Text

Issuance of Amendment No. 315 Adoption of Technical Specification Task Force Traveler TSTF-425, Revision 3
	ML19063B948
Person / Time
Site:	Arkansas Nuclear
Issue date:	04/23/2019
From:	Thomas Wengert; Plant Licensing Branch IV
To:	; Entergy Operations
	Wengert T, 415-4037
References
	EPID L-2018-LLA-0047
	Download: ML19063B948 (131)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 April 23, 2019 ANO Site Vice President Arkansas Nuclear One Entergy Operations, Inc.

N-TSB-58 1448 S.R. 333 Russellville, AR 72802

SUBJECT:

ARKANSAS NUCLEAR ONE, UNIT 2 - ISSUANCE OF AMENDMENT RE:

ADOPTION OF TECHNICAL SPECIFICATIONS TASK FORCE {TSTF)

TRAVELER TSTF-425, REVISION 3 (EPID L-2018-LLA-0047)

Dear Sir or Madam:

The U.S. Nuclear Regulatory Commission (NRC, the Commission) has issued the enclosed Amendment No. 315 to Renewed Facility Operating License No. NPF-6 for Arkansas Nuclear One, Unit 2 (AN0-2). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated February 6, 2018, as supplemented by letters dated March 26, September 7, and November 16, 2018.

The amendment revises the TSs by relocating certain surveillance frequencies to a licensee-controlled program, consistent with the NRG-approved Technical Specifications Task Force {TSTF) Improved Standard Technical Specifications Traveler TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - RITSTF [Risk-informed TSTF]

Initiative 5b."

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

Docket No. 50-368

Enclosures:

1. Amendment No. 315 to NPF-6

2. Safety Evaluation cc: Listserv Sincerely, Thomas J. Wengert, Senior Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 ENTERGY OPERATIONS, INC.

DOCKET NO. 50-368 ARKANSAS NUCLEAR ONE, UNIT 2 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 315 Renewed License No. NPF-6

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Entergy Operations, Inc. (the licensee), dated February 6, 2018, as supplemented by letters dated March 26, September 7, and November 16, 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-6 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 315, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

Additionally, paragraph 2.C.3.d of Renewed Facility Operating License No. NPF-6 is amended to read as follows:

(d)

Surveillance Frequency Control Program The licensee shall implement the items listed in Table 2 of the enclosure to Entergy letter 2CAN111801, dated November 16, 2018, prior to implementation of the Surveillance Frequency Control Program.

3.

This amendment is effective as of its date of issuance and shall be implemented within 90 days from the date of issuance.

Attachment:

Changes to the Renewed Facility Operating License No. NPF-6 and Technical Specifications FOR THE NUCLEAR REGULATORY COMMISSION Robert J. Pascarelli, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Date of Issuance: Apr i 1 2 3, 2 O 1 9

ATTACHMENT TO LICENSE AMENDMENT NO. 315 RENEWED FACILITY OPERATING LICENSE NO. NPF-6 ARKANSAS NUCLEAR ONE, UNIT 2 DOCKET NO. 50-368 Replace the following pages of the Renewed Facility Operating License No. NPF-6 and 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.

Renewed Facility Operating License REMOVE REMOVE 1-4 1-7 1-8 1-9 3/4 1-1 3/4 1-2 3/4 1-3 3/4 1-4 3/4 1-6 3/4 1-18 3/4 1-21 3/4 1-22 3/4 1-23 3/4 1-24 3/4 1-26 3/4 2-1 3/4 2-2 3/4 2-4 3/4 2-6 3/4 2-7 3/4 2-8 3/4 2-9 3/4 2-10 3/4 3-1 3/4 3-7 3/4 3-9 3/4 3-10 3/4 3-21 Technical Specifications INSERT INSERT 1-4 1-7 3/4 1-1 3/4 1-2 3/4 1-3 3/4 1-4 3/4 1-6 3/41-18 3/4 1-21 3/4 1-22 3/4 1-23 3/4 1-24 3/4 1-26 3/4 2-1 3/4 2-2 3/4 2-4 3/4 2-6 3/4 2-7 3/4 2-8 3/4 2-9 3/42-10 3/4 3-1 3/4 3-7 3/4 3-9 3/4 3-10 3/4 3-21 Technical Specifications (continued)

REMOVE 3/4 3-22 3/4 3-23 3/4 3-27 3/4 3-38 3/4 3-42 3/4 4-1 3/4 4-2 3/4 4-2a 3/4 4-5 3/4 4-13a 3/4 4-14a 3/4 4-18 3/4 4-23 3/4 4-27 3/4 4-29 3/4 5-1 3/4 5-2 3/4 5-4 3/4 5-5 3/4 5-7 3/4 6-1 3/4 6-5 3/4 6-6 3/46-9 3/4 6-10 3/4 6-11 3/4 6-12 3/4 6-15 3/4 6-17 3/4 7-6 3/4 7-7 3/4 7-9 3/4 7-14 3/4 7-15 3/4 7-16 3/4 7-16a 3/4 7-18 3/4 7-27 3/4 8-2b 3/4 8-3 3/4 8-4a 3/4 8-5a 3/4 8-6 3/4 8-7 3/4 8-8 3/4 8-9 3/4 8-10 3/4 8-12 INSERT 3/4 3-22 3/4 3-23 3/4 3-27 3/4 3-38 3/4 3-42 3/4 4-1 3/4 4-2 3/4 4-2a 3/4 4-5 3/4 4-13a 3/4 4-14a 3/4 4-18 3/4 4-23 3/4 4-27 3/4 4-29 3/4 5-1 3/4 5-2 3/4 5-4 3/4 5-5 3/4 5-7 3/4 6-1 3/46-5 3/4 6-6 3/4 6-9 3/4 6-10 3/4 6-11 3/4 6-12 3/4 6-15 3/4 6-17 3/4 7-6 3/4 7-7 3/4 7-9 3/4 7-14 3/4 7-15 3/4 7-16 3/4 7-16a 3/4 7-18 3/4 7-27 3/4 8-2b 3/4 8-3 3/4 8-4a 3/4 8-5a 3/4 8-6 3/4 8-7 3/4 8-8 3/4 8-9 3/4 8-10 3/4 8-12 Technical Specifications (continued)

REMOVE 3/4 9-1 3/4 9-2 3/4 9-4 3/4 9-6 3/4 9-8 3/4 9-9 3/4 9-10 3/4 9-11 3/4 9-14 3/4 10-1 3/4 10-2 3/4 10-3 3/4 10-4 3/4 10-5 3/4 11-1 3/4 11-2 6-5 6-16 6-17 6-18a INSERT 3/4 9-1 3/4 9-2 3/4 9-4 3/49-6 3/4 9-8 3/4 9-9 3/4 9-10 3/49-11 3/4 9-14 3/4 10-1 3/4 10-2 3/4 10-3 3/4 10-4 3/4 10-5 3/411-1 3/4 11-2 6-5 6-16 6-17 6-18a

3 (4)

EOI, pursuant to the Act and 10 CFR Parts 30, 40 and 70 to receive, possess and use at any time any byproduct, source and 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)

EOI, 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)

EOI, pursuant to the Act and 10 CFR Parts 30 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 conditions specified in the following Commission regulations in 10 CFR Chapter I; Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 EOI is authorized to operate the facility at steady state reactor core power levels not in excess of 3026 megawatts thermal. Prior to attaining this power level EOI shall comply with the conditions in Paragraph 2.C.(3).

(2)

Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 315, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications.

Exemptive 2nd paragraph of 2.C.2 deleted per Amendment 20, 3/3/81.

(3)

Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods following issuance of the renewed license or within the operational restrictions indicated.

The removal of these conditions shall be made by an amendment to the renewed license supported by a favorable evaluation by the Commission.

2.C.(3)(a)

Deleted per Amendment 24, 6/19/81.

Renewed License No. NPF-6 Amendment No. 315

(c)

(d) 2.C.(3)(f) 2.C.(3)(g) 2.C.(3)(h) 2.C.(3)(h)

(i) 2.C.(3)0) 2.C.(3)(k) 6 Transition License Conditions

1. Before achieving full compliance with 10 CFR 50.48(c), as specified by 2. below, risk-informed changes to the Entergy Operations, Inc. fire protection program may not be made without prior NRC review and approval unless the change has been demonstrated to have no more than a minimal risk impact, as described in 2. above.

2. The licensee shall implement the modifications to its facility, as described in Table S-1, "Plant Modifications," Attachment 2, of Entergy Operations, Inc. letter 2CAN101601, dated October 27, 2016, prior to startup from the second refueling outage following issuance of the Safety Evaluation. The licensee shall maintain appropriate compensatory measures in place until completion of the modifications.

3. The licensee shall complete the implementation items as listed in Table S-2, "Implementation Items," Attachment, of Entergy Operations, Inc. letter 2CAN091402, dated September 24, 2014, within six months after issuance of the Safety Evaluation.

Less Than Four Reactor Coolant Pump Operation EOI shall not operate the reactor in operational Modes 1 and 2 with fewer than four reactor coolant pumps in operation, except as allowed by Special Test Exception 3.10.3 of the facility Technical Specifications.

Surveillance Frequency Control Program The licensee shall implement the items listed in Table 2 of the enclosure to Entergy letter 2CAN111801, dated November 16, 2018, prior to implementation of the Surveillance Frequency Control Program.

Deleted per Amendment 300, 2/18/15.

Deleted per Amendment 24, 6/19/81.

Deleted per Amendment 93, 4/25/89.

Deleted per Amendment 29, (3/4/82) and its correction letter, (3/15/82).

Containment Radiation Monitor AP&L shall, prior to July 31, 1980 submit for Commission review and approval documentation which establishes the adequacy of the qualifications of the containment radiation monitors located inside the containment and shall complete the installation and testing of these instruments to demonstrate that they meet the operability requirements of Technical Specification No. 3.3.3.6.

Deleted per Amendment 7, 12/1/78.

Deleted per Amendment 12, 6/12/79 and Amendment 31, 5/12/82.

Renewed License No. NPF-6 Amendment No. JOO, 300, 315

DEFINITIONS UNIDENTIFIED LEAKAGE 1.15 UNI DENTI Fl ED LEAKAGE shall be all leakage which is not I DENTI Fl ED LEAKAGE or controlled leakage.

PRESSURE BOUNDARY LEAKAGE 1.16 PRESSURE BOUNDARY LEAKAGE shall be leakage (except primary to secondary leakage) through a non-isolable fault in a Reactor Coolant System component body, pipe wall or vessel wall.

AZIMUTHAL POWER TILT - Tg 1.17 AZIMUTHAL POWER TILT shall be the power asymmetry between azimuthally symmetric fuel assemblies.

DOSE EQUIVALENT 1-131 1.18 DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microcuries per gram) that alone would produce the same committed effective dose equivalent (CEDE) as the quantity and isotopic mixture of 1-131, 1-132, 1-133, 1-134, and 1-135 actually present.

The CEDE dose conversion factors used to determine the DOSE EQUIVALENT 1-131 shall be performed using Table 2.1 of EPA Federal Guidance Report No. 11, 1988, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion."

DOSE EQUIVALENT XE-133 1.19 DOSE EQUIVALENT XE-133 shall be that concentration of Xe-133 (microcuries per gram) that alone would produce the same acute dose to the whole body as the combined activities of noble gas nuclides Kr-85m, Kr-85, Kr-87, Kr-88, Xe-131m, Xe-133m, Xe-133, Xe-135m, Xe-135, and Xe-138 actually present. If a specific noble gas nuclide is not detected, it should be assumed to be present at the minimum detectable activity. The determination of DOSE EQUIVALENT XE-133 shall be performed using effective dose conversion factors for air submersion listed in Table 111.1 of EPA Federal Guidance Report No. 12, 1993, "External Exposure to Radionuclides in Air, Water, and Soil."

1.20 Deleted FREQUENCY NOTATION 1.21 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.2.

ARKANSAS-UNIT 2 1-4 Amendment No. 4-a+.~.~.~.

293,315

MODE

1.

POWER OPERATION

2.

STARTUP

3.

HOT STANDBY

4.

HOT SHUTDOWN

5.

COLD SHUTDOWN

6.

REFUELING**

Excluding decay heat.

TABLE 1.1 OPERATIONAL MODES REACTIVITY

%RATED CONDITION. Kett THERMAL POWER*

2 0.99

>5%

2 0.99

S:5%

< 0.99 0

s: 0.95 0

AVERAGE COOLANT TEMPERATURE 2 300 °F 2 300 °F 2 300 °F 300 °F > Tavg > 200 °F

s: 200 °F

s: 140 °F

- Reactor vessel head unbolted or removed and fuel in the vessel.

NOTATION S/U N.A.

SFCP ARKANSAS - UNIT 2 TABLE 1.2 FREQUENCY NOTATION 1-7 FREQUENCY Prior to each reactor startup Not applicable In accordance with the Surveillance Frequency Control Program Amendment No. e0,449,4a-7,486,4W, 315

3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORA TION CONTROL SHUTDOWN MARGIN - Tavg > 200 °F LIMITING CONDITION FOR OPERATION 3.1.1.1 The SHUTDOWN MARGIN shall be greater than or equal to that specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY:

MODES 1, 2*, 3 and 4.

ACTION:

With the SHUTDOWN MARGIN less than that required above, immediately initiate and continue boration at ~ 40 gpm of 2500 ppm boric acid solution or equivalent until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.1.1 The SHUTDOWN MARGIN shall be determined to be greater than or equal to that specified in the CORE OPERATING LIMITS REPORT:

a.

Within one hour after detection of an inoperable CEA(s) and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter while the CEA( s) is inoperable. If the inoperable CEA is immovable or untrippable, the above required SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable CEA(s).

b.

When in MODES 1 or 2#, in accordance with the Surveillance Frequency Control Program by verifying that CEA group withdrawal is within the Transient Insertion Limits of Specification 3.1.3.6.

c.

When in MODE 2##, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to achieving reactor criticality by verifying that the predicted critical CEA position is within the limits of Specification 3.1.3.6.

d.

Prior to initial operation above 5% RATED THERMAL POWER after each fuel loading, by consideration of the factors of (e) below, with the CEA groups at the Transient Insertion Limits of Specification 3.1.3.6.

See Special Test Exception 3.10.1.

With Kett~ 1.0.

1. With Kett< 1.0.

ARKANSAS - UNIT 2 3/4 1-1 Amendment No. ~.82,449,4a7-,315

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

e.

When in MODES 3 or 4, in accordance with the Surveillance Frequency Control Program by consideration of at least the following factors:

1.

Reactor coolant system boron concentration,

2.

CEA position,

3.

Reactor coolant system average temperature,

4.

Fuel burnup based on gross thermal energy generation,

5.

Xenon concentration, and

6.

Samarium concentration.

4.1.1.1.2 The overall core reactivity balance shall be compared to predicted values to demonstrate agreement within +/- 1.0% ~k/k in accordance with the Surveillance Frequency Control Program. This comparison shall consider at least those factors stated in Specification 4.1.1.1.1.e, above. The predicted reactivity values shall be adjusted (normalized) to correspond to the actual core conditions prior to exceeding a fuel burnup of 60 Effective Full Power Days after each fuel loading.

ARKANSAS - UNIT 2 3/4 1-2 Amendment NO. 315

REACTIVITY CONTROL SYSTEMS SHUTDOWN MARGIN-Tfil(g < 200 °F LIMITING CONDITION FOR OPERATION 3.1.1.2 The SHUTDOWN MARGIN shall be greater than or equal to that specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY:

MODE 5.

ACTION:

With the SHUTDOWN MARGIN less than that required above, immediately initiate and continue boration at ~ 40 gpm of 2500 ppm boric acid solution or equivalent until the required SHUTDOWN MARGIN is restored.

SURVEILLANCE REQUIREMENTS 4.1.1.2 The SHUTDOWN MARGIN shall be determined to be greater than or equal to that specified in the CORE OPERATING LIMITS REPORT:

a.

Within one hour after detection of an inoperable CEA(S) and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter while the CEA(S) is inoperable. If the inoperable CEA is immovable or untrippable, the above required SHUTDOWN MARGIN shall be increased by an amount at least equal to the withdrawn worth of the immovable or untrippable CEA(s).

b.

In accordance with the Surveillance Frequency Control Program by consideration of at least the following factors:

1.

Reactor coolant system boron concentration,

2.

CEA position,

3.

Reactor coolant system average temperature,

4.

Fuel burnup based on gross thermal energy generation,

5.

Xenon concentration, and

6.

Samarium concentration.

ARKANSAS - UNIT 2 3/4 1-3 Amendment No. 24,82-,4§.7, 315

REACTIVITY CONTROL SYSTEMS BORON DILUTION LIMITING CONDITION FOR OPERATION 3.1.1.3 The flow rate of reactor coolant through the reactor coolant system shall be

~ 2000 gpm whenever a reduction in Reactor Coolant System boron concentration is being made.

APPLICABILITY:

ALL MODES.

ACTION:

With the flow rate of reactor coolant through the reactor coolant system< 2000 gpm, immediately suspend all operations involving a reduction in boron concentration of the Reactor Coolant System.

SURVEILLANCE REQUIREMENTS 4.1.1.3 The flow rate of reactor coolant through the reactor coolant system shall be determined to be ~ 2000 gpm within one hour prior to the start of and in accordance with the Surveillance Frequency Control Program during a reduction in the Reactor Coolant System boron concentration by either:

a.

Verifying at least one reactor coolant pump is in operation, or

b.

Verifying that at least one low pressure safety injection pump or containment spray pump is in operation as a shutdown cooling pump and supplying ~ 2000 gpm through the reactor coolant system.

ARKANSAS - UNIT 2 3/4 1-4 Amendment No. 429,255,315

REACTIVITY CONTROL SYSTEMS MINIMUM TEMPERATURE FOR CRITICALITY LIMITING CONDITION FOR OPERATION 3.1.1.5 The Reactor Coolant System lowest operating loop temperature (T avg) shall be

~ 540 °F.

APPLICABILITY:

MODES 1 and 2#*.

ACTION:

With a Reactor Coolant System operating loop temperature (Tavg) < 540 °F, restore Tavg to within its limit within 15 minutes or be in HOT STANDBY within the next 15 minutes.

SURVEILLANCE REQUIREMENTS 4.1.1.5 The Reactor Coolant System temperature (Tavg) shall be determined to be:~ 540 °F in accordance with the Surveillance Frequency Control Program.

With Kett~ 1.0.

See Special Test Exception 3.10.5.

ARKANSAS - UNIT 2 3/4 1-6 Amendment No. ~.294, 315 Next page is 3/4 1-17

REACTIVITY CONTROL SYSTEMS ACTION: (Continued)

e.

With more than one CEA misaligned from any other CEA in its group by more than 7 inches (indicated position), be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The position of each CEA shall be determined to be within 7 inches (indicated position) of all other CEAs in its group in accordance with the Surveillance Frequency Control Program.

4.1.3.1.2 Each CEA not fully inserted in the core shall be determined to be OPERABLE by movement of at least 5 inches in any one direction in accordance with the Surveillance Frequency Control Program.

Note 1 - Movement of CEA 4 is not required for the remainder of Cycle 26. If an outage of sufficient duration occurs prior to the end of Cycle 26, maintenance activities will be performed to restore the CEA.

ARKANSAS - UNIT 2 3/4 1-18 Amendment No. +G.~.~.489.~,

~.244,J02,308,315

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.2 Each of the above required position indicator channels shall be determined to be OPERABLE by verifying that for the same CEA, the position indicator channels agree within 5 inches of each other in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 1-21 Amendment No. 315

REACTIVITY CONTROL SYSTEMS POSITION INDICATOR CHANNELS - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.1.3.3 At least one CEA Reed Switch Position Transmitter indicator channel shall be OPERABLE for each CEA not fully inserted.

APPLICABILITY:

MODES 3*, 4* and 5*.

ACTION:

With less than the above required position indicator channel(s) OPERABLE, immediately open the reactor trip breakers.

SURVEILLANCE REQUIREMENTS 4.1.3.3 Each of the above required CEA Reed Switch Position Transmitter indicator channel(s) shall be determined to be OPERABLE by performance of a CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency Control Program.

With the reactor trip breakers in the closed position.

ARKANSAS-UNIT 2 3/4 1-22 Amendment No. 4e9,315

REACTIVITY CONTROL SYSTEMS CEA DROP TIME LIMITING CONDITION FOR OPERATION 3.1.3.4 The individual CEA drop time, from a fully withdrawn position, shall be::;; 3.7 seconds and the arithmetic average of the CEA drop times of all CEAs, from a fully withdrawn position, shall be::;; 3.2 seconds from when the electrical power is interrupted to the CEA drive mechanisms until the CEAs reach their 90 percent insertion positions with:

a.

Tavg ~ 525 °F, and

b.

All reactor coolant pumps operating.

APPLICABILITY:

MODES 1 and 2.

ACTION:

a.

With the CEA drop times determined to exceed either of the above limits, restore the CEA drop times to within the above limits prior to proceeding to MODE 1 or 2.

b.

With the CEA drop times within limits but determined at less than full reactor coolant flow, operation may proceed provided THERMAL POWER is restricted to less than or equal to the maximum THERMAL POWER level allowable for the reactor coolant pump combination operating at the time of CEA drop time determination.

SURVEILLANCE REQUIREMENTS 4.1.3.4 The CEA drop time of all CEAs shall be demonstrated through measurement prior to reactor criticality:

a.

For all CEAs following each removal of the reactor vessel head,

b.

For specifically affected individuals CEAs following any maintenance on or modification to the CEA drive system which could affect the drop time of those specific CEAs, and

c.

In accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 1-23 Amendment No. M,94,400,4-eQ.,~, 315 Correction Letter dated 10/24.'95

REACTIVITY CONTROL SYSTEMS SHUTDOWN CEA INSERTION LIMIT LIMITING CONDITION FOR OPERATION 3.1.3.5 All shutdown CEAs shall be withdrawn to the Full Out position.

APPLICABILITY:

MODES 1 and 2*#.

ACTION:

With a maximum of one shutdown CEA withdrawn to less than the Full Out position, except for surveillance testing pursuant to Specification 4.1.3.1.2, within one hour either:

a.

Withdraw the CEA to the Full Out position, or

b.

Declare the CEA inoperable and apply Specification 3.1.3.1.

SURVEILLANCE REQUIREMENTS 4.1.3.5 Each shutdown CEA shall be determined to be withdrawn to the Full Out position:

a.

Within 15 minutes prior to withdrawal of any CEAs in regulating groups during an approach to reactor criticality, and

b.

In accordance with the Surveillance Frequency Control Program.

See Special Test Exception 3.10.2.

With l<eff ~ 1.0.

ARKANSAS-UNIT 2 3/4 1-24 Amendment No. 315

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION ACTION: {Continued) b)

Both CEA Cs inoperable:

Be in at least HOT STANDBY within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months of exceeding the Transient Insertion Limit.

b.

With the regulating CEA groups or Group P CEAs inserted between the Long Term Steady State Insertion Limit and the Transient Insertion Limit for intervals

> 5 EFPD per 30 EFPD interval or > 14 EFPD per calendar year, either:

1.

Restore the regulating groups or Group P CEAs to within the Long Term Steady State Insertion Limit within two hours, or

2.

Be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

c.

With the regulating CEA groups or Group P CEAs inserted between the Short Term Steady State Insertion Limit and the Transient Insertion Limit for intervals

> 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months interval, operation may proceed provided any subsequent increase in thermal power is restricted to :'.S: 5% of rated thermal power per hour.

SURVEILLANCE REQUIREMENTS 4.1.3.6 The position of each regulating CEA group and Group P CEAs shall be determined to be within the Transient Insertion Limits in accordance with the Surveillance Frequency Control Program except during time intervals when the PDIL Alarm is inoperable, then verify the individual CEA positions at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The accumulated times during which the regulating CEA groups or Group P CEAs are inserted beyond the Long Term Steady State Insertion Limit or the Short Term Steady State Insertion Limit but within the Transient Insertion Limit shall be determined in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 1-26 Amendment No. 37,499,244,315

3/4. 2 POWER DISTRIBUTION LIMITS 3/4.2.1 LINEAR HEAT RATE LIMITING CONDITION FOR OPERATION 3.2.1 The linear heat rate limit shall be maintained by either:

a.

Maintaining COLSS calculated core power less than or equal to COLSS calculated core power operating limit based on linear heat rate (when COLSS is in service); or

b.

Operating within the region of acceptable operation specified in the CORE OPERATING LIMITS REPORT using any operable CPC Channel (when COLSS is out of service).

APPLICABILITY:

MODE 1 above 20% of RATED THERMAL POWER.

ACTION:

a.

With COLSS in service and the linear heat rate limit not being maintained as indicated by COLSS calculated core power exceeding the COLSS calculated core power operating limit based on linear heat rate, within 15 minutes initiate corrective action to reduce the linear heat rate to within the limit and either:

1.

Restore the linear heat rate to within its limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of the initiating event, or

2.

Reduce THERMAL POWER to less than or equal to 20% of RATED THERMAL POWER within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

With COLSS out of service and the linear heat rate limit not being maintained as indicated by operation outside the region of acceptable operation specified in the CORE OPERATING LIMITS REPORT, either:

1.

Restore the linear heat rate to within its limits within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of the initiating event, or

2.

Reduce THERMAL POWER to less than or equal to 20% of RATED THERMAL POWER within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.1.1 The provisions of Specification 4.0.4 are not applicable.

4.2.1.2 The linear heat rate shall be determined to be within its limits when THERMAL POWER is above 20% of RA TED THERMAL POWER by continuously monitoring the core power distribution with the Core Operating Limit Supervisory System (COLSS) or, with the COLSS out of service, by verifying in accordance with the Surveillance Frequency Control Program that the linear heat rate, as indicated on any OPERABLE CPC channel, is within the limit specified in the CORE OPERATING LIMITS REPORT.

4.2.1.3 In accordance with the Surveillance Frequency Control Program, the COLSS Margin Alarm shall be verified to actuate at a THERMAL POWER level less than or equal to the core power operating limit based on linear heat rate.

ARKANSAS - UNIT 2 3/4 2-1 Amendment No. 24,-79,~,4a7.315

POWER DISTRIBUTION LIMITS RADIAL PEAKING FACTORS LIMITING CONDITION FOR OPERATION 3.2.2 The measured PLANAR RADIAL PEAKING FACTORS ( F~) shall be less than or equal to the PLANAR RADIAL PEAKING FACTORS (F~) used in the Core Operating Limit Supervisory System (COLSS) and in the Core Protection Calculators (CPC).

APPLICABILITY:

MODE 1 above 20% of RATED THERMAL POWER*

ACTION:

With a F~ exceeding a corresponding Fi),, within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months either:

a.

Adjust the CPC addressable constants to increase the multiplier applied to PLANAR RADIAL PEAKING FACTOR by a factor equivalent to ~ F~ /F~ and restrict subsequent operation so that a margin to the COLSS operating limits of at least [(F~/F~) - 1.0] x 100% is maintained; or

b.

Adjust the affected PLANAR RADIAL PEAKING FACTORS ( F~) used in the COLSS and CPC to a value greater than or equal to the measured PLANAR RADIAL PEAKING FACTORS (F~); or

c.

Be in at least HOT STANDBY.

SURVEILLANCE REQUIREMENTS 4.2.2.1 The provisions of Specification 4.0.4 are not applicable.

4.2.2.2 The measured PLANAR RADIAL PEAKING FACTORS ( F~). obtained by using the incore detection system, shall be determined to be less than or equal to the PLANAR RADIAL PEAKING FACTORS (F~) used in the COLSS and CPC at the following intervals:

a.

After each fuel loading with THERMAL POWER greater than 40% but prior to operation above 70% of RATED THERMAL POWER, and

b.

In accordance with the Surveillance Frequency Control Program in MODE 1.

See Special Test Exception 3.10.2.

ARKANSAS - UNIT 2 3/4 2-2 Amendment No. 24,4-a+,2-55, 315

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS 4.2.3 The AZIMUTHAL POWER TILT shall be determined to be within the limit above 20%

of RA TED THERMAL POWER by:

a.

Continuously monitoring the tilt with COLSS when the COLSS is OPERABLE.

b.

Calculating the tilt in accordance with the Surveillance Frequency Control Program when the COLSS is inoperable.

c.

Verifying in accordance with the Surveillance Frequency Control Program, that the COLSS Azimuthal Tilt Alarm is actuated at an AZIMUTHAL POWER TILT greater than the AZIMUTHAL POWER TILT Allowance used in the CPCs.

d.

Using the incore detectors in accordance with the Surveillance Frequency Control Program to independently confirm the validity of the COLSS calculated AZIMUTHAL POWER TILT.

ARKANSAS - UNIT 2 3/4 2-4 Amendment No. 24,4-a+, 315

POWER DISTRIBUTION LIMITS SURVEILLANCE REQUIREMENTS 4.2.4.1 The provisions of Specification 4.0.4 are not applicable.

4.2.4.2 The DNBR shall be determined to be within its limits when THERMAL POWER is above 20% of RATED THERMAL POWER by continuously monitoring the core power distribution with the Core Operating Limit Supervisory System (COLSS) or, with the COLSS out of service, by verifying in accordance with the Surveillance Frequency Control Program that the DNBR, as indicated on any OPERABLE CPC channel, is within the limit specified in the CORE OPERATING LIMITS REPORT.

4.2.4.3 In accordance with the Surveillance Frequency Control Program, the COLSS Margin Alarm shall be verified to actuate at a THERMAL POWER level less than or equal to the core power operating limit based on DNBR.

ARKANSAS - UNIT 2 3/4 2-6 Amendment No. -79,4-a-7, 315

POWER DISTRIBUTION LIMITS RCS FLOW RA TE LIMITING CONDITION FOR OPERATION 3.2.5 The actual Reactor Coolant System total flow rate shall be greater than or equal to 120.4 x 106 lbm/hr.

APPLICABILITY:

MODE 1 ACTION:

With the actual Reactor Coolant System total flow rate determined to be less than the above limit, reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.5 The actual Reactor Coolant System total flow rate shall be determined to be within its limit in accordance with the Surveillance Frequency Control Program.

ARKANSAS-UNIT 2 3/4 2-7 Amendment No. ~.~.490.~. 315

POWER DISTRIBUTION LIMITS REACTOR COOLANT COLD LEG TEMPERATURE LIMITING CONDITION FOR OPERATION 3.2.6 The Reactor Coolant Cold Leg Temperature (Tc) shall be maintained between 542 °F and 554.7 °F.

APPLICABILITY:

MODE 1 above 30% of RATED THERMAL POWER.

ACTION:

With the Reactor Coolant Cold Leg Temperature exceeding its limit, restore the temperature to within its limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 30% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.6 The Reactor Coolant Cold Leg Temperature shall be determined to be within its limit in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 2-8 Amendment No. ~.4-a+, 315

POWER DISTRIBUTION LIMITS AXIAL SHAPE INDEX LIMITING CONDITION FOR OPERATION 3.2.7 The core average AXIAL SHAPE INDEX (ASI) shall be maintained within the limits specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY:

MODE 1 above 20% of RATED THERMAL POWER.*

ACTION:

With the core average AXIAL SHAPE INDEX (ASI) exceeding its limit, restore the ASI to within its limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 20% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.7 The core average AXIAL SHAPE INDEX shall be determined to be within its limits in accordance with the Surveillance Frequency Control Program using the COLSS or any OPERABLE Core Protection Calculator channel.

See Special Test Exception 3.10.2.

ARKANSAS - UNIT 2 3/4 2-9 Amendment No. 24,49,4§.7, 315

POWER DISTRIBUTION LIMITS PRESSURIZER PRESSURE LIMITING CONDITION FOR OPERATION 3.2.8 The average pressurizer pressure shall be maintained between 2025 psia and 2275 psia.

APPLICABILITY:

MODE 1.

ACTION:

With the average pressurizer pressure exceeding its limits, restore the pressure to within its limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.8 The average pressurizer pressure shall be determined to be within its limit in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 2-10 Amendment No. ~.~.49.~,4-a+. 315

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTIVE INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1.1 As a minimum, the reactor protective instrumentation channels and bypasses of Table 3.3-1 shall be OPERABLE.

APPLICABILITY:

As shown in Table 3.3-1.

ACTION:

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.1.1.1 Each reactor protective instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-1.

4.3.1.1.2 The logic for the bypasses shall be demonstrated OPERABLE prior to each reactor startup unless performed during the preceding 92 days. The total bypass function shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during CHANNEL CALIBRATION testing of each channel affected by bypass operation.

4.3.1.1.3 The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be demonstrated to be within its limit in accordance with the Surveillance Frequency Control Program. Neutron detectors are exempt from response time testing.

4.3.1.1.4 The Core Protection Calculator System shall be determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying that less than three auto restarts have occurred on each calculator during the past 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

4.3.1.1.5 The affected Core Protection Calculator Channel shall be subjected to a CHANNEL FUNCTIONAL TEST to verify OPERABILITY within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of receipt of a valid CPC Cabinet High Temperature alarm.

ARKANSAS - UNIT 2 3/4 3-1 Amendment No. ~.4G4.~.~. 315

TABLE 4.3-1 REACTOR PROTECTION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL FUNCTIONAL UNIT CHECK

1.

Manual Reactor Trip N.A.

2.

Linear Power Level - High SFCP

3.

Logarithmic Power Level - High SFCP

4.

Pressurizer Pressure - High SFCP

5.

Pressurizer Pressure - Low SFCP

6.

Containment Pressure - High SFCP

7.

Steam Generator Pressure - Low SFCP

8.

Steam Generator Level - Low SFCP

9.

Local Power Density - High SFCP

10. DNBR-Low SFCP

11. Reactor Protection System Logic N.A.

12. Reactor Trip Breakers N.A.

13. Core Protection Calculators SFCP

14. CEA Calculators SFCP ARKANSAS-UNIT 2 CHANNEL MODES IN WHICH CHANNEL FUNCTIONAL SURVEILLANCE CALIBRATION TEST REQUIRED N.A.

S/U (1)

N.A.

SFCP (2,3,4)

SFCP 1,2 SFCP (4)

SFCP 1,2,3*,4*,5*

SIU (1)

SFCP SFCP 1,2 SFCP SFCP 1,2 SFCP SFCP 1,2 SFCP SFCP 1,2 SFCP SFCP 1,2 SFCP (2,4,5)

SFCP (6) 1,2 SFCP (2,4,5,7)

SFCP (6) 1,2 N.A.

SFCP 1,2,3*,4*,5*

N.A.

SFCP 1,2,3*,4*,5*

SFCP (2,4,5)

SFCP (6,9) 1,2 SFCP SFCP (6) 1,2 3/4 3-7 Amendment No. ~.d9,+7,4W,48e, 24S.~.289. 315

(7) -

Above 70% of RATED THERMAL POWER, verify that the total RCS flow rate as indicated by each CPC is less than or equal to the RCS total flow rate determined by either using the reactor coolant pump differential pressure instrumentation or by calorimetric calculations and, if necessary, adjust the CPC flow calibration addressable constant FC1 such that each CPC indicated flow is less than or equal to the measured flow rate.

(8) -

Deleted (9) -

The CPC CHANNEL FUNCTIONAL TEST shall include the verification that the correct values of addressable constants are installed in each OPERABLE CPC.

ARKANSAS-UNIT 2 3/4 3-9 Amendment No. 24-.~.+7,4-iJ,4-Se,

~.315

INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2.1 The Engineered Safety Feature Actuation System (ESFAS) instrumentation channels and bypasses shown in Table 3.3-3 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3-4.

APPLICABILITY:

As shown in Table 3.3-3.

ACTION:

a.

With an ESFAS instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3-4, declare the channel inoperable and apply the applicable ACTION requirement of Table 3.3-3 until the channel is restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint value.

b.

With an ESFAS instrumentation channel inoperable, take the ACTION shown in Table 3.3-3.

SURVEILLANCE REQUIREMENTS 4.3.2.1.1 Each ESFAS instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-2.

4.3.2.1.2 The logic for the bypasses shall be demonstrated OPERABLE during the at power CHANNEL FUNCTIONAL TEST of channels affected by bypass operation. The total bypass function shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during CHANNEL CALIBRATION testing of each channel affected by bypass operation.

4.3.2.1.3 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESFAS function shall be demonstrated to be within the limit in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 3-10 Amendment No. 489, 315

TABLE 4.3-2 ENGINEERED SAFETY FEATURE ACTUATION SYSTEM 11'-J_STRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED

1.

SAFETY INJECTION (SIAS)

a.

Manual (Trip Buttons)

N.A.

SFCP N.A.

b.

Containment Pressure - High SFCP SFCP SFCP 1,2,3 C.

Pressurizer Pressure - Low SFCP SFCP SFCP 1,2,3

d.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3

2.

CONTAINMENT SPRAY (CSAS)

a.

Manual (Trip Buttons)

N.A.

SFCP N.A.

b.

Containment Pressure -- High - High SFCP SFCP SFCP 1,2,3 C.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3

3.

CONTAINMENT ISOLATION (CIAS)

a.

Manual (Trip Buttons)

N.A.

SFCP N.A.

b.

Containment Pressure -- High SFCP SFCP SFCP 1,2,3 C.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3

4.

MAIN STEAM AND FEEDWATER ISOLATION (MSIS)

a.

Manual (Trip Buttons)

N.A.

SFCP N.A.

b.

Steam Generator Pressure - Low SFCP SFCP SFCP 1,2,3 C.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3 ARKANSAS-UNIT 2 3/4 3-21 Amendment No. 489,315

TABLE 4.3-2 (Continued)

ENGINEERED SAFETY FEATURE ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL MODES IN WHICH CHANNEL CHANNEL FUNCTIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST REQUIRED

5.

CONTAINMENT COOLING (CCAS)

a.

Manual (Trip Buttons)

N.A.

SFCP N.A.

b.

Containment Pressure - High SFCP SFCP SFCP 1,2,3 C.

Pressurizer Pressure - Low SFCP SFCP SFCP 1,2,3

d.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3

6.

RECIRCULATION (RAS)

a.

Manual (Trip Buttons) (a)

N.A.

SFCP N.A.

b.

Refueling Water Tank-Low SFCP SFCP SFCP 1,2,3 C.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3

7.

LOSS OF POWER

a.

4.16 kv Emergency Bus SFCP SFCP SFCP 1,2,3 Undervoltage (Loss of Voltage)

b.

460 volt Emergency Bus SFCP SFCP SFCP 1,2,3 Undervoltage (Degraded Voltage)

8.

EMERGENCY FEEDWATER (EFAS)

a.

Manual (Trip Switches)

N.A.

SFCP N.A.

b.

SG Level and Pressure (A/B)- low SFCP SFCP SFCP 1,2,3 and ~p (A/B) - High C.

SG Level (A/B) - Low and SFCP SFCP SFCP 1,2,3 No Pressure - Low Trip (A/B)

d.

Automatic Actuation Logic N.A.

N.A.

SFCP (1) 1,2,3 ARKANSAS - UNIT 2 3/4 3-22 Amendment No. 489,315

Table 4.3-2 (Continued)

TABLE NOTATION (a)

Remote manual not provided for RAS. These are local manuals at each ESF auxiliary relay cabinet.

(1)

The logic circuits shall be tested manually at least once per 123 days.

ARKANSAS - UNIT 2 3/4 3-23 Amendment No. 489,315

TABLE 4.3-3 RADIATION MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS MODES IN WHICH CHANNEL CHANNEL CHANNEL SURVEILLANCE INSTRUMENT CHECK CALIBRATION FUNCTIONAL TEST REQUIRED

1.

AREA MONITORS

a.

Spent Fuel Pool Area Monitor SFCP SFCP SFCP Note 1

b.

Containment High Range SFCP SFCP Note 4 SFCP 1, 2, 3, & 4

2.

PROCESS MONITORS

a.

Containment Purge and Note 2 SFCP Note 3 5&6 Exhaust Isolation

b.

Control Room Ventilation SFCP SFCP SFCP Note 6 Note 5 Intake Duct Monitors C.

Main Steam Line SFCP SFCP SFCP 1, 2, 3, & 4 Radiation Monitors Note 1 - With fuel in the spent fuel pool or building.

Note 2 - Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months prior to initiating containment purge operations and in accordance with the Surveillance Frequency Control Program during containment purge operations.

Note 3 - Within 31 days prior to initiating containment purge operations and in accordance with the Surveillance Frequency Control Program during containment purge operations.

Note 4 - Acceptable criteria for calibration are provided in Table 11.F.1-3 of NUREG-0737.

Note 5 - MODES 1, 2, 3, 4, and during handling of irradiated fuel.

Note 6 - When the Control Room Ventilation Intake Duct Monitor is placed in an inoperable status solely for performance of this Surveillance, entry into associated ACTIONS may be delayed up to 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months .

ARKANSAS - UNIT 2 3/4 3-27 Amendment No. 63,130,44a,200,2J4,2-aa, 315

TABLE 4.3-6 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

1.

Logarithmic Neutron Channel SFCP N.A.

2.

Startup Channel SFCP N.A.

3.

Reactor Trip Breaker Indication SFCP N.A.

4.

Reactor Coolant Cold Leg Temperature SFCP SFCP

5.

Pressurizer Pressure SFCP SFCP

6.

Pressurizer Level SFCP SFCP

7.

Steam Generator Level SFCP SFCP

8.

Steam Generator Pressure SFCP SFCP

9.

Shutdown Cooling Flow Rate SFCP SFCP

10.

Condensate Storage Tank Level SFCP SFCP ARKANSAS - UNIT 2 3/4 3-38 Amendment No. 2&a,315

TABLE 4.3-10 POST-ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS FUNCTION

1.

Penetration Flow Path Containment Isolation Valve Position

2.

Containment Pressure (Wide Range)

3.

Pressurizer Pressure (Wide Range)

4.

Pressurizer Level

5.

Steam Generator (SG) Pressure

6.

SG Water Level (Wide Range)

7.

Refueling Water Tank Water Level

8.

Containment Water Level (Wide Range)

9.

Emergency Feedwater Flow Rate

10.

Reactor Coolant System Hot Leg Temperature (Narrow Range)

11.

Reactor Coolant System Hot Leg Temperature (Wide Range)

12.

High Pressure Safety Injection Flow Rate

13.

Core Exit Thermocouples (CETs)- Quadrant 1

14.

CETs - Quadrant 2

15.

CETs -Quadrant 3

16.

CETs - Quadrant 4

17.

Reactor Vessel Level Monitoring System (RVLMS)

ARKANSAS - UNIT 2 3/4 3-42 CHANNEL CHANNEL CHECK CALIBRATION SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP SFCP Amendment No. 7,4-3.~.~.89,423,

~.315

3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION STARTUP AND POWER OPERATION LIMITING CONDITION FOR OPERATION 3.4.1.1 Both reactor coolant loops and both reactor coolant pumps in each loop shall be in operation.

APPLICABILITY:

MODES 1 and 2.

ACTION:

With less than the above required reactor coolant pumps in operation, be in at least HOT STANDBY within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

SURVEILLANCE REQUIREMENTS 4.4.1.1 The above required reactor coolant loops shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.

See Special Test Exception 3.10.3.

ARKANSAS - UNIT 2 3/4 4-1 Amendment No. 24.~.315

REACTOR COOLANT SYSTEM HOT STANDBY LIMITING CONDITION FOR OPERATION 3.4.1.2

a.

The reactor coolant loops listed below shall be in operable:

1.

Reactor Coolant Loop (A) and at least one associated reactor coolant pump.

2.

Reactor Coolant Loop (8) and at least one associated reactor coolant pump.

b.

At least one of the above Reactor Coolant Loops shall be in operation.*

APPLICABILITY:

MODE 3.

ACTION:

a.

With less than the above required reactor coolant loops operable, restore the required loops to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

With no reactor coolant loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required loop to operation.

SURVEILLANCE REQUIREMENTS 4.4.1.2.1 At least the above required reactor coolant pumps, if not in operation, shall be determined to be OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments and indicated power availability.

4.4.1.2.2 At least one cooling loop shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.

All reactor coolant pumps may be de-energized for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided (1) no operations are permitted that would cause dilution of the reactor coolant system boron concentration, and (2) core outlet temperature is maintained at least 1 O °F below saturation temperature.

ARKANSAS - UNIT 2 3/4 4-2 Amendment No. 24,29-, 315

REACTOR COOLANT SYSTEM SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.1.3

a.

At least two of the coolant loops listed below shall be OPERABLE:

1.

Reactor Coolant Loop (A) and its associated steam generator and at least one associated reactor coolant pump.

2.

Reactor Coolant Loop (8) and its associated steam generator and at least one associated reactor coolant pump.

3.

Shutdown Cooling Loop (A) #.

4.

Shutdown Cooling Loop (B) #.

b.

At least one of the above coolant loops shall be in operation.*

APPLICABILITY:

Modes 4 and 5.

ACTION:

a.

With less than the above required coolant loops OPERABLE, immediately initiate corrective action to return the required coolant loops to OPERABLE status as soon as possible and initiate action to make at least one steam generator available for decay heat removal via natural circulation. LCO 3.0.4.a is not applicable when entering HOT SHUTDOWN.

b.

With no coolant loop in operation, suspend all operations involving a reduction in boron concentration of the Reactor Coolant System and immediately initiate corrective action to return the required coolant loop to operation.

SURVEILLANCE REQUIREMENTS 4.4.1.3.1 The required shutdown cooling loop(s) shall be determined OPERABLE per the INSERVICE TESTING PROGRAM.

4.4.1.3.2 The required reactor coolant pump(s), if not in operation, shall be determined to be OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments and indicated power availability.

4.4.1.3.3 The required steam generator(s) shall be determined OPERABLE by verifying the secondary side water level to be ~ 23% indicated level in accordance with the Surveillance Frequency Control Program.

4.4.1.3.4 At least one coolant loop shall be verified to be in operation and circulating reactor coolant in accordance with the Surveillance Frequency Control Program.

All reactor coolant pumps and decay heat removal pumps may be de-energized for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months provided (1) no operations are permitted that would cause dilution of the reactor coolant system boron concentration, and (2) core outlet temperature is maintained at least 1 O °F below saturation temperature.

The normal or emergency power source may be inoperable in Mode 5.

ARKANSAS - UNIT 2 3/4 4-2a Amendment No. ~.~.~.dG4.~. 315

REACTOR COOLANT SYSTEM PRESSURIZER LIMITING CONDITION FOR OPERATION 3.4.4 The pressurizer shall be OPERABLE with a water volume of~ 910 cubic feet (equivalent to~ 82% of wide range indicated level) and both pressurizer proportional heater groups shall be OPERABLE.

APPLICABILITY:

MODES 1, 2 and 3.

ACTION:

(a)

With the pressurizer inoperable due to water volume~ 910 cubic feet, be in at least HOT SHUTDOWN with the reactor trip breakers open within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

(b)

With the pressurizer inoperable due to an inoperable emergency power supply to the pressurizer heaters, either restore the inoperable emergency power supply in accordance with TS 3.8.1.1, Action b.3, for an inoperable Emergency Diesel Generator, or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

(c)

With the pressurizer inoperable due to a single proportional heater group having less than a 150 KW capacity, restore the inoperable proportional heater group to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

(d)

With the pressurizer inoperable due to both proportional heater groups being inoperable for any reason (Note 1 ), restore at least one proportional heater group to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.4.1 The pressurizer water volume shall be determined to be within its limits in accordance with the Surveillance Frequency Control Program.

4.4.4.2 The pressurizer proportional heater groups shall be determined to be OPERABLE.

(a)

In accordance with the Surveillance Frequency Control Program by verifying emergency power is available to the heater groups, and (b)

In accordance with the Surveillance Frequency Control Program by verifying that the summed power consumption of the two proportional heater groups is ~ 150 KW.

Note 1: Action (d) is not applicable when the second group of required pressurizer heaters is intentionally made inoperable.

ARKANSAS-UNIT 2 3/4 4-5 Amendment No. ~.~,JQ4, 315

REACTOR COOLANT SYSTEM 3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE LEAKAGE DETECTION SYSTEMS SURVEILLANCE REQUIREMENTS 4.4.6.1 The leakage detection instrumentation shall be demonstrated OPERABLE by:

a.

Performing a CHANNEL CHECK of the required containment atmosphere radioactivity monitors in accordance with the Surveillance Frequency Control Program.

b.

Performing a CHANNEL CHECK of the containment sump level monitor in accordance with the Surveillance Frequency Control Program.

c.

Performing a CHANNEL FUNCTIONAL TEST of the required containment atmosphere radioactivity monitors in accordance with the Surveillance Frequency Control Program.

d.

Performing a CHANNEL CALIBRATION of the containment sump level monitor in accordance with the Surveillance Frequency Control Program.

e.

Performing a CHANNEL CALIBRATION of the required containment atmosphere radioactivity monitors in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 4-13a Amendment No. ~.315

REACTOR COOLANT SYSTEM REACTOR COOLANT SYSTEM OPERATIONAL LEAKAGE SURVEILLANCE REQUIREMENTS 4.4.6.2.1 Reactor Coolant System operational leakage, except for primary to secondary leakage, shall be demonstrated to be within each of the above limits by:

a.

Performance of a Reactor Coolant System water inventory balance in accordance with the Surveillance Frequency Control Program during steady state operation except when operating in the shutdown cooling mode*.

b.

Monitoring the reactor head flange leakoff temperature in accordance with the Surveillance Frequency Control Program.

4.4.6.2.2 Primary to secondary leakage shall be verified to be :s; 150 gallons per day through any one SG in accordance with the Surveillance Frequency Control Program*.

4.4.6.2.3 Each Reactor Coolant System Pressure Isolation Valve specified in Table 3.4.6-1 shall be demonstrated OPERABLE by individually verifying leakage to be within its limit:

a.

Prior to entering MODE 2 after each refueling outage,

b.

Prior to entering MODE 2 whenever the plant has been in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or more and if leakage testing has not been performed in the previous 9 months, and

c.

Prior to returning the valve to service following maintenance, repair or replacement work on the valve.

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

ARKANSAS-UNIT 2 3/4 4-14a Greer eate 4/20/81 Amendment No. ~.2ee, 315

REACTOR COOLANT SYSTEM SPECIFIC ACTIVITY LIMITING CONDITION FOR OPERATION 3.4.8 RCS DOSE EQUIVALENT 1-131 and DOSE EQUIVALENT XE-133 specific activity shall be within limits.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTION Note: The provisions of Specification 3.0.4.c are applicable to ACTION a and b.

a.

With the DOSE EQUIVALENT 1-131 not within limit:

1.

Verify DOSE EQUIVALENT 1-131 s 60 µCi/gm once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , and

2.

Restore DOSE EQUIVALENT 1-131 within limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

b.

With the DOSE EQUIVALENT XE-133 not within limit, restore DOSE EQUIVALENT XE-133 within limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

c.

With the requirements of ACTION a and/orb not met, or with DOSE EQUIVALENT 1-131

> 60 µCi/gm, be in at least HOT STANDBY in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.8.1 Verify reactor coolant DOSE EQUIVALENT XE-133 specific activity s 3100 µCi/gm in accordance with the Surveillance Frequency Control Program.*

4.4.8.2 Verify reactor coolant DOSE EQUIVALENT 1-131 specific activity s 1.0 µCi/gm:*

a.

in accordance with the Surveillance Frequency Control Program, and

b.

between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after THERMAL POWER change of~ 15% RATED THERMAL POWER within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period.

Only required to be performed in MODE 1.

ARKANSAS - UNIT 2 3/4 4-18 Amendment No. Qa,~.~.293. 315 Next Page is 3/4 4-22

SURVEILLANCE REQUIREMENTS 4.4.9.1.1 The Reactor Coolant System temperature and pressure shall be determined to be within the limits in accordance with the Surveillance Frequency Control Program during system heatup, cooldown, and inservice leak and hydrostatic testing operations.

4.4.9.1.2 The reactor vessel material irradiation surveillance specimens shall be removed and examined, to determine changes in material properties, at the intervals shown in SAR Table 5.2-12. The results of these examinations shall be used to update Figures 3.4-2A, 3.4-2B and 3.4-2C.

ARKANSAS - UNIT 2 3/4 4-23 Amendment No. 424.~.2-70,315

REACTOR COOLANT SYSTEM REACTOR COOLANT SYSTEM VENTS LIMITING CONDITION FOR OPERATION 3.4.11 At least one reactor coolant system vent path consisting of at least two valves in series shall be OPERABLE at each of the following locations:

1.

Reactor Vessel Head

2.

Pressurizer Steam Space (RCS High Point Vents)

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTION:

a.

With less than one vent path from each of the locations OPERABLE, STARTUP and/or POWER OPERATION may continue provided the inoperable vent path(s) is maintained closed; restore the inoperable vent path to OPERABLE status within 30 days or be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

With both vent paths 1 and 2 above inoperable, restore at least one of the vent paths to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.4.11 Each reactor coolant system vent path shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying flow through the reactor coolant vent system vent paths.

ARKANSAS - UNIT 2 3/4 4-27 Amendment No. 93,244,315

SURVEILLANCE REQUIREMENTS 4.4.12.1 Verify both sets of L TOP relief valve isolation valves are open in accordance with the Surveillance Frequency Control Program when the L TOP relief valves are being used for overpressure protection.

4.4.12.2 The RCS vent path shall be verified to be open in accordance with the Surveillance Frequency Control Program** when the vent path is being used for overpressure protection.

4.4.12.3 Verify that each SIT is isolated, when required, in accordance with the Surveillance Frequency Control Program.

4.4.12.4 No additional L TOP relief valve Surveillance Requirements other than those required by the INSERVICE TESTING PROGRAM.

- Except when the vent path is provided with a valve which is locked, sealed, or otherwise secured in the open position, then verify this valve is open in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 4-29 Amendment No. 480,233.~.315

3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

SAFETY INJECTION TANKS LIMITING CONDITION FOR OPERATION 3.5.1 Each reactor coolant system safety injection tank shall be OPERABLE with:

a.

The isolation valve open,

b.

A contained borated water volume of between 1413 and 1539 cubic feet (equivalent to an indicated level between 80.1 % and 87.9%, respectively},

c.

Between 2200 and 3000 ppm of boron, and

d.

A nitrogen cover-pressure of between 600 and 624 psig.

APPLICABILITY:

MODES 1, 2 and 3.*

ACTION:

a.

With one safety injection tank inoperable, due to boron concentration not within limits, restore the boron concentration to within limits within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and reduce pressurizer pressure to< 700 psia within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

With one safety injection tank inoperable due to inability to verify level or pressure, restore the SIT to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and reduce pressurizer pressure to < 700 psia within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c.

With one safety injection tank inoperable for reasons other than ACTION a or b, restore the SIT to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and reduce pressurizer pressure to < 700 psia within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.5.1 Each safety injection tank shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Verifying the contained borated water volume and nitrogen cover-pressure in the tanks, and

2.

Verifying that each safety injection tank isolation valve (2CV-5003-1, 2CV-5023-1, 2CV-5043-2, and 2CV-5063-2) is open.

With pressurizer pressure ~ 700 psia.

ARKANSAS - UNIT 2 3/4 5-1 Amendment No. 82,~.~.315

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b.

In accordance with the Surveillance Frequency Control Program and within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of ~ 5% of indicated tank level that is not the result of addition from the RWT, by verifying the boron concentration of the safety injection tank solution.

c.

In accordance with the Surveillance Frequency Control Program when the RCS pressure is above 2000 psia, by verifying that power to the isolation valve operator is removed by maintaining the motor circuit breaker open under administrative control.

d.

In accordance with the Surveillance Frequency Control Program by verifying that each safety injection tank isolation valve opens automatically under each of the following conditions:

1.

When the RCS pressure exceeds 700 psia, and

2.

Upon receipt of a safety injection test signal.

ARKANSAS - UNIT 2 3/4 5-2 Amendment No. 452-, 315

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.2 Each ECCS subsystem shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by verifying that the following valves are in the indicated positions with power to the 2CV-5101-1 and 2CV-5102-2 valve operators removed:

Valve Number 2CV-5101-1 2CV-5102-2 2BS-26 Valve Function HPSI Hot Leg Injection Isolation HPSI Hot Leg Injection Isolation RWT Return Line Valve Position Closed Closed Open

b.

In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

c.

By a visual inspection which verifies that no loose debris (rags, trash, clothing, etc.)

is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. This visual inspection shall be performed:

1.

For all accessible areas of the containment prior to establishing CONTAINMENT INTEGRITY, and

2.

At least once daily of the areas affected within containment if containment has been entered that day, and during the final entry when CONTAINMENT INTEGRITY is established.

d.

In accordance with the Surveillance Frequency Control Program by a visual inspection of the containment sump and verifying that the subsystem suction inlets are not restricted by debris and that the sump components (trash racks, screens, etc.) show no evidence of structural distress or corrosion.

e.

In accordance with the Surveillance Frequency Control Program, during shutdown, by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position on SIAS and RAS test signals.

2.

Verifying that each of the following pumps start automatically upon receipt of a Safety Injection Actuation Test Signal:

a.

High-Pressure Safety Injection pump.

b.

Low-Pressure Safety Injection pump.

ARKANSAS-UNIT 2 3/4 5-4 Amendment No.~.~.~.~. 315

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

f.

By verifying that each of the following pumps develops the indicated differential pressure on recirculation flow when tested pursuant to the INSERVICE TESTING PROGRAM:

1.

High-Pressure Safety Injection pump ~ 1360.4 psid with 90 °F water.

2.

Low-Pressure Safety Injection pump ~ 156.25 psid with 90 °F water.

g.

In accordance with the Surveillance Frequency Control Program by verifying the correct position of each electrical and/or mechanical position stop for the following ECCS throttle valves:

LPSI System Valve Number

a.

b.

c.

d.

h.

By performing a flow balance test, during shutdown, following completion of modifications to the ECCS subsystem that alter the subsystem flow characteristics and verifying the following flow rates:

HPSI System - Single Pump The sum of the injection line flow rates, excluding the highest flow rate is greater than or equal to 570 gpm.

ARKANSAS - UNIT 2 3/4 5-5 LPSI System - Single Pump

a.

Injection Leg 1, ~ 1059 gpm

b.

Injection Leg 2, ~ 1059 gpm

c.

Injection Leg 3, ~ 1059 gpm

d.

Injection Leg 4, ~ 1059 gpm Amendment No. 89,443,4-ea,4-7G,~.

Wa,315

EMERGENCY CORE COOLING SYSTEMS REFUELING WATER TANK LIMITING CONDITION FOR OPERATION 3.5.4 The refueling water tank shall be OPERABLE with:

a.

An available borated water volume of between 384,000 and 503,300 gallons

b.

Between 2500 and 3000 ppm of boron,

c.

A minimum solution temperature of 40 °F, and

d.

A maximum solution temperature of 110 °F APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

With the refueling water tank inoperable, restore tank to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.5.4 The RWT shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Verifying the contained borated water volume in the tank, and

2.

Verifying the boron concentration of the water.

b.

In accordance with the Surveillance Frequency Control Program by verifying the RWT temperature.

ARKANSAS - UNIT 2 3/4 5-7 Amendment No. 84.~.~.315

3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 Primary CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTION:

Without primary CONTAINMENT INTEGRITY, restore CONTAINMENT INTEGRITY within one hour or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.1 Primary CONTAINMENT INTEGRITY shall be demonstrated:

a.

In accordance with the Surveillance Frequency Control Program by verifying that each containment isolation manual valve and blind flange (Note 1) that is located outside containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative control as permitted by Specification 3.6.3.1.

b.

By verifying that each containment air lock is OPERABLE per Specification 3.6.1.3.

c.

After each closing of the equipment hatch, by leak rate testing the equipment hatch seals in accordance with the Containment Leakage Rate Testing Program.

d.

Prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days by verifying each containment isolation manual valve and blind flange (Note 1) that is located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed, except for containment isolation valves that are open under administrative controls as permitted by Specification 3.6.3.1.

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

ARKANSAS - UNIT 2 3/4 6-1 Amendment No. +a4,4-7&,~,2e9. 315

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3.1 Each containment air lock shall be demonstrated OPERABLE as specified in the Containment Leakage Rate Testing Program5*6.

4.6.1.3.2 Each containment air lock interlock shall be demonstrated OPERABLE by testing the air lock interlock mechanism in accordance with the Surveillance Frequency Control Program7.

5 Leakrate results shall also be evaluated against the acceptance criteria of specification 3.6.1.2.

6 An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

7 This surveillance requirement is only required to be performed upon entry or exit through the associated containment air lock.

ARKANSAS - UNIT 2 3/4 6-5 Amendment No. 475,4-79, 315

CONTAINMENT SYSTEMS INTERNAL PRESSURE AND AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.4 The combination of containment internal pressure and average air temperature shall be maintained within the region of acceptable operation shown on Figure 3.6-1.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

With the point defined by the combination of containment internal pressure and average air temperature outside the region of acceptable operation shown on Figure 3.6-1, restore the combination of containment internal pressure and average air temperature to within the above limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . LCO 3.0.4.a is not applicable when entering HOT SHUTDOWN.

SURVEILLANCE REQUIREMENTS 4.6.1.4 The primary containment internal pressure and average air temperature shall be determined to be within the limits in accordance with the Surveillance Frequency Control Program. The containment average air temperature shall be the temperature of the air in the containment HVAC common return air duct upstream of the fan/cooler units.

ARKANSAS - UNIT 2 3/4 6-6 Amendment No. 22a,30+, 315

CONTAINMENT SYSTEMS CONTAINMENT VENTILATION SYSTEM LIMITING CONDITION FOR OPERATION 3.6.1.6 The containment purge supply and exhaust isolation valves shall be closed and hand switch keys removed.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTION:

With one or more containment purge supply and/or exhaust isolation valves not closed with the handswitch keys removed, place the valve(s) in the closed position with handswitch keys(s) removed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.6.1.6 The containment purge supply and exhaust isolation valves shall be determined closed in accordance with the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 3/4 6-9 Amendment No. 94,262-, 315

CONTAINMENT SYSTEMS 3/4.6.2 DEPRESSURIZATION, COOLING, AND pH CONTROL SYSTEMS CONTAINMENT SPRAY SYSTEM LIMITING CONDITION FOR OPERATION 3.6.2.1 Two independent containment spray systems shall be OPERABLE with each spray system capable of taking suction from the RWT on a Containment Spray Actuation Signal (CSAS) and automatically transferring suction to the containment sump on a Recirculation Actuation Signal (RAS). Each spray system flow path from the containment sump shall be via an OPERABLE shutdown cooling heat exchanger.

APPLICABILITY:

MODES 1, 2, and 3.

ACTION:

a.

With one containment spray system inoperable, restore the inoperable spray system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

With both containment spray systems inoperable (Note 1 ):

1.

Within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months verify both CREVS trains are OPERABLE, and

2.

Restore at least one containment spray system to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Otherwise, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.2.1 Each containment spray system shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Verify each containment spray manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

2.

Verifying that the system piping is full of water from the RWT to at least elevation 505' (equivalent to> 12.5% indicated narrow range level) in the risers within the containment.

b.

Verify each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head when tested pursuant to the INSERVICE TESTING PROGRAM.

Note 1: ACTION b is not applicable when the second containment spray system is intentionally made inoperable.

ARKANSAS-UNIT 2 3/4 6-10 Amendment No. 494.~.~.~.

JO+,JQ4,~, 315

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c.

In accordance with the Surveillance Frequency Control Program, during shutdown, by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position on CSAS and RAS test signals.

2.

Verifying that upon a RAS test signal, the containment sump isolation valves open and that a recirculation mode flow path via an OPERABLE shutdown cooling heat exchanger is established.

3.

Verifying that each spray pump starts automatically on a CSAS test signal.

d.

Verify each spray nozzle is unobstructed following maintenance which could result in nozzle blockage.

ARKANSAS - UNIT 2 3/4 6-11 Amendment No. 94.~.2-+-2-.315

CONTAINMENT SYSTEMS CONTAINMENT SUMP BUFFERING AGENT LIMITING CONDITION FOR OPERATION 3.6.2.2 The buffering agent baskets shall contain ~ 308 ft3 of sodium tetraborate (Na TB) decahydrate.

APPLICABILITY:

MODES 1, 2 and 3.

ACTION:

With the buffering agent not within limits, restore the buffering agent to within limits within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and be in at least HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.2.2 The buffering agent shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by verifying that the buffering agent baskets contain~ 308 ft3 of NaTB decahydrate.

b.

In accordance with the Surveillance Frequency Control Program by verifying that a sample from the buffering agent baskets provides adequate pH adjustment of borated water.

ARKANSAS-UNIT 2 3/4 6-12 Amendment No. 4-94,~.315

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.2.3 Each containment cooling group shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Verifying that service water flow rate to the group of cooling units is :::: 1250 gpm and that each group has two operable fans.

2.

Addition of a biocide to the service water during the surveillance in 4.6.2.3.a.1 above, whenever service water temperature is between 60 °F and 80 °F.

b.

In accordance with the Surveillance Frequency Control Program by:

1.

Starting (unless already operating) each operational cooling unit from the control room.

2.

Verifying that each operational cooling unit operates for at least 15 minutes.

c.

In accordance with the Surveillance Frequency Control Program by verifying that each cooling unit starts automatically on a CCAS test signal.

ARKANSAS-UNIT 2 3/4 6-15 Amendment No. 44,4e.~,4.Q+,44Q.,

226,315

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.6.3.1.2 Each containment isolation valve shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying that on a containment isolation test signal, each isolation valve actuates to its isolation position.

4.6.3.1.3 The isolation time of each power operated or automatic containment isolation valve shall be determined to be within its limit when tested pursuant to the INSERVICE TESTING PROGRAM.

4.6.3.1.4 The containment purge supply and exhaust isolation valves shall be demonstrated OPERABLE as specified in the Containment Leakage Rate Testing Program.

ARKANSAS - UNIT 2 3/4 6-17 Amendment No. 4e,449,4a4,~.~.

2aa.~.315

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS

4. 7.1.2 Each EFW pump shall be demonstrated OPERABLE:

a In accordance with the Surveillance Frequency Control Program by:

1.

Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

b.

In accordance with the INSERVICE TESTING PROGRAM by:

1.

Verifying the developed head of each EFW pump at the flow test point is greater than or equal to the required developed head. This surveillance requirement is not required to be performed for the turbine-driven EFW pump until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after exceeding 700 psia in the steam generators.

c In accordance with the Surveillance Frequency Control Program by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position on actual or simulated MSIS and EFAS.

2.

Verifying each EFW pump starts automatically on an actual or simulated EFAS.

d.

By verifying proper alignment of the required EFW flow paths by verifying flow from the condensate storage tank to each steam generator. This SR is required to be verified prior to entering MODE 2 whenever plant has been in MODES 4, 5, 6, or defueled for > 30 days.

ARKANSAS-UNIT 2 3/4 7-6 Amendment No. W,4,Sg,~.~.315

PLANT SYSTEMS CONDENSATE STORAGE TANK LIMITING CONDITION FOR OPERATION 3.7.1.3 At least one condensate storage tank (CST) shall be OPERABLE with a minimum contained water volume of either:

a.

160,000 gallons in either 2T41A or 2T41B, or

b.

A minimum of 267,000 gallons of water is available in condensate storage tank, T 41 B, when required for both units. A minimum of 160,000 gallons of water is available in T41B when only required for Unit 2.

APPLICABILITY:

MODES 1, 2 and 3.

ACTION:

With the required condensate storage tank inoperable, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months either:

a.

Restore at least one CST to OPERABLE status or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , or

b.

Demonstrate the OPERABILITY of the service water system as a backup supply to the emergency feedwater pumps and restore at least one condensate storage tank to OPERABLE status within 7 days or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.1.3.1 The above required condensate storage tank shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying the contained water volume is within its limits when the tank is the supply source for the emergency feedwater pumps.

4. 7.1.3.2 The service water system shall be demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program by verifying that at least one service water loop is operating and that the service water system - emergency feedwater system isolation valves are either open or OPERABLE whenever the service water system is the supply source for the emergency feedwater pumps.

ARKANSAS - UNIT 2 3/4 7-7 Amendment No.~. 315

TABLE 4.7-2 SECONDARY COOLANT SYSTEM SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM TYPE OF MEASUREMENT AND ANALYSIS

1.

Gross Activity Determination

2.

Isotopic Analysis for DOSE EQUIVALENT 1-131 Concentration ARKANSAS-UNIT 2 SAMPLE AND ANALYSIS FREQUENCY In accordance with the Surveillance Frequency Control Program a)

In accordance with the Surveillance Frequency Control Program, whenever the gross activity determination is greater than 10% of the allowable iodine limit.

b)

In accordance with the Surveillance Frequency Control Program, whenever the gross activity determination is below 10% of the allowable iodine limit.

3/4 7-9 Amendment No. 315

PLANT SYSTEMS 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION LIMITING CONDITION FOR OPERATION 3.7.2.1 The temperatures of both the primary and secondary coolants in the steam generators shall be> 90 °F when the pressure of either coolant in the steam generator is > 275 psig.

APPLICABILITY:

At all times.

ACTION:

With the requirements of the above specification not satisfied:

a.

Reduce the steam generator pressure of the applicable side to ::; 275 psig within 30 minutes, and

b.

Perform an engineering evaluation to determine the effect of the overpressurization on the structural integrity of the steam generator. Determine that the steam generator remains acceptable for continued operation prior to increasing its temperatures above 200 °F.

SURVEILLANCE REQUIREMENTS 4.7.2.1 The pressure in each side of the steam generators shall be determined to be

< 275 psig in accordance with the Surveillance Frequency Control Program when the temperature of either the primary or secondary coolant is< 90 °F.

ARKANSAS-UNIT 2 3/4 7-14 Amendment No. 315

PLANT SYSTEMS 3/4.7.3 SERVICE WATER SYSTEM LIMITING CONDITION FOR OPERATION 3.7.3.1 At least two independent service water loops shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

With only one service water loop OPERABLE, restore at least two loops to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . LCO 3.0.4.a is not applicable when entering HOT SHUTDOWN.

SURVEILLANCE REQUIREMENTS 4.7.3.1 At least two service water loops shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by verifying that each valve (manual, power operated or automatic) servicing safety related equipment that is not locked, sealed, or otherwise secured in position, is in its correct position.

b.

In accordance with the Surveillance Frequency Control Program during shutdown, by verifying that each automatic valve servicing safety related equipment actuates to its correct position on CCAS, MSIS and RAS test signals.

ARKANSAS-UNIT 2 3/4 7-15 Amendment No. 3G4, 315

PLANT SYSTEMS 3/4.7.4 EMERGENCY COOLING POND LIMITING CONDITION FOR OPERATION 3.7.4.1 The emergency cooling pond (ECP) shall be OPERABLE with:

a.

A minimum contained water volume of 70 acre-feet.

b.

An average water temperature of::; 100 °F.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With the volume and/or temperature requirements of the above specification not satisfied or, with the requirements of Action b not met, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

b.

If degradation is noted pursuant to 4.7.4.1.d below or by other inspection, perform an evaluation to determine that the ECP remains acceptable for continued operation within 7 days.

SURVEILLANCE REQUIREMENTS 4.7.4.1 The ECP shall be determined OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by verifying that the indicated water level of the ECP is greater than or equal to that required for an ECP volume of 70 acre-feet.

b.

In accordance with the Surveillance Frequency Control Program during the period of June 1 through September 30 by verifying that the pond's average water temperature at the point of discharge from the pond is within its limit.

c.

In accordance with the Surveillance Frequency Control Program by making soundings of the pond and verifying:

1.

A contained water volume of ECP ;;::: 70 acre-feet, and

2.

The minimum indicated water level needed to ensure a volume of 70 acre-feet is maintained.

d.

In accordance with the Surveillance Frequency Control Program by performance of a visual inspection of the ECP to verify conformance with design requirements.

ARKANSAS - UNIT 2 3/4 7-16 Amendment No. ~.214, 315

PLANT SYSTEMS 3/4.7.5 FLOOD PROTECTION LIMITING CONDITION FOR OPERATION 3.7.5.1 Flood protection shall be provided for all safety related systems, components and structures when the water level of the Dardanelle Reservoir exceeds 350 feet Mean Sea Level USGS datum, at the intake structure.

APPLICABILITY:

When a flood warning exists at the facility site.

ACTION:

With the water level at the intake structure above elevation 350 feet Mean Sea Level USGS datum, initiate and complete within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , closure of the openings and penetrations listed in Table 3.7-6 using the equipment listed in Table 3.7-6.

SURVEILLANCE REQUIREMENTS

4. 7.5.1 The water level at the intake structure shall be determined to be within the limits by:

a.

Measurement in accordance with the Surveillance Frequency Control Program when the water level is below elevation 350 feet Mean Sea Level USGS datum, and

b.

Measurement in accordance with the Surveillance Frequency Control Program when the water level is equal to or above elevation 350 feet Mean Sea Level USGS datum.

ARKANSAS - UNIT 2 3/4 7-16a Amendment No. 315

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.6.1.1 Each control room emergency air conditioning system shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Starting each unit from the control room, and

2.

Verifying that each unit operates for at least 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and maintains the control room air temperature :=:; 84 °F D.B.

b.

In accordance with the Surveillance Frequency Control Program by verifying a system flow rate of 9900 cfm +/- 10%.

4.7.6.1.2 Each control room emergency air filtration system shall be demonstrated OPERABLE:

a.

In accordance with the Surveillance Frequency Control Program by verifying that the system operates for at least 15 minutes.

b.

In accordance with the Surveillance Frequency Control Program by verifying that on a control room high radiation signal, either actual or simulated, the system automatically isolates the control room and switches into a recirculation mode of operation.

c.

By performing the required Control Room Emergency Ventilation filter testing in accordance with the Ventilation Filter Testing Program (VFTP).

d.

Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program.

ARKANSAS - UNIT 2 3/4 7-18 Next Page is 3/4 7-27 Amendment No. 4Q4,~.~.~.

~.~.315

PLANT SYSTEMS 3/4.7.9 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.9.1 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 5 microcuries of alpha emitting material shall be free of~ 0.005 microcuries of removable contamination.

APPLICABILITY:

At all times.

ACTION:

a.

Each sealed source with removable contamination in excess of the above limit shall be immediately withdrawn from use and:

1.

Either decontaminated and repaired, or

2.

Disposed of in accordance with Commission Regulations.

b.

The provisions of Specifications 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.9.1.1 Test Requirements - Each sealed source shall be tested for leakage and/or contamination by:

a.

The licensee, or

b.

Other persons specifically authorized by the Commission or an Agreement State.

The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample.

4. 7.9.1.2 Test Frequencies - Each category of sealed sources (excluding startup sources and fission detectors previously subjected to core flux) shall be tested at the frequencies described below.

a.

Sources in use - In accordance with the Surveillance Frequency Control Program for all sealed sources containing radioactive material:

ARKANSAS - UNIT 2 3/4 7-27 Amendment No. 434,315

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

a.

Determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignments, indicated power availability, and

b.

Demonstrated OPERABLE in accordance with the Surveillance Frequency Control Program during shutdown by transferring (manually and automatically) unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each diesel generator shall be demonstrated OPERABLE: (Note 1)

a.

In accordance with the Surveillance Frequency Control Program by:

1.

Verifying the fuel level in the day fuel tank.

2.

deleted

3.

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

4.

Verifying the diesel starts from a standby condition and accelerates to at least 900 rpm in s 15 seconds. (Note 2)

5.

Verifying the generator is synchronized, loaded to an indicated 2600 to 2850 Kw and operates for~ 60 minutes. (Notes 3 & 4)

6.

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

b.

deleted Note 1 All planned diesel generator starts for the purposes of these surveillances may be preceded by prelube procedures.

Note 2 This diesel generator start from a standby condition in ~ 15 sec. shall be accomplished at least once every 184 days. All other diesel generator starts for this surveillance may be in accordance with vendor recommendations.

Note 3 Diesel generator loading may be accomplished in accordance with vendor recommendations such as gradual loading.

Note 4 Momentary transients outside this load band due to changing loads will not invalidate the test.

Load ranges are allowed to preclude over-loading the diesel generators.

ARKANSAS - UNIT 2 3/4 8-2b Amendment No. 44i.~.249.2aa, 315

ELECTRICAL POWER SYSTEM SURVEILLANCE REQUIREMENTS (Continued)

c.

In accordance with the Surveillance Frequency Control Program by:

1.

Deleted

2.

Verifying during shutdown that the automatic sequence time delay relays are OPERABLE at their setpoint +/- 10% of the elapsed time for each load block.

3.

Verifying during shutdown the generator capability to reject a load of greater than or equal to its associated single largest post-accident load, and maintain voltage at 4160 +/- 500 volts and frequency at 60 +/- 3 Hz.

4.

Verifying during shutdown the generator capability to reject a load of 2850 Kw without exceeding 75% of the difference between nominal speed and the overspeed trip setpoint, or 15% above nominal, whichever is lower.

5.

Simulating during shutdown a loss of offsite power by itself, and:

a.

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

b.

Verifying the diesel starts from a standby condition on the undervoltage auto-start signal, energizes the emergency busses with permanently connected loads, energizes the auto-connected shutdown loads through the time delay relays and operates for ~ 5 minutes while its generator is loaded with the shutdown loads.

6.

Verifying during shutdown that on a Safety Injection Actuation Signal (SIAS) actuation test signal (without loss of offsite power) the diesel generator starts on the auto-start signal and operates on standby for ~ 5 minutes.

ARKANSAS - UNIT 2 3/4 8-3 Amendment No. ~.444-,204,~.~. 315

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

11. Verifying during shutdown 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.

12. Verifying during shutdown that with the diesel generator operating in a test mode (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 energizes the auto-connected emergency (accident) loads with offsite power.

13. Verifying that the fuel transfer pump transfers fuel from each fuel storage tank to the day tank of each diesel via the installed cross connection lines.

d.

In accordance with 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 900 rpm in ~ 15 seconds.

ARKANSAS-UNIT 2 3/4 8-4a Amendment No. 94,444-,~,315

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION 3.8.1.3 The stored diesel fuel oil shall be within limits for each required diesel generator.

APPLICABILITY:

When associated diesel generator is required to be OPERABLE.

ACTION:

With the volume of the stored diesel fuel oil less than 22,500 gallons for either fuel oil storage tank or the new or stored fuel oil properties outside the limits of the Diesel Fuel Oil Testing Program, perform the following as appropriate: (Note - Separate ACTION entry is allowed for each diesel generator.)

1.

If one or more fuel storage tanks contain less than 22,500 gallons and greater than 17,446 gallons, restore the fuel oil volume to within limits within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

2.

If the stored fuel oil total particulates are not within limits for one or more diesel generators, restore fuel oil total particulates to within limits within 7 days.

3.

If new fuel oil properties are not within limits for the one or more diesel generators, restore stored fuel oil properties to within limits within 30 days.

4.

If ACTION 1 is not met within the allowable outage time or is outside the allowable limits, or if ACTION 2 or 3 is not met within the allowable outage time, then immediately declare the associated diesel generator inoperable.

SURVEILLANCE REQUIREMENTS 4.8.1.3.1 In accordance with the Surveillance Frequency Control Program verify the fuel oil storage tank contains ~ 22,500 gallons of fuel.

4.8.1.3.2 Verify 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.

ARKANSAS - UNIT 2 3/4 8-5a Amendment No. ~.315

ELECTRICAL POWER SYSTEMS 3/4.8.2 ONSITE POWER DISTRIBUTION SYSTEMS A.C. DISTRIBUTION - OPERA TING LIMITING CONDITION FOR OPERATION 3.8.2.1 The following A.C. electrical busses shall be OPERABLE and energized with tie breakers open between redundant busses:

4160 volt Emergency Bus # 2A3 4160 volt Emergency Bus # 2A4 480 volt Emergency Bus # 285 480 volt Emergency Bus # 286 120 volt A.C. Vital Bus# 2RS1 120 volt A.C. Vital Bus# 2RS2 120 volt A.C. Vital Bus# 2RS3 120 volt A.C. Vital Bus# 2RS4 APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

With less than the above complement of A.C. busses OPERABLE, restore the inoperable bus to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

SURVEILLANCE REQUIREMENTS 4.8.2.1 The specified A.C. busses shall be determined OPERABLE with tie breakers open between redundant busses in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated power availability.

ARKANSAS - UNIT 2 3/4 8-6 Amendment No. 315

ELECTRICAL POWER SYSTEMS A.C. DISTRIBUTION - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, the following A.C. electrical busses shall be OPERABLE:

1 -

4160 volt Emergency Bus 1 -

480 volt Emergency Load Center Bus 4 -

480 volt Motor Control Center Susses 2 -

120 volt A.C. Vital Susses APPLICABILITY:

MODES 5 and 6 ACTION:

With less than the above complement of A.C. busses OPERABLE and energized, immediately suspend core alterations, the movement of irradiated fuel assemblies, and any operations involving positive reactivity additions.

SURVEILLANCE REQUIREMENTS 4.8.2.2 The specified A.C. busses shall be determined OPERABLE in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated power availability.

ARKANSAS - UNIT 2 3/4 8-7 Amendment No. 2:2-7, 315

ELECTRICAL POWER SYSTEMS DC SOURCES-OPERATING LIMITING CONDITION FOR OPERATION 3.8.2.3 The Train A and Train B DC electrical power subsystems shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3 and 4.

ACTION:

a.

With one of the required full capacity chargers inoperable:

i.

Restore the battery terminal voltage to greater than or equal to the minimum established float voltage within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , and ii.

Verify battery float current s 2 amps once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

With one DC electrical power subsystem inoperable for reasons other than ACTION 'a' above, restore the inoperable DC electrical power subsystem to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Otherwise, be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . LCO 3.0.4.a is not applicable when entering HOT SHUTDOWN.

SURVEILLANCE REQUIREMENTS 4.8.2.3.1 In accordance with the Surveillance Frequency Control Program by verifying that the battery terminal voltage is greater than or equal to the minimum established float voltage.

ARKANSAS - UNIT 2 3/4 8-8 Amendment No. a4,+a,94,~.~. 315

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 4.8.2.3.2 In accordance with the Surveillance Frequency Control Program by verifying that each battery charger supplies ~ 300 amps at greater than or equal to the minimum established float voltage for ~ 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or, by verifying that each battery charger can recharge the battery to the fully charged state within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months while supplying the largest combined demands of the various continuous steady state loads, after a battery discharge to the bounding design basis event discharge state.

4.8.2.3.3 In accordance with the Surveillance Frequency Control Program by verifying that the battery capacity is adequate to supply, and maintain in OPERABLE status, required emergency loads for the design duty cycle when subjected to a battery service test. This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

However, credit may be taken for unplanned events that satisfy this Surveillance.

The battery performance discharge test required by Surveillance Requirement 4.8.3.6 may be performed in lieu of the battery service test once per 60 months.

ARKANSAS - UNIT 2 3/4 8-9 Amendment No. M,493,~. 315

ELECTRICAL POWER SYSTEMS DC SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.4 As a minimum, the following DC electrical equipment and bus shall be energized and OPERABLE:

1 -

125-volt DC bus, and 1 -

125-volt battery bank and charger supplying the above DC bus.

APPLICABILITY:

MODES 5 and 6.

ACTION:

a.

With the required battery charger inoperable:

i.

Restore battery terminal voltage to greater than or equal to the minimum established float voltage within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , and ii.

Verify battery float current s 2 amps once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b.

With the requirements of ACTION 'a' not met or with the above complement of DC equipment and bus otherwise inoperable, immediately suspend core alterations, the movement of irradiated fuel assemblies, and any operations involving positive reactivity additions.

SURVEILLANCE REQUIREMENTS 4.8.2.4.1 The above required 125-volt D.C. bus shall be determined OPERABLE and energized in accordance with the Surveillance Frequency Control Program by verifying correct breaker alignment and indicated power availability.

4.8.2.4.2 The above required 125-volt battery bank and charger shall be demonstrated OPERABLE per Surveillance Requirements 4.8.2.3.1, 4.8.2.3.2, and 4.8.2.3.3; however, while each of these Surveillance Requirements must be met, Surveillance Requirements 4.8.2.3.2 and 4.8.2.3.3 are not required to be performed.

ARKANSAS - UNIT 2 3/4 8-10 Amendment No. Q4,~.~.315

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.3.1 4.8.3.2 4.8.3.3 4.8.3.4 4.8.3.5 4.8.3.6 In accordance with the Surveillance Frequency Control Program by verifying that each battery float current is s 2 amps. This Surveillance is not required when battery terminal voltage is less than the minimum established float voltage of Surveillance Requirement 4.8.2.3.1.

In accordance with the Surveillance Frequency Control Program by verifying that each battery pilot cell float voltage is;:: 2.07 V.

In accordance with the Surveillance Frequency Control Program by verifying that each battery connected cell electrolyte level is greater than or equal to minimum established design limits.

In accordance with the Surveillance Frequency Control Program by verifying that each battery pilot cell temperature is greater than or equal to minimum established design limits.

In accordance with the Surveillance Frequency Control Program by verifying that each battery connected cell float voltage is ;:: 2.07 V.

In accordance with the Surveillance Frequency Control Program by verifying the battery capacity is ;:: 80% of the manufacturer's rating when subjected to a performance discharge test. This Surveillance shall not be performed in MODE 1, 2, 3, or 4. However, credit may be taken for unplanned events that satisfy this Surveillance. In addition, the performance discharge test shall be performed:

a.

At least once per 12 months when battery shows degradation, or has reached 85% of the expected life with capacity < 100% of manufacturer's rating, and

b.

At least once per 24 months when battery has reached 85% of the expected life with capacity;:: 100% of manufacturer's rating.

ARKANSAS - UNIT 2 3/4 8-12 Amendment No. 287,315

3/4.9 REFUELING OPERATIONS BORON CONCENTRATION LIMITING CONDITION FOR OPERATION 3.9.1 With the reactor vessel head unbolted or removed, the boron concentration of the reactor coolant and the refueling canal shall be maintained uniform and sufficient to ensure that the more restrictive of following reactivity conditions is met:

a.

Either a Kett of 0.95 or less, which includes a 1 % ~k/k conservative allowance for uncertainties, or

b.

A boron concentration of~ 2500 ppm, which includes a 50 ppm conservative allowance for uncertainties.

APPLICABILITY:

MODE 6*.

ACTION:

With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE AL TERA TIONS or positive reactivity changes and initiate and continue boration at ~ 40 gpm of~ 2500 ppm boric acid solution until Kett is reduced to ~ 0.95 or the boron concentration is restored to~ 2500 ppm, whichever is the more restrictive. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.1.1 The more restrictive of the above two reactivity conditions shall be determined prior to:

a.

Removing or unbolting the reactor vessel head, and

b.

Withdrawal of any CEA in excess of 3 feet from its fully inserted position within the reactor pressure vessel.

4.9.1.2 The boron concentration of the reactor coolant and the refueling canal shall be determined by chemical analysis in accordance with the Surveillance Frequency Control Program.

The reactor shall be maintained in MODE 6 when the reactor vessel head is unbolted or removed.

ARKANSAS - UNIT 2 3/4 9-1 Amendment No. ~.499.~.315 Correction Letter dated 10/24/95

REFUELING OPERATIONS INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.9.2 As a minimum, two source range neutron flux monitors shall be operating, each with continuous visual indication in the control room and one with audible indication in the containment and control room.

APPLICABILITY:

MODE 6.

ACTION:

a.

With one of the above required monitors inoperable, immediately suspend all operations involving CORE AL TERA TIONS or positive reactivity changes.

b.

With both of the above required monitors inoperable, determine the boron concentration of the reactor coolant system at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.2 Each source range neutron flux monitor shall be demonstrated OPERABLE by performance of:

a.

A CHANNEL CHECK in accordance with the Surveillance Frequency Control I

Program,

b.

A CHANNEL FUNCTIONAL TEST in accordance with the Surveillance Frequency I

Control Program, and

c.

A CHANNEL FUNCTIONAL TEST within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months prior to the initial start of CORE ALTERATIONS.

ARKANSAS - UNIT 2 3/4 9-2 Amendment No. 315

REFUELING OPERATIONS CONTAINMENT BUILDING PENETRATIONS LIMITING CONDITION FOR OPERATION 3.9.4 The containment building penetrations shall be in the following status:

a.

The equipment door is capable* of being closed,

b.

A minimum of one door in each airlock is capable* of being closed, and

c.

Each penetration providing direct access from the containment atmosphere to the outside atmosphere shall be either:

1.

Closed* by a manual or automatic isolation valve, blind flange, or equivalent, or

2.

Capable* of being closed by an OPERABLE containment purge and exhaust isolation system.

APPLICABILITY:

During CORE ALTERATIONS or movement of irradiated fuel within the containment.

ACTION:

With the requirements of the above specification not satisfied, immediately suspend all operations involving CORE AL TERA TIONS or movement of irradiated fuel in the containment.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.4.1 Each of the above required containment penetrations shall be determined to be in its above required conditions within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months prior to the start of and in accordance with the Surveillance Frequency Control Program during CORE ALTERATIONS or movement of irradiated fuel in the containment.

Penetration flow path(s) providing direct access from the containment atmosphere to the outside atmosphere may be unisolated under administrative controls. Administrative controls shall ensure that appropriate personnel are aware that when containment penetrations, including both personnel airlock doors and/or the equipment door are open, a specific individual(s) is designated and available to close the penetration following a required evacuation of containment, and any obstruction(s) (e.g., cables and hoses) that could prevent closure of an airlock door and/or the equipment door be capable of being quickly removed.

ARKANSAS - UNIT 2 3/4 9-4 Amendment No. 400,~.~.315 Next page is 3/4 9-6

REFUELING OPERATIONS COMMUNICATIONS LIMITING CONDITION FOR OPERATION 3.9.5 Direct communications shall be maintained between the control room and personnel at the refueling station.

APPLICABILITY:

During CORE ALTERATIONS.

ACTION:

When direct communications between the control room and personnel at the refueling station cannot be maintained, suspend all CORE ALTERATIONS. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.5 Direct communications between the control room and personnel at the refueling station shall be demonstrated within one hour prior to the start of and in accordance with the Surveillance Frequency Control Program during CORE ALTERATIONS.

ARKANSAS - UNIT 2 3/4 9-6 Amendment No. 315

REFUELING OPERATIONS CRANE TRAVEL-SPENT FUEL POOL BUILDING LIMITING CONDITION FOR OPERATION 3.9.7 Loads in excess of 2000 pounds shall be prohibited from travel over fuel assemblies in the spent fuel pool.

APPLICABILITY:

With fuel assemblies in the spent fuel pool.

ACTION:

With the requirements of the above specification not satisfied, place the crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9. 7 The crane electrical power disconnect which prevents crane travel over the spent fuel pool shall be verified open under administrative control in accordance with the Surveillance Frequency Control Program, or the crane travel interlock which prevents crane travel over the spent fuel pool shall be demonstrated OPERABLE within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to each use of the crane for lifting loads in excess of 2000 pounds.

ARKANSAS - UNIT 2 3/4 9-8 Amendment No. 315

REFUELING OPERATIONS SHUTDOWN COOLING AND COOLANT CIRCULATION SHUTDOWN COOLING - ONE LOOP LIMITING CONDITION FOR OPERATION 3.9.8.1 At least one shutdown cooling loop shall be in operation.

APPLICABILITY:

MODE 6.

ACTION:

a.

With less than one shutdown cooling loop in operation, except as provided in b.

below, suspend all operations involving an increase in the reactor decay heat load or a reduction in boron concentration of the Reactor Coolant System. Close all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

b.

The shutdown cooling loop may be removed from operation for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period during the performance of CORE ALTERATIONS.

c.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.8.1 A shutdown cooling loop shall be determined to be in operation and circulating reactor coolant at a flow rate of 2'. 2000 gpm in accordance with the Surveillance Frequency Control Program.

ARKANSAS-UNIT 2 3/4 9-9 Amendment No. 29,404,315

REFUELING OPERATIONS WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.9 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated within the reactor pressure vessel.

APPLICABILITY:

During movement of fuel assemblies or CEAs within the reactor pressure vessel while in MODE 6, except during latching and unlatching of CEAs.

ACTION:

With the requirements of the above specification not satisfied, suspend all operations involving movement of fuel assemblies or CEAs within the pressure vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.9 The water level shall be determined to be at least its minimum required depth within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to the start of and in accordance with the Surveillance Frequency Control Program thereafter during movement of fuel assemblies or CEAs.

ARKANSAS - UNIT 2 3/4 9-10 Amendment No. 49+, 315

REFUELING OPERATIONS SPENT FUEL POOL WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.10 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the storage racks.

APPLICABILITY:

Whenever irradiated fuel assemblies are in the spent fuel pool.

ACTION:

With the requirement of the specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the spent fuel pool areas and restore the water level to within its limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.10 The water level in the spent fuel pool shall be determined to be at least its minimum required depth in accordance with the Surveillance Frequency Control Program when irradiated fuel assemblies are in the spent fuel pool.

ARKANSAS - UNIT 2 3/4 9-11 Amendment No.~. 315 Next Page is 3/4 9-14

REFUELING OPERATIONS FUEL STORAGE LIMITING CONDITION FOR OPERATION 3.9.12.a Storage in the spent fuel pool shall be restricted to fuel assemblies having initial enrichment less than or equal to 4.95 w/o U-235. The provisions of Specification 3.0.3 are not applicable.

3.9.12.b Storage in the spent fuel pool shall be further restricted by the limits specified in Table 3.9-1. The provisions of Specification 3.0.3 are not applicable.

3.9.12.c The boron concentration in the spent fuel pool shall be maintained (at all times) at greater than 2000 parts per million.

APPLICABILITY:

During storage of fuel in the spent fuel pool ACTION:

Suspend all actions involving the movement of fuel in the spent fuel pool if it is determined a fuel assembly has been placed in an incorrect location until such time as the correct storage location is determined. Move the assembly to its correct location before resumption of any other fuel movement.

Suspend all actions involving the movement of fuel in the spent fuel pool if it is determined the pool boron concentration is less than 2001 ppm, until such time as the boron concentration is increased to 2001 ppm or greater.

SURVEILLANCE REQUIREMENTS 4.9.12.a Verify all fuel assemblies to be placed in the spent fuel pool have an initial enrichment of less than or equal to 4.95 w/o U-235 by checking the assemblies' design documentation.

4.9.12.b Verify all fuel assemblies to be placed in the spent fuel pool are within the limits of Table 3.9-1 by checking the assemblies' design and burnup documentation.

4.9.12.c Verify in accordance with the Surveillance Frequency Control Program the spent fuel pool boron concentration is greater than 2000 ppm.

4.9.12.d Verify Metamic properties are in accordance with, and are maintained within the limits of, the Metamic Coupon Sampling Program.

ARKANSAS - UNIT 2 3/4 9-14 Amendment No. ~.4+8.~.~.~.

~.315

3/4.10 SPECIAL TEST EXCEPTIONS SHUTDOWN MARGIN LIMITING CONDITION FOR OPERATION 3.10.1 The SHUTDOWN MARGIN requirement of Specification 3.1.1.1 may be suspended for measurement of CEA worth and shutdown margin provided reactivity equivalent to at least the highest estimated CEA worth is available for trip insertion from OPERABLE CEA(s).

APPLICABILITY:

MODE 2.

ACTION:

a.

With any CEA not fully inserted and with less than the above reactivity equivalent available for trip insertion, immediately initiate and continue boration at ~ 40 gpm of 2500 ppm boric acid solution or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

b.

With all CEAs inserted and the reactor subcritical by less than the above reactivity equivalent, immediately initiate and continue boration at ~ 40 gpm of 2500 ppm boric acid solution or its equivalent until the SHUTDOWN MARGIN required by Specification 3.1.1.1 is restored.

SURVEILLANCE REQUIREMENTS 4.10.1.1 The position of each CEA required either partially or fully withdrawn shall be determined in accordance with the Surveillance Frequency Control Program.

4.10.1.2 Each CEA not fully inserted shall be demonstrated capable of full insertion when tripped from at least the 50% withdrawn position within 7 days prior to reducing the SHUTDOWN MARGIN to less than the limits of Specification 3.1.1.1.

ARKANSAS - UNIT 2 3/4 10-1 Amendment No. +e,~,499.315 Correction Letter dated 1 Ot24tQ5

SPECIAL TEST EXCEPTIONS GROUP HEIGHT, INSERTION AND POWER DISTRIBUTION LIMITS LIMITING CONDITION FOR OPERATION 3.10.2 The group height, insertion and power distribution limits of Specifications 3.1.1.4, 3.1.3.1, 3.1.3.5, 3.1.3.6, 3.2.2, 3.2.3, 3.2. 7 and the Minimum Channels OPERABLE requirement of Functional Unit 14 of Table 3.3-1 may be suspended during the performance of PHYSICS TESTS provided:

a.

The THERMAL POWER is restricted to the test power plateau which shall not exceed 85% of RATED THERMAL POWER, and

b.

The linear heat rate limit shall be maintained by either:

1.

Maintaining COLSS calculated core power less than or equal to COLSS calculated core power operating limit based on linear heat rate (when COLSS is in service); or

2.

Operating within the region of acceptable operation as specified in the CORE OPERATING LIMITS REPORT using any operable CPC channel (when COLSS is out of service.)

APPLICABILITY:

During startup and PHYSICS TESTS.

ACTION:

With any of the above limits being exceeded while any of the above requirements are suspended, either:

a.

Reduce THERMAL POWER sufficiently to satisfy the requirements of the above Specification, or

b.

Be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.10.2.1 The THERMAL POWER shall be determined in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS in which any of the above requirements are suspended and shall be verified to be within the test power plateau.

4.10.2.2 The linear heat rate shall be determined to be within its limits during PHYSICS TESTS above 5% of RA TED THERMAL POWER in which any of the above requirements are suspended.

ARKANSAS - UNIT 2 3/4 10-2 Amendment No. 3+,4-0a,4-a+,499,~,315 Correotion Letter dated 10/24195

SPECIAL TEST EXCEPTIONS REACTOR COOLANT LOOPS LIMITING CONDITION FOR OPERATION 3.10.3 The limitations of Specification 3.4.1.1 and noted requirements of Tables 2.2-1 and 3.3-1 may be suspended during the performance of startup and PHYSICS TESTS, provided:

a.

The THERMAL POWER does not exceed 5% of RA TED THERMAL POWER, and

b.

The reactor trip setpoints of the OPERABLE power level channels are set at ::;; 20%

of RA TED THERMAL POWER APPLICABILITY:

During startup and PHYSICS TESTS.

ACTION:

With the THERMAL POWER > 5% of RATED THERMAL POWER, immediately trip the reactor.

SURVEILLANCE REQUIREMENTS 4.10.3.1 The THERMAL POWER shall be determined to be ::;; 5% of RATED THERMAL POWER in accordance with the Surveillance Frequency Control Program during startup and PHYSICS TESTS.

4.10.3.2 Each wide range logarithmic and power level neutron flux monitoring channel shall be subjected to a CHANNEL FUNCTIONAL TEST within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months prior to initiating startup or PHYSICS TESTS.

ARKANSAS - UNIT 2 3/4 10-3 Amendment No. 449,499,315

SPECIAL TEST EXCEPTIONS CENTER CEA MISALIGNMENT LIMITING CONDITION FOR OPERATION 3.10.4 The requirements of Specifications 3.1.3.1 and 3.1.3.6 may be suspended during the performance of PHYSICS TESTS to determine the isothermal temperature coefficient, moderator temperature coefficient and power coefficient provided:

a.

Only the center CEA (CEA #1) is misaligned, and

b.

The limits of Specification 3.2.1 are maintained and determined as specified in Specification 4.10.4.2 below.

APPLICABILITY:

MODES 1 and 2.

ACTION:

With any of the limits of Specification 3.2.1 being exceeded while the requirements of Specifications 3.1.3.1 and 3.1.3.6 are suspended, either:

a.

Reduce THERMAL POWER sufficiently to satisfy the requirements of Specification 3.2.1, or

b.

Be in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.10.4.1 The THERMAL POWER shall be determined in accordance with the Surveillance Frequency Control Program during PHYSICS TESTS in which the requirements of Specifications 3.1.3.1 and/or 3.1.3.6 are suspended and shall be verified to be within the test power plateau.

4.10.4.2 The linear heat rate shall be determined to be within the limits of Specification 3.2.1 by monitoring it continuously with the incore detection system during PHYSICS TESTS above 5% of RATED THERMAL POWER in which the requirements of Specifications 3.1.3.1 and/or 3.1.3.6 are suspended.

ARKANSAS - UNIT 2 3/4 10-4 Amendment No. ~.315

SPECIAL TEST EXCEPTIONS MINIMUM TEMPERATURE FOR CRITICALITY LIMITING CONDITION FOR OPERATION 3.10.5 The minimum temperature for criticality limits of Specification 3.1.1.5 may be suspended during low temperature PHYSICS TESTS provided:

a.

The THERMAL POWER does not exceed 5% of RA TED THERMAL POWER,

b.

The reactor trip setpoints on the OPERABLE Linear Power Level - High neutron flux monitoring channels are set at :,;; 20% of RATED THERMAL POWER, and

c.

The Reactor Coolant System temperature and pressure relationship is maintained within the acceptable region of operation shown on Figure 3.4-2.

APPLICABILITY:

During startup and PHYSICS TESTS.

ACTION:

a.

With the THERMAL POWER > 5 percent of RA TED THERMAL POWER, immediately open the reactor trip breakers.

b.

With the Reactor Coolant System temperature and pressure relationship within the region of unacceptable operation on Figure 3.4-2, immediately open the reactor trip breakers and restore the temperature-pressure relationship to within its limit within 30 minutes; perform the engineering evaluation required by Specification 3.4.9.1 prior to the next reactor criticality.

SURVEILLANCE REQUIREMENTS 4.10.5.1 The Reactor Coolant System temperature and pressure relationship shall be verified to be within the acceptable region for operation of Figure 3.4-2 in accordance with the Surveillance Frequency Control Program.

4.10.5.2 The THERMAL POWER shall be determined to be::;; 5% of RATED THERMAL POWER in accordance with the Surveillance Frequency Control Program.

4.10.5.3 Each Logarithmic Power Level and Linear Power Level channel shall be subjected to a CHANNEL FUNCTIONAL TEST within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months prior to initiating low temperature PHYSICS TESTS.

ARKANSAS - UNIT 2 3/4 10-5 Amendment No. 315

3/4.11 RADIOACTIVE EFFLUENTS 3/4.11.1 LIQUID HOLDUP TANKS*

LIMITING CONDITION FOR OPERATION 3.11.1 The quantity of radioactive material contained in each unprotected outside temporary radioactive liquid storage tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble gases.

APPLICABILITY:

At all times.

ACTION:

a.

With the quantity of radioactive material exceeding the above limit, immediately suspend all additions of radioactive material to the affected tank and within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months reduce the tank contents to within the limit and describe the events leading to the condition in the next Radioactive Effluents Release Report pursuant to Specification 6.9.3.

b.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.1 The quantity of radioactive material contained in each unprotected outside temporary radioactive liquid storage tank shall be determined to be within the above limit by analyzing a representative sample of the contents of the tank in accordance with the Surveillance Frequency Control Program when radioactive materials are being added to the tank.

Tanks included in this specification are those outdoor temporary tanks that 1) are not surrounded by liners, dikes, or walls capable of holding the tank contents, and 2) do not have overflows and surrounding area drains connected to the liquid radwaste treatment system.

ARKANSAS - UNIT 2 3/4 11-1 Amendment No. 00,4d4,44Q,493,315

RADIOACTIVE EFFLUENTS 3/4.11.2 GAS STORAGE TANKS LIMITING CONDITION FOR OPERATION 3.11.2 The quantity of radioactivity contained in each gas storage tank shall be limited to less than or equal to 82,400 curies noble gases (considered as Xe-133).

APPLICABILITY:

At all times.

ACTION:

a.

With the quantity of radioactive material in any gas storage tank exceeding the above limit, immediately suspend all additions of radioactive material to the tank and within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months reduce the tank contents to within the limit and describe the events leading to the condition in the next Radioactive Effluent Release Report pursuant to Specification 6.9.3.

b.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.2 The quantity of radioactive material contained in each gas storage tank shall be determined to be within the above limit in accordance with the Surveillance Frequency Control Program when radioactive materials are being added to the tank and the reactor coolant activity exceeds the limits of Specification 3.4.8.

ARKANSAS-UNIT 2 3/4 11-2 Amendment No. 00,434,493,~. 315

ADMINISTRATIVE CONTROLS 6.5 PROGRAMS AND MANUALS 6.5.2 Primary Coolant Sources Outside Containment 6.5.3 6.5.4 This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The program shall include the following:

c.

Preventive maintenance and periodic visual inspection requirements; and

d.

Integrated leak test requirements for each system at a Frequency in accordance with the Surveillance Frequency Control Program. The provisions of Surveillance Requirements 4.0.2 are applicable.

Iodine Monitoring This program provides controls that ensure the capability to accurately determine the airborne iodine concentration under accident conditions. The program shall include the following:

a.

Training of personnel;

b.

Procedures for monitoring; and

c.

Provisions for maintenance of sampling and analysis equipment.

Radioactive Effluent Controls Program This program conforms with 1 O CFR 50.36a for the control of radioactive effluents and for maintaining the doses to MEMBERS OF THE PUBLIC from radioactive effluents as low as reasonably achievable. The program shall be contained in the ODCM, shall be implemented by procedures, and shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements:

a.

Limitations on the functional capability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the ODCM;

b.

Limitations on the concentrations of radioactive material released in liquid effluents to UNRESTRICTED AREAS, conforming to 10 CFR 20, Appendix B, Table 11, Column 2;

c.

Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the ODCM;

d.

Limitations on the annual and quarterly doses or dose commitment to a MEMBER OF THE PUBLIC from radioactive materials in liquid effluents released from each unit to UNRESTRICTED AREAS, conforming to 1 O CFR 50, Appendix I; ARKANSAS - UNIT 2 6-5 Amendment No. 2-aa, 315

ADMINISTRATIVE CONTROLS 6.5.12 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Ventilation System (CREVS), CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (OBA) conditions without personnel receiving radiation exposures in excess of 5 rem Total Effective Dose Equivalent (TEDE) for the duration of the accident. The program shall include the following elements:

a.

The definition of the CRE and the CRE boundary.

b.

Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.

c.

Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"

Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0.

d.

Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the CREVS, operating at the flow rate required by the VFTP, at a Frequency in accordance with the Surveillance Frequency Control Program. The results shall be trended and used as part of the assessment of the CRE boundary.

e.

The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of OBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.

f.

The provisions of Specification 4.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.

ARKANSAS-UNIT 2 6-16 Amendment No. ~.~.~.315

ADMINISTRATIVE CONTROLS 6.5.13 Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a.

Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has:

1.

an API gravity or an absolute specific gravity within limits,

2.

a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and

3.

water and sediment within limits;

b.

Within 31 days following addition of new fuel oil to storage tanks, verify that the properties of the new fuel oil, other than those addressed in a. above, are within limits for ASTM 2D fuel oil;

c.

Total particulate concentration of the fuel oil is::,; 10 mg/I when tested based on ASTM D-2276, Method A-2 or A-3 at a Frequency in accordance with the Surveillance Frequency Control Program; and

d.

The provisions of SR 4.0.2 and SR 4.0.3 are applicable to the Diesel Fuel Oil Testing Program surveillance frequencies.

6.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a.

Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b.

Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1.

A change in the TS incorporated in the license or

2.

A change to the updated SAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

c.

The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the SAR.

d.

Proposed changes that do not meet the criteria of 6.5.14b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e).

ARKANSAS - UNIT 2 6-17 Amendment No. 2aa.~.~. 315

ADMINISTRATIVE CONTROLS 6.5.17 Metamic Coupon Sampling Program A coupon surveillance program will be implemented to maintain surveillance of the Metamic absorber material under the radiation, chemical, and thermal environment of the SFP. The purpose of the program is to establish the following:

Coupons will be examined on a two year basis for the first three intervals with the first coupon retrieved for inspection being on or before October 31, 2009 and thereafter at increasing intervals over the service life of the inserts.

Measurements to be performed at each inspection will be as follows:

a.

Physical observations of the surface appearance to detect pitting, swelling or other degradation,

b.

Length, width, and thickness measurements to monitor for bulging and swelling

c.

Weight and density to monitor for material loss, and

d.

Neutron attenuation to confirm the 8-10 concentration or destructive chemical testing to determine the boron content.

The provisions of SR 4.0.2 are applicable to the Metamic Coupon Sampling Program.

The provisions of SR 4.0.3 are not applicable to the Metamic Coupon Sampling Program.

6.5.18 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a.

The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.

b.

Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c.

The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

ARKANSAS - UNIT 2 6-18a Amendment No. 2-73, 315

1.0 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 315 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-6 INTRODUCTION ENTERGY OPERATIONS. INC.

ARKANSAS NUCLEAR ONE. UNIT 2 DOCKET NO. 50-368 By application dated February 6, 2018 (Reference 1 ), as supplemented by letters dated March 26 (Reference 2), September 7 (Reference 3), and November 16, 2018 (Reference 4),

Entergy Operations, Inc. (Entergy, the licensee) requested changes to the Technical Specifications (TSs) for Arkansas Nuclear One, Unit 2 (AN0-2), which are contained in Appendix A of Renewed Facility Operating License No. NPF-6.

The proposed changes would revise the AN0-2 TSs to adopt the U.S. Nuclear Regulatory Commission (NRC)-approved Technical Specifications Task Force (TSTF) Standard Technical Specifications (STS) Change Traveler TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - RITSTF [Risk-Informed TSTF] Initiative 5b" (Reference 5), for AN0-2.

The supplemental letters dated September 7 and November 16, 2018, provided additional information that clarified the application, did not expand the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register (FR) on June 5, 2018 (83 FR 26102).

2.0

2.1 REGULATORY EVALUATION

Description of the Proposed Changes The licensee proposed to modify the AN0-2 TSs by relocating certain surveillance frequencies to a licensee-controlled program (i.e., the Surveillance Frequency Control Program (SFCP)) in accordance with Nuclear Energy Institute (NEI) 04-10, Revision 1 (Reference 6). The licensee stated that the proposed change is consistent with the adoption of NRC-approved TSTF-425, Revision 3. When implemented, TSTF-425 relocates most periodic frequencies of TS surveillances to the SFCP, and provides requirements for the new SFCP in the Administrative Controls section of the TSs. All surveillance frequencies can be relocated except the following:

Frequencies that reference other approved programs for the specific interval, such as the lnservice Testing Program or the Primary Containment Leakage Rate Testing Program; Frequencies that are purely event-driven (e.g., "each time the control rod is withdrawn to the 'full out' position");

Frequencies that are event-driven, but have a time component for performing the surveillance on a one-time basis once the event occurs (e.g., "within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after thermal power reaching~ [greater than or equal to] 95% RTP [rated thermal power]"); and Frequencies that are related to specific conditions (e.g., battery degradation, age and capacity) or conditions for the performance of a surveillance requirement (e.g., "drywell to suppression chamber differential pressure decrease").

The licensee proposed to relocate certain surveillance frequencies from the following TS sections to the SFCP:

4.1 Reactivity Control Systems 4.2 Power Distribution Limits 4.3 Instrumentation 4.4 Reactor Coolant System 4.5 Emergency Core Cooling Systems 4.6 Containment Systems

4. 7 Plant Systems 4.8 Electrical Power Systems 4.9 Refueling Operations 4.10 Special Test Exceptions 4.11 Radioactive Effluents 6.5 Programs and Manuals The licensee proposed to add the SFCP to AN0-2 TS, Section 6.0, "Administrative Controls."

Proposed TS 6.5.18, "Surveillance Frequency Control Program," describes the requirements for the SFCP to control changes to the relocated surveillance frequencies to ensure that surveillances are performed at intervals to ensure that limiting conditions for operation (LCOs) are met. The TS Bases for each affected surveillance would be revised to state that the surveillance frequency is controlled under the SFCP and were included in the application for information only. The proposed changes to the Administrative Controls section of the TSs include a specific reference to NEI 04-10, Revision 1, as the basis for making any changes to the surveillance frequencies when they are relocated out of the TSs.

In a letter dated September 19, 2007 (Reference 7), the NRC staff approved Topical Report NEI 04-10, Revision 1, as an acceptable methodology for referencing in licensing actions to the extent specified and under the limitations delineated in NEI 04-10, Revision 1, and the safety evaluation (SE) providing the basis for NRC acceptance of NEI 04-10, Revision 1.

The licensee proposed other changes and deviations from TSTF-425, which are discussed in Section 3.3 of this SE.

2.2 Applicable Commission Policy Statements In the "Final Policy Statement: Technical Specifications Improvements for Nuclear Power Reactors," dated July 22, 1993 (58 FR 39132), the NRC addressed the use of probabilistic safety analysis (PSA, currently referred to as probabilistic risk assessment or PRA) in STS. In this 1993 publication, the NRC states, in part:

The Commission believes that it would be inappropriate at this time to allow requirements which meet one or more of the first three criteria [of Title 10 of the Code of Federal Regulations (10 CFR), Section 50.36]1 to be deleted from Technical Specifications based solely on PSA (Criterion 4). However, if the results of PSA indicate that Technical Specifications can be relaxed or removed, a deterministic review will be performed....

The Commission Policy in this regard is consistent with its Policy Statement on "Safety Goals for the Operation of Nuclear Power Plants," 51 FR 30028, published on August 21, 1986. The Policy Statement on Safety Goals states in part, "... probabilistic results should also be reasonably balanced and supported through use of deterministic arguments. In this way, judgments can be made...

about the degree of confidence to be given these [probabilistic]2 estimates and assumptions. This is a key part of the process of determining the degree of regulatory conservatism that may be warranted for particular decisions. This defense-in-depth approach is expected to continue to ensure the protection of public health and safety."...

The Commission will continue to use PSA,.consistent with its policy on Safety Goals, as a tool in evaluating specific line-item improvements to Technical Specifications, new requirements, and industry proposals for risk-based Technical Specification changes.

Approximately 2 years later the NRC provided additional detail concerning the use of PRA in the "Final Policy Statement: Use of Probabilistic Risk Assessment Methods in Nuclear Regulatory Activities," dated August 16, 1995 (60 FR 42622). In this publication, the NRC states, in part:

The Commission believes that an overall policy on the use of PRA methods in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that would promote regulatory stability and efficiency. In addition, the Commission believes that the use of PRA technology in NRC regulatory activities should be increased to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach....

1 This clarification is not part of the original policy statement.

2 The Federal Register Notice 58 FR 39135 (Alteration in Original) explains the brackets.

PRA addresses a broad spectrum of initiating events by assessing the event frequency. Mitigating system reliability is then assessed, including the potential for multiple and common cause failures. The treatment therefore goes beyond the single failure requirements in the deterministic approach. The probabilistic approach to regulation is, therefore, considered an extension and enhancement of traditional regulation by considering risk in a more coherent and complete manner....

Therefore, the Commission believes that an overall policy on the use of PRA in nuclear regulatory activities should be established so that the many potential applications of PRA can be implemented in a consistent and predictable manner that promotes regulatory stability and efficiency. This policy statement sets forth the Commission's intention to encourage the use of PRA and to expand the scope of PRA applications in all nuclear regulatory matters to the extent supported by the state-of-the-art in terms of methods and data....

Therefore, the Commission adopts the following policy statement regarding the expanded NRC use of PRA:

(1) The use of PRA technology should be increased in all regulatory matters to the extent supported by the state-of-the-art in PRA methods and data and in a manner that complements the NRC's deterministic approach and supports the NRC's traditional defense-in-depth philosophy.

(2) PRA and associated analyses (e.g., sensitivity studies, uncertainty analyses, and importance measures) should be used in regulatory matters, where practical within the bounds of the state-of-the-art, to reduce unnecessary conservatism associated with current regulatory requirements, regulatory guides, license commitments, and staff practices. Where appropriate, PRA should be used to support the proposal for additional regulatory requirements in accordance with 10 CFR 50.109 (Backfit Rule). Appropriate procedures for including PRA in the process for changing regulatory requirements should be developed and followed. It is, of course, understood that the intent of this policy is that existing rules and regulations shall be complied with unless these rules and regulations are revised.

(3) PRA evaluations in support of regulatory decisions should be as realistic as practicable and appropriate supporting data should be publicly available for review.

(4) The Commission's safety goals for nuclear power plants and subsidiary numerical objectives are to be used with appropriate consideration of uncertainties in making regulatory judgments on the need for proposing and backfitting new generic requirements on nuclear power plant licensees.

2.3 Applicable Regulations In 10 CFR 50.36, "Technical specifications," the NRC established its regulatory requirements related to the content of TSs. Pursuant to 1 O CFR 50.36, TSs are required to include items in the following five specific categories related to station operation: (1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) surveillance requirements (SRs);

(4) design features; and (5) administrative controls. These categories will remain in the AN0-2 TSs.

Paragraph 50.36(c)(3) of 10 CFR states, "[s]urveillance requirements 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 limiting conditions for operation will be met." The FR notice published on July 6, 2009 (74 FR 31996),

which announced the availability of TSTF-425, Revision 3, states that the addition of the SFCP to the TSs provides the necessary administrative controls to require that surveillances frequencies relocated to the SFCP are conducted at a frequency 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. The FR notice also states that changes to surveillance frequencies in the SFCP are made using the methodology contained in NEI 04-10, Revision 1, including qualitative considerations, results of risk analyses, sensitivity studies and any bounding analyses, and recommended monitoring of structures, systems, and components (SSCs), and are required to be documented.

Existing regulatory requirements, such as 10 CFR 50.65, "Requirements for monitoring the effectiveness of maintenance at nuclear power plants" (i.e., the Maintenance Rule), and 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," require licensee monitoring of surveillance test failures and implementing corrective actions to address such failures. Such failures can result in the licensee increasing the frequency of a surveillance test. In addition, by having the TSs require that changes to the frequencies listed in the SFCP be made in accordance with NEI 04-10, Revision 1, the licensee will be required to monitor the performance of SSCs for which surveillance frequencies are decreased to assure reduced testing does not adversely impact the SSCs.

2.4 Applicable NRC Regulatory Guides and Review Plans Regulatory Guide (RG) 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 3, dated January 2018 (Reference 8), describes an acceptable risk-informed approach for assessing the nature and impact of proposed permanent licensing-basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

RG 1.177, Revision 1, "An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications," dated May 2011 (Reference 9), describes an acceptable risk-informed approach specifically for assessing proposed TS changes.

RG 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," dated March 2009 (Reference 10),

describes an acceptable approach for determining whether the quality of the PRA, in total or the parts that are used to support an application, is sufficient to provide confidence in the results, such that the PRA can be used in regulatory decisionmaking for light-water reactors (LWRs).

NUREG-0800, "Standard Review Plan [SRP] for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition," Chapter 19, Section 19.2, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance," dated June 2007 (Reference 11 ), provides general guidance for evaluating the technical basis for proposed risk-informed changes. Guidance on evaluating PRA technical adequacy is provided in SRP, Chapter 19, Section 19.1, Revision 3, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load," dated September 2012 (Reference 12). More specific guidance related to risk-informed TS changes is provided in SRP, Chapter 16, Section 16. 1, Revision 1, "Risk-Informed Decision Making: Technical Specifications" (Reference 13), which includes changes to surveillance test intervals (STls) (i.e., surveillance frequencies) as part of risk-informed decisionmaking. Section 19.2 of the SRP references the same criteria as RG 1.17 4, Revision 3, and RG 1.177, Revision 1, and states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

The proposed change meets the current regulations, unless it is explicitly related to a requested exemption or rule change; The proposed change is consistent with the defense-in-depth philosophy; The proposed change maintains sufficient safety margins; When proposed changes result in an increase in risk associated with core damage frequency (CDF) or large early release frequency (LERF), the increases should be small and consistent with the intent of the Commission's Safety Goal Policy Statement; The impact of the proposed change should be monitored using performance measurement strategies.

The regulatory requirements in 1 O CFR 50.65 and 1 O CFR Part 50, Appendix B, Criterion XV~.

and the performance monitoring required by NEI 04-10, Revision 1, ensure that surveillance frequencies are sufficient to assure that the requirements of 10 CFR 50.36 are satisfied and that any performance deficiencies will be identified and appropriate corrective actions taken.

NUREG-1432 "Standard Technical Specifications, Combustion Engineering Plants," Volume 1, Specifications and Volume 2, Bases, Revision 4.0 (Reference 14), contain the improved STS for Combustion Engineering plants. The improved STS were developed based on the criteria in the Final Commission Policy Statement of Technical Specifications Improvements for Nuclear Power Reactors, dated July 22, 1993 (58 FR 39132), which was subsequently codified by changes to 10 CFR 50.36 (60 FR 36953).

3.0 TECHNICAL EVALUATION

The licensee's adoption of TSTF-425, Revision 3, provides for administrative relocation of applicable surveillance frequencies, and provides for the addition of the SFCP to the Administrative Controls section of TSs. The changes to the Administrative Controls section of the TSs will also require the application of NEI 04-10, Revision 1, for any changes to surveillance frequencies within the SFCP. The licensee's application for the changes described in TSTF-425, Revision 3, included documentation regarding the PRA technical adequacy, consistent with the requirements of RG 1.200, Revision 2. NEI 04-10, Revision 1, states that PRA methods are used with plant performance data and other considerations to identify and justify modifications to the surveillance frequencies of equipment at nuclear power plants. This is consistent with guidance provided in RG 1.17 4, Revision 3, and RG 1.177, Revision 1, in support of changes to STls.

3.1 Key Safety Principles RG 1.177, Revision 1 (Reference 9), identifies five key safety principles required for risk-informed changes to TSs. Each of these principles is addressed by NEI 04-10, Revision 1.

Sections 3.1.1 through 3.1.5 of this SE provide a discussion of the five principles, including the NRC staff's evaluation of how the licensee's license amendment request (LAR) satisfies each principle.

3.1.1 The Proposed Change Meets Current Regulations Paragraph 50.36(c)(3) of 10 CFR requires that TSs include surveillances, which are "requirements relating to test, calibration, or inspection to assure that necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met." The licensee is required by its TSs to perform surveillance tests, calibration, or inspection on specific safety-related equipment (e.g.,

reactivity control, power distribution, electrical, and instrumentation) to verify system operability.

Surveillance frequencies are based primarily upon deterministic methods, such as engineering judgment, operating experience, and manufacturer's recommendations. The licensee's use of NRG-approved methodologies identified in NEI 04-10, Revision 1, provides a way to establish risk-informed surveillance frequencies that complements the deterministic approach and supports the NRC's traditional defense-in-depth philosophy.

The SRs remain in the TSs, as required by 10 CFR 50.36(c)(3). This change is analogous with other NRG-approved TS changes in which the SRs are retained in the TSs, but the related surveillance frequencies are relocated to licensee-controlled documents, such as surveillances performed in accordance with the lnservice Testing Program and the Primary Containment Leakage Rate Testing Program. Thus, this proposed change complies with 10 CFR 50.36(c)(3) by retaining the requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components for operation must be met.

The regulatory requirements in 10 CFR 50.65 and 10 CFR Part 50, Appendix B, and the monitoring required by NEI 04-10, Revision 1, ensure that surveillance frequencies are sufficient to assure that the requirements of 10 CFR 50.36 are satisfied, and that any performance deficiencies will be identified and appropriate corrective actions taken. The licensee's SFCP ensures that SRs specified in the TSs are performed at intervals sufficient to assure that the above regulatory requirements are met. Based on the foregoing, the NRC staff concludes that the proposed change meets the first key safety principle of RG 1.177, Revision 1, by complying with current regulations.

3.1.2 The Proposed Change Is Consistent With the Defense-in-Depth Philosophy The defense-in-depth philosophy (i.e., the second key safety principle of RG 1.177, Revision 1 ),

is maintained if:

A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation; Over-reliance on programmatic activities to compensate for weaknesses in plant design is avoided; System redundancy, independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers). (Because the scope of the proposed methodology is limited to revision of surveillance frequencies, the redundancy, independence, and diversity of plant systems are not impacted.);

Defenses against potential common cause failures (CCFs) are preserved, and the potential for the introduction of new CCF mechanisms is assessed; Independence of barriers is not degraded; Defenses against human errors are preserved; The intent of the General Design Criteria in 10 CFR Part 50, Appendix A, is maintained.

The changes to the Administrative Controls section of the TSs will require the application of NEI 04-10, Revision 1, for any changes to surveillance frequencies within the SFCP.

NEI 04-10, Revision 1, uses both the CDF and the LERF metrics to evaluate the impact of proposed changes to surveillance frequencies. In accordance with RG 1.174, Revision 3, and RG 1.177, Revision 1, changes to the CDF and LERF are evaluated using a comprehensive risk analysis, which assesses the impact of proposed changes, including contributions from human errors and CCFs. Defense-in-depth is also included in the methodology explicitly as a qualitative consideration outside of the risk analysis, as is the potential impact on detection of component degradation that could lead to an increased likelihood of CCFs. The NRC staff concludes that both the quantitative risk analysis and the qualitative considerations provide reasonable assurance that defense-in-depth is maintained to ensure protection of public health and safety, satisfying the second key safety principle of RG 1.177, Revision 1.

3.1.3 The Proposed Change Maintains Sufficient Safety Margins The engineering evaluation that will be conducted by the licensee under the SFCP when frequencies are revised will assess the impact of the proposed frequency change to assure that sufficient safety margins are maintained. The guidelines used for making that assessment will include ensuring the proposed surveillance test frequency change is not in conflict with approved industry codes and standards or adversely affects any assumptions or inputs to the safety analysis; or, if such inputs are affected, justification is provided to ensure sufficient safety margin will continue to exist.

The design, operation, testing methods, and acceptance criteria for SSCs, specified in applicable codes and standards (or alternatives approved for use by the NRC), will continue to be met as described in the plant licensing bases (including the Safety Analysis Report and the TS Bases), because these are not affected by changes to the surveillance frequencies.

Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. On this basis, the NRC staff concludes that safety margins are maintained by the proposed methodology and, therefore, the third key safety principle of RG 1.177, Revision 1, is satisfied.

3.1.4 When Proposed Changes Result in an Increase in Core Damage Frequency or Risk, the Increases Should be Small and Consistent with the Intent of the Commission's Safety Goal Policy Statement The guidance in RG 1.177, Revision 1, provides a framework for evaluating the risk impact of proposed changes to surveillance frequencies, which requires the identification of the risk contribution from impacted surveillances, determination of the risk impact from the change to the proposed surveillance frequency, and performance of sensitivity and uncertainty evaluations. The changes to the Administrative Controls section of the TSs will require application of NEI 04-10, Revision 1, in the SFCP. The guidance in NEI 04-10, Revision 1, satisfies the intent of RG 1.177, Revision 1, guidance for evaluation of the change in risk, and for assuring that such changes are small by providing the technical methodology to support risk-informed TSs for control of surveillance frequencies.

3.1.4.1 Quality of the PRA The quality of the licensee's PRA must be commensurate with the safety significance of the proposed TS change and the role the PRA plays in justifying the change. That is, the greater the change in risk or the greater the uncertainty in that risk from the requested TS change, or both, the more rigor that must go into ensuring the quality of the PRA.

The guidance in RG 1.200 provides regulatory guidance for assessing the technical adequacy of a PRA. The current revision (i.e., Revision 2) of this RG endorses, with clarifications and qualifications, the use of the following:

1.

American Society of Mechanical Engineers (ASME)/American Nuclear Society (ANS) RA-Sa-2009, "Addenda to ASME RA-S-2008 Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications" (hereafter, referred to as the ASME/ANS PRA Standard)

(Reference 15);

2.

NEI 00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance" (Reference 16); and

3.

NEI 05-04, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard (Reference 17)."

The licensee performed an assessment of the PRA models used to support the SFCP using the guidance of RG 1.200, Revision 2, to ensure that the PRA models are capable of determining the change in risk due to changes to surveillance frequencies of SSCs, using plant-specific data and models. Capability Category (CC) II of the NRG-endorsed PRA standard is the target capability level for supporting requirements for the internal events PRA for this application. Any identified deficiencies to those requirements are further assessed to determine any impacts to proposed decreases to surveillance frequencies, including the use of sensitivity studies where appropriate, in accordance with NEI 04-10, Revision 1.

Internal Events As discussed in Section 3.2.2, "Peer Review Facts and Observations (F&Os) of Attachment 2; "Documentation of PRA Technical Adequacy," to the LAR dated February 6, 2018 (Reference 1 ), the licensee described the history of its peer review for the internal events PRA.

In 2002, a Combustion Engineering Owners Group peer review was conducted and, based on this review, several revisions to the PRA model were performed. In July 2008, a second full-scope peer review was conducted for the updated model. The results of this peer review superseded those from the 2002 review, as it scoped in all applicable supporting requirements to the internal events PRA model. The licensee performed a series of focused-scope peer reviews to the latest, endorsed version of the ASME/ANS PRA Standard, for transition to the National Fire Protection Association (NFPA) Standard NFPA 805 (Reference 18). Therefore, the licensee has addressed any gaps between the 2008 peer review and ASME/ANS PRA Standard, as endorsed by RG 1.200, Revision 2.

The NRC staff reviewed the facts and observations (F&Os) from the 2008 full-scope peer review of the internal events PRA model provided in the LAR. In addition, the NRC staff reviewed the summary of the peer review findings and the licensee's resolution or assessment of the impact on this application to determine whether any gaps in the PRA model were identified that could impact the application, and to ensure that any gaps in meeting CC II can be addressed for the SFCP per the NEI 04-10, Revision 1, methodology, and consistent with the guidance in RG 1.200, Revision 2. Based on information provided in the LAR, the staff determined that some of the F&Os for internal events were not sufficiently resolved. The results and conclusions of the staff's evaluation are provided below.

F&O SY-815-01 was generated because there was not enough evidence that an assessment of SSCs operating beyond environmental qualifications was sufficiently resolved. The LAR indicated that this finding applies to PRA supporting requirement SY-815 of the ASME/ANS PRA Standard. The supporting requirement SY-815 of the ASME/ANS PRA Standard requires that the PRA "[i]nclude operator interface dependencies across systems or trains, where applicable." After further review, it was determined that this finding discusses the lack of environmental qualification for SSCs in three systems, which was acknowledged as more applicable to supporting requirement SY-814. Furthermore, supporting requirement SY-814 requires identification of SSCs that need to operate beyond their environmental qualification and requires inclusion of failures in the PRA that results from operation in adverse conditions. The disposition to this F&O stated that the documentation for the Revision 6 PRA model will be updated to discuss: (1) walkdowns of credited equipment that were performed to identify potential susceptibility to flooding, spray, and a steam environment due to a pipe break, and (2) evaluation of the ability of systems to operate after loss of heating, ventilation, and air conditioning (HVAC). The NRC staff requested additional information to determine whether the environmental qualification concerns for SSCs in the three systems from the originating finding were resolved.

In response to Request for Additional Information {RAl)-PRA-01 by letter dated September 7, 2018 (Reference 3), the licensee explained that the supporting requirement in question (SY-815) was renumbered to SY-B14 after the AN0-2 peer review. The licensee also explained that an assessment was performed in relation to this matter and determined that there was no impact to the results of the model. However, the response stated that the HVAC modeling required modification and would be included in the next revision of the model of record (MOR) (i.e., Revision 6). Given that the MOR described in the LAR is Revision 5, the licensee proposed a license condition by supplemental letter dated November 16, 2018 (Reference 4),

that the MOR used for STI evaluations incorporates the updated modeling, which would include that for HVAC. In this supplement, the licensee stated that "[t]he Revision 6 PRA model documentation for AN0-2 shall include a new subsection to address the potential degraded environments applicable to each of the systems modeled." Therefore, as mandated by the license condition, the licensee will implement the necessary updates to its HVAC modeling. The NRC staff concludes that this resolution is acceptable for implementation of the TSTF-425 program.

RG 1.200, Revision 2, provides guidance for determining the technical adequacy of internal events PRAs by comparing the PRA to the relevant parts of the ASME/ANS PRA Standard using a peer review process. The NRC staff has reviewed the peer review results, dispositions, and RAI response, and finds that the quality and level of detail of the internal events PRA is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1, Technical Adequacy of the PRA," of RG 1.177, Revision 1. Significant errors and weaknesses with the internal events PRA will be resolved with the completion of the MOR, Revision 6, as required by the license condition (discussed in Section 4.0 of this SE). Therefore, the NRC staff concludes that the quality of the internal events PRA, with the completion of the latest revision to the MOR, meets the requirement in TSTF-425, Revision 3 (Reference 5).

Internal Flooding In Section 3.2.2 of Attachment 2 to the LAR (Reference 1 ), the licensee explained that the internal flooding model was developed in 2016, with a focused-scope peer review completed in February 2017 using the ASME/ANS PRA Standard, as endorsed and clarified by RG 1.200, Revision 2 (Reference 10).

The NRC staff reviewed the internal flooding F&Os from the 2017 focused-scope peer review provided in the LAR. The staff also reviewed the summary of the peer review findings and the licensee's resolution or assessment of the impact on this application to determine whether any gaps in the PRA model were identified that could impact the application and to ensure that any gaps in meeting CC II can be addressed for the SFCP per the NEI 04-10, Revision 1 methodology, consistent with RG 1.200, Revision 2.

In Attachment 2 to the LAR, the licensee provided finding-level F&Os for some internal flooding events that are currently being resolved. The NRC staff requested additional information from the licensee to clarify its disposition of the findings. In its response, the licensee stated that, for the internal flooding analysis, refined modeling of HVAC will be addressed in Revision 6 to the MOR. The staff's review of unresolved internal flooding F&Os is discussed below.

The F&O to IFEV-A7 (MCR A2-5859) stated that "[m]aintenance event screening is currently documented as a [approximately] -1 E-05/year frequency," and concludes that the quantitative screening criteria are not met. The disposition for this finding states that resolution of the F&O is only a documentation issue and that additional discussion of potential maintenance-related flooding mechanisms will be added to the documentation. It was not clear to the NRC staff how the disposition was addressed in the F&O, given that the basis for screening maintenance-induced flooding was not provided. In RAI-PRA-02.a by e-mail dated August 2, 2018 (Reference 19), the NRC staff requested specific details regarding the screening value of maintenance-induced flooding events and its exclusion from the model, and if the screening was in accordance with the ASME/ANS PRA Standard. In its response to RAI-PRA-02.a.i by letter dated September 7, 2018 (Reference 3), the licensee provided a detailed explanation for using a screening value of 1 E-05/year based on very conservative criteria and relying on the most restrictive component unavailability (i.e., 4.27E-02). The screening value assumes that all maintenance activities resulting in component unavailability involve activities that breach the pressure boundary. Based on these factors, a frequency for maintenance-induced floods could result in 2 to 4 orders of magnitude lower than 1 E-05/year. The response continued with a discussion of the probability for failure of detection and isolation and the distribution of flood flow rates (e.g., high flow rates versus low flow rates). The licensee confirmed that the internal flooding PRA initiating events analysis will be updated in the latest MOR. In addition, in its letter dated November 16, 2019, the licensee stated that the internal flooding MOR update supporting Revision 6 of the AN0-2 PRA will be completed, as required by the license condition, prior to implementation of the SFCP (discussed in Section 4.0 of this SE).

Furthermore, in response to RAI-PRA-02.a.ii, the NRC staff requested additional information to determine if maintenance-induced flooding events that exceed the ASME/ANS PRA Standard threshold have been incorporated in the MOR. The licensee referenced Supporting Requirement IE-C6 as the screening criteria provided in the PRA standard and concluded, based on discussion provided in response to RAI-PRA-02.a.i, that there are no maintenance-induced flooding events that exceed ASME/ANS PRA Standard supporting requirements related to internal flooding. The NRC staff finds that the licensee's resolution is acceptable for this application because the licensee has completed an update to its internal flooding PRA and performed the appropriate analysis to ensure maintenance-induced failures were properly considered.

In Attachment 2 to the LAR, F&O 19-5, concerning internal flooding operator action execution steps, presented several issues related to the calculation of human error probabilities (HEPs).

They included: (1) lack of operator verifications to ensure as-built, as-operated human factor events (HFEs) are modeled, (2) inconsistent timings assumptions that can affect HEP values, and (3) the use of non-proceduralized recovery actions for execution steps. The disposition of this F&O stated that, "adjustments to some flooding HFE timing will be implemented." The disposition further stated that these adjustments are not expected to impact flooding results, but are expected to be assessed in case-by-case STI evaluations. The licensee stated that the human reliability analysis (HRA) issues related to this finding will be included in the updated human factors engineering analysis. It was unclear to the NRC staff if this updated HRA would be included in the MOR to be used for the STI evaluations. In RAI-PRA-02.bi and RAI-PRA-02.bii (Reference 19), the staff requested clarification on the status of this update and its impact to the application. In its responses to RAI-PRA-02.bi and RAI-PRA-02.bii by letter (Reference 3), the licensee discussed the status of the updated HRA, confirming that it would be included in the next model update, expected in the fourth quarter of 2018. Additionally, the licensee clarified that the impact of this change is minor. In its letter dated November 16, 2019, the licensee confirmed that the HEP values for internal flooding will be incorporated into the HRA supporting the internal flooding update associated with Revision 6 of the AN0-2 PRA model, as required by the license condition, prior to implementation of the SFCP (discussed in Section 4.0 of this SE). The NRC staff finds this acceptable because the HRA will account for the problems with timing, and the licensee confirmed the significance of this change to the application was low.

In Attachment 2 to the LAR, the finding associated with F&O 20-9, concerning dependency analysis seeding value, addresses the HFE values in the dependency analysis that were not seeded with high enough values to ensure inclusion of all relative combinations. The disposition states, "[t]he impacted HFEs will be updated as needed in the IFA [Internal Flooding Assessment] model and documentation." It further states that the HEP seed values are expected to have minimal or no impact on the flooding results, but are expected to be assessed in case-by-case STI evaluations. In RAI-PRA-02.c (Reference 19), the NRC staff requested confirmation that the appropriate seeding value is incorporated in the PRA models dependency analyses used for STI evaluations. In its response to RAI-PRA-02.c (Reference 3), the licensee stated that the updated HRA seeding values will adjust its seeding process to the same approach that was accepted for the internal events analysis. The licensee has entered this issue into its corrective action tracking system to ensure the MOR used for STI evaluations includes these updates. In its letter dated November 16, 2019, the licensee confirmed that the the internal flooding PRA update logic model will be constructed using the internal events logic model as the basis, and that the model will use the same method for seeding HEP values as the internal events PRA model, thereby ensuring that the appropriate seeding values are used.

This item is required to be completed prior to implementation of the SFCP, in accordance with the license condition (discussed in Section 4.0 of this SE). The NRC staff finds this acceptable because the dependency analysis is being updated to one that is more appropriate for use in the TSTF-425 application.

RG 1.200, Revision 2, provides guidance for determining the technical adequacy of internal flooding PRA by comparing the PRAs to the relevant parts of the ASME/ANS PRA Standard using a peer review process. The NRC staff reviewed the peer review results, dispositions to F&Os, and the licensee's RAI responses, and finds that the quality and level of detail of the internal flooding PRA is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1 of RG 1.177, Revision 1. Any discrepancies with the internal flooding PRA will be resolved with the completion of implementation items (Reference 4) required by the license condition, as discussed in Section 4.0 of this SE. Therefore, the NRC staff concludes that the quality of the internal flooding PRA with the completion of the implementation items, is consistent with TSTF-425, Revision 3 (Reference 5).

Fire In Section 3.3, "AN0-2 Fire PRA Model," of Attachment 2 to the LAR (Reference 1 ), the licensee states that as part of the AN0-2 fire PRA transition to NFPA 805, several full-scope and focused-scope peer reviews were performed. In September 2009, a full-scope peer review against the ASME/ANS PRA Standard was conducted. This was followed by four separate focused-scope peer reviews: (1) October 2011 for High Level Requirements (HLRs) FSS-A, C, D, E, and H associated with the AN0-2 transient fire scenario development process; (2) June 2014 for the human reliability portion of the fire PRA; (3) November 2012 for FSS-A, C, D, E, and H HLRs; and (4) September 2016 for FSS-C, D, and H HLRs.

The NRC staff reviewed the F&Os from the 2009 full-scope peer review and all four focused-scope peer reviews provided in the LAR. The staff also reviewed the summary of the peer review findings and the licensee's F&O resolutions including the assessment of the impact on this application to determine whether any gaps in the PRA model were identified that could impact the application and to ensure that any gaps in the fire PRA model were identified that could impact the application, and to ensure that any gaps in meeting CC II or being cited as "Met" can be addressed for the SFCP per the NEI 04-10, Revision 1, methodology, and is consistent with the guidance in RG 1.200, Revision 2.

In Attachment 2 to the LAR, the licensee provided finding-level F&Os for some fire PRA scenarios that are currently being resolved. The NRC staff requested additional information to obtain clarification of the licensee's disposition of the findings. The staff's review of unresolved fire F&Os is discussed below.

F&O HR-G7-01, which pertains to joint HEP states, in part, that "the dependency approach does not consider availability of resources.... " The disposition states, "[a] review was performed for the most challenging scenario with respect to manpower requirements, control room abandonment, which confirmed that available manpower is sufficient to support multiple HEPs

[HFEs] in a cutset for the control room abandonment cutsets." The disposition also states that the HRA methodology was updated using NUREG-1921, "EPRI/NRC-RES Fire Human Reliability Analysis Guidelines" (Reference 20). It was not clear to the NRC staff how reviewing the resources associated with one scenario (albeit the most challenging one) for adequate availability of resources substituted for not considering the availability of resources in the dependency analysis. The NRC staff noted in RAI-PRA-04a (Reference 19), that manpower limitations can occur for HFEs that have overlapping execution windows. The disposition for F&O HR-G7-01 stated that the fire dependency analysis did not consider resource limitations in order to determine if certain combinations of operator actions were feasible. The licensee responded by analyzing the most challenging scenario (control room abandonment) and determined there were sufficient resources to perform the actions. The NRC staff also noted that resource limitations do not always occur in the most challenging scenarios because it only requires a couple of actions occurring during the same execution window to challenge resource limitations. In RAI-PRA-04a, the NRC staff requested confirmation that no fire scenarios were resource challenged. In response to RAI-PRA-04.a by letter dated September 7, 2018 (Reference 3), the licensee confirmed that the fire PRA MOR incorporated an HRA produced from the HRA calculator that includes resource availability during the dependency analysis process. The NRC staff, therefore, concludes that the licensee has appropriately resolved this finding because it addressed resource limitations for its fire scenarios.

In its disposition of F&Os CF-A1-01, ES-C1-01, ES-D1-01, ES-D1-02, HRA-A2-01, HRA-A4-02, PRM-B2-01, PRM-B9-01, and HR-G3-01, the licensee stated that the HRA methodology was revised to follow the guidance of NUREG-1921. The NRC staff notes that new human error analysis methods meet the ASME/ANS PRA Standard as defined for a PRA upgrade. In RAI-PRA-04.b (Reference 19), the staff requested the licensee to clarify whether the HRA revision was an upgrade that required a peer review. In response to RAI-PRA-04.b (Reference 3), the licensee stated that the new HRA methodology was previously identified as a PRA upgrade, which resulted in a focused-scope peer review performed in June 2014. The NRC staff finds that the licensee has adequately addressed the issue by conducting a peer review, as dictated by the ASME/ANS PRA Standard.

During the transition to NFPA 805, plants used frequently asked question (FAQ) 08-0046 in relation to incipient fire detection systems. On July 1, 2016, this FAQ was retired and the industry was notified of the NRC staff's expectation that licensees were required to recalculate their analyses without the credit from FAQ 08-0046. In RAI-PRA-06 (Reference 19) the NRC staff requested confirmation that the AN0-2 fire PRA incorporated this change in its guidance.

In response to RAI-PRA-06 (Reference 3), the licensee confirmed that any credit for incipient fire detection had been removed from the fire PRA MOR. The NRC staff finds that the licensee has adequately addressed this concern.

RG 1.200, Revision 2, provides guidance for determining the technical adequacy of fire PRA by comparing the PRAs to the relevant parts of the ASME/ANS PRA Standard using a peer review process. The NRC staff has reviewed the peer review results, F&O dispositions, and RAI responses and finds that the technical quality and level of detail of the fire PRA is sufficient to support the evaluation of changes proposed to surveillance frequencies within the SFCP, and is consistent with Regulatory Position 2.3.1 of RG 1.177, Revision 1. Therefore, the NRC staff concludes that the technical quality of the fire PRA is consistent with TSTF-425, Revision 3.

3.1.4.2 Scope of the Probabilistic Risk Assessment The proposed changes to the Administrative Controls section of the TSs would require the licensee to evaluate each proposed change to a relocated surveillance frequency using the guidance contained in NEI 04-10, Revision 1, to determine its potential impact on CDF and LERF risk from internal events, fires, seismic, other external events, and shutdown conditions.

In cases where a PRA of sufficient scope or quantitative risk models were unavailable, the licensee uses bounding analyses, or other conservative quantitative evaluations. A qualitative screening analysis may be used when the surveillance frequency impact on plant risk is shown to be negligible or zero.

The licensee has full-power internal events and internal flooding PRA models, as well as fire PRA models. These models received peer reviews as discussed above in Section 3.1.4.1 of this SE. In accordance with NEI 04-10, Revision 1, the licensee will use these models to perform quantitative evaluations to support the development of changes to surveillance frequencies in the SFCP. This is acceptable because the NRG-approved methodology in NEI 04-10, Revision 1, allows for more refined analysis to be performed to support changes to surveillance frequencies in the SFCP.

The licensee does not have PRA models for high winds, seismic events, external events, and transportation and nearby facility accidents. These events were assessed in the Individual Plant Examination of External Events, which was a one-time review. In PRA-RAl-05 (Reference 19),

the NRC staff requested a description of the process to ensure that the external events data reflected the as-built, as-operated plant and incorporated updated hazard information. In response to PRA RAl-05 (Reference 3), the licensee stated that Entergy procedure EN-DC-151, "PSA Maintenance and Update," ensures that the PRA analysts will review all future updates to determine when new external events data should be incorporated into the analysis. Based on this response, the NRC staff finds that the licensee has adequately addressed the resolution of this finding.

In accordance with NEI 04-10, Revision 1, the licensee can perform an initial qualitative screening analysis, and if the qualitative information is not sufficient to provide confidence that the net impact of the STI change would be negligible, a bounding analysis will be performed.

The bounding analysis will be performed in accordance with Step 1 Ob of NEI 04-10, Revision 1.

This is an acceptable approach in accordance with NEI 04-10, Revision 1.

The licensee stated that for assessing the shutdown risk, the shutdown risk management program for implementation of Nuclear Management Resources Council (NUMARC) 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," dated December 1991 (Reference 21 ), will be used for the proposed changes to surveillance frequencies under the SFCP. This is an acceptable approach in accordance with NEI 04-10, Revision 1.

Based on the above, the NRC staff concludes that, by application of NRG-approved NEI 04-10, Revision 1, the licensee's evaluation methodology is sufficient to ensure that the scope of the risk contribution of each surveillance frequency change is properly identified for evaluation, and is consistent with Regulatory Position 2.3.2, "Scope of the Probabilistic Risk Assessment for Technical Specification Change Evaluations," of RG 1.177, Revision 1.

3.1.4.3 Probabilistic Risk Assessment Modeling The licensee's methodology includes the determination of whether the SSCs affected by a proposed change to a surveillance frequency are modeled in the PRA. Where the SSC is directly or implicitly modeled, a quantitative evaluation of the risk impact may be carried out.

The methodology adjusts the failure probability of the impacted SSCs, including any impacted CCF modes, based on the proposed change to the surveillance frequency. Where the SSC is not modeled in the PRA, bounding analyses are performed to characterize the impact of the proposed change to the surveillance frequency. Potential impacts on the risk analyses due to screening criteria and truncation levels are addressed by the requirements for PRA technical adequacy, consistent with the guidance contained in RG 1.200, Revision 2, and by sensitivity studies identified in NEI 04-10, Revision 1.

The NRC staff concludes that, through the application of NRG-approved NEI 04-10, Revision 1, the AN0-2 PRA modeling is sufficient to ensure that an acceptable evaluation of risk will be performed for the proposed changes in surveillance frequency, and is consistent with Regulatory Position 2.3.3, "Probabilistic Risk Assessment Modeling," of RG 1.177, Revision 1.

3.1.4.4 Assumptions for Time-Related Failure Contributions The failure probabilities of SSCs modeled in PRAs may include a standby time-related contribution and a cyclic demand-related contribution. The licensee identified one source of uncertainty with standby failure rate. The standby time-dependent failure rate evaluation must be performed in accordance with NEI 04-10, Revision 1. The NEI 04-10, Revision 1, criteria adjust the time-related failure contribution of SSCs affected by the proposed change to a surveillance frequency. This is consistent with RG 1.177, Revision 1, Section 2.3.3, which permits separation of the failure rate contributions into demand and standby for evaluation of supporting requirements. If the available data do not support distinguishing between the time-related failures and demand failures, then the change to surveillance frequency is conservatively assumed to impact the total failure probability of the SSC, including both standby and demand contributions. The SSC failure rate (per unit time) is assumed to be unaffected by the change in test frequency, such that the failure probability is assumed to increase linearly with time. This assumption will be confirmed by the required monitoring and feedback implemented after the change in surveillance frequency is implemented. The NEI 04-10, Revision 1, process requires consideration of qualitative sources of information with regard to potential impacts of test frequency on SSC performance, including industry and plant-specific operating experience, vendor recommendations, industry standards, and code-specified test intervals. Thus, the NRC staff concludes that the licensee's process is not reliant upon risk analyses as the sole basis for the proposed changes because the licensee has, and will, apply the associated guidance in NRG-approved NEI 04-10, Revision 1.

The potential benefits of a reduced surveillance frequency, including reduced downtime and reduced potential for restoration errors, test-caused transients, and test-caused wear of equipment, are identified qualitatively, but not quantitatively assessed. The NRC staff concludes that the licensee applied NRG-approved NEI 04-10, Revision 1, to employ reasonable assumptions with regard to extensions of STls, and the requested changes are consistent with Regulatory Position 2.3.4, "Assumptions in Completion Time and Surveillance Frequency Evaluations," of RG 1.177, Revision 1.

3.1.4.5 Sensitivity and Uncertainty Analyses The proposed amended TSs would require that changes to the frequencies listed in the SFCP be made in accordance with NEI 04-10, Revision 1. Therefore, the licensee will be required to have sensitivity studies to assess the impact of uncertainties from key assumptions of the PRA, uncertainty in the failure probabilities of the affected SSCs, impact on the frequency of initiating events, and any identified deviations from CC II of the PRA standard. Where the sensitivity analyses identify a potential impact on the proposed change, revised surveillance frequencies are considered, along with any qualitative considerations that may bear on the results of such sensitivity studies. Step 5 of the NEI 04-10, Revision 1 process states that the identification of key sources of uncertainty is used to perform the appropriate sensitivity cases required by Step 14. In Attachment 2 to the LAR (Reference 1 ), two F&Os identified as QU-F4-01 and 20-4, relate to model assumptions and uncertainties. According to the NRC staff, the disposition of these F&Os provided information that was insufficient to conclude that the F&Os have been sufficiently resolved. In RAI-PRA-03 (Reference 19), the NRC staff requested details of the process used for STI evaluations. In response to RAI-PRA-03 (Reference 3), the licensee explained that the process used for STI evaluations was in accordance with NUREG-1855, "Guidance of the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking," Revision 1, dated March 2017 (Reference 22), and the MOR assumptions were reviewed for applicability following the procedures identified in EPRI TRs EPRl-1013491, "Guideline for treatment of Uncertainty in Risk-Informed Applications, and EPRl-1016737, "Treatment of Parameter and Modeling Uncertainty for Probabilistic Risk Assessments," dated December 2008 (References 23 and 24, respectively). The NRC staff noted that these EPRI TRs are referenced in NUREG-1855 dated March 2009 (Reference 25), which has been superseded by Revision 1 (Reference 22). NUREG-1855, Revision 1, uses information available in the updated EPRI TR (1026511, "Practical Guidance on the Use of PRA in Risk-Informed applications with a Focus on the treatment of Uncertainty" (Reference 26)) related to this subject matter.

In accordance with NEI 04-10, Revision 1, as required by proposed TS 6.5.18, the licensee will also perform monitoring and feedback of SSC performance, once the revised surveillance frequencies are implemented. Therefore, the NRC staff concludes that the licensee appropriately considered the possible impact of PRA model uncertainty and sensitivity to key assumptions and model limitations. In addition, the staff concludes that the LAR is consistent with Regulatory Position 2.3.5, "Sensitivity and Uncertainty Analyses Relating to Assumptions in Technical Specification Change Evaluations," of RG 1.177, Revision 1, because the licensee has or will apply the associated guidance in NRG-approved NEI 04-10, Revision 1.

3.1.4.6 Acceptance Guidelines In accordance with NEI 04-10, Revision 1, as required by proposed TS 6.5.18, the licensee will quantitatively evaluate the change in total risk (including internal and external events contributions) in terms of CDF and LERF for both the individual risk impact of a proposed change in surveillance frequency and the cumulative impact from all individual changes to surveillance frequencies using the guidance contained in NRG-approved NEI 04-10, Revision 1, in accordance with the TS SFCP. Each individual change to surveillance frequency must show a risk increase below 1 E-6 per year for CDF, and below 1 E-7 per year for LERF. These changes to CDF and LERF are consistent with the acceptance criteria of RG 1.17 4, Revision 3, for very small changes in risk. Where the RG 1.17 4, Revision 3, acceptance criteria are not met, the process in NEI 04-10, Revision 1, either considers revised surveillance frequencies that are consistent with RG 1.17 4, Revision 3, or the process terminates without permitting the proposed changes. Where quantitative results are unavailable for comparison with the acceptance guidelines, appropriate qualitative analyses are required to demonstrate that the associated risk impact of a proposed change to surveillance frequency is negligible or insignificant. Otherwise, bounding quantitative analyses are required to demonstrate that the risk impact is at least one order of magnitude lower than the RG 1.17 4, Revision 3, acceptance guidelines for very small changes in risk. In addition, in assessing each individual SSC surveillance frequency change, the cumulative impact of all changes must result in a risk increase less than 1 E-5 per year for CDF, and less than 1 E-6 per year for LERF. The total CDF and total LERF must be reasonably shown to be less than 1 E-4 per year and 1 E-5 per year, respectively. These values are consistent with the acceptance criteria of RG 1.17 4, Revision 3, as referenced by RG 1.177, Revision 1, for changes to surveillance frequencies.

Consistent with the NRC staff's SE dated September 19, 2007, for NEI 04-10, Revision 1 (Reference 7), the TS SFCP will require the licensee to calculate the total change in risk (i.e.,

the cumulative risk) by comparing a baseline model that uses failure probabilities based on surveillance frequencies prior to being changed per the SFCP to a revised model that uses failure probabilities based on the changed surveillance frequencies. The staff further notes that the licensee includes a provision to exclude the contribution to cumulative risk from indiyidual changes to surveillance frequencies associated with insignificant risk increases (i.e., less than 5E-8 CDF and 5E-9 LERF, respectively) once the baseline PRA models are updated to include the effects of the revised surveillance frequencies.

The quantitative acceptance guidance of RG 1.174, Revision 3, is supplemented by qualitative information to evaluate the proposed changes to surveillance frequencies, including industry and plant-specific operating experience, vendor recommendations, and industry standards, or at least bounding, quantitative results of sensitivity studies and SSC performance data and test history. The final acceptability of the proposed change is based on all of these considerations and not solely on the PRA results. Post-implementation performance monitoring and feedback are also required to assure continued reliability of the components. The licensee's application of NEI 04-10, Revision 1, provides acceptable methods for evaluating the risk increase associated with proposed changes to surveillance frequencies, consistent with Regulatory Position 2.4, "Acceptance Guidelines for Technical Specification Changes," of RG 1.177, Revision 1. Therefore, NRC staff concludes that the proposed methodology satisfies the fourth key safety principle of RG 1.177, Revision 1, by assuring that any increase in risk is small, consistent with the intent of the Commission's Safety Goal Policy Statement.

3.1.5 The Impact of the Proposed Change Should Be Monitored Using Performance Measurement Strategies The licensee's proposed adoption of TSTF-425, Revision 3, requires application of NEI 04-10, Revision 1, in the SFCP. NEI 04-10, Revision 1, requires performance monitoring of SSCs whose surveillance frequencies have been revised as part of a feedback process to assure that the change in test frequency has not resulted in degradation of equipment performance and operational safety. The monitoring and feedback includes consideration of Maintenance Rule (i.e., 10 CFR 50.65) monitoring of equipment performance. In the event of SSC performance degradation, the surveillance frequency will be reassessed in accordance with the methodology, in addition to any corrective actions that may be required by the Maintenance Rule. The performance monitoring and feedback specified in NEI 04-10, Revision 1, is sufficient to reasonably assure acceptable SSC performance and is consistent with Regulatory Position 3.2, "Maintenance Rule Control," of RG 1.177, Revision 1. Thus, the NRC staff concludes that the fifth key safety principle of RG 1.177, Revision 1, is satisfied.

3.2 Addition of Surveillance Frequency Control Program to the Administrative Controls Section of TSs The licensee proposed including the SFCP and specific requirements in the AN0-2 TSs, Section 6.5.18, as follows:

Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a.

The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.

b.

Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c.

The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

The NRC staff concludes that the proposed TS 6.5.18, which requires an acceptable program to control surveillance frequencies to ensure that LCOs are met and includes necessary program and applicability requirements, and its requirements set forth above are consistent with the model application of TSTF-425, Revision 3, and are therefore, acceptable.

3.3 Deviations from TSTF-425 and Other Changes The licensee identified optional changes and variations with the approved TSTF-425, Revision 3, in Section 2.2 of Attachment 1 to the LAR. The NRC staff reviewed the changes and variations and made the following determinations:

1.

The licensee stated in its application dated, February 6, 2018 (Reference 1 ), that the AN0-2 TS were based on the STS at the time of issue, which did not contain TS Bases as comprehensive as those in NUREG-1432 (Reference 14). Therefore, many of the TS Bases mark-ups in TSTF-425 are not applicable to the AN0-2 TSs. The licensee also stated that the proposed Bases changes, provided in Attachment 4 of the LAR, revise only those TS Bases that currently discuss surveillance frequencies.

The regulation at 10 CFR 50.36(a)(1) states that a summary statement of the Bases or reasons for such specifications, other than those covering administrative controls, shall also be included in the application, but shall not become part of the TSs. Consistent with 10 CFR 50.36(a)( 1 ), the licensee submitted corresponding TS Bases changes that provide the reasons for the proposed TSs changes. The NRC staff concludes that the proposed TS Bases changes describe the bases for the affected TSs and follow the "Final Policy Statement on Technical Specifications Improvements for Nuclear Power Reactors" (58 FR 39132).

2.

The licensee proposed to make various changes to TS Table 1.2, "Frequency Notation,"

pages 1-7, 1-8, and 1-9. These changes are listed below:

To reflect the proposed change, allowing instrument function frequencies to be controlled in accordance with the SFCP, AN0-2 TS Table 1.2, will be updated to include the notation "SFCP." In addition, the following notations and associated frequencies, S, D, W, M, Q, TA, SA, and R, will be deleted because they are no longer used in the TSs:

AN0-2 TS page 1-7 is currently blank and is being deleted. Subsequently, TS page 1-8 is renumbered as 1-7 and the revised Table 1.2 is moved to the same page as Table 1.1. As a result, pages 1-8 and 1-9 are proposed to be deleted from the TSs.

The licensee also proposed to include the use of "SFCP" as a frequency notation in the tables and/or footnotes, where applicable, that are linked to affected instrumentation SRs (TS Tables4.3-1, 4.3-2, 4.3-3, 4.3-6, 4.3-10, and SR 4.4.12.2). A table notation or footnote in the AN0-2 TSs specifies the frequency for a SR, where the frequency is being proposed for relocation to the SFCP. The NRC staff reviewed the proposed changes listed above and determined that they are administrative in nature and continue to meet the requirements of 1 O CFR 50.36 and the intent of TSTF-425. Therefore, the proposed changes to TS Table 1.2, Pages 1-7, 1-8, and 1-9 are acceptable.

3.

The approved programs for AN0-2 are described in Section 6.0, "Administrative Controls," of the AN0-2 TSs (the equivalent STS section is 5.0). Therefore, the SFCP requirements specified in TSTF-425 are proposed to be added to TS Section 6.0, TS 6.5.18. The NRC staff reviewed this deviation and determined that it is administrative in nature with no impact on the NRC model SE dated July 6, 2009 (74 FR 32001 ). Therefore, this deviation from TSTF-425 is acceptable.

4.

Because the AN0-2 TSs are based on the standard TSs at the time they were issued, the applicable SRs and associated bases numbers differ from those presented in NUREG-1432 and TSTF-425 and are retained in this license amendment request. The NRC staff reviewed this deviation and determined that it is administrative in nature with no impact on the NRC model SE dated July 6, 2009 (74 FR 32001). Therefore, this deviation from TSTF-425 is acceptable.

5.

For NUREG-1432 surveillances not contained in the AN0-2 TSs, the corresponding mark-ups included in TSTF-425 for these surveillances are not applicable to AN0-2.

The NRC staff reviewed this deviation and determined that it is administrative in nature with no impact on the NRC model SE dated July 6, 2009 (7 4 FR 32001 ). Therefore, this deviation from TSTF-425 is acceptable.

6.

The licensee identified that the AN0-2 TSs contain plant-specific SRs that are not included in the approved TSTF-425, Revision 3. Approved TSTF-425, Revision 3 states, "The proposed change relocates all periodic Surveillance Frequencies from the Technical Specifications and places the Frequencies under licensee control in accordance with a new program" and "All surveillances are relocated except.... [four exclusion criteria for the surveillance frequencies are listed]." It does not add, delete, or modify the content of the surveillance requirements themselves. These statements denote that TSTF-425, Revision 3, applies to all surveillances, including the AN0-2 plant-specific surveillances, that are periodic and do not meet one of the exclusion criteria. Application of the TSTF to AN0-2's TS format is in accordance with the Commission's final policy statement on TSs, as published in the Federal Register on July 22, 1993 (58 FR 39132). The NRC staff reviewed the marked-up SRs in the LAR to ensure that no surveillances were included that matched the exclusion criteria. The NRC staff determined that all marked-up surveillances included in the original LAR, as supplemented, were included within the scope of approved TSTF-425, Revision 3.

Therefore, the NRC staff concludes that the SRs are acceptable and will continue to meet 10 CFR 50.36(c)(3).

7.

The licensee proposed to include AN0-2 TSs 6.5.2 and 6.5.13, which are not identified for relocation in TSTF-425, Revision 3. The first sentence of TS 6.5.2.b is proposed to be revised as follows (deleted text in strikeout and added text in italics):

Integrated leak test requirements for each system at least onse per 18 moRths a Frequency in accordance with the Surveillance Frequency Control Program.

TS 6.5.13.c is proposed to be revised as follows ( deleted text in strikeout and added text in italics):

Total particulate concentration of the fuel oil is s 10 mg/I when tested every 31 days based on ASTM D-2276, Method A-2 or A-3 at a frequency in accordance with the Surveillance Frequency Control Program; The NRC staff reviewed the proposed changes and determined that they are periodic frequencies and do not meet the scope exclusion criteria identified in Section 1.0, "Introduction," of the model SE. The licensee stated in the LAR that, in accordance with TSTF-425, changes to the frequencies for these surveillances would be controlled under the SFCP. The licensee further stated that changes to frequencies in the SFCP would be evaluated using the NRG-approved methodology and probabilistic risk guidelines contained in NEI 04-10, Revision 1.

The relocation of these periodic frequencies is consistent with the intent of TSTF-425, Revision 3, and with the NRC's model SE dated July 6, 2009 (74 FR 32001 ). Therefore, the NRC staff finds the proposed deviation acceptable.

8.

TSTF-425, Revision 3, includes the relocation of the frequency for NU REG 1432, SR 3. 7.11.4, which is associated with verifying that one Control Room Emergency Air Cleanup System maintains a positive pressure relative to adjacent area(s). This SR was revised under TSTF-448, "Control Room Habitability" in Amendment No. 288 (Reference 27), to perform control room envelope unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program. AN0-2 adopted TSTF-448, Revision 3, and designated the Control Room Envelope Habitability Program as TS 6.5.12. The licensee is proposing to adopt the frequency change identified for NUREG-1432 SR 3.7.11.4 in TSTF-425 as the AN0-2 TS 6.5.12.d frequency. The NRC staff reviewed the changes and confirmed that the frequency for AN0-2 TS SR 3.7.11.4 has been moved to TS 6.5.12.d with the adoption of TSTF-448. The frequency located in TS 6.5.12.d is a periodic frequency, does not meet the scope exclusion criteria, and is consistent with the intent of TSTF-425, Revision 3. These changes are administrative in nature and the frequency will be controlled under the SFCP. Therefore, the NRC staff concludes that the proposed changes to TS Section 6.5.12.d are acceptable.

9.

The licensee proposed changes to SRs related to the response time tests of the reactor protective instrumentation and engineered safety features actuation system (ESFAS) instrumentation that contain text describing what constitutes "N" for response time testing (SRs 4.3.1.1.3 and 4.3.2.1.3). SR 4.3.1.1.3 currently states:

The REACTOR TRIP SYSTEM RESPONSE TIME of each reactor trip function shall be demonstrated to be within its limit at least once per 18 months. Neutron detectors are exempt from response time testing. Each test shall include at least one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip function as shown in the "Total No. of Channels" column of Table 3.3-1.

The licensee stated that this plant-specific text identified for deletion in Attachment 3 of the LAR is not specified in the NUREG-1432 mark-ups provided in TSTF-425, Revision 3. However, text that describes what constitutes "N" is identified as Notes in other STS NUREGs (e.g., Note 2, NUREG-1434, SR 3.3.1.1.15, RPS Response Time test) and is identified for deletion in TSTF-425.

The NRC staff reviewed the proposed changes and concluded that they do not meet the scope exclusion criteria identified in Section 1.0, "Introduction," of the model SE.

Although these plant-specific SR frequency changes are not included in NUREG-1432, there are similar SRs related to the response time tests of the reactor protective instrumentation and ESFAS instrumentation contained in NUREG-1434. "N" for response time testing is similar to the TS definition of Staggered Test Basis. NEI 04-10, Revision 1, states, in part, that NEI 04-10 contains new information to address how Surveillances which are performed on a Staggered Test Basis are modeled in the risk assessment performed to support a change to the Frequency. This will allow licensees to add or remove the requirement to perform Surveillances on a Staggered Test Basis under the SFCP. The licensee stated that in accordance with TSTF-425, Revision 3, changes to the frequencies for these SRs would be controlled under the SFCP. These changes are consistent with the intent of TSTF-425, Revision 3, and with the model SE dated July 6, 2009 (74 FR 32001). Therefore, the NRC staff finds the proposed changes acceptable.

10.

The licensee proposed changes to AN0-2 SRs 4.5.1.a.2 and 4.5.2 by correcting valve numbering and clarifying that the requirement to verify power is removed applies only to the two motor operated valves. These valve numbers are correctly illustrated in Table 5.2-2 of the AN0-2 Safety Analysis Report (SAR). The NRC staff reviewed the proposed changes and confirmed that the valves are listed correctly in the SAR. These changes are editorial in nature and do not change the intent of TSTF-425, Revision 3.

Therefore the NRC staff finds these changes acceptable.

11.

The licensee proposed editorial changes to AN0-2 TS 6.5.17, "Metamic Coupon Sampling Program." Currently, the program contains reference to SR 3.0.2 and SR 3.0.3, which is the numbering in NUREG-1432. The numbering will be corrected to refer to the equivalent AN0-2 TS numbering of SR 4.0.2 and SR 4,0.3. The NRC staff reviewed the changes and determined that they are editorial in nature and are needed for consistency with the numbering used in the AN0-2 TSs. Therefore, the NRC staff finds these changes acceptable.

3.4 Technical Evaluation Summary The NRC staff has reviewed the licensee's proposed relocation of certain surveillance frequencies in AN0-2 TS Sections 4.1 through 4.11 to a licensee-controlled document, and controlling changes to surveillance frequencies in accordance with a new program, the SFCP, by the proposed addition of TS 6.5.18 to the Administrative Controls section of TSs. The NRC staff confirmed that this amendment does not relocate surveillance frequencies that reference other approved programs for the specific interval, are purely event-driven, are event-driven but have a time component for performing the surveillance on a one-time basis once the event occurs, or are related to specific conditions. The SFCP and TS Section 6.0, Subsection 6.5.18, references NEI 04-10, Revision 1, which provides a risk-informed methodology using plant-specific risk insights and performance data to revise surveillance frequencies within the SFCP. This methodology supports relocating surveillance frequencies from TSs to a licensee-controlled document, provided those frequencies are changed in accordance with the NRC-approved NEI 04-10, Revision 1.

The licensee proposed to relocate certain surveillance frequencies from the following TS sections to the SFCP:

4. 1 Reactivity Control Systems 4.2 Power Distribution Limits 4.3 Instrumentation 4.4 Reactor Coolant System 4.5 Emergency Core Cooling Systems 4.6 Containment Systems

4. 7 Plant Systems 4.8 Electrical Power Systems 4.9 Refueling Operations 4.10 Special Test Exceptions 4.11 Radioactive Effluents 6.5 Programs and Manuals The licensee's proposed adoption of TSTF-425, Revision 3, and the risk-informed methodology of NRC-approved NEI 04-10, Revision 1, as referenced in the Administrative Controls section of TSs, satisfies the key principles of risk-informed decisionmaking applied to changes to TSs, as delineated in RG 1.177 and RG 1.17 4, in that:

The proposed change meets current regulations; The proposed change is consistent with defense-in-depth philosophy; The proposed change maintains sufficient safety margins; Increases in risk resulting from the proposed change are small and consistent with the Commission's Safety Goal Policy Statement; and The impact of the proposed change is monitored with performance measurement strategies.

In addition, the regulatory requirements in 10 CFR 50.65, and 10 CFR Part 50, Appendix B, Criterion XVI, and the performance monitoring required by NEI 04-10, Revision 1, ensure that surveillance frequencies are sufficient to assure that the requirements of 10 CFR 50.36 are satisfied and that any performance deficiencies will be identified and appropriate corrective actions will be taken. The NRG staff concludes the licensee's SFCP ensures that SRs specified in the TSs are performed at intervals sufficient to assure the above regulatory requirements are met.

The licensee also proposed a license condition, as described in Section 4.0 of this SE, which will ensure that important updates will be incorporated into the PRA model prior to the implementation of the SFCP.

Based on the above evaluation, the NRG staff concludes that, with the proposed relocation of surveillance frequencies to a licensee-controlled document and administratively controlled in accordance with the TS SFCP, the licensee continues to meet the requirements in 10 CFR 50.36(c)(3), 10 CFR 50.65, and 10 CFR Part 50, Appendix B, Criterion XVI.

4.0 LICENSE CONDITIONS With the issuance of this amendment, a condition will be added to the license for AN0-2. The condition will read:

Surveillance Frequency Control Program The licensee shall implement the items listed in Table 2 of the enclosure to Entergy letter 2CAN111801, dated November 16, 2018, prior to implementation of the Surveillance Frequency Control Program.

This license condition requires the licensee to complete the following items prior to implementation of the SFCP, as identified in its letter dated November 16, 2018 (Reference 4):

The Revision 6 PRA model documentation for AN0-2 shall include a new subsection to address the potential degraded environments applicable to each of the systems modeled.

The internal flooding MOR update supporting Revision 6 of the AN0-2 PRA model shall be completed.

The human error probabilities (HEP) values for internal flooding shall be incorporated into the human reliability analysis (HRA) supporting the internal flooding update associated with Revision 6 of the AN0-2 PRA model.

The internal flooding PRA update logic model shall be constructed using the internal events logic model as the basis. The internal flooding PRA model shall use the same method for seeding HEP values as the internal events PRA model, thereby ensuring the appropriate seeding values are used.

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the NRC staff notified the State of Arkansas official of the proposed issuance of the amendment on March 8, 2019. The State official had no comments.

6.0 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 surveillance requirements. 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 published in the Federal Register on June 5, 2018 (83 FR 26102).

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 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.

8.0 REFERENCES

1.

Anderson, Richard L., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425), Arkansas Nuclear One, Unit 2, Docket No. 50-368, License No. NPF-6," dated February 6, 2018 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML180388354).

2.

Anderson, Richard L., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Supplemental Information Supporting the Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425), Arkansas Nuclear One, Unit 2, Docket No. 50-368, License No. NPF-6,"

dated March 26, 2018 (ADAMS Accession No. ML18085A816).

3.

Anderson, Richard L., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information Related to the Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425), Arkansas Nuclear One, Unit 2, Docket No. 50-368, License No. NPF-6," dated September 7, 2018 (ADAMS Accession No. ML18250A282).

4.

Anderson, Richard L., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Supplemental to the Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program (TSTF-425), Arkansas Nuclear One, Unit 2, Docket No. 50-368, License No. NPF-6," dated November 16, 2018 (ADAMS Accession No. ML18320A222).

5.

Technical Specifications Task Force, letter and enclosure to U.S. Nuclear Regulatory Commission, "Transmittal of TSTF-425, Revision 3, 'Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative Sb,"' dated March 18, 2009 (ADAMS Accession No. ML090850642).

6.

Nuclear Energy Institute, "Risk-Informed Technical Specifications Initiative Sb, Risk-Informed Method for Control of Surveillance Frequencies," NEI 04-10, Revision 1, dated April 2007 (ADAMS Accession No. ML071360456).

7.

Nieh, H. K., U.S. Nuclear Regulatory Commission, letter to Biff Bradley, Nuclear Energy Institute, "Final Safety Evaluation for Nuclear Energy Institute (NEI) Topical Report (TR) 04-10, Revision 1, 'Risk-Informed Technical Specifications Initiative Sb, Risk-Informed Method for Control of Surveillance Frequencies,' (TAC No. MD6111 ),"

dated September 19, 2007 (ADAMS Accession No. ML072570267).

8.

U.S. Nuclear Regulatory Commission, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Regulatory Guide 1.17 4, Revision 3, dated January 2018 (ADAMS Accession No. ML17317A256).

9.

U.S. Nuclear Regulatory Commission, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," Regulatory Guide 1.177, Revision 1, dated May 2011 (ADAMS Accession No. ML100910008).

10.

U.S. Nuclear Regulatory Commission, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities,"

Regulatory Guide 1.200, Revision 2, dated March 2009 (ADAMS Accession No. ML090410014).

11.

U.S. Nuclear Regulatory Commission, "Review of Risk Information Used to Support Permanent Plant-Specific Changes to the Licensing Basis: General Guidance,"

NUREG-0800, Section 19.2, dated June 2007 (ADAMS Accession No. ML071700658).

12.

U.S. Nuclear Regulatory Commission, "Determining the Technical Adequacy of Probabilistic Risk Assessment for Risk-Informed License Amendment Requests After Initial Fuel Load," NUREG-0800, Section 19.1, Revision 3, dated September 2012 (ADAMS Accession No. ML12193A107).

13.

U.S. Nuclear Regulatory Commission, "Risk-Informed Decision Making: Technical Specifications," NUREG-0800, Section 16.1, Revision 1, dated March 2007 (ADAMS Accession No. ML070380228).

14.

U.S. Nuclear Regulatory Commission, "Standard Technical Specifications, Combustion Engineering Plants," NUREG-1432, Revision 4, Volume 1, Specifications and Volume 2, Bases (ADAMS Accession No. ML12102A165 and ML12102A169, respectively).

15.

American Society of Mechanical Engineers and American Nuclear Society (ASME/ANS)

PRA Standard ASME/ANS RA-Sa-2009, "Addenda to ASME RA-S-2008, Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," February 2009, New York, NY.

16.

Nuclear Energy Institute, "Probabilistic Risk Assessment (PRA) Peer Review Process Guidance," NEI 00-02, Revision 1, dated May 2006 (ADAMS Accession No. ML061510619).

17.

Nuclear Energy Institute, "Process for Performing Internal Events PRA Peer Reviews Using the ASME/ANS PRA Standard," NEI 05-04, Revision 2, dated November 2008 (ADAMS Accession No. ML083430462).

18.

Browning, J. G., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information, Adoption of National Fire Protection Association Standard NFPA-805," Arkansas Nuclear One - Unit 2, Docket No. 50-368, License No. NPF-6, dated August 7, 2014 (ADAMS Accession No. ML14219A635).

19.

Wengert, T., U.S. Nuclear Regulatory Commission, e-mail to Stephenie L. Pyle, Entergy Operations, Inc., "AN0-2 Final RAI Re: License Amendment Request To Adopt TSTF-425, Revision 3 (EPID L-2018-LLA-0047)," dated August 2, 2018 (ADAMS Accession No. ML18218A501 ).

20.

U.S. Nuclear Regulatory Commission, "EPRI/NRC-RES Fire Human Reliability Analysis Guidelines," NUREG-1921, dated July 2012 (ADAMS Accession No. ML12216A104).

21.

Nuclear Management Resources Council, "Guidelines for Industry Actions to Assess Shutdown Management," NUMARC 91-06, December 1991, (ADAMS Accession No. ML14365A203).

22.

U.S. Nuclear Regulatory Commission, "Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decisionmaking," NUREG-1855, Revision 1, dated March 2017 (ADAMS Accession No. ML17062A466).

23.

Electric Power Research Institute, "Guideline for Treatment of Uncertainty in Risk-Informed Applications: Applications Guide," EPRI 1013491, Palo Alto, CA, 2006.

24.

Electric Power Research Institute, "Treatment of Parameter and Model Uncertainty for Probabilistic Risk Assessments," EPRI 1016737, Palo Alto, CA, December 2008.

25.

U.S. Nuclear Regulatory Commission, "Guidelines on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making," NUREG-1855, dated March 2009 (ADAMS Accession No. ML090970525).

26.

Electric Power Research Institute, "Practical Guidance on the Use of PRA in Risk-Informed Applications with a Focus on the Treatment of Uncertainty,"

EPRI 1026511, Palo Alto, CA, 2012.

27.

Wang, A. B., U.S. Nuclear Regulatory Commission, "Arkansas Nuclear One, Unit No. 2-lssuance of Amendment Re: Adoption of Technical Specification Task Force (TSTF)

Change Traveler TSTF-448, Revision 3, 'Control Room Envelope Habitability' (TAC No. MD7175)," dated October 29, 2009 (ADAMS Accession No. ML082520574).

Principal Contributors: L. Fields, NRR J. Evans, NRR T. Sweat, NRR Date: Apr i 1 2 3, 201 9

ML190638948

via memorandum

- via e-mail OFFICE NRR/DORL/LPL4/PM NRR/DORL/LPL4/LA NRR/DRA/APLA/BC(A)*/** NRR/DSS/STSB/BC**

NAME TWengert PBlechman MWentzel VCusumano DATE 3/20/19 3/19/19 2/11 /19; reconcur 3/22/19 3/29/19 OFFICE NRR/DE/EEOB/BC(A)** NRR/DE/EICB/BC**

NRR/DSS/SCPB/BC**

NRR/DE/EMIB/BC**

NAME DWilliams MWaters (RAlvarado for)

SAnderson SBailey DATE 3/25/19 3/29/19 3/29/19 3/21/19 OFFICE NRR/DMLR/MCCB/BC** OGC NRR/DORL/LPL4/BC NRR/DORL/LPL4/PM NAME SBloom AGhosh RPascarelli TWengert DATE 3/25/19 4/17/19 4/23/19 4/23/19

v t e Letter Sequence Approval
EPID:L-2018-LLA-0047, TSTF-425 (Approved, Closed)
Initiation Request, Request, Request Acceptance, Acceptance Supplement, Supplement Administration Questions 2 August 2018 Answers Results Approval Other: ML19127A299
MONTHYEAR2018-04-11 [Table View]

ML19063B948

Text

SUBJECT:

Dear Sir or Madam:

Enclosures:

Attachment:

2.1 REGULATORY EVALUATION

3.0 TECHNICAL EVALUATION

5.0 STATE CONSULTATION

6.0 ENVIRONMENTAL CONSIDERATION

7.0 CONCLUSION

8.0 REFERENCES

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