 Hz) proposed inTSs.

The NRC staff evaluated the proposed changes of EDG steady-state frequency limit and finds that the new frequency limits of 0.8 percent are more conservative than the 2 percent limit currently used in the TS SRs and meet the criteria in Regulatory Guide 1.9, Revision 2. The use of 0.8 percent frequency limit will ensure compliance with GDC 17 because the EDGs perform and provide power to safety-related equipment when operating between these limits.

Therefore, the NRC staff finds the propose EDG steady-state frequency limits acceptable.

3.5 Evaluation of the Proposed Voltage Limit for Full Load Rejection Testing The NRC staff reviewed the licensee's determination of voltage limit for Full Load Rejection Testing to verify the methodology followed by the licensee to determine the proposed changes to TS SR 4.8.1.1.2.f.11 is acceptable. The licensee proposed to increase the limit for the maximum EDG voltage value achieved during full load rejection test from 110 percent of the EDG voltage at the start of the test to 8280 volts at any time during the test, which is 120 percent of the EDG nominal voltage rating. The licensee proposed this change because test results show that the peak voltage often approaches the maximum allowed voltage of 110 percent of the EDG voltage at the start of the test. Based on the data gathered by the licensee from the full load rejection test, the average transient peak voltage is approximately 9 percent above the steady-state nominal voltage.

GDC 18, "Inspection and testing of electric power systems," requires that electric power systems that are important to safety be designed to permit appropriate periodic inspection and testing of important areas and features to assess the continuity of the systems and the condition of their components. In its LAR, the licensee stated that a technical basis for the specific 110 percent value does not exist in any applicable industry or regulatory standards. IEEE Standard 387-1977, "IEEE Standard Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations," Section 6.4.5, Load Rejection Tests, identifies that load rejection tests shall demonstrate the capability of rejecting the maximum rated load without exceeding speed or voltage that would cause tripping, mechanical damage, or harmful overstresses. Specific voltage limit values are not provided. The NRC staff reviewed the criteria within IEEE Standard 387-1977, Regulatory Guide 1.9, "Selection, Design, and Qualification of Diesel-Generator Units Used As Standby (Onsite) Electric Power Systems at Nuclear Power Plants," Revision 2, and Regulatory Guide 1.108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Revision 1 and did not find a specific limit for the maximum EDG voltage achieved during full load rejection test. In order to ensure the new 120 percent value was acceptable, the licensee evaluated the impact to the EDG equipment to ensure that there will be no component degradation of any connected equipment as a result of voltage transients. In addition the licensee evaluated the effect of volt-ampere reactive power loading on the full load rejection test. The NRC staff reviewed the evaluations performed by the licensee of the impact on the equipment of the transient voltage of a 120 percent of the nominal voltage. The purpose of the evaluations was to ensure the equipment was capable of withstanding a transient voltage of a 120 percent of the nominal voltage with no component degradation. The licensee evaluated all the equipment that could be potentially affected by EDG voltage's transient, which were the EDG cables, the switchgear, voltage regulator and control circuits, exciter power transformer, and 3-phase potential transformer. The NRC staff finds the licensee's evaluation demonstrates the equipment will not have component degradation due to a voltage transient and that the equipment is capable to withstand the transients of a 120 percent of the nominal voltage.

Based on the licensee's evaluations provided in the LAR, the NRC staff finds that the increase in voltage will not create degradation of the equipment connected to the EDG during the transient event. The NRC staff finds the licensee has provided sufficient justification to revised TS SR 4.8.1.1.2.f.11 to change the EDG transient voltage value during full load rejection test from 110 percent to 120 percent. The proposed changes are in accordance with GDC 18 because the licensee is capable to perform the EDGs full load rejection testing to assess the functioning of the EDGs and the components using the proposed value without challenging the EDG's design function. Therefore, the NRC staff finds the revision of TS SR 4.8.1.1.2.f.11 acceptable.

The NRC staff has reviewed the licensee's proposed changes to TS SR 4.8.1.1.2.a.4, SR 4.8.1.1.2.e, SR 4.8.1.1.2.f.2, SR 4.8.1.1.2.f.4.b, SR 4.8.1.1.2.f.6.b, SR 4.8.1.1.2.f.14, and SR 4.8.1.1.2.f.11. The NRC staff finds that the proposed changes to TS SRs to revise the steady-state voltage and frequency limits meet the requirement of GDC 17 because the proposed limits provide reasonable assurance that the EDGs will provide power to allow functioning of the safety-related loads. The new EDG steady-state voltage and frequency values are more conservative and meet the guidance specified in Regulatory Guide 1.9, Revision 2. In addition, the NRC staff finds that the revised voltage value for the full load rejection test is acceptable because the licensee has properly evaluated the EDG voltage increase of the maximum allowed voltage from 110 percent to 120 percent. The licensee's evaluation provides reasonable assurance that there is not going to be component degradation due to the voltage transients. The NRC staff finds the EDGs continue to meet the requirements of GDC 18 because the licensee is able to perform the EDGs testing to assess the functioning of the EDGs and the components.

The NRC staff finds that: (1) the revised changes to TS 3/4.8.1 are adequately supported by the AOR in HNP FSAR Chapter 15; (2) the revised TS 3/4.8.1 meets 10 CFR 50.36(c)(3) that requires TS SRs to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the LCOs will be met; and (3) the revised TS will assure that the AOR remains valid in meeting the GDC 10 requirement as it is related to the requirement of the fuel rod integrity, GDC 15 as it is related to the requirements of the reactor coolant pressure boundary, and 10 CFR 50.46 as it is related to the acceptance criteria for the ECCS performance.

Therefore, the NRC staff determined that the proposed changes to TS 3/4.8.1 related to the EDG voltage and frequency limits are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the State of North Carolina official was notified of the proposed issuance of the amendment on May 7, 2018. The State official had no comments.

5.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and changes SRs.

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, and there has been no public comment on such finding (82 FR 44851 ). 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.

6.0 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 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.

Principal Contributors: Summer Sun Date: June 20, 2018 Robert Wolfgang Jorge Rivera-Cintron

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT, UNIT 1 - ISSUANCE OF AMENDMENT FOR EMERGENCY DIESEL GENERATOR SURVEILLANCE REQUIREMENTS REGARDING VOLTAGE AND FREQUENCY LIMITS AND THE VOLTAGE LIMIT FOR EMERGENCY DIESEL GENERATOR LOAD REJECTION (CAC No. MF9828; EPID L-2017-LLA-0244)

DATED JUNE 20, 2018 DISTRIBUTION:

PUBLIC PM File Copy RidsNrrDorlLpl2-2 Resource RidsNrrLABClayton Resource RidsACRS_MailCTR Resource RidsNrrPMShearonHarris Resource RidsRgn2MailCenter Resource RidsNrrDssSrxb Resource RidsNrrDssStsb Resource RidsNrrDeEeob Resource RidsNrrDeEmib Resource SSun, NRR RWolfgang, NRR JCintron-Rivera, NRR ADAMS A ccess1on N ML18130A270 o.:

OFFICE DORULPL2-2/PM NAME MBarillas DATE 05/16/18 OFFICE DSS/STSB**

NAME VCusumano DATE 05/15/18 OFFICE OGC**

NAME SSpicer DATE 06/08/18

• b d

,y memoran um

• • b

• 1 1y e-ma1 DORULPL2-2/LA DSS/SRXB*

BClayton JWhitman 06/14/18 01/30/18 DE/EEOB*

DE/EMIB*

JQuichocho SBailey 04/30/18 02/21/18 DORULPL2-2/BC (A)

DORULPL2-2/PM BVenkataraman MBarillas 06/19/18 06/20/18 OFFICIAL RECORD COPY