Text

Proposed Techincal Specification Changes
	ML12277A081
Person / Time
Site:	Grand Gulf
Issue date:	10/02/2012
From:	; Entergy Operations
To:	; Office of Nuclear Reactor Regulation
Shared Package
Ml122770130	List: GNRO-2012/00096, License Amendment Request for Implementing a 24-Month Fuel Cycle, Grand Gulf Nuclear Station, Unit 1; ML12277A081;
References
	Download: ML12277A081 (171)
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PAM Instrumentation 3,3,2.1 SURVEILLANCE REQUIREMENTS

NOTE---------------------------------------

These SRs apply to each Function in Table 3.3.3.1-1.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3. 3.1. 2 Deleted SR 3 . 3 . 3 . 1. 3 ------------------NOTE-------------------

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. 24 months GRAND GULF 3,3-21 Amendment No. 120, li§.

Remote Shutdown System 3.3.3.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.3.2.2 Verify each required control circuit and 24 months transfer switch is capable of performing the intended functions.

SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel.

GRAND GULF 3.3-24 Amendment No. ~

EOC-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS

NOTE-------------------------------------

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains EOC-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4 .1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4.1.2 Calibrate the trip units. 92 days SR 3.3. 4. 1. 3 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. TSV Closure, Trip Oil PressureCLow:

2 37 psig.

b. TCV Fast Closure, Trip Oil Pressure C Low: 2 42 psig.

SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, 24 months including breaker actuation.

SR 3.3.4.1.5 Verify TSV Closure, Trip Oil 24 months Pressure C Low and TCV Fast Closure, Trip Oil Pressure C Low Functions are not bypassed when THERMAL POWER is 2 35.4% RTP.

(continued)

GRAND GULF 3.3-27 Amendment No. ~, -+/--9-+/--

EOC-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.4. 1. 6 ------------------NOTE-------------------

Breaker interruption time may be assumed from the most recent performance of SR 3.3.4.1.7.

Verify the EOC-RPT SYSTEM RESPONSE TIME 24 months on a is within limits. STAGGERED TEST BASIS SR 3.3.4.1.7 Determine RPT breaker interruption time. 60 months GRAND GULF 3.3-28 Amendment No. ~, ~

ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4.2.3 Calibrate the trip units. 92 days SR 3.3.4.2.4 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Reactor Vessel Water LevelCLow Low, Level 2: 2 -43.8 inches; and

b. Reactor Vessel Pressure C High:

S; 1139 psig.

SR 3.3.4.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST, 24 months including breaker actuation.

GRAND GULF 3.3-31 Amendment No. ~

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 3.c, 3.f, 3.g, and 3.h; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions other than 3.c, 3.f, 3.g, and 3.h, provided the associated Function or the redundant Function maintains ECCS initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.1.3 Calibrate the trip unit. 92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.1.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-38 Amendment No. ~

RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 2 and 5; and (b) for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for Functions 1, 3, and 4 provided the associated Function maintains RCIC initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.3 Calibrate the trip units. 92 days SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-46 Amendment No.-hW

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.1.3 Calibrate the trip unit. 92 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.1.5 Perform CHANNEL CALIBRATION. 12 months SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 18 months SR 3.3.6.1.7 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.1.8 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months (contlnued)

GRAND GULF 3.3-53 Amendment No. ~, +eJ.

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.6.1.9 -------------------NOTE-----------------

Channel sensors may be excluded.

Verify the ISOLATION SYSTEM RESPONSE TIME 24 months on a for the Main Steam Isolation Valves is STAGGERED TEST within limits. BASIS SR 3.3.6.1.10 -------------------NOTE------------------

Only required to be performed when Function S.b is not OPERABLE as allowed by NOTE (h) of Table 3.3.6.1-1.

Verify the water level in the Upper 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Containment Pool is Z 22 feet, 8 inches above the reactor pressure vessel flange.

GRAND GULF 3.3-53a Amendment No. ~

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 1 of 5)

Primary Containment and Drywell Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED REQUIRED SURVEILLANCE ALLOWABL PER TRIP E FUNCTION CONDITIONS SYSTEM ACTION C.I REQUIREMENTS VALUE

1. Main Steam Line Isolation

a. Reactor Vessel Water 1,2,3 2 D SR 3.3.6.1.1 ~-152.5 Level C Low Low Low, SR 3.3.6.1.2 inches Levell SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 SR 3.3.6.1.9

b. Main Steam Line 2 E SR 3.3.6.1.1 ~ 837 psig Pressure C Low SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 SR 3.3.6.1.9

c. Main Steam Line 1,2,3 2 perMSL D SR 3.3.6.1.1 ::; 255.9 Flowc High SR 3.3.6.1.2 psid SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 SR 3.3.6.1.9

d. Condenser Vacuum C Low 1,2(a), 2 D SR 3.3.6.1.1 ~ 8.7 SR 3.3.6.1.2 inches 3(a) SR 3.3.6.1.3 Hgvacuum SR 3.3.6.1.7 SR 3.3.6.1.8

e. Main Steam Tunnel 1,2,3 2 D SR 3.3.6.1.1 ::; 191°F Ambient SR 3.3.6.1.2 Temperature C High SR 3.3.6.1.5 SR 3.3.6.1.8

f. Manual Initiation 1,2,3 2 G SR 3.3.6.1.8 NA

2. Prima Containment and dl Drywe 1 Isolation

a. Reactor Vessel Water 1,2,3 2(b) H SR 3.3.6.1.1 ~ -43.8 Level C Low Low, Level 2 SR 3.3.6.1.2 inches SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 (continued)

(a) With any turbine stop valve not closed.

(b) Also required to initiate the associated drywell isolation function.

GRAND GULF 3.3-54 Amendment No. ~, l-9+/-

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 2 of 5)

Primary Containment and Drywell Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED SPECIFIED CHANNELS FROM CONDITION PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION S SYSTEM ACTION C.I REQUIREMENTS VALUE

2. primaill Containment and Drywe 1 Isolation (continued)

b. Drywell Pressure C High 1,2,3 2(b) H SR 3.3.6.1.1 ::; 1.43 psig SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

c. Reactor Vessel 1,2,3 2(b) F SR 3.3.6.1.1 ~-152.5 WaterLevel C Low Low SR 3.3.6.1.2 inches Low, SR 3.3.6.1.3 Level 1 (ECCS SR 3.3.6.1.7 Divisions 1 and 2) SR 3.3.6.1.8

d. DftCell Pressure C High 1,2,3 2 F SR 3.3.6.1.1 ::; 1.44 psig (E CS Divisions 1 SR 3.3.6.1.2 and 2) SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

e. Reactor Vessel Water 1,2,3 4 F SR 3.3.6.1.1 ~ -43.8 Level C Low Low, Level SR 3.3.6.1.2 inches 2 (HPCS) SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

f. D~ell Pressure C High 1,2,3 4 F SR 3.3.6.1.1 ::; 1.44 psig (H CS) SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

g. Containment and Drywell 1,2,3 2(b) F SR 3.3.6.1.1 ::;4.0 mR/hr Ventilation Exhaust SR 3.3.6.1.2 Radiation C High SR 3.3.6.1.5 SR 3.3.6.1.6 I (c) 2 K SR 3.3.6.1.1 ::;4.0 mRJhr SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6

h. Manual Initiation 1,2,3 2(b) G SR 3.3.6.1.8 NAI (c) 2 G SR 3.3.6.1.8 NAI (contmued)

(b) Also required to initiate the associated drywell isolation function.

(c) During movement of recently irradiated fuel assemblies in primary or secondary containment and operations with a potential for draining the reactor vessel.

GRAND GULF 3.3-55 Amendment No. RQ,H9

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 3 of 5)

Primary Containment and Drywell Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER RE~RED FROM SPECIFIED CHA ELS REf>yUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS PER TRIP ACT ON C.I REQUIREMENTS VALUE SYSTEM

3. Reactor Core Isolation Cooling (RCIC) System Isolation

a. RCIC Steam Line 1,2,3 F SR 3.3.6.1.1 :::: 64 inches Flowc High SR 3.3.6.1.2 water SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

b. RCIC Steam Line Flow 1,2,3 F SR 3.3.6.1.2 :::: 3 seconds and Time Delay SR 3.3.6.1.4 :::: 7 seconds 1,2(d),3(d)

SR 3.3.6.1.8 I

c. RCIC Steam SU~ly F SR 3.3.6.1.1 :::: 53 psig Line Pressure C ow SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

d. RCIC Turbine Exhaust 1,2,3 2 F SR 3.3.6.1.1 :::: 20 psig D~hragm Pressure SR 3.3.6.1.2 c Igh SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

e. RCIC Equipment Room 1,2,3 F SR 3.3.6.1.1 :::: 191EF Ambient SR 3.3.6.1.2 Temperature C High SR 3.3.6.1.5 SR 3.3.6.1.8 I

f. Main Steam Line 1,2,3 F SR 3.3.6.1.1 :::: 191EF Tunnel Ambient SR 3.3.6.1.2 Temperature C High SR 3.3 .6.1.5 SR 3.3.6.1.8

g. Main Steam Line 1,2,3 F SR 3.3.6.1.2 :::: 30 minutes Tunnel Temperature SR 3.3.6.1.4 Timer SR 3.3.6.1.8 I

h. RHR Equipment Room 1,2,3 I per room F SR 3.3.6.1.1 :::: 171EF Ambient SR 3.3.6.1.2 Temperature C High SR 3.3.6.1.5 SR 3.3.6.1.8

i. RCIC/RHR Steam Line 1,2,3 F SR 3.3.6.1.1 :::: 43 inches Flow-High SR 3.3.6.1.2 water SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 (continued)

(d)

Not required to be OPERABLE in MODE 2 or 3 with reactor steam dome pressure less than 150 psig during reactor startup.

GRAND GULF 3.3-56 Amendment No. 121:), ill

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 4 of 5)

Primary Containment and Drywell Isolation Instrumentation APPLICABLE CONDITIONS MODES OR OTHER RE~D REFERENCED SPECIFIED CH EL FROM SURVEILLANC CONDITION S PER TRIP ACT REgUlRED E ALLOWABLE FUNCTION S SYSTEM ON C.I REQUIREMENT VALUE S

3. RCIC System Isolation (continued)

j. Drywell Pressure C High 1,2,3 F SR 3.3.6.1.1 ~ 1.44 psig SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

k. Manual Initiation 1,2,3 G SR 3.3.6.1.8 NA

4. Reactor Water Cleanup (RWCU) System Isolation

a. Differential Flow C High 1,2,3 F SR 3.3.6.1.1 ~ 89 gpm SR 3.3.6.1.2 SR 3.3.6.1.7 SR 3.3.6.1.8

b. Differential FlowC 1,2,3 F SR 3.3.6.1.2 ~ 57 seconds Timer SR 3.3.6.1.4 SR 3.3.6.1.8 I

c. RWCU Heat Exchanger 1,2,3 F SR 3.3.6.1.1 ~ 126EF Equipment Room SR 3.3.6.1.2 Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.8 I

d. RWCU Pump Room 1,2,3 I per room F SR 3.3.6.1.1 ~ 176EF Temperature - High SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.8 I

e. RWCU Heat Exchanger 1,2,3 F SR 3.3.6.1.1 ~ 141EF Room Valve Nest SR 3.3.6.1.2 Area Temperature - High SR 3.3.6.1.5 SR 3.3.6.1.8 I

f. Main Steam Line Tunnel 1,2,3 F SR 3.3.6.1.1 ~ 191EF Ambient Temperature- SR 3.3.6.1.2 High SR 3.3.6.1.5 SR 3.3.6.1.8

g. Reactor Vessel Water 1,2,3 2 F SR 3.3.6.1.1 ~ -43.8 inches Level C Low Low, Level 2 SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

h. Standby Liquid Control 1,2 SR 3.3.6.1.8 NA System Initiation

i. Manual Initiation 1,2,3 2 G SR 3.3.6.1.8 NA (contInued)

GRAND GULF 3.3-57 Amendment No. ~

Primary Containment and Drywell Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 5 of 5)

Primary Containment and Drywell Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REFERENCED OTHER REQUIRED FROM SPECIFIED CHANNELS RERUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS PER TRIP ACT ONC.1 REQUIREMENTS VALUE SYSTEM

5. RHR System Isolation

a. RHR Equipment Room 1,2,3 1 per room F SR 3.3.6.1.1 :s 171EF Ambient SR 3.3.6.1.2 Temperature C High SR 3.3.6.1.5 SR 3.3.6.1.8

b. Reactor Vessel Water 1,2,3(f) 2 F SR 3.3.6.1.1 2: 10.8 inches Level C Low, Level 3 SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 3(g),4,5(h) 2(e) J SR 3.3.6.1.1 2: \ 0.8 inches SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.6 SR 3.3.6.1.7 SR 3.3.6.1.10

c. Reactor Steam Dome 1,2,3 2 F SR 3.3.6.1.1 :s 150 psig Pressure C High SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8

d. Drywell Pressure C High 1,2,3 2 F SR 3.3.6.1.1 :s 1.43 psig SR 3.3.6.1.2 SR 3.3.6.1.3 SR 3.3.6.1.7 SR 3.3.6.1.8 I

e. Manual Initiation 1,2,3 2 G SR 3.3.6.1.8 N!

(e) Only one trip system required in MODES 4 and 5 with RHR Shutdown Cooling System integrity maintained.

(f) With reactor steam dome pressure greater than or equal to the RHR cut-in permissive pressure.

(g) With reactor steam dome pressure less than the RHR cut-in permissive pressure.

(h) Not applicable when the upper containment reactor cavity and transfer canal gates are removed and SR 3.3.6.1.10 is met.

GRAND GULF 3.3-58 Amendment No. +&2-,~

Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.2.3 Calibrate the trip unit. 92 days SR 3.3.6.2.4 Perform CHANNEL CALIBRATION. 12 months SR 3.3.6.2.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.2.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.6.2.7 ------------------NOTE-------------------

Radiation detectors may be excluded.

Verify the ISOLATION SYSTEM RESPONSE TIME 24 months on a for air operated Secondary Containment STAGGERED TEST isolation dampers is within limits. BASIS GRAND GULF 3.3-61 Amendment No. hU:)

RHR Containment Spray System Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.6.3-1 to determine which SRs apply for each RHR Containment Spray System Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RHR containment spray initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.3.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.3.3 Calibrate the trip unit. 92 days SR 3.3.6.3.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.3.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.3.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-65 Amendment No. ~

SPMU System Instrumentation 3.3.6.4 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.6.4-1 to determine which SRs apply for each SPMU Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains SPMU initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.4.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.6.4.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.4.3 Calibrate the trip unit. 92 days SR 3.3.6.4.4 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.4.5 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.4.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-69 Amendment No. ~

SPMU System Instrumentation 3.3.6.4 SURVEILLANCE REQUIREMENTS

NOTE-------------------------------------

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains LLS or relief initiation capability, as applicable.

SURVEILLANCE FREQUENCY SR 3.3.6.5.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.5.2 Calibrate the trip unit. 92 days SR 3.3.6.5.3 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Relief Function Low: 1103 V 15 psig Medium: 1113 V 15 psig High: 1123 V 15 psig

b. LLS Function Low open: 1033 V 15 psig close: 926 V 15 psig Medium open: 1073 V 15 psig close: 936 V 15 psig High open: 1113 V 15 psig close: 946 V 15 psig SR 3.3.6.5.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-72 Amendment No. ~

CRFA System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS

NOTE-------------------------------------

When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided CR isolation capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-75 Amendment No. -l-W, ~

LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS

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

1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains DG initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 18 months SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 24 months SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months GRAND GULF 3.3-78 Amendment No. ~

LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)

Loss of Power Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCTION DIVISION REQUIREMENTS VALUE

1. Divisions 1 and 2 C 4.16 kV Emergency Bus Undervoltage

a. Loss of Voltage C 4.16 kV 4 SR 3.3.8.1.1 2': 2621 V and ~ 2912 V basis SR 3.3.8.1.2 SR 3.3.8.1.4

b. Loss of Voltage C Time 2 SR 3.3.8.1.3 2': 0.4 seconds and ~ 1.0 seconds Delay SR 3.3.8.1.4

c. Degraded Voltage C 4.16 kV 4 SR 3.3.8.1.1 2': 3744 V and ~ 3837.6 V basis SR 3.3.8.1.2 SR 3.3.8.1.4

d. Degraded Voltage C Time 2 SR 3.3.8.1.3 2': 8.5 seconds and ~ 9.5 seconds Delay SR 3.3.8.1.4

2. Division 3 C 4.16 kV Emergency Bus Undervoltage

a. Loss of Voltage C 4.16 kV 4 SR 3.3.8.1.3 2': 2984 V and ~ 3106 V basis SR 3.3.8.1.4

b. Loss of Voltage C Time 2 SR 3.3.8.1.3 2': 2.0 seconds and ~ 2.5 seconds Delay SR 3.3.8.1.4

c. Degraded Voltage C 4.16 kV 4 SR 3.3.8.1.3 2': 3558.5 V and ~ 3763.5 V basis SR 3.3.8.1.4

d. Degraded Voltage C Time 2 SR 3.3.8.1.3 2': 4.5 minutes and ~ 5.5 minutes Delay, No LOCA SR 3.3.8.1.4

e. Degraded Voltage C Time 4 SR 3.3.8.1.3 2': 3.6 seconds and ~ 4.4 seconds Delay, LOCA SR 3.3.8.1.4 GRAND GULF 3.3-79 Amendment No. ~

RPS Electric Power Monitoring 3.3.8.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Overvoltage Bus A :0; 132.9 V Bus B :0; 133.0 V

b. Undervoltage Bus A ~ 115.0 V Bus B ~ 115.9 V

c. Under frequency (with time delay set to :0; 4 seconds)

Bus A ~ 57 Hz Bus B ~ 57 Hz SR 3.3.8.2.3 Perform a system functional test. 24 months GRAND GULF 3.3-82 Amendment No. ~

FCVs 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 Flow Control Valves (FCVs)

LCO 3.4.2 A recirculation loop FCV shall be OPERABLE in each operating recirculation loop.

APPLICABILITY: MODES 1 and 2.

ACTIONS

NOTE------------------------------------

Separate Condition entry is allowed for each FCV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or two required FCVs A.l Lock up the FCV. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months inoperable.

8. Required Action and associated 8.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1 Verify each FCV fails "as is" on loss of hydraulic pressure at 24 months the hydraulic unit.

(continued)

GRAND GULF 3.4-6 Amendment No.-h?,()

FCVs 3.4.2 SURVEILLANCE REQUIREMENTS (continued SURVEILLANCE FREQUENCY SR 3.4.2.2 Verify average rate of each FCV movement is: 24 months

a. :s 11 % of stroke per second for opening; and

b. :s 11 % of stroke per second for closing.

GRAND GULF 3.4-7 Amendment No. ~

S/RVs 3.4.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.4.4.2 -------------------NOTE--------------------

Valve actuation may be excluded.

Verify each required relief function S/RV actuates on an actual 24 months or simulated automatic initiation signal.

SR 3.4.4.3 -------------------NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify each required S/RV relief-mode actuator strokes when manually actuated. In accordance with the Inservice Testing Program on a STAGGERED TEST BASIS for each valve solenoid GRAND GULF 3.4-11 Amendment No. ~, HG

Res Leakage Detection Instrumentation 3.4.7 ACTIONS (continued) I CONDITION REQUIRED ACTION COMPLETION TIME E. Required drywell E.1 Restore required drywell 30 days atmospheric monitoring atmospheric monitoring system inoperable. system to OPERABLE status.

AND OR 30 days Drywell air cooler E.2 Restore drywell air cooler condensate flow rate condensate flow rate monitoring system monitoring system to inoperable. OPERABLE status.

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

G. All required leakage G.1 Enter LCO 3.0.3 Immediately detection systems inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.7.1 Perform CHANNEL CHECK of required drywell 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months atmospheric monitoring system.

SR 3.4.7.2 Perform CHANNEL FUNCTIONAL TEST of required 31 days leakage detection instrumentation.

SR 3.4.7.3 Perform CHANNEL CALIBRATION of required leakage 24 months detection instrumentation.

GRAND GULF 3.4-18 Amendment No. ~, -+/--8-+

ECCS - Operati ng 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1. 5 -------------------NOTE------------------

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.

SR 3.5.1. 6 -------------------NOTE------------------

Valve actuation may be excluded.

Verify the ADS actuates on an actual or 24 months simulated automatic initiation signal.

SR 3.5.1. 7 -------------------NOTE--------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify each ADS valve relief-mode actuator In accordance strokes when manually actuated. with the Inservice Testing Program on a STAGGERED TEST BASIS for each valve solenoid SR 3.5.1. 8 --------------Note-------------------------

ECCS Actuation instrumentation is excluded.

Verify the ECCS RESPONSE TIME for the HPCS 24 months System is within limits.

GRAND GULF 3.5-5 Amendment No. 120,130,~

ECCS - Operati ng 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.2.5 Verify each required ECCS pump develops the In accordance specified flow rate with the specified with the total developed head. Inservice Testing Program TOTAL SYSTEM FLOW RATE DEVELOPED HEAD LPCS ~ 7115 gpm ~ 290 psid LPCI ~ 7450 gpm ~ 125 psid HPCS ~ 7115 gpm ~ 445 psid SR 3.5.2.6 ----------------NOTE-------------------

Vessel injection/spray may be excluded.

Verify each required ECCS injection/spray 24 months subsystem actuates on an actual or simulated automatic initiation signal.

GRAND GULF 3.5-9 Amendment No. ~, ~ I

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System plplng is filled 31 days with water from the pump discharge valve to the injection valve.

SR 3.5.3.2 Verify each RCIC System manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.3.3 -------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with RCIC steam supply pressure 92 days

~ 1045 psig and ~ 945 psig, the RCIC pump can develop a flow rate ~ 800 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.4 -------------------NOTE-------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perform the test.

Verify, with RCIC steam supply pressure 24 months

~ 165 psig and ~ 150 psig, the RCIC pump can develop a flow rate ~ 800 gpm against a system head corresponding to reactor pressure.

(continued)

GRAND GULF 3.5-11 Amendment No. +/-re

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.3.5 ----------------NOTE---------------------

Vessel injection may be excluded.

Verify the RCIC System actuates on an 24 months actual or simulated automatic initiation signal.

GRAND GULF 3.5-12 Amendment No. !r9

Primary Containment Air Locks 3.6.1.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.2.3 Verify only one door in the primary containment air lock can 24 months be opened at a time.

SR 3.6.1.2.4 Verify, from an initial pressure of 24 months 90 psig, the primary containment air lock seal pneumatic system pressure does not decay at a rate equivalent to

> 2 psig for a period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

GRAND GULF 3.6-8 Amendment No. ~,-l4!

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.3.6 Verify the isolation time of each MSIV is 2: 3 seconds and:::: 5 In accordance with the seconds. Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position 24 months on an actual or simulated isolation signal.

SR 3.6.1.3.8 ------------------NOTE-------------------

Only required to be met in MODES 1,2, and 3.

Verify leakage rate through each main steam line is :::: 100 scth when tested at In accordance 2: Pa, and the total leakage rate through all four main with 10 CFR 50, steam lines is :::: 250 scth when tested at 2: Pa . Appendix J, Testing Program SR 3.6.1.3.9 ------------------NOTE-------------------

Only required to be met in MODES 1, 2, and 3.

Verify combined leakage rate of 1 gpm times the total number of PCIVs through hydrostatically tested lines that penetrate In accordance the primary containment is not exceeded when these isolation with 10 CFR 50, valves are tested at 2: 1.1 P a . Appendix J, Testing Program GRAND GULF 3.6-17 Amendment No. .rn ~

LLS Valves 3.6.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 ------------------NOTE-------------------

Not required to be perfonned until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure and flow are adequate to perfonn the test.

Verify each LLS valve relief-mode actuator strokes when manually actuated. In accordance with the Inservice Testing Program on a STAGGERED TEST BASIS for each valve solenoid SR 3.6.1.6.2 ------------------NOTE-------------------

Valve actuation may be excluded.

Verify the LLS System actuates on an actual or simulated 24 months automatic initiation signal.

GRAND GULF 3.6-21 Amendment No. -HQ, ~

RHR Containment Spray System 3.6.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.7.1 ------------------NOTE-------------------

RHR containment spray subsystems may be considered OPERABLE during alignment and operation for decay heat removal when below the RHR cut in permissive pressure in MODE 3 ifcapable of being manually realigned and not otherwise inoperable.

Verify each RHR containment spray subsystem manual, power operated, and automatic valve in the flow path that is 31 days not locked, sealed, or otherwise secured in position is in the correct position.

SR 3.6.1.7.2 Verify each RHR pump develops a flow rate of~ 7450 gpm In on recirculation flow through the associated heat exchanger to accordance the suppression pool. with the Inservice Testing Program SR 3.6.1.7.3 Verify each RHR containment spray subsystem automatic 24 months valve in the flow path actuates to its correct position on an actual or simulated automatic initiation signal.

GRAND GULF 3.6-23 Amendment No. ~

MSIVLCS 3.6.1.9 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.9.2 Deleted not applicable SR 3.6.1.9.3 Perfonn a system functional test of each MSIV LCS 24 months subsystem.

GRAND GULF 3.6-26 Amendment No. ~~

SPMU System 3.6.2.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.4.1 Verify upper containment pool water level is 2: 23 ft 3 inches 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months above the pool bottom.

SR 3.6.2.4.2 Verify upper containment pool water temperature is::::: 125EF. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.6.2.4.3 Verify each SPMU subsystem manual, power operated, and 31 days automatic valve that is not locked, sealed, or otherwise secured in position is in the correct position.

NOTE-------------------

The requirements of this SR are not required to be met when all upper containment pool levels are maintained per SR 3.6.2.4.1 and suppression pool water level is maintained 2: 18 ft 5 1/12 inches (one inch above LCO 3.6.2.2 Low Water Level).

SR 3.6.2.4.4 Verify all upper containment pool gates are in the stored position or are otherwise removed from the upper 31 days containment pool.

SR 3.6.2.4.5 ------------------NOTE-------------------

Actual makeup to the suppression pool may be excluded.

Verify each SPMU subsystem automatic valve actuates to the correct position on an actual or simulated automatic initiation 24 months signal.

GRAND GULF 3.6-34 Amendment No. ~.f.M.

Primary Containment and Drywell Hydrogen Igniters 3.6.3.2 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated C.l Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.2.1 Energize each primary containment and drywell hydrogen 184 days igniter division and perform current versus voltage measurements to verify required igniters in service.

SR 3.6.3.2.2 ------------------NOTE-------------------

Not required to be performed until 92 days after discovery of four or more igniters in the division inoperable.

Energize each primary containment and drywell hydrogen igniter division and perform current versus voltage 92 days measurements to verify required igniters in service.

SR 3.6.3.2.3 Verify each required igniter in inaccessible areas develops 24 months sufficient current draw for a 2: 1700EF surface temperature.

(continued)

GRAND GULF 3.6-38 Amendment No. ~

Primary Containment and Drywell Hydrogen Igniters 3.6.3.2 SURVEILLANCE RE SURVEILLANCE FREQUENCY SR 3.6.3.2.4 Verify each required igniter in accessible areas develops a 24 months surface temperature of2: l700EF.

GRAND GULF 3.6-39 Amendment No. ~

Drywell Purge System 3.6.3.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.3.1 Perfonn a CHANNEL FUNCTIONAL TEST of the isolation 31 days valve pressure actuation instrumentation.

SR 3.6.3.3.2 Operate each drywell purge subsystem for:::: 15 minutes. 92 days SR 3.6.3.3.3 Verify each drywell purge subsystem 24 months flow rate is :::: 1000 cfm.

SR 3.6.3.3.4 Verify the opening pressure differential of each vacuum 24 months breaker and isolation valve is:S 1.0 psid.

GRAND GULF 3.6-41 AmendmentNo.+W

Secondary Containment 3.6.4.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.4.1.3 Verify the secondary containment can be drawn down to :::: 24 months on a 0.25 inch of vacuum water gauge in:S 180 seconds using one STAGGERED TEST standby gas treatment (SGT) subsystem. BASIS for each SGT subsystem SR 3.6.4.1.4 Verify the secondary containment can be maintained:::: 0.266 24 months on a inch of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months using one SGT STAGGERED TEST subsystem at a flow rate :s 4000 cfm. BASIS for each SGT subsystem GRAND GULF 3.6-44 Amendment No. -l4.), +e9-

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

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

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

Verify each secondary containment isolation manual valve, damper, rupture disk, and blind flange that is required to be closed during accident conditions is closed. 31 days SR 3.6.4.2.2 Verify the isolation time of each power operated, automatic In accordance SCIV is within limits. with the Inservice Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation position 24 months on an actual or simulated automatic isolation signal.

GRAND GULF 3.6-48 Amendment No. ~,139

SGT System 3.6.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for 2: 10 continuous hours with 31 days heaters operating.

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

GRAND GULF 3.6-51 Amendment No. ~

Drywell Isolation Valves 3.6.5.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.5.3.3 Verify the isolation time of each power operated, automatic In accordance drywell isolation valve is within limits. with the Inservice Testing Program SR 3.6.5.3.4 Verify each automatic drywell isolation valve actuates to the 24 months isolation position on an actual or simulated isolation signal.

GRAND GULF 3.6-61 Amendment No. RG, +e9

Drywell Vacuum Relief System 3.6.5.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.5.6.1 -----------------NOTES-------------------

1. Not required to be met for vacuum breakers or isolation valves open during surveillances.

2. Not required to be met for vacuum breakers or isolation valves open when performing their intended function.

Verify each vacuum breaker and its associated isolation valve is closed.

7 days SR 3.6.5.6.2 Perform a functional test of each vacuum breaker and its 31 days associated isolation valve.

SR 3.6.5.6.3 Verify the opening pressure differential of each vacuum 24 months breaker and isolation valve is :::; 1.0 psid.

GRAND GULF 3.6-67 Amendment No. ~

SSW System and UHS 3.7.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.7.1. 3 Verify each required SSW subsystem manual, 31 days power operated, and automatic valve in the flow path servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.1.4 Verify each SSW subsystem actuates on an 24 months actual or simulated initiation signal.

GRAND GULF 3.7-4 Amendment No. Tr9

HPCS SWS 3.7.2 3.7 PLANT SYSTEMS 3.7.2 High Pressure Core Spray (HPCS) Service Water System (SWS)

LCO 3.7.2 The HPCS SWS shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. HPCS SWS inoperable. A.1 Declare HPCS System Immediately inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 Verify each required HPCS SWS manual, power 31 days operated, and automatic valve in the flow path servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.2.2 Verify the HPCS SWS actuates on an actual 24 months or simulated initiation signal.

GRAND GULF 3.7- 5 Amendment No. +/-re

CRFA SYSTEM 3.7.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Two CRFA subsystems E.1 Enter LCO 3.0.3. Immediately inoperable in MODE 1, 2, or 3 for reasons other than Condition B.

F. Two CRFA subsystems F.1 Initiate action to Immediately inoperable during suspend OPDRVs.

OPDRVs.

OR One or more CRFA subsystems inoperable due to inoperable CRE boundary duri ng OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 Operate each CRFA subsystem for ~ 10 31 days continuous hours with the heaters operating.

SR 3.7.3.2 Perform required CRFA filter testing in In accordance accordance with the Ventilation Filter with the VFTP Testing Program (VFTP).

SR 3.7.3.3 Verify each CRFA subsystem actuates on an 24 months actual or simulated initiation signal.

SR 3.7.3.4 Perform required CRE unfiltered air In accordance inleakage testing in accordance with the with the Control Room Envelope Habitability Control Room Program. Envelope Habitability Program GRAND GULF 3.7-8 Amendment No. +/-45, fT8

Control Room AC System 3.7.4 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. Required Action and E.1 Initiate action to Immediately associated Completion suspend OPDRVs.

Time of Condition B not met during OPDRVs.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.4.1 Verify each control room AC subsystem has 24 months the capability to remove the assumed heat load.

GRAND GULF 3.7-11 Amendment No. ~, ~

AC Sources-operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.8 -----------------NOTE----------------------

This Surveillance shall not be performed in MODE 1 and 2.

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

Verify manual transfer of unit power supply from the normal 24 months offsite circuit to required alternate offsite circuit.

SR 3.8.1.9 -----------------NOTES---------------------

I. Credit may be taken for unplanned events that satisfy this SR.

2. If performed with the DG synchronized with offsite power, it shall be performed at a power factor:::: 0.9 for DG II and DG 13 and:::: 0.89 for DG 12. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG rejects a load greater than or equal to its associated single largest post accident load and engine speed is maintained less than nominal plus 75% of the difference between 24 months nominal speed and the overspeed setpoint or 15% above nominal, whichever is lower.

(continued)

GRAND GULF 3.8-7 Amendment No. +£, -l-69

AC Sources-operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.10 -------------------NOTE--------------------

I. Credit may be taken for unplanned events that satisfy this SR.

2. If performed with the DO synchronized with offsite power, it shall be performed at a power factor:S 0.9 for DO II and DO 13 :s 0.89 for DO 12. However, if grid conditions do not permit, the power factor limit is not required to be met.

Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DO does not trip and voltage is maintained:S 5000 V during and following a load rejection of a load 2: 5450 kW and

s 5740 kW for DO 11 and DO 12 and 2: 3300 kW for DO 13,.

24 months (continued)

ORANDOULF 3.8-8 AmendmentNo.~,+e9

AC Sources-operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.11 -------------------NOTES-------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1,2, or 3 (Not Applicable to DG 13). However, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated loss of offsite power signal:

a. De-energization of emergency buses; 24 months

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in S 10 seconds,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage 2: 3744 V and S 4576 V,

4. maintains steady state frequency 2: 58.8 Hz and S 61.2 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for 2: 5 minutes.

(continued)

GRAND GULF 3.8-9 Amendment No. 12Q,ill

AC Sources-operating 3.8.1 SURVEILLANCE RE SURVEILLANCE FREQUENCY SR 3.8.1.12 -------------------NOTES-------------------

I. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE I,or 2 (Not Applicable to DG 13). However, credit may be taken for unplanned events that satisfy this SR.

Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each DG auto-starts from standby condition and: 24 months

a. In :::: 10 seconds after auto-start and during tests, achieve voltage 2: 3744 V and frequency 2: 58.8 Hz;

b. Achieves steady state voltage 2: 3744 V and:::: 4576 V and frequency 2: 58.8 Hz and:::: 61.2 Hz;

c. Operates for 2: 5 minutes; and

d. Emergency loads are auto-connected to the offsite power system.

(continued)

GRAND GULF 3.8-10 Amendment No. ~,~,~

AC Sources-operating 3.8.1 SURVEILLANCE RE SURVEILLANCE FREQUENCY SR 3.8.1.13 ------------------NOTE---------------------

Credit may be taken for unplanned events that satisfy this SR.

Verify each DO's non-critical automatic trips are bypassed on an actual or simulated ECCS initiation signal. 24months (continued)

GRAND GULF 3.8-11 Amendment No. 153, ~

AC Sources-operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.14 -------------------NaTES-------------------

1. Momentary transients outside the load and power factor ranges do not invalidate this test.

2. Credit may be taken for unplanned events that satisfy this SR.

3. If performed with the DG synchronized with offsite power, it shall be performed at a power factor ~ 0.9 for DG 11 and DG 13 and ~ 0.89 for DG 12. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.

Verify each DG operates for:::: 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a. For DG 11 and DG 12 loaded:::: 5450 kW and ~ 5740 kW;and 24 months

b. ForDG 13:

1. For:::: 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded:::: 3630 kW, and

2. For the remaining hours of the test loaded:::: 3300 kW.

(continued)

GRAND GULF 3.8-12 Amendment No.~,-l69-

AC Sources--operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued SURVEILLANCE FREQUENCY SR 3.8.1.15 ------------------NOTES-------------------

1. This Surveillance shall be perfonned within 5 minutes of shutting down the DG after the DG has operated:::>: 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or until operating temperatures stabilized loaded

:>: 5450 kW and:s 5740 kW for DG 11 and DG 12, and

:>: 3300 kW for DG 13.

Momentary transients outside of the load range do not invalidate this test.

2. All DG starts may be preceded by an engine prelube period.

Verify each DG starts and achieves:

a. in:S 10 seconds, voltage:::>: 3744 V and frequency:::>: 58.8 Hz; and 24 months

b. steady state voltage:::>: 3744 V and:s 4576 V and frequency:::>: 58.8 Hz and:s 61.2 Hz.

(continued)

GRAND GULF 3.8-13 Amendment No. HG,~

AC Sources-Operating 3.8.1 SURVEILLANCE FREQUENCY SR 3.8.1.16 -------------------NOTE--------------------

This Surveillance shall not be performed in MODE I, 2, or 3 (Not Applicable to DG 13). However, credit may be taken for unplanned events that satisfy this SR.

Verify each DG:

24 months

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-Ioad operation.

(continued)

GRAND GULF 3.8-13a Amendment No. ~, +42-, +M

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.17 -------------------N OTE--------------------

Credit may be taken for unplanned events that satisfy this SR.

Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the 24 months test mode by:

a. Returning DG to ready-to-load operation; and

b. Automatically energizing the emergency loads from offsite power.

SR 3.8.1.18 ------------------NOTE--------------------

This Surveillance shall not be performed in MODE 1,2, or 3.

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

Verify interval between each sequenced load block is within

+/- 10% of design interval for each automatic load sequencer. 24 months (continued)

GRAND GULF 3.8-14 Amendment No. ~~

AC Sources-operating 3.8.1 SURVEILLANCE RE SURVEILLANCE FREQUENCY SR 3.8.1.19 -------------------NOTES-------------------

1. All DG starts may be preceded by an engine prelube period.

2. This Surveillance shall not be performed in MODE 1, 2, or 3 (Not Applicable to DG 13). However, credit may be taken for unplanned events that satisfy this SR.

Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

24 months

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in ::::

10 seconds,

2. energizes auto-connected emergency loads,

3. achieves steady state voltage ~ 3744 V and

4576 V,

4. achieves steady state frequency ~ 58.8 Hz and

61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for ~ 5 minutes.

GRAND GULF 3.8-15 Amendment No. ~, ~

DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.4.3 Verify battery cells, cell plates, and racks show no visual 24 months indication of physical damage or abnormal deterioration that could degrade battery performance.

SR 3.8.4.4 Remove visible corrosion and verify battery cell to cell and 24 months terminal connections are coated with anti-corrosion material.

SR 3.8.4.5 Verify battery connection resistance is:::: 1.5 E-4 ohm for inter- 24 months cell connections, :::: 1.5 E-4 ohm for inter-rack connections,

1.5 E-4 ohm for inter-tier connections, and:::: 1.5 E-4 ohm for terminal connections.

SR 3.8.4.6 Verify each Division 1 and 2 required battery charger supplies 24 months

400 amps at:::: 125 V for:::: 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months ; and the Division 3 battery charger supplies:::: 50 amps at:::: 125 V for:::: 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

(continued)

GRAND GULF 3.8-28 Amendment No. ~,~

Distribution Systems-Shutdown 3.8.8 SURVEILLANCE FREQUENCY SR 3.8.4.7 -------------------NOTES-------------------

1. SR 3.8.4.8 may be performed in lieu ofSR 3.8.4.7 once per 60 months.

2. This Surveillance shall not be performed in MODE 1,2, or 3 (not applicable to Division 3). However, credit may be taken for unplanned events that satisfy this SR.

Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test. 24 months (continued)

GRAND GULF 3.8-29 Amendment No. 120

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.7 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in Regulatory Guide 1.52, Revision 2, except that testing specified at a frequency of 18 months is required at a frequency of 24 months.

a. Demonstrate for each of the ESF systems that an inplace test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass < 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1975 at the system flowrate specified below +/- 10%:

ESF Ventilation System Flowrate SGTS 4000 cfm CRFA 4000 cfm

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ANSI N510-1975 at the system flowrate specified below +/- 10%:

ESF Ventilation System Flowrate SGTS 4000 cfm

c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 30DC and the relative humidity specified below:

ESF Ventilation System Penetration RH SGTS 0.5% 70%

(continued)

GRAND GULF 5.0-12 Amendment No. -144, -l# I

Attachment 5 GNRO-2012/00096 GL 91-04 Review to GNRO-2012/00096 Page 1 of 50

1. BACKGROUND Technical Specification (TS) Surveillance Requirement (SR) frequency changes are required to accommodate a 24-month fuel cycle for Grand Gulf Nuclear Station. The proposed changes associated with this submittal were evaluated in accordance with the guidance provided in NRC Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991. GL 91-04 provides NRC Staff guidance that identifies the types of information that must be addressed when proposing extensions of TS SR frequency intervals from 18 months to 24 months.

Historical surveillance test data and associated maintenance records were reviewed in evaluating the effect of these changes on safety. In addition, the licensing basis was reviewed to ensure it was not invalidated. Based on the results of these reviews, it is concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 to 24 months with the continued application of the SR 3.0.2 25% grace period.

GL 91-04 addressed steam generator inspections, which are not applicable to Grand Gulf and therefore are not discussed in this submittal. Additionally, the GL addressed interval extensions to leak rate testing pursuant to 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," which is also not addressed by the Grand Gulf submittal because individual leak testing requirements have been replaced by the Primary Containment Leakage Rate Testing Program.

2. EVALUATION In GL 91-04, the NRC provided generic guidance for evaluating a 24 month surveillance test interval for TS SRs. Attachment 1 of this submittal defines each step outlined by the NRC in GL 91-04 and prOVides a description of the methodology used by Grand Gulf to complete the evaluation for each specific TS SR line item. The methodology utilized in the GGNS drift analysis is the similar to the methodology used for previous plant submittals such as the River Bend, Perry Nuclear Power Plant, and for E.!. Hatch Nuclear Plant submittals. There have been minor revisions incorporated into the Grand Gulf drift design guide based on NRC comments or Requests for Additional Information from previous 24-Month Fuel Cycle Extension submittals, such as GGNS added the requirement that 30 samples were generally required to produce a statistically significant sample set.

For each of the identified surveillances, an effort was made to retrieve the five most recent surveillance test performances (Le., approximately seven years of history). This provided approximately three 30-month surveillance periods of data to identify any repetitive problems. It has been concluded, based on engineering judgment, that three 30 month periods provide adequate performance test history. In some instances, additional surveillance performances were included when insufficient data was available for adequate statistical analysis of instrument drift. Further references to performance history reflect evaluations of the five most recent performances available unless otherwise stated.

In addition to evaluating the historical drift associated with current 18-month calibrations, the failure history of each 18-month surveillance was also evaluated. With the extension of the testing frequency to 24 months, there will be a longer period between each surveillance performance. If a failure that results in the loss of the associated safety function should occur during the operating cycle that, would only be detected by the performance of the 18-month TS to GNRO-2012/00096 Page 2 of 50 SR, then the increase in the surveillance testing interval might result in a decrease in the associated function's availability. Furthermore, potential common failures of similar components tested by different surveillances were also evaluated. This additional evaluation determined whether there is evidence of repetitive failures among similar plant components.

The surveillance failures detailed with each SR exclude failures that:

(a) Did not impact a TS safety function or TS operability; (b) Are detectable by required testing performed more frequently than the 18 month surveillance being extended; or (c) Where the cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification or previously existing design deficiency, or that were subsequently re-performed successfully with no intervening corrective maintenance (e.g., plant conditions or malfunctioning measurement and test equipment (M&TE) may have caused aborting the test performance).

These categories of failures are not related to potential unavailability due to testing interval extension, and are therefore not listed or further evaluated in this submittal.

The following sections summarize the results of the failure history evaluation. The evaluation confirmed that the impact on system availability, if any, would be small as a result of the change to a 24-month testing frequency.

The proposed TS changes related to GL 91-04 test interval extensions have been divided into two categories. The categories are: (A) changes to surveillances other than channel calibrations, identified as "Non-Calibration Changes" and (8) changes involving the channel calibration frequency identified as "Channel Calibration Changes."

A. Non-Calibration Changes For the non-calibration 18-month surveillances, GL 91-04 requires the following information to support conversion to a 24-month frequency:

1) Licensees should evaluate the effect on safety of the change in surveillance intervals to accommodate a 24-month fuel cycle. This evaluation should support a conclusion that the effect on safety is small.

2) Licensees should confirm that historical maintenance and surveillance data do not invalidate this conclusion.

3) Licensees should confirm that the performance of surveillances at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle would not invalidate any assumption in the plant licensing basis.

In consideration of these confirmations, GL 91-04 provides that licensees need not quantify the effect of the change in surveillance intervals on the availability of individual systems or components.

The following non-calibration TS SRs are proposed for revision to a 24-month frequency. The associated qualitative evaluation is provided for each of these changes, which concludes that the effect on plant safety is small, that the change does not invalidate any assumption in the plant licensing basis, and that the impact, if any, on system availability is minimal from the to GNRO-2012/00096 Page 3 of 50 proposed change to a 24-month testing frequency. These conclusions have been validated by a review of the surveillance test history at Grand Gulf as summarized below for each SR.

TS 3.1.7 Standby Liquid Control (SLC) System SR 3.1.7.8 Verify flow through one SLC subsystem from pump into reactor pressure vessel.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

The flow path through one SLC subsystem is verified per SR 3.1.7.8 during every refueling outage on a staggered test basis. This test could inadvertently cause a reactor transient if performed with the unit operating. Therefore, to decrease the potential impact of the test, it is performed during outage conditions.

The SLC system is required to be operable in the event of a plant power failure, therefore the pumps, heaters, valves, and controls are powered from the standby ac power supply. The piping electric heat tracing is powered from the normal power supply. The pumps and valves are powered and controlled from separate buses and circuits so that a single failure will not prevent system operation .. The SLC pumps are tested in accordance with the In-service Testing Program per SR 3.1.7.7 to verify operability. Similarly, the temperature of the sodium pentaborate solution in the storage tank and the temperature of the pump suction piping are verified every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months in accordance with SR 3.1.7.2 and 3.1.7.3 to preclude precipitation of the boron solution. The equipment and tank containing the solution are installed in a room in which the air temperature is maintained within the range of 70°F to 100°F. In addition, an electrical resistance heater system provides a backup heat source to the environment and maintains the solution temperature at 85 F (automatic operation) to 95 F (automatic shutoff) to prevent precipitation of the sodium pentaborate from the solution during storage. In addition, SR 3.1.7.4 verifies the continuity of the charge in the explosive valves. These more frequent tests ensure that the SLC system remains operable during the operating cycle. Based on the inherent system and component reliability and the testing performed during the operating cycle, the impact, if any, from this change on system availability is small.

A review of the surveillance history verified that this subsystem had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the subsystem checks required by the other TS surveillances and the history of the subsystem failures, the impact of this change on safety, if any, is small.

TS 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves SR 3.1.8.3 Verify each SDV vent and drain valve:

a. Closes in S 30 seconds after receipt of an actual or simulated scram signal; and

b. Opens when the actual or simulated scram signal is reset.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR to GNRO-2012/00096 Page 4 of 50 ensures that the SDV vent and drain valves close in S 30 seconds after receipt of an actual or simulated scram signal and open when the actual or simulated scram signal is reset.

SR 3.1.8.2 requires that the SDV vent and drain valves be cycled fully closed and fully open every 92 days during the operating cycle, which ensures that the mechanical components and a portion of the valve logic remain operable. Additionally, it has been previously accepted that the failure rate of components is dominated by the mechanical components, not by the logic systems (refer to specific discussion in the Logic System Functional Test (LSFT) section below).

A review of the applicable Grand Gulf surveillance history demonstrated that the logic sUbsystem for the scram discharge volume vent and drain valves had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the manual cycling of the valves to ensure that the valves are operable, as required by SR 3.1.8.2, and the history of logic subsystem performance, the impact of this change on safety, if any, is small.

LOGIC SYSTEM FUNCTIONAL TESTS (LSFTs) and SELECTED CHANNEL FUNCTIONAL TESTS 3.3.1.1 Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.

(This test is essentially a Logic System Functional Test for the Reactor Mode Switch scram circuit. The justification for extending LSFTs is also valid for the extension of this SR.)

SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.2.1 Control Rod Block Instrumentation SR 3.3.2.1.8 Perform CHANNEL FUNCTIONAL TEST.

(This test is essentially a Logic System Functional Test for the Reactor Mode Switch rod block circuit. The justification for extending LSFTs is also valid for the extension of this SR.)

3.3.3.2 Remote Shutdown System Instrumentation SR 3.3.3.2.2 Verify each required control circuit and transfer switch is capable of performing the intended functions.

(This test is essentially a Logic System Functional Test for the transfer circuits associated with shifting indication and control from the control room to the remote shutdown panel. The justification for extending LSFTs is also valid for the extension of this SR.)

3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, including breaker actuation.

3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation SR 3.3.4.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST, including breaker actuation.

to GNRO-2012/00096 Page 5 of 50 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.6.1 Primary Containment and Drywell Isolation Instrumentation SR 3.3.6.1.7 Perform LOGIC SYSTEM FUNCTIONAL TEST.

Functions 1.a, b, c, d, e and f Functions 2.a, b, c, d, e, f and h Functions 3.a, b, c, d, e, f, g, h, i, j and k Functions 4.a, b, c, d, e, f, g, h, and i Functions 5.a, b, c, d and e.

3.3.6.2 Secondary Containment Isolation Instrumentation SR 3.3.6.2.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.6.3 Residual Heat Removal (RHR) Containment Spray System Instrumentation SR 3.3.6.3.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.6.4 Suppression Pool Makeup (SPMU) System Instrumentation SR 3.3.6.4.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.6.5 Relief and Low-Low Set (LLS) Instrumentation SR 3.3.6.5.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.

3.3.7.1 Control Room Fresh Air (CRFA) System Instrumentation SR 3.3.7.1.1 Perform LOGIC SYSTEM FUNCTIONAL TEST.

3.3.8.1 Loss of Power (LOP) Instrumentation SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST.

(All Functions) 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring SR 3.3.8.2.3 Perform a system functional test.

(This test is essentially a Logic System Functional Test for the RPS Electric Power Monitor circuits. The justification for extending LSFTs is also valid for this SR.)

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

Extending the surveillance test interval for the LSFTs and selected functional tests is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks, Channel Functional Tests, analog trip module calibration, and visual to GNRO-2012/00096 Page 6 of 50 confirmation of satisfactory operation (as applicable). This more frequent testing ensures that a major portion of the circuitry is operating properly and will detect significant failures within the instrument loop. Additionally, all of the above actuation instrumentation and logic, controls, monitoring capabilities, and protection systems, are designed to meet applicable reliability, redundancy, single failure, and qualification standards and regulations as described in the Grand Gulf Updated Safety Analysis Report (USAR). As such, these functions are designed to be highly reliable. Furthermore, as stated in the August 2, 1993 NRC Safety Evaluation Report relating to extension of the Peach Bottom Atomic Power Station, Unit Numbers 2 and 3 surveillance intervals from 18 to 24 months:

"Industry reliability studies for boiling water reactors (BWRs), prepared by the BWR Owners Group (NEDC-30936P) show that the overall safety systems' reliabilities are not dominated by the reliabilities of the logic systems, but by that of the mechanical components, (e.g., pumps and valves), which are consequently tested on a more frequent basis. Since the probability of a relay or contact failure is small relative to the probability of mechanical component failure, increasing the Logic System Functional Test interval represents no significant change in the overall safety system unavailability."

A review of the applicable Grand Gulf surveillance history demonstrated that the logic systems for these functions had six failures of the TS functions that would have been detected solely by the periodic performance of one of the above SRs.

On September 9,2010, Float Switch 1C11-N013C did not trip. Work Order 25002 found an actuating screw on a spare microswitch stuck on the micro switch arm. The work order adjusted the microswitch pivot arm and reperformed the surveillance procedure. The As left data was all within satisfactory limits.

On May 19, 2010, valve P45-F068 did not stroke closed during testing as required by Technical Specifications. Work Orders 236306 and 237204 were implemented to determine and repair the problem which prevented proper valve operation. Although no direct cause could be determined, the disassembly and reassembly of the actuator resulted in all sub-components that could cause upper piston seal blow-by and resultant actuator failure were replaced. Post maintenance diagnostics and testing determined proper and satisfactory valve operation. CRs 2010-03939 and 2010-03507 document this issue.

On May 15, 2010, valve 1D23-F591 did not stroke closed on a high drywell pressure initiation signal. Work Order 237327 was written to determine cause of failure. Troubleshooting by the work order failed to identify any obvious problem. After the troubleshooting the valve was retested satisfactorily. CR 2010-04089 documented this issue.

On March 29, 2007, the failure of Agastat relay 1E21AK108 prevented valve E12-F042A from opening. Work Order 00106508 determined the relay had failed and replaced the relay.

Retesting following the relay replacement was completed satisfactorily. CR 2007-01617 documented this issue.

On September 24,2002, four valves (1 P72-F123, 1P72-F124, 1P72-F126 and 1P45-F274) did not close on an isolation signal. It was determined that relay 1M71 R065, which controls all four valves, failed to de-energize with its plunger stuck in the energized position. MAl 321408 replaced the Agastat relay and performed satisfactory retesting with all Technical Specifications acceptance criteria met. CR 2002-1936 documented this issue.

to GNRO-2012/00096 Page 7 of 50 On September 18, 2002, an apparent failure of relay 1B21 HK023A prevented the proper operation of the Shutdown Cooling isolation logic for valve 1E12-F040. MAl 320958 was written to troubleshoot and subsequently replace the Agastat relay for 1B21 HK023A. Post replacement retesting was satisfactory for all Technical Specification requirements. CR 2002-01806 documented this issue.

For the September 9,2010, May 19, 2010, and May 15, 2010 issues, no similar failures are identified, therefore the failures are not repetitive in nature. No timed-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

For the September 24,2002, September 18, 2002 and March 29, 2007 issues, there are a total of four failures identified relative to Agastat relays over the review period. Of the four Agastat relay failures, one failure was Model EGPI, one was Model FGPD, one was Model EGPB, and one was Model EGPD. In all four Agastat relay failures, the defective relays were replaced. The Agastat Model EGPI failure occurred in 2002 and was in the RHR Valve Isolation logic for Division 1. The Agastat Model FGPD failure occurred in 2002 and was in the Drywell Chilled Water Supply and Return Lines and Equipment Drain Transfer Tank Pump Discharge Line Valve Isolation Logic for Division II. The Agastat EGPB failure occurred in 2005 and was in the Control Room HVAC B Breaker Logic in the LOP Division 2 Load Shed Test. The Agastat Model EGPD relay failure occurred in 2007 and was in the RHR A Containment Spray Initiation Logic Division 1. There does not appear to be any common cause for these failures and no time-based mechanisms are apparent in these failures based on the fact that the failures are in different plant systems and are spread out over a five year period with not more than two failures in anyone year. When considering the total number of Agastat relays in the various plant system applications, a total of four different relay failures over the review period is a small percentage of the total population of relays tested. Therefore, this failure is unique and an increase in the surveillance test interval will have an insignificant effect on system availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of portions of the circuits, and the history of logic system performance, and the corrective action for relay failures the impact of this change on safety, if any, is small.

RESPONSE TIME TESTS 3.3.1.1 Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.15 Verify the RPS RESPONSE TIME is within limits.

Functions 2.b and d, 3 ,4, 5, 6, 9 and 10 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation SR 3.3.4.1.6 Verify the EOC-RPT SYSTEM RESPONSE TIME is within limits.

3.3.6.1 Primary Containment and Drvwell Isolation Instrumentation SR 3.3.6.1.8 Verify the ISOLATION SYSTEM RESPONSE TIME for the Main Steam Isolation Valves is within limits.

Functions 1.a, b, and c to GNRO-2012/00096 Page 8 of 50 3.3.6.2 Secondary Containment Isolation Instrumentation SR 3.3.6.2.7 Verify the ISOLATION SYSTEM RESPONSE TIME for air operated Secondary Containment isolation dampers is within limits.

Functions 3 and 4 The "on a staggered test basis" surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. Extending the interval between response time tests is acceptable because the functions are verified to be operating properly throughout the operating cycle by the performance of Channel Checks and Channel Functional Tests (as applicable). This testing ensures that a significant portion of the circuitry is operating properly and will detect significant failures of this circuitry. Additional justification for extending the surveillance test interval is that these functions, inclUding the actuating logic, are designed to be single failure proof and, therefore, are highly reliable.

Furthermore, the Grand Gulf TS Bases (as well as the Improved Standard TS, NUREG-1434) states that the frequency of response time testing is based in part "upon plant operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent."

A review of the applicable Grand Gulf surveillance history demonstrated that the logic systems for these functions had no previous failures of TS reqUired system response times that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of portions of the circuits, and the history of logic system performance, the impact of this change on safety, if any, is small.

3.4.2 Flow Control Valves (FCVs)

SR 3.4.2.1 Verify each FCV fails "as is" on loss of hydraulic pressure at the hydraulic unit.

SR 3.4.2.2 Verify average rate of each FCV movement is:

a. S 11 % of stroke per second for opening; and

b. S 11 % of stroke per second for closing.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

For SR 3.4.2.1, the hydraulic power unit pilot operated isolation valves located between the servo valves and the common "open" and "close" lines are required to close on a loss of hydraulic pressure. When closed, these valves inhibit FCV motion by blocking hydraulic pressure from the servo valve to the common open and close lines as well as to the alternate subloop. This surveillance verifies the FCV lockup on a loss of hydraulic pressure.

For SR 3.4.2.2, the test ensures the overall average rate of FCV movement at all positions is maintained within the analyzed limits. Due to the nature of the control components in this application, there are no definable components or any timed-based conditions that could appreciably change the rate of change for opening or closing the FCV during the operating cycle. The FCV actuator has an inherent rate-limiting feature that will limit the resulting rate of to GNRO-2012/00096 Page 9 of 50 change of core flow and power to within safe limits in the event of an upscale or downscale failure of the valve position or velocity control system. The surveillance test interval is being increased from once every 18 months to once every 24 months, for a maximum of 30 months including the 25% grace period.

A review of the applicable Grand Gulf surveillance history demonstrated that the hydraulic power unit pilot operated lock out valves had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

Based on the reliability of the check valves and history of system performance, the impact of this change on safety, if any, is small.

3.4.4 Safety/Relief Valves lS/RVs)

SR 3.4.4.2 Verify each required relief function S/RV actuates on an actual or simulated automatic initiation signal.

The surveillance test interval of SR 3.4.4.2 is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

The required relief function S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test (Le., SR 3.4.4.2) is performed to verify the mechanical portions of the automatic relief function operate as designed when initiated either by an actual or simulated initiation signal. The LSFT in SR 3.3.6.5.4 overlaps this SR to provide complete testing of the safety function. Valve operability and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation by performance of SR 3.4.4.1. This verification proves that the valve was actually functioning when installed and that the mechanical valve components were in good condition. The valves are normally tested prior to or soon after startup; any failure of actual valve function would be noted and corrected prior to extended plant operation.

A review of the applicable Grand Gulf surveillance history demonstrated that the S/RVs had three previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

On October 13, 2008, the as-found set pressure to Main Steam Relief Valve 1B21-F041 E was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure. CR 2008-5174 was written to document the issue.

On April 4, 2007, the as-found set pressure to Main Steam Relief Valve 1B21-F051C was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure. CR 2007-1450 was written to document the issue.

On October 11,2005, the as-found set pressure to Main Steam Relief Valve 1B21-F047D was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure.

to GNRO-2012/00096 Page 10 of 50 The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

There are a total of three failures identified relative to Dikkers Model G-471.6 Relief Valves over the review period. Of the three identified failures, each involved a different Main Steam Relief Valve and each failure occurred during a different refueling cycle (Le., one failure in 2005, one in 2007 and one in 2008). In each case, the valve was replaced with a rotatable spare. No timed-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.5.1 / 3.5.2 EGGS-Operating / EGGS-Shutdown SR 3.5.1.5 Verify each EGGS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.

SR 3.5.1.6 Verify the ADS actuates on an actual or simulated automatic initiation signal.

SR 3.5.1.8 Verify the EGGS RESPONSE TIME for the HPGS System is within limits.

SR 3.5.2.6 Verify each required EGGS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

These EGGS and ADS functional tests (SR 3.5.1.5, SR 3.5.1.6 and SR 3.5.2.6) ensure that a system initiation signal (actual or simulated) to the automatic initiation logic will cause the systems or subsystems to operate as designed. SR 3.5.1.8 ensures that the HPGS System response time is less than or equal to the maximum value assumed in the accident analysis.

The EGGS network has built-in redundancy so that no single active failure prevents accomplishing the safety function of the EGGS. The pumps and valves associated with EGGS are tested quarterly in accordance with the In-service Testing (1ST) Program and SR 3.5.1.4 (some valves may have independent 1ST relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function. The tests proposed to be extended need to be performed during outage conditions since they have the potential to initiate an unplanned transient if performed during operating conditions.

A review of the applicable Grand Gulf surveillance history demonstrated that EGGS had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 11 of 50 3.5.3 RCIC System SR 3.5.3.4 Verify, with RCIC steam supply pressure s; 165 psig and;;:= 150 psig, the RCIC pump can develop a flow rate ;;:= 800 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.5 Verify the RCIC System actuates on an actual or simulated automatic initiation signal.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

These RCIC functional tests ensure that the system will operate as designed. The pumps and valves associated with RCIC system are tested quarterly in accordance with the In-service Testing Program (some valves may have independent relief justifying less frequent testing).

This testing ensures that the major components of the systems are capable of performing their design function.

A review of the applicable Grand Gulf surveillance history demonstrated that RCIC had no previous failures of these TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.1.2 Primary Containment Air Locks SR 3.6.1.2.4 Verify, from an initial pressure of 90 psig, the primary containment air lock seal pneumatic system pressure does not decay at a rate equivalent to > 2 psig for a period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR ensures that the primary containment air lock seal pneumatic system pressure does not decay at an unacceptable rate. System availability during the operating cycle is assured by:

the air lock seal air flask pressure is verified in SR 3.6.1.2.2 to be ; := 90 psig every 7 days to ensure that the seal system remains viable. In addition SR 3.6.1.2.3 verifies only one door in the primary containment air lock can be opened at one time every 24 months. Closure of a single door in the air lock is necessary to support containment OPERABILITY following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for entry into and exit from the primary containment.

A review of the applicable Grand Gulf surveillance history demonstrated that the drywell air lock valves had one previous failure of the TS function that would have been detected solely by the periodic performance of this SR.

On April 24, 2008, the as-found leakage rate of the Lower Containment Inner Door exceeded the Technical Specification allowable leakage rate values. A leak on a fitting to a pressure switch was found and fixed. After this repair the leakage rate was retested satisfactory. CR 2008-02008 documented this issue.

to GNRO-2012/00096 Page 12 of 50 The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

No similar failures are identified, therefore the failure is not repetitive in nature. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.1.3 Primary Containment Isolation Valves (PCIVs)

SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position on an actual or simulated isolation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. During the operating cycle, SR 3.6.1.3.4 requires automatic PCIV isolation times to be verified in accordance with the In-service Testing Program. Stroke testing of PCIVs tests a significant portion of the PCIV circuitry as well as the mechanical function, which will detect failures of this circuitry or failures with valve movement. The frequency of this testing is typically quarterly, unless approved relief has been granted justifying less frequent testing.

A review of the applicable Grand Gulf surveillance history demonstrated that the logic systems for these functions had five failures of the TS functions that would have been detected solely by the periodic performance of one of the above SRs.

On May 19, 2010, valve P45-F068 did not stroke closed during testing as required by Technical Specifications. Work Orders 236306 and 237204 were implemented to determine and repair the problem which prevented proper valve operation. Although no direct cause could be determined, the disassembly and reassembly of the actuator resulted in all sub-components that could cause upper piston seal blow-by and resultant actuator failure were replaced. Post maintenance diagnostics and testing determined proper and satisfactory valve operation. CRs 2010-03939 and 2010-03507 document this issue.

On May 15, 2010, valve 1D23-F591 did not stroke closed on a high drywell pressure initiation signal. Work Order 237327 was written to determine cause of failure. Troubleshooting by the work order failed to identify any obvious problem. After the troubleshooting the valve was retested satisfactorily. CR 2010-04089 documented this issue.

On March 29, 2007, the failure of Agastat relay 1E21AK108 prevented valve E12-F042A from opening. Work Order 00106508 determined the relay had failed and replaced the relay.

Retesting following the relay replacement was completed satisfactorily. CR 2007-01617 documented this issue.

to GNRO-2012/00096 Page 13 of 50 On September 24,2002, four valves (1P72-F123, 1P72-F124, 1P72-F126 and 1P45-F274) did not close on an isolation signal. It was determined that relay 1M71 R065, which controls all four valves, failed to de-energize with its plunger stuck in the energized position. MAl 321408 replaced the Agastat relay and performed satisfactory retesting with all Technical Specifications acceptance criteria met. CR 2002-1936 documented this issue.

On September 18, 2002, an apparent failure of relay 1B21 HK023A prevented the proper operation of the Shutdown Cooling isolation logic for valve 1E12-F040. MAl 320958 was written to troubleshoot and SUbsequently replace the Agastat relay for 1B21 HK023A. Post replacement retesting was satisfactory for all Technical Specification requirements. CR 2002-01806 documented this issue.

For the May 19, 2010 and May 15, 2010 issues, no similar failures are identified, therefore the failures are not repetitive in nature. No timed-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

For the March 29, 2007, September 24,2002 and September 18, 2002 issues, there are a total of four failures identified relative to Agastat relays over the review period. Of the four Agastat relay failures, one failure was Model EGPI, one was Model FGPD, one was Model EGPB, and one was Model EGPD. In all four Agastat relay failures, the defective relays were replaced. The Agastat Model EGPI failure occurred in 2002 and was in the RHR Valve Isolation logic for Division 1. The Agastat Model FGPD failure occurred in 2002 and was in the Drywell Chilled Water Supply and Return Lines and Equipment Drain Transfer Tank Pump Discharge Line Valve Isolation Logic for Division II. The Agastat EGPB failure occurred in 2005 and was in the Control Room HVAC B Breaker Logic in the LOP Division 2 Load Shed Test. The Agastat Model EGPD relay failure occurred in 2007 and was in the RHR A Containment Spray Initiation Logic Division 1. There does not appear to be any common cause for these failures and no time-based mechanisms are apparent in these failures based on the fact that the failures are in different plant systems and are spread out over a five year period with not more than two failures in anyone year. When considering the total number of Agastat relays in the various plant system applications, a total of four different relay failures over the review period is a small percentage of the total population of relays tested. Therefore, this failure is unique and an increase in the surveillance test interval will have an insignificant effect on system availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of portions of the circuits, and the history of logic system performance, and the corrective action for relay failures the impact of this change on safety, if any, is small.

3.6.1.6 Low-Low Set (LLSl Valves SR 3.6.1.6.2 Verify the LLS System actuates on an actual or simulated automatic initiation signal.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

Extending the surveillance test interval for these functional tests is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Functional Tests (Le., SR 3.3.6.5.1) and analog trip module calibrations (Le., SR 3.3.6.5.2).

to GNRO-2012/00096 Page 14 of 50 This more frequent testing ensures that a major portion of the circuitry is operating properly and will detect significant failures within the instrument loop. Additionally, the LLS valves (Le.,

safety/relief valves assigned to the LLS logic) are designed to meet applicable reliability, redundancy, single failure, and qualification standards and regulations as described in the Grand Gulf USAR. As such, these functions are designed to be highly reliable.

A review of the applicable Grand Gulf surveillance test history verified that the LLS valves had three previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.

On October 13, 2008, the as-found set pressure to Main Steam Relief Valve 1B21-F041E was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure. CR 2008-5174 was written to document the issue.

On April 4, 2007, the as-found set pressure to Main Steam Relief Valve 1B21-F051C was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure. CR 2007-1450 was written to document the issue.

On October 11,2005, the as-found set pressure to Main Steam Relief Valve 1B21-F047D was found outside the Technical Specification allowable value. The valve was replaced with a rotatable spare with acceptable Technical Specification set pressure.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

There are a total of three failures identified relative to Dikkers Model G-471.6 Relief Valves over the review period. Of the three identified failures, each involved a different Main Steam Relief Valve and each failure occurred during a different refueling cycle (Le., one failure in 2005, one in 2007 and one in 2008). In each case, the valve was replaced with a rotatable spare. No timed-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

TS 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System SR 3.6.1.7.3 Verify each RHR containment spray subsystem automatic valve in the flow path actuates to its correct position on an actual or simulated automatic initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. The Residual Heat Removal (RHR) Containment Spray System has built-in redundancy so that no single active failure prevents the ability to mitigate the effects of bypass leakage and low energy to GNRO-2012/00096 Page 15 of 50 line breaks. The pumps and valves associated with the RHR Containment Spray System are tested quarterly in accordance with the In-service Testing (1ST) Program and SR 3.6.1.7.2 (some valves may have independent 1ST relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function. The test proposed to be extended needs to be performed during outage conditions since there is the potential to initiate an unplanned transient if performed during operating conditions.

A review of the applicable Grand Gulf surveillance history demonstrated that the RHR Containment Spray System had one previous failure of the TS function that would have been detected solely by the periodic performance of this SR.

On March 29, 2007, the failure of Agastat relay 1E21AK108 prevented valve E12-F042A from opening. Work Order 00106508 determined the relay had failed and replaced the relay.

Retesting following the relay replacement was completed satisfactorily. CR 2007-01617 documented this issue.

The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.1.9 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS)

SR 3.6.1.9.3 Perform a system functional test of each MSIV-LCS subsystem.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. A system functional test is performed to ensure that the MSIV-LCS will operate through its operating sequence. SR 3.6.1.9.1 operates each each outboard MSIV LCS blower ~

15 minutes every 31 days. This more frequent testing ensures that the major components of the outboard subsystems are capable of performing their design function. Since the major components of this manually initiated system is tested on a more frequent basis, this testing would indicate any degradation to the MSIV-LCS. Additionally, the MSIV-LCS subsystems are designed to perform the safety function in the event of any single active failure, and therefore, are highly reliable. The test proposed to be extended needs to be performed during outage conditions since they have the potential to initiate an unplanned transient if performed during operating conditions.

A review of the applicable Grand Gulf surveillance history demonstrated that the MSIV-LCS had no previous failure of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 16 of 50 3.6.2.4 Suppression Pool Makeup (SPMU) System SR 3.6.2.4.5 Verify each SPMU subsystem automatic valve actuates to the correct position on an actual or simulated automatic initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. The function of the SPMU System is to transfer water from the upper containment pool to the suppression pool after a loss of coolant accident (LOCA). This SR requires a verification that each SPMU subsystem automatic valve actuates to its correct position on receipt of an actual or simulated automatic initiation signal. This includes verification of the correct automatic positioning of the valves and of the operation of each interlock and timer. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.4.6 overlaps this SR to provide complete testing of the safety function. The frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

A review of the applicable Grand Gulf surveillance history demonstrated that the SPMU System had no previous failure of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.3.2 Primary Containment and Drywell Hydrogen Igniters SR 3.6.3.2.3 Verify each required igniter in inaccessible areas develops sufficient current draw for a ~ 1700°F surface temperature.

SR 3.6.3.2.4 Verify each required igniter in accessible areas develops a surface temperature of ~ 1700°F.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

The igniters are mechanically passive and are not subject to mechanical failure. Extending the surveillance test interval for these tests is acceptable because the functions are verified to be operating properly by the performance of more frequent current versus voltage measurements every 184 days or 92 days per SR 3.6.3.2.1 or SR 3.6.3.2.2, respectively. These SRs verify there are no physical problems that could affect the igniter operation. The only credible failures are loss of power or burnout. The verification that each required igniter is energized is performed by circuit current versus voltage measurement.

A review of the applicable Grand Gulf surveillance history demonstrated that the Hydrogen Igniter System had nineteen previous failures of the TS function that would have been detected solely by the periodic performance of this SR.

On July 27,2010, Igniter 1E61D143 failed to operate. Work Order 245362 replaced the igniter.

Post replacement retesting was satisfactory.

to GNRO-2012/00096 Page 17 of 50 On May 13, 2010, Igniter 1E610150 failed to operate. Work Order 237141 was issued to replace the igniter. This work is scheduled to be completed during the next refueling outage.

On August 7, 2009, Igniter 1E61 0181 failed to operate. Work Order 203416 replaced the igniter. Post replacement retesting was satisfactory.

On February 1, 2009, Igniters 1E61 0139 and 1E61 0160 failed to operate. Work Orders 0181372 and 0181370 replaced the heating element faceplate assemblies. Post replacement retesting was satisfactory.

On July 23,2008, Igniters 1E610142 and 1E610149 failed to operate. Work Orders 00159641 and 00159642 replaced the igniters. Post replacement retesting was satisfactory.

On October 7, 2006, Igniter 1E61 0127 failed to operate. Work Order 00095612 replaced the igniter. Post replacement retesting was satisfactory.

On March 19,2006, Igniter 1E610127 failed to operate. Work Order 00084331 replaced the igniter. Post replacement retesting was satisfactory.

On August 16, 2004, Igniter 1E610172 failed to operate. Work Order 00049998 replaced the igniter. Post replacement retesting was satisfactory.

On April 3, 2003, Igniter 1E610171 failed to operate. Work Order 50324211 replaced the igniter. Post replacement retesting was satisfactory.

On February 17, 2003, Igniter 1E610134 failed to operate. Work Order 50308038 replaced the igniter. Post replacement retesting was satisfactory.

On September 16, 2002, Igniter 1E61 0117 failed to operate. MAl 320821 replaced the glow plug assembly. Post replacement retesting was satisfactory.

On July 27,2001, Igniters 1E610134 and 1E610174 failed to operate. MAl 302347 and Work Order 50308038 replaced the 1E61 0134 igniter. MAl 302348 replaced the glow plug assembly for 1E61 0174. Post replacement retesting was satisfactory for both igniters.

On January 11, 2001, Igniters 1E61 D182, 1E61 0189, 1E61 0194 and 1E61 0195 failed to operate. MAl 292088 replaced the 1E61D182 igniter. MAl 280535 replaced the 1E610189 and 1E610194 igniters. MAl 145859 replaced the 1E610195 igniter. Post replacement retesting was satisfactory for all igniters.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

There are a total of nineteen failures identified relative to Hydrogen Igniters over the review period. The surveillance procedure tests both Division 1 and Division 2 Hydrogen Igniters located in the Containment, Containment Dome, Drywell, Main Steam Tunnel, RWCU Backwash Room, RWCU Heat Exchanger Room, RWCU FID Room and RWCU Precoat Room.

There are no time-based mechanisms apparent since only two igniters failed more than once (D134 failed in 2001 and 2003 and D127 failed twice in 2006); there were three igniter failures in to GNRO-2012/00096 Page 18 of 50 2009, two igniter failures in 2003, 2006, 2008 and 2010, and one igniter failure in 2002 and 2004. The only year in which more than three igniter failures occurred was 2001 when three Division 1 igniters failed and three Division 2 igniters failed. At no time in the review period did the number of failures in any Division exceed three, which is less than the threshold number of four failures which triggers more frequent testing of igniters per SR 3.6.3.2.2. Each complete performance of the surveillance procedure tests a total of 90 igniters. There are 7 complete surveillances of the Hydrogen Ignition system over the review period resulting in a total of 630 igniters being tested. Nineteen igniter failures over the review period represents a small percentage of the total igniters tested (approximately 3.0%). Based on the fact that the hydrogen igniter failures are not timed-based, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.3.3 Drywell Purge System SR 3.6.3.3.3 Verify each drywell purge subsystem flow rate is ~ 1000 cfm.

SR 3.6.3.3.4 Verify the opening pressure differential of each vacuum breaker and isolation valve is S 1.0 psid.

The surveillance test interval of these SRs are being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

SR 3.6.3.3.2 requires operation of each subsystem every 91 days and SR 3.6.3.3.1 performs a CHANNEL FUNCTIONAL TEST of the isolation valve pressure actuation instrumentation every 31 days. Furthermore, the Drywell Purge System has built-in redundancy so that no single-failure prevents system operation.

A review of the applicable Grand Gulf surveillance history demonstrated that the Drywell Purge System had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.4.1 Secondary Containment-Operating SR 3.6.4.1.3 Verify the secondary containment can be drawn down to ~ 0.25 inch of vacuum water gauge in S 180 seconds using one standby gas treatment (SGT) subsystem.

SR 3.6.4.1.4 Verify the secondary containment can be maintained ~ 0.266 inch of vacuum water gauge for one hour using one SGT subsystem at a flow rate S 4000 cfm.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

to GNRO-2012/00096 Page 19 of 50 To ensure that all fission products are treated, the tests required per SR 3.6.4.1.3 and SR 3.6.4.1.4 are performed utilizing one SGT subsystem (on a staggered test basis) to ensure secondary containment boundary integrity. SRs 3.6.4.1.1 (every 31 days), and 3.6.4.1.2 (every 31 days) provide more frequent assurance that no significant boundary degradation has occurred.

A review of the applicable Grand Gulf surveillance history demonstrated that the secondary containment had no previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.4.2 Secondarv Containment Isolation Valves (SCIVs)

SR 3.6.4.2.3 Verify each required automatic SCIV actuates to the isolation position on an actual or simulated automatic isolation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. During the operating cycle, SR 3.6.4.2.2 requires that each power-operated automatic SCIV isolation times to be tested (Le., stroke timed to the closed position) in accordance with the Inservice Test Program (some valves may have independent relief justifying less frequent testing).). The stroke testing of these SCIDs tests a portion of the circuitry and the mechanical function, and provides more frequent testing to detect failures.

A review of surveillance test history verified that SCIVs had four previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On May 19, 2010, valve P45-F068 did not stroke closed during testing as required by Technical Specifications. Work Orders 236306 and 237204 were implemented to determine and repair the problem which prevented proper valve operation. Although no direct cause could be determined, the disassembly and reassembly of the actuator resulted in all sub-components that could cause upper piston seal blow-by and resultant actuator failure were replaced. Post maintenance diagnostics and testing determined proper and satisfactory valve operation. CRs 2010-03939 and 2010-03507 document this issue.

On May 15, 2010, valve 1D23-F591 did not stroke closed on a high drywell pressure initiation signal. Work Order 237327 was written to determine cause of failure. Troubleshooting by the work order failed to identify any obvious problem. After the troubleshooting the valve was retested satisfactorily. CR 2010-04089 documented this issue.

On September 24, 2002, four valves (1 P72-F123, 1P72-F124, 1P72-F126 and 1P45-F274) did not close on an isolation signal. It was determined that relay 1M71 R065, which controls all four valves, failed to de-energize with its plunger stuck in the energized position. MAl 321408 replaced the Agastat relay and performed satisfactory retesting with all Technical Specifications acceptance criteria met. CR 2002-1936 documented this issue.

to GNRO-2012/00096 Page 20 of 50 On September 18, 2002, an apparent failure of relay 1B21 HK023A prevented the proper operation of the Shutdown Cooling isolation logic for valve 1E12-F040. MAl 320958 was written to troubleshoot and subsequently replace the Agastat relay for 1B21 HK023A. Post replacement retesting was satisfactory for all Technical Specification requirements. CR 2002-01806 documented this issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the May 19, 2010 and May 15, 2010 issues, no similar failures are identified, therefore the failures are not repetitive in nature. No timed-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

For the September 24, 2002 and September 18, 2002 issues, there are a total of four failures identified relative to Agastat relays over the review period. Of the four Agastat relay failures, one failure was Model EGPI, one was Model FGPD, one was Model EGPB, and one was Model EGPD. In all four Agastat relay failures, the defective relays were replaced. The Agastat Model EGPI failure occurred in 2002 and was in the RHR Valve Isolation logic for Division 1. The Agastat Model FGPD failure occurred in 2002 and was in the Drywell Chilled Water Supply and Return Lines and Equipment Drain Transfer Tank Pump Discharge Line Valve Isolation Logic for Division II. The Agastat EGPB failure occurred in 2005 and was in the Control Room HVAC B Breaker Logic in the LOP Division 2 Load Shed Test. The Agastat Model EGPD relay failure occurred in 2007 and was in the RHR A Containment Spray Initiation Logic Division 1. There does not appear to be any common cause for these failures and no time-based mechanisms are apparent in these failures based on the fact that the failures are in different plant systems and are spread out over a five year period with not more than two failures in anyone year. When considering the total number of Agastat relays in the various plant system applications, a total of four different relay failures over the review period is a small percentage of the total population of relays tested. Therefore, this failure is unique and an increase in the surveillance test interval will have an insignificant effect on system availability.

Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.4.3 Standby Gas Treatment (SGT) System SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual or simulated initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR requires verification that each SGT subsystem starts upon receipt of an actual or simulated initiation signal.. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.6 overlaps this SR to provide complete testing of the safety function. The SGT sUbsystems are redundant so that no single-failure prevents accomplishing the safety function of filtering the discharge from secondary containment, and are therefore reliable. More frequent verification of portions of the SGT function are accomplished by operating each SGT subsystem and heaters every 31 days (Le., SR 3.6.4.3.1)..

to GNRO-2012/00096 Page 21 of 50 A review of the applicable Grand Gulf surveillance history demonstrated that the SGT System had no previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.5.3 Drvwell Isolation Valves SR 3.6.5.3.4 Verify each automatic drywell isolation valve actuates to the isolation position on an actual or simulated isolation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. During the operating cycle, automatic drywell isolation valve isolation times are tested per SR 3.6.5.3.3 in accordance with the In-service Testing Program. Stroke testing of drywell isolation valves tests a significant portion of the circuitry as well as the mechanical function, which will detect failures of this circuitry or failures with valve movement. The frequency of this testing is typically quarterly, unless approved relief has been granted justifying less frequent testing.

A review of the applicable Grand Gulf surveillance history demonstrated that the drywell isolation valves had four previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On September 24, 2002, three valves (1 P72-F124, 1P72-F126 and 1P45-F274) did not close on an isolation signal. It was determined that relay 1M71 R065, which controls all three valves, failed to de-energize with its plunger stuck in the energized position. MAl 321408 replaced the Agastat relay and performed satisfactory retesting with all Technical Specifications acceptance criteria met. CR 2002-1936 documented this issue.

The identified failure is unique and not a repetitive failure and is not associated with any time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

3.6.5.6 Drvwell Vacuum Relief System SR 3.6.5.6.3 Verify the opening pressure differential of each vacuum breaker and isolation valve is S 1.0 psid.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

Verification of the opening pressure differential is necessary to ensure that the safety analysis assumption that the vacuum breaker or isolation valve will open fully at a differential pressure of 1.0 psid is valid. More frequent verification of portions of the Drywell Vacuum Relief System are accomplished by verification of each vacuum breaker and its associated isolation valve every 7 days and by performance of a functional test every 31 days.

to GNRO-2012/00096 Page 22 of 50 A review of the applicable Grand Gulf surveillance history demonstrated that the Drywell Vacuum Relief System had no previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.7.1 Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)

SR 3.7.1.4 Verify each SSW subsystem actuates on an actual or simulated initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR verifies that the automatic isolation valves of the SSW System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This SR also verifies the automatic start capability of the SSW pump and cooling tower fans in each subsystem. The SSW subsystems are redundant so that no single-failure prevents accomplishing the safety function of providing the required cooling. The SSW system pumps and valves are tested quarterly in accordance with the In-service Testing Program (some valves may have independent relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position monthly (Le., SR 3.7.1.3). Since most of the components and associated circuits are tested on a more frequent basis, this testing would indicate any degradation to the SSW System which would result in an inability to start based on a demand signal.

A review of the applicable Grand Gulf surveillance history demonstrated that the SSW subsystems had no previous failure of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, the history of system performance, and the corrective action taken for the relay failures the impact of this change on safety, if any, is small.

3.7.2 High Pressure Core Spray (HPCS) Service Water System (SWS)

SR 3.7.2.2 Verify the HPCS SWS actuates on an actual or simulated initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR verifies that the automatic isolation valves of the HPCS SWS will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This SR also verifies the automatic start capability of the HPCS SWS pump. The HPCS SWS pump and valves are tested quarterly in accordance with the In-service Testing Program (some valves may have independent relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position monthly (Le., SR 3.7.2.1). Since most of the components and associated to GNRO-2012/00096 Page 23 of 50 circuits are tested on a more frequent basis, this testing would indicate any degradation to the HPCS SWS System which would result in an inability to start based on a demand signal.

A review of the applicable Grand Gulf surveillance history demonstrated that the HPCS SWS had no previous failure of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, the history of system performance, and the corrective action taken for the relay failures the impact of this change on safety, if any, is small.

3.7.3 Control Room Fresh Air lCRFA) System SR 3.7.3.3 Verify each CRFA subsystem actuates on an actual or simulated initiation signal.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. The Control Room Fresh Air subsystems are redundant so that no single-failure prevents accomplishing the safety function. More frequent verification of portions of the Control Room Fresh Air System function is accomplished by operating each Control Room Ventilation SUbsystem every 31 days (SR 3.7.3.1).

A review of the applicable Grand Gulf surveillance history demonstrated that the Control Room Fresh Air (CRFA) System had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

3.7.4 Control Room Air Conditioning lAC) System SR 3.7.4.1 Verify each control room AC subsystem has the capability to remove the assumed heat load.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. This SR verifies that the heat removal capability of the system is sufficient to remove the control room heat load assumed in the safety analysis. The SR consists of a combination of testing and calculation. The system is normally operating; thus, malfunctions of the cooling units can be detected by Operations personnel and corrected. The active components and power supplies of the control room AC system are designed with redundancy to ensure that a single-failure will not prevent system operability.

A review of the applicable Grand Gulf surveillance history demonstrated that the Control Room Air Conditioning System had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent observation of the system performance, system design, and the history of performance testing, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 24 of 50 3.8.1 AC Sources-Operating SR 3.8.1.8 Verify manual transfer of unit power supply from the normal offsite circuit to required alternate offsite circuit.

SR 3.8.1.9 Verify each DG rejects a load greater than or equal to its associated single largest post accident load and engine speed is maintained less than nominal plus 75% of the difference between nominal speed and the overspeed trip setpoint or 15%

above nominal, whichever is lower.

SR 3.8.1.10 Verify each DG does not trip and voltage is maintained S; 5000 V during and following a load rejection of a load ~ 5450 kW and s; 5740 kW for DG 11 and DG 12 and ~ 3300 kW for DG 13.

SR 3.8.1.11 Verify on an actual or simulated loss of offsite power signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in S; 10 seconds,

2. energizes auto-connected shutdown loads,

3. maintains steady state voltage ~ 3744 V and s; 4576 V,

4. maintains steady state frequency ~ 58.8 Hz and s; 61.2 Hz, and

5. supplies permanently connected and auto-connected shutdown loads for 2: 5 minutes.

SR 3.8.1.12 Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each DG auto-starts from standby condition and:

a. In S; 10 seconds after auto-start and during tests, achieve voltage ~ 3744 V and frequency ~ 58.8 Hz;

b. Achieves steady state voltage 2: 3744 V and S; 4576 V and frequency ~ 58.8 Hz and S; 61.2 Hz;

c. Operates for ~ 5 minutes; and

d. Emergency loads are auto-connected to the offsite power system.

SR 3.8.1.13 Verify each DG's non-critical automatic trips are bypassed on an actual or simulated ECCS initiation signal.

to GNRO-2012/00096 Page 25 of 50 SR 3.8.1.14 Verify each DG operates for ~ 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months s:

a. For DG 11 and DG 12 loaded ~ 5450 kW and S 5740 kW; and

b. For DG 13:

1. For ~ 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months loaded ~ 3630 kW, and

2. For the remaining hours of the test loaded ~ 3300 kW.

SR 3.8.1.15 Verify each DG starts and achieves;

a. in S 10 seconds, voltage ~ 3744 V and frequency ~ 58.8 Hz;

b. steady state voltage ~ 3744 V and S 4576 V and frequency ~ 58.8 Hz and S 61.2 Hz.

SR 3.8.1.16 Verify each DG:

a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b. Transfers loads to offsite power source; and

c. Returns to ready-to-Ioad operation.

SR 3.8.1.17 Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by:

a. Returning DG to ready-to-Ioad operation; and

b. Automatically energizing the emergency loads from offsite power.

SR 3.8.1.18 Verify interval between each sequenced load block is within +/- 10% of design interval for each automatic load sequencer.

SR 3.8.1.19 Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal:

a. De-energization of emergency buses;

b. Load shedding from emergency buses for Divisions 1 and 2; and

c. DG auto-starts from standby condition and:

1. energizes permanently connected loads in S 10 seconds,

2. energizes auto-connected emergency loads,

3. achieves steady state voltage ~ 3744 V and S 4576 V,

4. achieves steady state frequency ~ 58.8 Hz and S 61.2 Hz, and

5. supplies permanently connected and auto-connected emergency loads for

~ 5 minutes.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

The Grand Gulf Class 1E AC distribution system supplies electrical power to three divisional load groups, with each division powered by an independent Class 1E 4.16 kV Engineered Safety Feature (ESF) bus. Each ESF bus has three separate and independent offsite sources of power. Each ESF bus has a dedicated onsite diesel generator (DG). The ESF systems of any two of the three divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition. This design provides substantial redundancy in AC power sources. The DGs are infrequently operated; thus, the risk of wear-related degradation is minimal. Historical testing and surveillance testing during operation prove the ability of the diesel engines to start and operate under various load conditions. Diesel to GNRO-2012/00096 Page 26 of 50 Generator loading is listed on USAR Tables 8.3-1 through 4. Through the normal engineering design process, all load additions and deletions are tracked and any changes to loading are verified to be within the capacity of their power sources. More frequent testing of the AC sources is also required as follows:

Verifying correct breaker alignment and indicated power availability for each required offsite circuit every 7 days (Le., SR 3.8.1.1);

Verifying the DG starting and load carrying capability is demonstrated every 31 days (Le.,

SRs 3.8.1.2 and 3.8.1.3), the ability to continuously supply makeup fuel oil is also demonstrated every 31 days (Le., SR 3.8.1.6), and the load shedding and sequencing panels ability to respond within design criteria is demonstrated every 31 days (SR 3.8.1.7);

Verifying the necessary support for DG start and operation as well as verifying the DG factors that are subject to degradation due to aging, such as fuel oil quality, (Le.,

SRs 3.8.1.4, 3.8.1.5, 3.8.3.1, 3.8.3.2 and 3.8.3.4) are required every 31 days and/or prior to addition of new fuel oil.

A review of the applicable Grand Gulf surveillance history for the AC Sources demonstrated there have been seven previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On October 2, 2008, the Diesel Generator Outside Air Fan failed to automatically restart after the load shed signal was initiated. The breaker for the fan (Breaker 52-16104) was manually closed which started the fan. Work Order 00166795 cleaned the stabs on the breaker and successfully performed a retest on the fan. CR 2008-05208 documented this issue.

On March 5, 2008, the Division 3 Diesel Generator experienced voltage and amperage fluctuations. Work Order 142180 replaced the E22B-K9 GE Model 12HFA151A2F relay. Post replacement testing of the replaced relay did not identify any abnormalities, and inspections of various breakers did not identify anything that could have caused the fluctuations. Retesting was performed satisfactorily. Therefore, the condition that caused the fluctuations was either eliminated by the replacement of the relay, or was no longer present during the post maintenance Technical Specification testing. CR 2008-1199 documented this issue.

On August 9, 2007, the Division 2 Diesel Generator tripped 13.22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months into a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months performance run. Work Order 00118539 replaced the Division 2 Diesel Generator Right Bank Turbocharger Vibration Switch 1P75N165B, and recalibrated the vibration switches to a higher setpoint. CR 2007-03913 documented this issue.

On March 27, 2007, the Diesel Generator tripped on high vibration approximately three minutes into the diesel generator run. It was determined that the vibration trip was most likely caused by a spurious actuation of the vibration sensor. The diesel was successfully started and run on April 4, 2007. CR 2007-01524 documented this issue.

On July 28, 2006, the Division 3 Diesel Generator failed to reach the required frequency in the required time. Retesting was completed satisfactorily on July 29,2006.

On May 3, 2006, the overspeed trip microswitch for Div. 3 Diesel Generator would not actuate without agitation. The over speed trip micro switch was disassembled, inspected and cleaned by WO 87119 and retested with satisfactory results.

to GNRO-2012/00096 Page 27 of 50 On September 29,2005, Control Room HVAC B breaker 52-16606 did not reclose following the LSS shed signals. Work Order 74067 determined that the M2-T2 contacts on the Agastat Load Shed Relay 1R21XK024 did not close as required. The relay was replaced and retesting was completed satisfactorily. CR 2005-04036 documented this issue.

For the October 2, 2008 issue, the identified failure of the D/G Outside Air Fan breaker is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

For the March 5, 2008, August 9,2007, July 28,2006 and May 3,2006 issues, the identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the March 27, 2007 issue, there are a total of two failures identified relative to AMOT Corporation Model 41 09B 1OB Vibration Switch actuations during Division 1 and 2 Diesel Generator 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months run time tests over the review period. In each case the Diesel Generator tripped due to spurious actuation of the vibration switch. In both cases, the vibration switch was replaced and retest was performed satisfactory. The purpose of these vibrations switches is not as a monitoring device but only to shut down the engine in response to a catastrophic event.

Evaluations under CR 2007-01524 and CR 2007-03913 determined that the spurious trips resulted from trip settings too close to ambient vibration levels. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the September 29, 2005 issue, there are a total of four failures identified relative to Agastat relays over the review period. Of the four Agastat relay failures, one failure was Model EGPI, one was Model FGPD, one was Model EGPB, and one was Model EGPD. In all four Agastat relay failures, the defective relays were replaced. The Agastat Model EGPI failure occurred in 2002 and was in the RHR Valve Isolation logic for Division 1. The Agastat Model FGPD failure occurred in 2002 and was in the Drywell Chilled Water Supply and Return Lines and Equipment Drain Transfer Tank Pump Discharge Line Valve Isolation Logic for Division 2. The Agastat EGPB failure occurred in 2005 and was in the Control Room HVAC B Breaker Logic in the LOP Division 2 Load Shed Test. The Agastat Model EGPD relay failure occurred in 2007 and was in the RHR A Containment Spray Initiation Logic Division 1. There does not appear to be any common cause for these failures and no time-based mechanisms are apparent in these failures based on the fact that the failures are in different plant systems and are spread out over a five year period with not more than two failures in anyone year. When considering the total number of Agastat relays in the various plant system applications, a total of four different relay failures over the review period is a small percentage of the total popUlation of relays tested. Therefore, this failure is unique and an increase in the surveillance test interval will have an insignificant effect on system availability.

Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 28 of 50 3.8.4 DC Sources-Operating SR 3.8.4.3 Verify battery cells, cell plates, and racks show no visual indication of physical damage or abnormal deterioration that could degrade battery performance.

SR 3.8.4.4 Remove visible corrosion and verify battery cell to cell and terminal connections are coated with anti-corrosion material.

SR 3.8.4.5 Verify battery connection resistance is S 1.5 E-4 ohm for inter-cell connections, S 1.5 E-4 ohm for inter-rack connections, S 1.5 E-4 ohm for inter-tier connections, and S 1.5 E-4 ohm for terminal connections.

SR 3.8.4.6 Verify each Division 1 and 2 required battery charger supplies ~ 400 amps at ~

125 V for ~ 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months ; and the Division 3 battery charger supplies ~ 50 amps at ~

125 V for ~ 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SR 3.8.4.7 Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.

The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period.

SR 3.8.4.1 and SR 3.8.6.1 are performed every 7 days to verify battery terminal voltage and pilot cell float voltage, electrolyte level and specific gravity, respectively. SR 3.8.6.2 and SR 3.8.6.3 are performed every 92 days to verify each cell float voltage, each cell electrolyte level, each cell specific gravity, and pilot cell temperature. SR 3.8.4.2 is performed every 92 days to verify no visible battery terminal/connector corrosion or high resistance. These more frequent surveillances will provide prompt identification of any substantial degradation or failure of the battery and/or battery chargers.

A review of the applicable Grand Gulf surveillance history demonstrated that the DC electric power subsystem had three previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On April 24, 2009, during performance of Work Order 51690933, the 1A4 Battery Charger current limit amperes As Found data value was out of tolerance low and the Current Limit Board of the 1A4 Battery Charger would not calibrate. The existing card was recalibrated on April 24, 2009 with all Technical Specification acceptance criteria met.

On October 24,2007, Battery Charger 1A4 Current Limit Amperes was found out of tolerance low and not within Technical specification limits. Work Order 127610-01 replaced six control cards. After repairs were completed all Technical Specification requirements were satisfactory.

On February 19, 2003, Battery Charger 1A4 Current Limit Amperes were found out of tolerance low and not within Technical Specification limits. MAl 329253 replaced a card in Control Board B. All Technical Specification criteria were met after the repairs.

There are a total of three failures identified relative to Battery Charger 1A4 Current Limit over the review period. In all three cases, the Current Limit Amps were out of tolerance; in two cases the Control B Board was replaced and in the third case the current limit board was recalibrated.

to GNRO-2012/00096 Page 29 of 50 As-left load test data was verified satisfactory. No timed-based mechanisms are apparent.

Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

Additionally, upon approval of this amendment request, commitments outlined in the Grand Gulf USAR related to RG 1.32, "Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants," RG 1.129, "Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants," and to IEEE-450, "Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," to perform the battery service test (Le., SR 3.8.4.3) during refueling outages, or at some other outage, with intervals between tests "not to exceed 18 months," will be revised to reflect intervals between tests "not to exceed 30 months."

5.5.7 Ventilation Filter Testing Program (VFTP) 5.5.7 A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in Regulatory Guide 1.52, Revision 2.

While this specified frequency of testing ESF filter ventilation systems does not explicitly state "18 months," TS Section 5.5.7 requires testing frequencies in accordance with RG 1.52, "Design, Testing and Maintenance Criteria for Post Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants," which does reference explicit "18 month" test intervals for various performance characteristics. With this change, these performance tests are being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25%

grace period. This exception to the RG 1.52 interval is explicitly addressed in the change to Grand Gulf TS 5.5.7. Administrative Control Specification 5.5.7 is revised to state (inserted text shown underlined):

5.5.7 A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in Regulatory Guide 1.52, Revision 2, except that testing specified at a frequency of 18 months is required at a frequency of 24 months.

In addition to the 24-month testing, ventilation filter (HEPA and charcoal) testing will continue to be performed in accordance with the other frequencies specified in RG 1.52: (1) on initial installation and (2) following painting, fire, or chemical release in any ventilation zone communicating with the system. Additionally, RG 1.52 requires a sample of the charcoal adsorber be removed and tested after each 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation, and an in-place charcoal test be performed following removal of these samples if the integrity of the adsorber section was affected. This proposed amendment request will not change the commitment to perform these required tests.

A review of the applicable Grand Gulf surveillance history demonstrated that the Technical Specification ESF ventilation systems (SR 3.6.4.3.2 and 3.7.3.2) had no previous failures of the to GNRO-2012/00096 Page 30 of 50 TS functions that would have been detected solely by the periodic performance of SRs that reference performance of the VFTP of Specification 5.5.7. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

B. Channel Calibration Changes NRC GL 91-04 requires that licensees address instrument drift when proposing an increase in the surveillance interval for calibrating instruments that perform safety functions including providing the capability for safe shutdown. The effect of the increased calibration interval on instrument errors must be addressed because instrument errors caused by drift were considered when determining safety system setpoints and when performing safety analyses.

NRC GL 91-04 identifies seven steps for the evaluation of instrumentation calibration changes.

These seven steps are discussed in Attachment 1 to this submittal. In that discussion, a description of the methodology used by Grand Gulf for each step is summarized. The detailed methodology is provided in Attachment 6.

The following are the calibration-related TS SRs being proposed for revision from 18 months to 24 months, for a maximum interval of 30 months (considering the 25% grace period allowed by TS SR 3.0.2). In each instance, the instrument channel loop drift was evaluated in accordance with Setpoint Methodology JS-09 Rev.1 "Methodology for the Generation of Instrument Loop Uncertainty & Setpoint Calculations" and Drift Design Guide ECH-NE-08-00015, Revision 1 "Instrument Drift Analysis Design Guide" (Attachment 6)

The projected 30-month drift values for many of the instruments analyzed from the historical as-found/as-left evaluation shows sufficient margin between the current plant setpoint and the allowable value to compensate for the 30-month drift. For each instrument function that has a channel calibration proposed frequency change to 24 months, the associated setpoint calculation assumes (or will be revised prior to implementation to assume) a consistent or conservative drift value appropriate for a 24-month calibration interval. All revised setpoint calculations have been completed in accordance with the guidance provided in RG 1.105, "Instrument Setpoints," as implemented by the Grand Gulf setpoint methodology, and the Instrument Society of America (ISA) Standard 67.04, 1994. These calculations determine the instrument uncertainties, setpoints, and allowable values for the affected functions. As such, the TS allowable values ensure that sufficient margins are maintained in the applicable safety analyses to confirm the affected instruments are capable of performing their intended design function. Also, review of the applicable safety analysis concluded that the setpoints, allowable values, and projected 30-month drift confirmed the safety limits and safety analysis assumptions remain bounding.

Below is a summary of the specific application of this methodology to the Grand Gulf 24-month fuel cycle extension project, as well as any required allowable value changes. Where optional methods are presented in Attachment 6, and where other alternate engineering justifications are allowed, the rationale for the selected method and alternate justification is summarized with the associated instrument calibration surveillance affected (e.g., for channel groupings having less than 30 calibrations, which is required to qualify for valid statistical evaluations).

to GNRO-2012/00096 Page 31 of 50 3.3.1.1 Reactor Protection System (RPS) Instrumentation The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limit, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS), and minimize the energy that must be absorbed following a loss of coolant accident (LOCA).

SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.

- Function 3, Reactor Vessel Steam Dome Pressure - High

- Function 4, Reactor Vessel Water Level - Low, Level 3

- Function 5, Reactor Vessel Water Level - High, Level 8

- Function 7, Drywell Pressure - High

- Function 8.a., Scram Discharge Volume Water Level- High, TransmitterlTrip Unit

- Function 9, Turbine Stop Valve Closure, Trip Oil Pressure - Low

- Function 10, Turbine Control Valve Fast Closure, Trip Oil Pressure - Low For these functions, no revisions to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical as-found minus as-left (AFAL) data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these Functions demonstrated that the as-found trip setpoint had six previous failures of TS required allowable values that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On January 27,2009, the as-found results for transmitter 1C71-N005C failed Technical Specification acceptance criteria. The transmitter was adjusted to within proper tolerances. CR 2009-00398 was written to document this issue.

On December 3,2007, the as found results for transmitter 1C71-N050C failed Technical Specification acceptance criteria low. The transmitter was adjusted to within proper tolerances. CR 2007-05620 was written to document this issue.

On May 31, 2007, the As Found value for transmitter 1C11-N012D was out of Technical Specification tolerance high. The transmitter was adjusted to within proper tolerances.

CR 2007-2933 was written to document this issue.

On November 18, 2005, the trip setpoint for transmitter 1C11-N012B did not meet Technical specification acceptance criteria. The transmitter was adjusted to within proper tolerances. CR 2005-05075 was written to document this issue.

On September 26, 2005, the Level 8 trip for 1B21-N683D was found outside of Technical Specification limits. The transmitter was adjusted within Technical Specification tolerances with no further actions. CR 2010-03840 documents the issue.

to GNRO-2012/00096 Page 32 of 50 On December 3, 2002, the as-found results for transmitter 1C71-N006D failed Technical Specification acceptance criteria high. The transmitter was adjusted to within proper tolerances. CR 2002-02562 was written to document this issue.

For the January 27,2009 issue, there are a total of three failures identified relative to Gould/Statham (2 Model PD3218 and 1 Model PG3200) over the review period. Of the three identified failures, each involved a different transmitter and each failure occurred during a different refueling cycle (Le., one failure in 2005, one in 2007 and one in 2009). In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any SUbsequent failure would not result in a significant impact on system/component availability.

For the September 26, 2005 issue, there are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter. Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010. When considering that a total of 44 Rosemount 1153D transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage << 3%) of the total transmitters tested. No time based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the May 31, 2007 and November 18, 2005 issues, there are a total of three failures identified relative to Gould/Statham (2 Model PD3218 and 1 Model PG3200) over the review period. Of the three identified failures, each involved a different transmitter and each failure occurred during a different refueling cycle (Le., one failure in 2005, one in 2007 and one in 2009). In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the December 3, 2007 issue, there are a total of two failures identified relative to Rosemount Model 1152 transmitters over the review period. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance. In one case, the transmitter was returned to service. In the other case, the electronic board was replaced and recalibrated, and the transmitter was returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

to GNRO-2012/00096 Page 33 of 50 For the December 3, 2002 issue, the identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

Based on the history of system performance, the impact of this change on safety, if any, is small.

SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.

- Function 1.a, Intermediate Range Monitors, Neutron Flux-High No revisions to TS allowable values or safety analyses result from the required evaluations. Drift evaluations were not performed for TS Table 3.3.1.1-1 Function 1.a, Intermediate Range Monitors (IRMs), Neutron Flux-High. This is acceptable because of the design requirements for the instruments and more frequent functional testing (Le.,

once per 7 days). When the IRM trip is required to be operable, a channel functional test is performed on the IRM trip function every 7 days in accordance with SR 3.3.1.1.3 or 3.3.1.1.4.

A review of the applicable Grand Gulf surveillance history for the IRM channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.

- Function 6, Main Steam Isolation Valve-Closure

- Function 8.b, Scram Discharge Volume Water Level-High, Float Switch No revisions to TS allowable values or safety analyses result from the required evaluations. Drift evaluations were not performed for TS Table 3.3.1.1-1 Functions 6 (MSIV limit switches), and 8.b (scram discharge volume float switches). The limit and float switches that perform these functions are mechanical devices that require mechanical adjustment only; drift is not applicable to these devices. The Functions are functionally tested quarterly (Le., SR 3.3.1.1.8) to verify operation.

A review of the applicable Grand Gulf surveillance history for these limit switch and float switch channels demonstrated that the as-found trip setpoint for these functions one previous failure of TS required allowable values that would have been detected solely by the periodic performance of this SR.

On September 9, 2010, Float Switch 1C11-N013C did not trip. Work Order 25002 found an actuating screw on a spare microswitch stuck on the micro switch arm. The work order adjusted the microswitch pivot arm and reperformed the surveillance procedure. The As left data was all within satisfactory limits.

No similar failures are identified. Therefore the failure is not repetitive in nature. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability. As such, to GNRO-2012/00096 Page 34 of 50 the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

SR 3.3.1.1.14 Verify Turbine Stop Valve Closure, Trip Oil Pressure-Low and Turbine Control Valve Fast Closure Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is ~ 40% RTP.

- Function 9, Turbine Stop Valve Closure, Trip Oil Pressure - Low

- Function 10, Turbine Control Valve Fast Closure, Trip Oil Pressure - Low This SR ensures that scrams initiated from the Turbine Stop Valve Closure, Trip Oil Pressure-Low and Turbine Control Valve Fast Closure Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is ~ 40% RTP. This involves calibration of the bypass channels.

No revisions to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calCUlations).

Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for this function demonstrated that the as-found trip setpoint had no previous failures of the TS reqUired allowable value that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

SR 3.3.1.1.17 Perform APRM recirculation flow transmitter calibration.

- Function 2.d, APRM Flow Biased Simulated Thermal Power - High Each APRM channel receives one total drive flow signal. The recirculation loop drive flow signals are generated by eight flow units. One flow unit from each recirculation loop is provided to each APRM channel. Total drive flow is determined by each APRM by summing up the flow signals provided to the APRM from the two recirculation loops. This SR is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy.

No revisions to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calCUlations).

Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for this function demonstrated that the as-found trip setpoint had no previous failures of the TS reqUired allowable value that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month to GNRO-2012/00096 Page 35 of 50 testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.1.2 Source Range Monitor (SRM) Instrumentation The SRMs provide the operator with information relative to very low neutron flux levels in the core. Specifically, the SRM indication is used by the operator to monitor the approach to criticality and to determine when criticality is achieved. During refueling, shutdown, and low power operations, the primary indication of neutron flux levels is provided by the SRMs to monitor reactivity changes during fuel or control rod movement and give the control room operator early indication of unexpected subcritical multiplication that could be indicative of an approach to criticality.

SR 3.3.1.2.6 Perform CHANNEL CALIBRATION.

No revisions to TS allowable values or safety analyses result from the required evaluations. Drift evaluations were not performed for SRMs. This is acceptable because there are no trip setpoints or allowable values specified by the TS or credited in accident or safe shutdown analyses. There are also more frequent Channel Checks (SR 3.3.1.2.1 and SR 3.3.1.2.3) and functional testing (SR 3.3.1.2.5).

Extending the SRM calibration interval from 18 months to 24 months is acceptable if calibration is sufficient to ensure neutron level is observable when the reactor is shutdown.

This is verified at least every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when the reactor is shutdown (Le., SR 3.3.1.2.4)..

Additionally, SRM response to reactivity changes is distinctive and well known to plant operators and SRM response is closely monitored during reactivity changes. Therefore, any substantial degradation of the SRMs will be evident prior to the scheduled performance of Channel Calibrations. Based on the above discussion, there will be no significant adverse impact from the surveillance test frequency increase on system reliability.

A review of the applicable Grand Gulf surveillance history for this function demonstrated that there were no previous failures of TS required channel calibration that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.3.1 Post Accident Monitoring (PAM) Instrumentation The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided.

to GNRO-2012/00096 Page 36 of 50 SR 3.3.3.1.3 Perform CHANNEL CALIBRATION.

(All Functions)

No allowable value is applicable to these functions. A separate drift evaluation has not been performed for the PAM instruments based on the design of the PAM instruments and equipment history. The PAM function is supported by a combination of process transmitters, indicators, and recorders. These components differ from other TS instruments in that they are not associated with a function trip, but indication only to the control room operator. As such, these instruments are not expected to function with the same high degree of accuracy demanded of functions with assumed trip actuations for accident detection and mitigation. The PAM devices are expected to maintain sufficient accuracy to detect trends or the existence or non-existence of a condition. The PAM functions require at least two operable channels (except for some PCIV indications) to ensure no single failure prevents the operators from being presented with the information.

The functioning status of the PAM instruments is also tested more frequently by SR 3.3.3.1.1 (Le., Channel Check every 31 days).

A review of the applicable Grand Gulf surveillance history for these functions demonstrated that there was one previous failure of TS required channel calibration that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on PAM system availability is minimal from the proposed change to a 24-month testing frequency.

On February 25,2002, Temperature Switch 1M71-N608B did not change state as required during testing. MAl 312199 documented replacement of the switch unit and acceptable post replacement testing.

The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

No similar failures are identified, therefore the failure is not repetitive in nature. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on system design and the history of system performance, the impact of this change on safety, if any, is small.

3.3.3.2 Remote Shutdown System The Remote Shutdown System provides the control room operator with sufficient instrumentation and controls to place and maintain the plant in a safe shutdown condition from a location other than the control room.

to GNRO-2012/00096 Page 37 of 50 SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each required instrumentation channel.

(All Instrumentation Functions)

No allowable value is applicable to these functions. A separate drift evaluation has not been performed for the Remote Shutdown System instrument channels based on the design function and equipment history.

The Remote Shutdown System instrument channels differ from other TS instruments in that they are not associated with an automatic protective action or trip. As such, these instruments are not expected to function with the same high degree of accuracy demanded of functions with assumed trip actuations for accident detection and mitigation.

The normally energized Remote Shutdown System instrument channels also require more frequent verification of the functioning status as required by SR 3.3.3.2.1 (Le.,Channel Check every 31 days).

A review of the applicable Grand Gulf surveillance history demonstrated that the Remote Shutdown System had no previous failure of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on Remote Shutdown System availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation The EOC-RPT instrumentation initiates a recirculation pump trip to reduce the peak reactor pressure and power resulting from turbine trip (TSV closure) or generator load rejection (TCV fast closure) transients to provide additional margin to core thermal minimum critical power ratio (MCPR) Safety Limits.

SR 3.3.4.1.3 Perform CHANNEL CALIBRATION. The Allowable Values shall be:

a. TSV Closure, Trip Oil Pressure-Low: ~ 37 psig.

b. TCV Fast Closure, Trip Oil Pressure-Low: ~ 42 psig.

No revisions to TS allowable values or safety analyses result from the required evaluations. More frequent testing includes a Channel Functional Test (SR 3.3.4.1.1) and a calibration of the trip units (SR 3.3.4.1.2) every 92 days. .

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had two previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On January 27,2009, the as-found results for transmitter 1C71-N005C failed Technical Specification acceptance criteria. The transmitter was adjusted to within proper tolerances. CR 2009-00398 was written to document this issue.

to GNRO-2012/00096 Page 38 of 50 On December 3,2002, the as-found results for transmitter 1C71-N006D failed Technical Specification acceptance criteria high. The transmitter was adjusted to within proper tolerances. CR 2002-02562 was written to document this issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the December 3, 2002 event, no similar failures were identified, therefore the failure is not repetitive in nature. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the January 27,2009 issue, there are a total of three failures identified relative to Gould/Statham (2 Model PD3218 and 1 Model PG3200) over the review period. Of the three identified failures, each involved a different transmitter and each failure occurred during a different refueling cycle (Le., one failure in 2005, one in 2007 and one in 2009). In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any SUbsequent failure would not result in a significant impact on system/component availability.

Based on the history of system performance, the impact of this change on safety, if any, is small.

SR 3.3.4.1.5 Verify TSV Closure, Trip Oil Pressure-Low and TCV Fast Closure, Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is ~

40% RTP.

No revisions to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calCUlations).

Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

This SR ensures that an EOC-RPT initiated from the Turbine Stop Valve Closure, Trip Oil Pressure-Low and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low functions will not be inadvertently bypassed when THERMAL POWER is ~ 40% RTP. This involves calibration of the bypass channels.

A review of the applicable Grand Gulf surveillance history for this function demonstrated that the as-found trip setpoint had no previous failures of the TS reqUired allowable value that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 39 of 50 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation The ATWS-RPT System initiates a recirculation pump trip, adding negative reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event.

Tripping the recirculation pumps adds negative reactivity from the increase in steam voiding in the core area as core flow decreases. When Reactor Vessel Water Level-Low Low, Level 2 or Reactor Vessel Pressure-High setpoint is reached, the recirculation pump motor breakers trip.

SR 3.3.4.2.4 Perform CHANNEL CALIBRATION. The Allowable Values shall be:

a, Reactor Vessel Water Level-Low Low, Level 2: ~ -43.8 inches; and b, Reactor Vessel Pressure-High: S 1139 psig For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these functions demonstrated that the as-found trip setpoint had no previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that fuel is adequately cooled in the event of a design basis accident or transient.

SR 3.3.5.1.5 Perform CHANNEL CALIBRATION.

- Function 1.a, 2.a, 4.a, 5.a, Reactor Vessel Water Level-Low Low Low, Level 1

- Function 1.b, 2.b, 3.b, 4.b, 5.b, Drywell Pressure-High

- Function 1.d, 2.d, Reactor Vessel Pressure-Low (Injection Permissive)

- Function 1.e, 1.f, 2.e, LPCS Pump & LPCI Pump A, B, & C Discharge Flow-Low (Bypass)

- Function 3.a, Reactor Vessel Water Level-Low Low, Level 2

- Function 3.c, Reactor Vessel Water Level-High, Level 8

- Function 3.d, Condensate Storage Tank Level-Low

- Function 3.e, Suppression Pool Water Level-High

- Function 3.f, HPCS Pump Discharge Pressure-High (Bypass)

- Function 3.g, HPCS System Flow Rate-Low (Bypass)

- Function 4.d, 5.d, Reactor Vessel Water Level-Low, Level 3 (Confirmatory)

- Function 4.e, 4.f, 5.e, LPCS Pump & LPCI Pump A, B, & C Discharge Pressure-High No revisions to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calCUlations).

Any necessary revisions to setpoint calculations and calibration procedures to incorporate to GNRO-2012/00096 Page 40 of 50 results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for all these functions had three previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On March 17, 2007 the Level 3 trip for trip unit 1B21-N695B was found out of tolerance.

Transmitter was adjusted to within proper specifications. CR 2007-01209 was written to document issue.

On September 20,2005, the As-Found value for trip unit 1B21-N673C exceeded Technical Specification tolerances high. The transmitter was adjusted to within tolerance.

CR 2005-3574 was written to document the issue.

On September 18, 2002, transmitter 1B21-N073G was found out of tolerance high and Low level trip unit 1B21-N673G exceeded Technical Specification tolerances. The instruments were adjusted to within proper tolerances. CR 2002-01807 was written to document the issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For these issues, there are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter. Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010. When considering that a total of 44 Rosemount 1153D transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage << 3%) of the total transmitters tested. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on the history of system performance, and the corrective actions for relay failures the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 41 of 50 3.3.5.2 Reactor Core Isolation Cooling (RCICl System Instrumentation The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the Reactor Feedwater System is unavailable, such that initiation of the low pressure ECCS pumps does not occur.

SR 3.3.5.2.4 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Vessel Water Level-Low Low, Level 2

- Function 2, Reactor Vessel Water Level-High, Level 8

- Function 3, Condensate Storage Tank Level-Low

- Function 4, Suppression Pool Water level-High For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these functions demonstrated that the as-found trip setpoint had one previous failure of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On April 29, 2010, transmitter 1B21-N091 F and associated 1B21-N692F were found outside Technical Specification limits. Transmitter 1B21-N091F was adjusted to within tolerances. CR 2010-02858 documents the issue.

The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24 month surveillance interval.

There are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter.

Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010.

When considering that a total of 44 Rosemount 1153D transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage << 3%) of the total transmitters tested. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

to GNRO-2012/00096 Page 42 of 50 Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.6.1 Primary Containment and Drywell Isolation Instrumentation The primary containment and drywell isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs) and drywell isolation valves.

SR 3.3.6.1.6 Perform CHANNEL CALIBRATION.

- Function 1.a, 2.c, Reactor Vessel Water Level-Low Low Low, Level 1 Function 1.b, Main Steam Line Pressure-Low Function 1.c, Main Steam Line Flow-High Function 1.d, Condenser Vacuum-Low Function 2.a, 2.e, 4.g, Reactor Vessel Water Level-Low Low, Level 2 Function 2.b, 2.d, 2.f, 3.j, 5.d, Drywell Pressure-High Function 3.a, RCIC Steam Line Flow-High Function 3.c, RCIC Steam Supply Line Pressure-Low Function 3.d, RCIC Turbine Exhaust Diaphragm Pressure-High Function 3.i, RCIC/RHR Steam Line Flow-High Function 4.a, Differential Flow-High Function 5.b, Reactor Vessel Water Level - Low, Level 3 Function 5.c, Reactor Steam Dome Pressure -High For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had five previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On May 5, 2010, transmitter 1B21-N081Awas found out of tolerance high, exceeding Technical Specification values. The transmitter was adjusted to within proper tolerances.

CR 2010-03354 was written to document issue.

On December 3, 2007, the as found results for transmitter 1C71-N050C failed Technical Specification acceptance criteria low. The transmitter was adjusted to within proper tolerances. CR 2007-05620 was written to document this issue.

On September 20, 2005, the As-Found value for trip unit 1B21-N673C exceeded Technical Specification tolerances high. The transmitter was adjusted to within tolerance.

CR 2005-3574 was written to document the issue.

to GNRO-2012/00096 Page 43 of 50 On March 4, 2004, during preventive maintenance to replace an amplifier and calibration boards for transmitter E31-N085B, readings were found out of tolerance high outside Technical Specification limits. After the replacement maintenance and adjustments were completed, the Technical Specification surveillance was completed satisfactorily. CR 2004-1015 was written to document this issue.

On September 18, 2002, transmitter 1B21-N073G was found out of tolerance high and Low level trip unit 1B21-N673G exceeded Technical Specification tolerances. The instruments were adjusted to within proper tolerances. CR 2002-01807 was written to document the issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the December 3, 2007 and March 4, 2004 issues, there are a total of two failures identified relative to Rosemount Model 1152 transmitters over the review period. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance. In one case, the transmitter was returned to service. In the other case, the electronic board was replaced and recalibrated, and the transmitter was returned to service. No timed-based mechanisms are apparent.

Therefore, this failure is unique and any sUbsequent failure would not result in a significant impact on system/component availability.

For the May 5, 2010, September 20, 2005, and September 18, 2002 issues, there are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter.

Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010.

When considering that a total of 44 Rosemount 11530 transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage (< 3%) of the total transmitters tested. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on system design and the history of system performance, the impact of this change on safety, if any, is small.

3.3.6.2 Secondarv Containment Isolation Instrumentation The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment System.

to GNRO-2012/00096 Page 44 of 50 SR 3.3.6.2.5 Perform CHANNEL CALIBRATION.

- Function 1, Reactor Vessel Water Level-Low Low, Level 2

- Function 2, Drywell Pressure-High For this function, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had two previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On May 5, 2010, transmitter 1B21-N081A was found out of tolerance high, exceeding Technical Specification values. The transmitter was adjusted to within proper tolerances.

CR 2010-03354 was written to document issue.

On December 3,2007, the as found results for transmitter 1C71-N050C failed Technical Specification acceptance criteria low. The transmitter was adjusted to within proper tolerances. CR 2007-05620 was written to document this issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the May 5, 2010 issue, there are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter. Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010. When considering that a total of 44 Rosemount 1153D transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage << 3%) of the total transmitters tested. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the December 3, 2007 issue, there are a total of two failures identified relative to Rosemount Model 1152 transmitters over the review period. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance. In one case, the transmitter was returned to service. In the other case, the electronic board was replaced and recalibrated, and the transmitter to GNRO-2012/00096 Page 45 of 50 was returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.6.3 Residual Heat Removal (RHR) Containment Spray System Instrumentation The RHR Containment Spray System is an operating mode of the RHR System that is initiated to condense steam in the containment atmosphere. This ensures that containment pressure is maintained within its limits following a loss of coolant accident (LOCA).

SR 3.3.6.3.5 Perform CHANNEL CALIBRATION.

- Function 1, Drywell Pressure-High

- Function 2, Containment Pressure-High

- Function 3, Reactor Vessel Water Level- Low Low Low, Level 1 For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for all these functions had no previous failures of a TS required allowable value that would have been detected solely by the periodic performance of this SR. As such, this failure is not indicative of a repetitive failure problem and does not invalidate the conclusion that only on rare occasions do as-found values exceed acceptable limits. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.6.4 Suppression Pool Makeup (SPMU) System Instrumentation The SPMU System provides water from the upper containment pool to the suppression pool, by gravity flow, after a loss of coolant accident (LOCA) to ensure that primary containment temperature and pressure design limits are met.

SR 3.3.6.4.5 Perform CHANNEL CALIBRATION.

- Function 1, 4, Drywell Pressure-High

- Function 2, Reactor Vessel Water Level-Low Low Low, Level 1

- Function 3, Suppression Pool Water Level -Low Low

- Function 5, Reactor Vessel Water Level -Low Low, Level 2 For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint to GNRO-2012/00096 Page 46 of 50 calculations). Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had two previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On May 5,2010, transmitter 1B21-N081Awas found out of tolerance high, exceeding Technical Specification values. The transmitter was adjusted to within proper tolerances.

CR 2010-03354 was written to document issue.

On December 3, 2007, the as found results for transmitter 1C71-N050C failed Technical Specification acceptance criteria low. The transmitter was adjusted to within proper tolerances. CR 2007-05620 was written to document this issue.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

For the May 5, 2010 issue, there are a total of six failures identified relative to Rosemount Model 1153 transmitters over the review period. All 6 transmitters are in the Reactor Vessel Water Level system. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance and returned to service. Each identified failure is a random out of tolerance condition and was not repeated during the review period. There were no failures that resulted in the replacement of a transmitter. Recalibration to within procedure acceptance tolerance was the only corrective action required. Of the six identified failures, each involved a different transmitter and there was one failure each in years 2002 and 2007 and two failures each in years 2005 and 2010. When considering that a total of 44 Rosemount 11530 transmitters in the scope of review were tested over the 5 performance review period for a total of 220 transmitters tested, a total of 6 failures does not represent a significant percentage << 3%) of the total transmitters tested. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

For the December 3, 2007 issue, there are a total of two failures identified relative to Rosemount Model 1152 transmitters over the review period. In each case, the transmitters were found outside the procedure acceptance tolerance and were recalibrated to within procedure acceptance tolerance. In one case, the transmitter was returned to service. In the other case, the electronic board was replaced and recalibrated, and the transmitter was returned to service. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on the history of system performance, the impact of this change on safety, if any, is small.

to GNRO-2012/00096 Page 47 of 50 3.3.6.5 Relief and Low-Low Set (LLS) Instrumentation The safety/relief valves (S/RVs) prevent overpressurization of the nuclear steam system.

Instrumentation is provided to support two modes (in addition to the automatic depressurization system (ADS) mode of operation for selected valves) of S/RV operation-the relief function (all valves) and the LLS function (selected valves).

SR 3.3.6.5.3 Perform CHANNEL CALIBRATION.

a) Relief Function b) LLS Function For these functions, no revision to TS allowable values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations. Any necessary revisions to setpoint calculations and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.8.1 Loss of Power (LOP) Instrumentation Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.

to GNRO-2012/00096 Page 48 of 50 SR 3.3.8.1.2 Perform CHANNEL CALIBRATION.

- Function 1.b, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage - Time Delay

- Function 1.d, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - Time Delay

- Function 2.a, Division 3 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage - 4.16 kV basis

- Function 2.b, Division 3 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage - Time Delay

- Function 2.c, Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage-4.16 kV basis

- Function 2.d, Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage-Time Delay, No LOCA

- Function 2.e, Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage -

Time Delay, LOCA For these functions, no TS allowable values or safety analysis result from the required evaluations. Any necessary revisions to setpoint calculations and calibration procedures will be completed prior to implementation.

A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or an alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage and frequency conditions.

SR 3.3.8.2.2 Perform CHANNEL CALIBRATION.

- Function a, Overvoltage

- Function b, Undervoltage

- Function c, Underfrequency(with time delay set to S 4 seconds)

For these functions, no revision to TS allowable values or safety analyses result from the required evaluations. Any necessary revisions to setpoint calculations and calibration procedures will be completed prior to implementation.

to GNRO-2012/00096 Page 49 of 50 A review of the applicable Grand Gulf surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

3.4.7 RCS Leakage Detection Instrumentation Leakage detection systems for the RCS are provided to alert the operators when leakage rates above normal background levels are detected and to supply quantitative measurement of rates.

SR 3.4.7.3 Perform CHANNEL CALIBRATION of required leakage detection instrumentation.

No allowable value is applicable to these functions. The leakage detection instrumentation differs from other TS instruments in that they are not associated with a function trip, but indication only to the control room operator. As such, these instruments are not expected to function with the same high degree of accuracy demanded of functions with assumed trip actuations for accident detection and mitigation. The leakage detection instrumentation devices are expected to maintain sufficient accuracy to detect trends or the existence or non-existence of an excessive leakage condition.

The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period. More frequent verification of the instrument functions are accomplished by SR 3.4.7.1 (Channel Check of the required drywell atmospheric monitoring system) once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and SR 3.4.7.2 (Channel Functional Tests of the required leakage detection instrumentation) once every 31 days.

A review of the applicable Grand Gulf surveillance history demonstrated that the RCS Leakage Detection System had two previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.

On August 2, 2009, the detector for Radiation Monitor 1D23-K601 was determined to be inoperable when non-Technical Specification as-found trip values were out of tolerance and a proper detector curve was unable to be obtained. Work Order 193632 was written to replace the detector. Following detector replacement, 06-IC-1 D23-R-1 002 was successfully performed in accordance with Work Order 51674100.

On June 12,2003, the D23K063 monitor efficiency failed low and the LCO was entered.

MAl 333946 was written and implemented to troubleshoot and replace the Gaseous Monitor. The surveillance was re-performed on June 19, 2003 following the replacement of the monitor.

The identified failures are unique and do not occur on a repetitive basis and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24 month surveillance interval.

to GNRO-2012/00096 Page 50 of 50 There are a total of two failures identified relative to Radiation Monitoring System equipment over the review period. In one case, a proper detector curve could not be obtained on Radiation Monitor 1D23-K601 and the particulate detector was replaced and retest was performed SAT. In the second case, monitor efficiency failed low on Gaseous Radiation Monitor 1D23-K603 and the gaseous detector was replaced and retest was performed SAT. No timed-based mechanisms are apparent. Therefore, this failure is unique and any subsequent failure would not result in a significant impact on system/component availability.

Based on the redundancy of detection methods, other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.

Attachment 6 GNRO*2012J00096 Instrument Drift Analysis Design Guide

Attachment 6 GNRO-2012/00096 Page 1 of 42 Engineering Report No. ECH-NE-OS-oOOI5 Rev Page of 55

~Entergy ENTERGY NUCLEAR Engineering Report Cover Sheet Engineering Report

Title:

Instrument Drift Analysis Design Guide Engineering Report Type:

New 181 Revision 0 Cancelled 0 Superseded 0 Applicable Site(s)

IPt 0 IP2 0 IP3 0 JAF 0 PNPS 0 VY 0 WPO 0 ANOI 0 AN02 0 ECH 0 GGNS 181 RBS 181 WF3 0 PLP 0 DRN No. ON/A; 0 __

(5) Report Origin: 0 Entergy 181 Vendor Vendor Document No.: _

(6) Quality-Related: 181 Yes o No Prepared by: Kirk R. Melson / .X!...1 I! //(,,/';""",- Date: 2-6-09

-=~~==~------------

Responsible Engineer (Print Name/Sign)

Date: f/!f,!oc, Reviewed by: N:..::..;./A~ _ Date: _

Reviewer (Print Name/Sign)

Reviewed by: ;,.:N~/A~ _ Date: _

Reviewer (Print Name/Sign)

Reviewed by*: --'N~/~A:...- _ Date: _

ANII (if required) (Print Name/Sign)

Approved by: ---'N~/~A:...- _ Date: _

Supervisor (Print Name/Sign)

For ASME Section XI Code Program plans per ENN-DC-120, if required GN RO-20 12/00096 Page 2 of 42 Engineering Report No. ECH-NE-08-00015 Rev.

Page 2 of 55 RECOMMENDAnON FOR APPROVAL FORM Verifier/Reviewer Responsible Supervisor (Print Name/Sign) (Print Name/Sign)

ANOI AN02 ECH GGNS IPI IP2 IP3 JAF PLP PNPS RBS VY WF3 WPO

Attachment 6 GN RO-20 12/00096 Page 3 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 3 of 55 TABLE OF CONTENTS SECTION HISTORY OF REVISIONS 3

1. OBJECTIVE/PURPOSE 5

2. DRIFT ANALYSIS SCOPE 5

3. DISCUSSION/METHODOLOGY 6 3.1. Methodology Options 6 3.2. Data Analysis Discussion 6 3.3. Confidence Interval 8 3.4. Calibration Data Collection 10 3.5. Categorizing Calibration Data 11 3.6. Outlier Analysis 15 3.7. Methods for Verifying Normality 17 3.8. Time-Dependent Drift Analysis 22 3.9. Calibration Point Drift 25 3.10. Drift Bias Determination 25 3.11. Time Dependent Drift Uncertainty 27 3.12. Shelf Life of Analysis Results 28

4. PERFORMING AN ANALYSIS 28 4.1. Populating the Spreadsheet 28 4.2. Spreadsheet Performance of Basic Statistics 29 4.3. Outlier Detection and Expulsion 31 4.4. Normality Tests 32 4.5. Time Dependency Testing 32 4.6. Calculate the Analyzed Drift (DA) Value 34

5. CALCULATIONS 37 5.1. Drift Calculations 37 5.2. Setpoint/Uncertainty Calculations 38

6. DEFINITIONS 39

7. REFERENCES 42 7.1. Industry Standards and Correspondence 42 7.2. Calculations and Programs 42 7.3. Miscellaneous 42 Appendix A: Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-l 03335, "Guidelines for Instrument Calibration Extension/Reduction Programs" 14 pages

Attachment 6 GNRO-2012/00096 Page 4 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 4 of 55 TABLES Table I - 95%/95%Tolerance Interval Factors 10 Table 2 - Critical Values fort-Test 16 Table 3 - Population Percentage for a Nonnal Distribution 21 Table 4 - Maximum Values of Non-Biased Mean 26 Record of Revision Rev. No. Description 0 Initial Issue I Added a statement to Section 3.3, regarding the assumption that the drift interval would be computed, expecting 95% of future drift values to be found within those limits. Provided additional detail for interpreting t-test results in Section 3.5.4. Provided clarifications of the details of the extrapolation methods used in Sections 3.11, 4.6 and 4.6.6, to conservatively require the use of the average time interval instead of the maximum time interval for extrapolation purposes, in cases where the drift data indicates potentially time-dependent behavior. Added infonnation for TDF to Section 3.4.2.3 and added a definition ofTDF to the table in Section 6.

Attachment 6 GNRO-2012/00096 Page 5 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 5 of 55

1. OBJECTIVE/PURPOSE The objective of this Design Guide is to provide the necessary detail and guidance to perform drift analyses using past calibration history data for the purposes of:

Quantifying component/loop drift characteristics within defined probability limits to gain an understanding of the expected behavior for the component/loop by evaluating past performance

Estimating component/loop drift for integration into setpoint calculations

Analysis aid for reliability centered maintenance practices (e.g., optimizing calibration frequency)

Establishing a technical basis for extending calibration and surveillance intervals using historical calibration data

Trending device performance based on extended surveillance intervals

2. DRIFT ANALYSIS SCOPE The scope of this design guide is limited to the calCulation of the expected performance for a component, group of components or loop, utilizing past calibration data. Drift Calculations are the final product of the data analysis.

The output from the Drift Calculations may be used directly as input to setpoint or loop accuracy calculations.

However, if desired, the output may be compared to the design values used within setpoint and loop accuracy calculations to show that the existing design approach is conservative.

The approaches described within this design guide can be applied to all devices that are surveilled or calibrated where As-Found and As-Left data is recorded. The scope of this design guide includes, but is not limited to, the following list of devices:

Transmitters (Differential Pressure, Flow, Level, Pressure, Temperature, etc.)

Bistables (Master & Slave Trip Units, Alarm Units, etc.)

Indicators (Analog, Digital)

Switches (Differential Pressure, Flow, Level, Position, Pressure, Temperature, etc.)

Signal Conditioners/Converters (Summers, E/P Converters, Square Root Converters, etc.)

Recorders (Temperature, Pressure, Flow, Level, etc.)

Monitors & Modules (Radiation, Neutron, H 20 2 , Pre-Amplifiers, etc.)

Relays (Time Delay, Undervoltage, Overvoltage, etc.)

Note that a given device or device type may be justified not to require drift analysis in accordance with this design guide, if appropriate.

Attachment 6 GNRO-2012/00096 Page 6 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 6 of 55

3. DISCUSSION/METHODOLOGY 3.1. Methodology Options This design guide is written to provide the methodology necessary for the analysis of As-Found versus As-Left calibration data, as a means of characterizing the performance of a component or group of components via the following methods:

3.1.1. Electric Power Research Institute (EPRI) has developed a guideline to provide nuclear plants with practical methods for analyzing historic component calibration data to predict component performance via a simple spreadsheet program (e.g., Excel, Lotus 1-2-3). This design guide is written in close adherence to this guideline, Reference 7.1.1. The Nuclear Regulatory Commission reviewed Revision 0 of Reference 7.1.1 and had a list of concerns documented in Reference 7.1. 8. These concerns prompted the issuance of Revision I to Reference 7.1.1. In addition, Appendix A to this design guide addresses each concern individually and provides the River Bend Station (RBS) and Grand Gulf Nuclear Station (GGNS) resolution.

3.1.2. Commercial Grade Software programs other than Microsoft Excel (e.g. IPASS, Lotus 1-2-3, SYSTAT, etc.), that perform the functions necessary to evaluate drift, may be utilized providing:

the intent of this design guide is met as outlined in Reference 7.1.1, and

software is used only as a tool to produce hard copy outputs which are to be independently verified.

3.1.3. The EPRI IPASS software, version 2.03, may be used to perform or independently verify certain portions of the drift analysis. The IPASS software does not have the functionality to perform many of the functions required by the drift analysis, such as certain time dependency functions, and therefore, should only be used in conjunction with other software products to produce or verify an entire Drift Calculation.

3.1.4. The final products of the data analyses are hard copy Drift Calculations. The electronic files of the Drift Calculations are an intermediate step from raw data to final product and are not controlled as QA files. The Drift Calculation is independently verified using different software than that used to create the Drift Calculation. The documentation of the review of the Drift Calculation will include a summary tabulation of results from each program used in the review process to provide visual evidence of the acceptability of the results of the review.

3.2. Data Analysis Discussion The following data analysis methods were evaluated for use at RBS and GGNS: I) As-Found Versus Setpoint, 2) Worst Case As-Found Versus As-Left, 3) Combined Calibration Data Points Analysis, and

4) As-Found Versus As-Left. The evaluation concluded that the As-Found versus As-Left methodology provided results that were more representative of the data and has been chosen for use by this Design Guide. Statistical tests not covered by this design guide may be utilized, provided the Engineer performing the analysis adequately justifies the use of the tests.

3.2.1. As-Found Versus As-Left Calibration Data Analysis The As-Found versus As-Left calibration data analysis is based on calculating drift by subtracting the previous As-Left component setting from the current As-Found setting. Each calibration point is treated as an independent set of data for purposes of characterizing drift across the full, calibrated span of the component/loop. By evaluating As-Found versus As-Left data for a component/loop or a similar group of components/loops, the following information may be obtained:

The typical component/loop drift between calibrations (Random in nature)

Any tendency for the component/loop to drift in a particular direction (Bias)

GNRO-2012/00096 Page 7 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 7 of 55

Any tendency for the component/loop drift to increase in magnitude over time (Time Dependency)

Confinnation that the selected setting or calibration tolerance is appropriate or achievable for the component/loop 3.2.1.1. General Features of As-Found Versus As-Left Analysis

The methodology evaluates historical calibration data only. The method does not monitor on-line component output; data is obtained from component calibration records.

Present and future perfonnance is predicted based on statistical analysis of past perfonnance.

Data is readily available from component calibration records. Data can be analyzed from plant startup to the present or only more recent data can be evaluated.

Since only historical data is evaluated, the method is not intended as a tool to identify individual faulty components, although it can be used to demonstrate that a particular component model or application historically performs poorly.

A similar class of components, i.e., same make, model, or application, is evaluated. For example, the method can detennine the drift of all analog indicators of a certain type installed in the control room.

The methodology is less suitable for evaluating the drift of a single component over time, due to statistical analysis penalties that occur with smaller sample sizes.

The methodology obtains a value of drift for a particular model, loop, or function that can be used in component or loop uncertainty and setpoint calculations.

The methodology is designed to support the analysis of longer calibration intervals and is consistent with the NRC expectations described in Reference 7.3.3. Values for instrument drift developed in accordance with this Design Guide are to be applied in accordance with References 7.2.1 and 7.2.2, as appropriate.

3.2.1.2. Error and Uncertainty Content in As-Found Versus As-Left Calibration Data The As-Found versus the As-Left data includes several sources of uncertainty over and above component drift. The difference between As-Found and previous As-Left data encompasses a number of instrument uncertainty tenns in addition to drift, as defined by References 7.2.1 and 7.2.2, the setpoint calculation methodologies for RBS and GGNS. The drift is not assumed to encompass the errors associated with temperature effect, since the temperature difference between the two calibrations is not quantified, and is not anticipated to be significant. Additional instruction for the use of As-Found and As-Left data may be found in Reference 7.1.2. The following possible contributors could be included within the measured variation, but are not necessarily considered as such.

Accuracy errors present between any two consecutive calibrations

Measurement and test equipment error between any two consecutive calibrations

Personnel-induced or human-related variation or error between any two consecutive calibrations

Nonnal temperature effects due to a difference in ambient temperature between GN RO-20 12/00096 Page 8 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 8 of 55 any two consecutive calibrations

Power Supply variations between any two consecutive calibrations

Environmental effects on component performance, e.g., radiation, humidity, vibration, etc., between any two consecutive calibrations that cause a shift in component output

Misapplication, improper installation, or other operating effects that affect component calibration between any two consecutive calibrations

True drift representing a change, time-dependent or otherwise, in component/loop output over the time period between any two consecutive calibrations 3.2.1.3. Potential Impacts of As-Found Versus As-Left Data Analysis Many of the bulleted items listed in step 3.2.1.2 are not expected to have a significant effect on the measured As-Found and As-Left settings. Because there are so many independent parameters contributing to the possible variance in calibration data, they are all considered together and termed the component's Analyzed Drift (DA) uncertainty. This approach has the following potential impacts on an analysis of the component's calibration data:

The magnitude of the calculated variation may exceed any assumptions or manufacturer predictions regarding drift. Attempts to validate manufacturer's performance claims should consider the possible contributors listed in step 3.2.1.2 to the calculated drift.

The magnitude of the calculated variation that includes all of the above sources of uncertainty may mask any "true" time-dependent drift. In other words, the analysis of As-Found versus As-Left data may not demonstrate any time dependency. This does not mean that time-dependent drift does not exist, only that it could be so small that it is negligible in the cumulative effects of component uncertainty, when all of the above sources of uncertainty are combined.

3.3. Confidence Interval This Design Guide recommends a single confidence interval level to be used for performing data analyses and the associated calculations.

NOTE: The default Tolerance Interval Factor (TIF) for all Drift Calculations, performed using this Design Guide, is chosen for a 95%/95% probability and confidence, although this is not specifically required in every situation. This term means that the results have a 95% confidence (y) that at least 95%

of the population lies between the stated interval (P) for a sample size (n). Extrapolating the drift value for the extended time between surveillance is based on the assumption that future drift values will also be within the calculated drift interval 95% of the time. Components that perform functions that support a specific Technical Specification value, Technical Requirements Manual (TRM) value or are associated with the safety analysis assumptions or inputs are always analyzed at a 95%/95% confidence interval.

Components/loops that fall into this level must:

be included in the data group (or be justified to apply the results per the guidance of Reference 7.1.1) if the analyzed drift value is to be applied to the componentlloop in a SetpointiUncertainty Calculation,

use the 95/95% TIF for determination of the Analyzed Drift term, and (see step 3.4.2 and Table 1 - 95%/95%Tolerance Interval Factors)

be evaluated in the SetpointiUncertainty Calculation for application ofthe Analyzed Drift term. (For example, the DA term may include the normal temperature effects for a given device, but due to the impossibility of separating out that specific term, an additional GN RO-20 12/00096 Page 9 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 9 of 55 temperature uncertainty may be included in the SetpointlUncertainty Calculation.}

GNRO-2012/00096 Page 10 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 10 of 55 3.4. Calibration Data Collection 3.4.1. Sources of Data The sources of data to perform a drift analysis are Surveillance Tests, Calibration Procedures and other calibration processes (calibration files, calibration sheets for Balance of Plant devices, Preventative Maintenance, etc.).

3.4.2. How Much Data to Collect 3.4.2.1. The goal is to collect enough data for the instrument or group of instruments to make a statistically valid pool. There is no hard fast number that must be attained for any given pool, but a minimum of 30 drift values must be attained before the drift analysis can be performed without additional justification. As a general rule, drift analyses should not be performed for sample sizes ofless than 20 drift values. Table I provides the 95%/95% TIF for various sample pool sizes; it should be noted that the smaller the pool the larger the penalty. A tolerance interval is a statement of confidence that a certain proportion of the total population is contained within a defined set of bounds.

For example, a 95%/95% TIF indicates a 95% level of confidence that 95% of the population is contained within the stated interval.

Table 1- 95%/95%Tolerance Interval Factors Sample Size 95%/95% Sample Size 95%/95% Sample Size 95%/95%

~2 37.674 > 23 2.673 > 120 2.205

~3 9.916 > 24 2.651 > 130 2.194

>4 6.370 > 25 2.631 > 140 2.184

>5 5.079 > 26 2.612 > 150 2.175

>6 4.414 > 27 2.595 > 160 2.167

>7 4.007 > 30 2.549 > 170 2.160

>8 3.732 > 35 2.490 > 180 2.154

>9 3.532 >40 2.445 > 190 2.148

~10 3.379 ~45 2.408 ~200 2.143

~ 11 3.259 ~ 50 2.379 > 250 2.121

~ 12 3.162 ~ 55 2.354 > 300 2.106

~ 13 3.081 >60 2.333 > 400 2.084

~14 3.012 > 65 2.315 > 500 2.070

~ 15 2.954 > 70 2.299 > 600 2.060

~ 16 2.903 > 75 2.285 > 700 2.052

> 17 2.858 > 80 2.272 > 800 2.046

~ 18 2.819 > 85 2.261 > 900 2.040

> 19 2.784 > 90 2.251 1000 2.036

~20 2.752 ~ 95 2.241 OCJ 1.960

> 21 2.723 > 100 2.233

> 22 2.697 > 110 2.218 3.4.2.2. Different information may be needed, depending on the analysis purpose, therefore, the total population of components - all makes, models, and applications that are to be analyzed must be known (e.g., all Rosemount transmitters).

GN RO-20 12/00096 Page 11 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 11 of 55 3.4.2.3. Once the total population of components is known, the components should be separated into functionally equivalent groups. Each grouping is treated as a separate population for analysis purposes. For example, start with all Rosemount Differential Pressure Transmitters as the initial group and break them down into various sub-groups -

Different Range Codes, Large vs. Small Turn Down Factors (TDF), Level vs. Flow Applications, etc. Note that TDF is a significant quantity, since drift is specified as a percent of Upper Range Limit for Rosemount transmitters.

3.4.2.4. Not all components or available calibration data points need to be analyzed within each group in order to establish statistical performance limits for the group. Acquisition of data should be considered from different perspectives.

For each grouping, a large enough sample of components should be randomly selected from the population, so there is assurance that the evaluated components are representative of the entire population. By randomly selecting the components and confirming that the behavior of the randomly selected components is similar, a basis for not evaluating the entire population can be established. For sensors, a random sample from the population should include representation of all desired component spans and functions.

For each selected component in the sample, enough historic calibration data should be provided to ensure that the component's performance over time is understood.

Due to the difficulty of determining the total sample set, developing specific sampling criteria is difficult. A sampling method must be used which ensures that various instruments calibrated at different frequencies are included. The sampling method must also ensure that the different component types, operating conditions and other influences on drift are included. Because of the difficulty in developing a valid sampling program, it is often simpler to evaluate all available data for the required instrumentation within the chosen time period.

This eliminates changing sample methods, should groups be combined or split, based on plant conditions or performance. For the purposes of this guide, specific justification in the Drift Calculation is required to document any sampling plan.

3.5. Categorizing Calibration Data 3.5.1. Grouping Calibration Data One analysis goal should be to combine functionally equivalent components (components with similar design and performance characteristics) into a single group. In some cases, all components of a particular manufacturer make and model can be combined into a single sample.

In other cases, virtually no grouping of data beyond a particular component make, model, and specific span or application may be possible. Some examples of possible groupings include, but are not limited to, the following:

3.5.1.1. Small Groupings

All devices of same manufacturer, model and range, covered by the same Surveillance Test

All trip units used to monitor a specific parameter (assuming that all trip units are the same manufacturer, model and range)

GNRO-2012/00096 Page 12 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 12 of 55 3.5.1.2. Larger Groupings

All transmitters of a specific manufacturer, model that have similar spans and performance requirements

All Foxboro Spec 200 isolators with functionally equivalent model numbers

All control room analog indicators of a specific manufacturer and model 3.5.2. Rationale for Grouping Components into a Larger Sample

A single component analysis may result in too few data points to make statistically meaningful performance predictions.

Smaller sample sizes associated with a single component may unduly penalize performance predictions by applying a larger TIF to account for the smaller data set.

Larger sample sizes reflect a greater understanding and assurance of representative data that in tum, reduces the uncertainty factor.

Large groupings of components into a sample set for a single population ultimately allows the user to state the plant-specific performance for a particular make and model of component. For example, the user may state, "Main Steam Flow Transmitters have historically drifted by less than I %", or "All control room indicators of a particular make and model have historically drifted by less than 1.5%".

An analysis of smaller sample sizes is more likely to be influenced by non-representative variations of a single component (outliers).

Grouping similar components together, rather than analyzing them separately, is more efficient and minimizes the number of separate calculations that must be maintained.

3.5.3. Considerations When Combining Components into a Single Group Grouping components together into a sample set for a single population does not have to become a complicated effort. Most components can be categorized readily into the appropriate population. Consider the following guidelines when grouping functionally equivalent components together.

If performed on a type-of-component basis, component groupings should usually be established down to the manufacturer make and model, as a minimum. For example, data from Rosemount and Foxboro transmitters should not be combined in the same drift analysis. The principles of operation are different for the various manufacturers, and combining the data could mask some trend for one type of component. This said; it might be desirable to combine groups of components for certain calculations. If dissimilar component types are combined, a separate analysis of each component type should still be completed to ensure analysis results of the mixed population are not misinterpreted or misapplied.

Sensors of the same manufacturer make and model, but with different calibrated spans or elevated zero points, can possibly still be combined into a single group. For example, a single analysis that determines the drift for all Rosemount pressure transmitters installed onsite might simplifY the application of the results. Note that some manufacturers provide a predicted accuracy and drift value for a given component model, regardless of its span. However, the validity of combining components with a variation of span, ranging from tens of pounds to several thousand pounds, should be confirmed. As part of the analysis, the performance of components within each span should be compared to the performance of the other devices to determine if any differences are evident between components with different spans.

GNRO-2012/00096 Page 13 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 13 of 55

Components combined into a single group should be exposed to similar calibration or surveillance conditions, as applicable. Note that the term operating condition was not used in this case. Although it is desirable that the grouped components perform similar functions, the method by which the data is obtained for this analysis is also significant. If half the components are calibrated in the summer at 90°F and the other half in the winter at 40°F, a difference in observed drift between the data for the two sets of components might exist. In many cases, ambient temperature variations are not expected to have a large effect, since the components are located in environmentally controlled areas.

3.5.4. Verification That Data Grouping Is Appropriate

Combining functionally equivalent components into a single group for analysis purposes may simplify the scope of work; however, some level of verification should be performed to confirm that the selected component grouping is appropriate. As an example, the manufacturer may claim the same accuracy and drift specifications for two components of the same model, but with different ranges, e.g., 0-5 PSIG and 0-3000 PSIG. However, in actual application, components of one range may perform differently than components of another range.

Standard statistics texts provide methods that can be used to determine if data from similar types of components can be pooled into a single group. If different groups of components have essentially equal variances and means at the desired statistical level, the data for the groups can be pooled into a single group.

When evaluating groupings, care must be taken not to split instrument groups only because they are calibrated on a different time frequency. Differences in variances may be indicative of a time dependent component to the device drift. The separation of these groups may mask a time-dependency for the component drift.

A t-Test (two samples assuming unequal variances) should also be performed on the proposed components to be grouped. The t-Test returns the probability associated with a Student's t-Test to determine whether two samples are likely to have come from the same two underlying populations that have unequal variances. If for example, the proposed group contains 5 sub-groups, the t-Tests should be performed on all possible combinations for the groupings. However, if there is no plausible engineering explanation for the two sets of data being incompatible, the groups should be combined, despite the results of the t-Test. The following formula is used to determine the test statistic value t.

- x2 - ~ 0 (Ref. 7.3.4) 2 2

~+~

nj n2 Where; t' - test statistic n - Total number of data points x - Mean of the samples S2 - Pooled variance

~o - Hypothesized mean difference GNRO-2012/00096 Page 14 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 14 of 55 The following fonnula is used to estimate the degrees of freedom (dt) for the test statistic.

[ !L+ ~)2 n I n2 n2 - 1 Where; Values are as previously defined.

The t-Test may be perfonned using the t-Test: Two-Sample Assuming Unequal Variances analysis tool within Microsoft Excel. The Microsoft Excel output will look similar to the following:

t-Test: Two-Sample Assuming Unequal Variances Variable 1 Vanabie 2 Mean -0.017045 0.08413462 Variance 0.1008523 0.31185697 Observations 11 26 Hypothesized Mean Difference o df 32 t Stat -0.695517 P(T<=t) one-tail 0.245876 t Critical one-tail 1.6938887 P(T<=t) two-tail 0.4917521 t Critical two-tail 2.0369333 A comparison is made to detennine whether the proposed groups of data can be combined for analysis. The t distribution is two-sided in this case, and therefore the t Critical two-tail is used as the criterion. If the absolute value ofthe t statistic (t Stat) is less than the t Critical two-tail value, then the data can be considered to have very similar means, and can be considered acceptable for combination on that basis.

3.5.5. Examples of Proven Groupings:

All control room indicators receiving a 4-20mAdc (or 1-5Vdc) signal. Notice that a combined grouping may be possible even though the indicators have different indication spans. For example, a 12 mAdc signal should move the indicator pointer to the 50% of span position on each indicator scale, regardless of the span indicated on the face plate (exceptions are non-linear meter scales).

All control room bistables of similar make or model tested quarterly for Technical Specification surveillance. Note that this assumes that all bistables are tested in a similar manner and have the same input range, e.g., a 1-5Vdc or 4-20mAdc spans.

A specific type of pressure transmitter used for similar applications in the plant in which the operating and calibration environment does not vary significantly between applications or location.

A group of transmitters of the same make and model, but with different spans, given that a review confinns that the transmitters of different spans have similar perfonnance characteristics.

GNRO-2012/00096 Page 15 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 15 of 55 3.5.6. Using Data from Other Nuclear Power Plants:

It is acceptable, although not recommended, to pool RBS or GGNS specific data with data obtained from other nuclear power plants, providing the data can be verified to be of high quality. In this case the data must also be verified to be acceptable for grouping.

Acceptability may be defined by verification of grouping, and an evaluation of calibration procedure methods, Measurement and Test Equipment used, and defined setting tolerances. Where there is agreement in calibration method (for instance, starting at zero increasing to 100 percent and decreasing to zero, taking data every 25%), calibration equipment, and area environment (if performance is affected by the temperature), there is a good possibility that the groups may be combined. Previously collected industry data may not have sufficient information about the manner of collection to allow combination with plant specific data.

3.6. Outlier Analysis An outlier is a data point significantly different in value from the rest of the sample. The presence of an outlier or multiple outliers in the sample of component or group data may result in the calculation of a larger than expected sample standard deviation and tolerance interval. Calibration data can contain outliers for several reasons. Outlier analyses can be used in the initial analysis process to help to identify problems with data that require correction. Examples include:

Data Transcription Errors - Calibration data can be recorded incorrectly either on the original calibration data sheet or in the spreadsheet program used to analyze the data.

Calibration Errors - Improper setting of a device at the time of calibration would indicate larger than normal drift during the subsequent calibration.

Measuring & Test Equipment Errors - Improperly selected or mis-calibrated test equipment could indicate drift, when little or no drift was actually present.

Scaling or Setpoint Changes - Changes in scaling or setpoints can appear in the data as larger than actual drift points unless the change is detected during the data entry or screening process.

Failed Instruments - Calibrations are occasionally performed to verify proper operation due to erratic indications, spurious alarms, etc. These calibrations may be indicative of component failure (not drift), which would introduce errors that are not representative of the device performance during routine conditions.

Design or Application Deficiencies - An analysis of calibration data may indicate a particular component that always tends to drift significantly more than all other similar components installed in the plant. In this case, the component may need an evaluation for the possibility of a design, application, or installation problem. Including this particular component in the same population as the other similar components may skew the drift analysis results.

3.6.1. Detection of Outliers There are several methods for determining the presence of outliers. This design guide utilizes the Critical Values for t-Test (Extreme Studentized Deviate). The t-Test utilizes the values listed in Table 2 with an upper significance level of 5% to compare a given data point against.

Note that the critical value oft increases as the sample size increases. This signifies that as the sample size grows, it is more likely that the sample is truly representative of the population. The t-Test assumes that the data is normally distributed.

GNRO-2012/00096 Page 16 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 16 of 55 Table 2 - Critical Values for t-Test Sample Size Upper 5% Significance Sample Size Upper 5% Significance Level Level

<3 1.15 22 2.60 4 1.46 23 2.62 5 1.67 24 2.64 6 1.82 25 2.66 7 1.94 ~30 2.75 8 2.03 ~ 35 2.82 9 2.11 ~40 2.87 10 2.18 <45 2.92 11 2.23 ~ 50 2.96 12 2.29 ~60 3.03 13 2.33 ~ 70 3.09 14 2.37 ~ 75 3.10 15 2.41 ~ 80 3.14 16 2.44 ~ 90 3.18 17 2.47 ~ 100 3.21 18 2.50 < 125 3.28 19 2.53 < 150 3.33 20 2.56 >150 4.00 21 2.58 3.6.2. t-Test Outlier Detection Equation t = IX i -xl

~---'- (Ref. 7.1.1)

S Where; Xi - An individual sample data point X - Mean of all sample data points s - Standard deviation of all sample data points

- Calculated value of extreme studentized deviate that is compared to the critical value of t for the sample size.

3.6.3. Outlier Expulsion This design guide does not permit multiple outlier tests or passes. The removal of poor quality data as listed in Section 3.6 is not considered removal of outliers, since it is merely assisting in identifying data errors. However, after removal of poor quality data as listed in Section 3.6, certain data points can still appear as outliers when the outlier analysis is performed. These "unique outliers" are not consistent with the other data collected; and could be judged as erroneous points, which tend to skew the representation of the distribution of the data.

However, for the general case, since these outliers may accurately represent instrument performance, only one (1) additional unique outlier (as indicated by the t-Test), may be removed from the drift data. After removal of poor quality data and the removal of the unique outlier (if necessary), the remaining drift data is known as the Final Data Set.

GN RO-20 12/00096 Page 17 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 17 of 55 For transmitters or other devices with multiple calibration points, the general process is to use the calibration point with the worst-case drift values. This is determined by comparing the different calibration points and using the one with the largest error, determined by adding the absolute value of the drift mean to 2 times the drift standard deviation. The data set with the largest of those terms is used throughout the rest of the analysis, after outlier removal, as the Final Data Set. (Note that it is possible to use a specific calibration point and neglect the others, only if that is the single point of concern for application of the results of the Drift Calculation.

Ifso, this fact should be stated boldly in the results / conclusions of the calculation.)

The data set basic statistics (i.e., the Mean, Median, Standard Deviation, Variance, Minimum, Maximum, Kurtosis, Skewness, Count and Average Time Interval between Calibrations) should be computed and displayed for the data set prior to removal of the unique outlier and for the Final Data Set, if different.

3.7. Methods for Verifying Normality A test for normality can be important because many frequently used statistical methods are based upon an assumption that the data is normally distributed. This assumption applies to the analysis of component calibration data also. For example, the following analyses may rely on an assumption that the data is normally distributed:

Determination of a tolerance interval that bounds a stated proportion of the population based on calculation of mean and standard deviation

Identification of outliers

Pooling of data from different samples into a single population The normal distribution occurs frequently and is an excellent approximation to describe many processes.

Testing the assumption of normality is important to confirm that the data appears to fit the model of a normal distribution, but the tests do not prove that the normal distribution is a correct model for the data.

At best, it can only be found that the data is reasonably consistent with the characteristics of a normal distribution, and that the treatment of a distribution as normal is conservative. For example, some tests for normality only allow the rejection of the hypothesis that the data is normally distributed. A group of data passing the test does not mean the data is normally distributed; it only means that there is no evidence to say that it is not normally distributed. However, because of the wealth of industry evidence that drift can be conservatively represented by a normal distribution, a group of data passing these tests is considered as normally distributed without adjustments to the standard deviation of the data set.

Distribution-free techniques are available when the data is not normally distributed; however, these techniques are not as well known and often result in penalizing the results by calculating tolerance intervals that are substantially larger than the normal distribution equivalent. Because of this fact, there is a good reason to demonstrate that the data is normally distributed or can be bounded by the assumption of normality.

Analy1ically verifying that a sample appears to be normally distributed usually invokes a form of statistics known as hypothesis testing. In general, a hypothesis test includes the following steps:

I) Statement of the hypothesis to be tested and any assumptions

2) Statement of a level of significance to use as the basis for acceptance or rejection ofthe hypothesis

3) Determination of a test statistic and a critical region

4) Calculation of the appropriate statistics to compare against the test statistic

5) Statement of conclusions GNRO-2012/00096 Page 18 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 18 of 55 The following sections discuss various ways in which the assumption of normality can be verified to be consistent with the data or can be claimed to be a conservative representation of the actual data.

Analytical hypothesis testing and subjective graphical analyses are discussed. If the analytical hypothesis test (either Chi-Squared or D Prime / W Test) are passed, the coverage analysis and additional graphical analyses are not required. Generally, only a single hypothesis test should be performed on a given data set. Because of the consistent approach given for the D Prime and W tests from Reference 7.104, these tests are recommended. However, use ofthe Chi-Squared test is allowed in place of the D Prime or W Test, if desired. The following are descriptions of the methods for assessing normality.

3.7.1. Chi-Squared, x 2 , Goodness of Fit Test This well-known test is stated as a method for assessing normality in References 7.1.1 and 7.1.2.

The x 2 test compares the actual distribution of sample values to the expected distribution. The expected values are calculated by using the normal mean and standard deviation for the sample.

Ifthe distribution is normally or approximately normally distributed, the difference between the actual versus expected values should be very small. And, if the distribution is not normally distributed, the differences should be significant.

3.7.1.1. Equations to Perform the x 2 Test

1) First calculate the mean for the sample group

- "'x.

X=_L...

__ 1 (Ref. 7.1.1) n Where; Xi - An individual sample data point X - Mean of all sample data points n - Total number of data points

2) Second calculate the standard deviation for the sample group s= n2:x 2 _(2: x)2 (Ref. 7.1.1) n(n -1)

Where; x - Sample data values (xl, x2, x3, .....)

s - Standard deviation of all sample data points n - Total number of data points

3) Third the data must be divided into bins to aid in determination of a normal distribution. The number of bins selected is up to the individual performing the analysis. Refer to Reference 7.1.1 for further guidance. For most applications, a 12-bin analysis is performed on the drift data. See Section 404.

GNRO-2012/00096 Page 19 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 19 of 55

4) Fourth calculate the x2 value for the sample group 0 _£.)2 X

2

=I ( 1 I (Ref. 7.1.1)

Ei Where; Ej - Expected values for the sample N - Total number of samples in the population Pj - Probability that a given sample is contained in a bin OJ - Observed sample values (a" O 2, 0 3, .....)

2 x - Chi squared result

5) Fifth, calculate the degrees of freedom. The degrees of freedom term is computed as the number of bins used for the chi-square computation minus the constraints. In all cases for these Drift Calculations, since the count, mean and standard deviation are computed, the constraints term is equal to three.

6) Sixth, compute the Chi squared per degree of freedom term (Xo2). This term is merely the Chi squared term computed in step 4 above, divided by the degrees of freedom.

7) Finally, evaluate the results. The results are evaluated in the following manner, as prescribed in Reference 7.1.1. If the Chi squared result computed in step 4 is less than or equal to the degrees of freedom, the assumption that the distribution is normal is not rejected. If the value from step 4 is greater than the degrees of freedom, then one final check is made. The degrees of freedom and X o2 are used to look up the probability of obtaining a Xo2 term greater than the observed value, in percent. (See Table C-3 of Reference 7.1.1.) If the lookup value is greater than or equal to 5%, then the assumption of normality is not rejected. However, if the lookup value is less than 5%, the assumption of normality is rejected.

3.7.2. W Test Reference 7.1.4 recommends this test for sample sizes less than 50. The W Test calculates a test statistic value for the sample population and compares the calculated value to the critical values for W, which are tabulated in Reference 7.1.4. The W Test is a lower-tailed test. Thus if the calculated value of W is less than the critical value of W, the assumption of normality would be rejected at the stated significance level. If the calculated value of W is larger than the critical value ofW, there is no evidence to reject the assumption of normality. Reference 7.1.4 establishes the methods and equations required for performing a W Test.

3.7.3. D-Prime Test Reference 7.1.4 recommends this test for moderate to large sample sizes, greater than or equal to

50. The D' Test calculates a test statistic value for the sample population and compares the calculated value to the values for the D' percentage points of the distribution, which are tabulated in Reference 7.1.4. The D' Test is two-sided, which means that the two-sided percentage limits at the stated level of significance must envelop the calculated D' value. For the given sample size, the calculated value of D' must lie within the two values provided in the Reference 7.1.4 table in order to accept the hypothesis of normality.

Altachment6 GNRO-2012/00096 Page 20 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 20 of 55 3.7.3.1. Equations to Perform the D' Test

1) First, calculate the linear combination of the sample group. (Note: Data must be placed in ascending order of magnitude, prior to the application of this formula.)

(Ref. 7.1.4)

Where; T - Linear combination Xi - An individual sample data point

- The number of the sample point n - Total number of data points

2) Second, calculate the S2 for the sample group.

S2 ={n-l)s2 (Ref. 7.1.4)

Where; S2 - Sum of the Squares about the mean S2 - Unbiased estimate of the sample population variance n - Total number of data points

3) Third, calculate the D' value for the sample group.

D'=!.. (Ref. 7.1.4)

S

4) Finally, evaluate the results. If the D' value lies within the acceptable range of results (for the given data count) per Table 5 of Reference 7.1.4, for the P = 0.025 and 0.975, then the assumption of normality is not rejected. (If the exact data count is not contained within the tables, the critical value limits for the D' value should be linearly interpolated to the correct data count.) Ifhowever, the value lies outside that range, the assumption of normality is rejected.

3.7.4. Probability Plots For most Drift Calculations performed per this methodology, probability plots will not be included, since numerical methods or coverage analyses are recommended. However, probability plots are discussed, since a graphical presentation of the data can sometimes reveal possible reasons for why the data is or is not normal. A probability plot is a graph of the sample data with the axes scaled for a normal distribution. If the data is normal, the data tends to follow a straight line. If the data is non-normal, a nonlinear shape should be evident from the graph.

This method of normality determination is subjective, and is not required if the numerical method shows the data to be normal, or if a coverage analysis is used. The types of probability plots used by this design guide are as follows:

GNRO-2012/00096 Page 21 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 21 of 55

Cumulative Probability Plot - an XY scatter plot of the Final Data Set plotted against the percent probability (Pi) for a nonnal distribution. Pi is calculated using the following equation:

~

100 x (i -~)

= ---'---'- (Ref. 7.1.1) n where; i = sample number i.e. 1,2,...

n = sample size NOTE: Refer, as necessary, to Appendix C Section C.4 of Reference 7.1.1.

Normalized Probability Plot - an XY scatter plot of the Final Data Set plotted against the probability for a nonnal distribution, expressed in multiples of the standard deviation.

3.7.5. Coverage Analysis A coverage analysis is recommended for cases in which the hypothesis tests reject the assumption of nonnality, but the assumption of nonnality is still a conservative representation of the data. The coverage analysis involves the use of a histogram of the Final Data Set, overlaid with the equivalent probability distribution curve for the nonnal distribution, based on the data sample's mean and standard deviation.

Visual examination of the plot is used to detennine if the distribution of the data is near nonnal, or if a nonnal distribution model for the data would adequately cover the data within the 2 sigma limits. Another measure of the conservatism in the use of a nonnal distribution as a model is the kurtosis of the data. Reference 7.1.1 states that samples that have a large value of kurtosis are the most likely candidates for a coverage analysis. Kurtosis characterizes the relative peakedness or flatness of the distribution compared to the nonnal distribution, and is readily calculated within statistical and spreadsheet programs. As shown in Reference 7.1.1, a positive kurtosis indicates a relatively high peaked distribution, and a negative kurtosis indicates a relatively flat distribution, with respect to the nonnal distribution.

If the data is near nonnal or is more peaked than a nonnal distribution (positive kurtosis), then a nonnal distribution model is derived, which adequately covers the set of drift data, as observed.

This nonnal distribution is used as the model for the drift of the device. Sample counting is used to detennine an acceptable nonnal distribution model. The Standard Deviation of the group is computed. The number of samples that are within +/- two Standard Deviations of the mean is computed. The count is divided by the total number of samples in the group to detennine a percentage. The following table provides the percentage that should fall within the two Standard Deviation values for a nonnal distribution.

Table 3 - Population Percentage for a Normal Distribution Percentage for a Normal Distribution I 2 Standard Deviations 95.45%

If the percentage of data within the two standard deviations tolerance is greater than the value in Table 3 for a given data set, the existing standard deviation is acceptable to be used for the encompassing nonnal distribution model. However, if the percentage is less than required, the standard deviation of the model is enlarged, such that greater than or equal to the required percentage falls within the +/- two Standard Deviations bounds. The required multiplier for the standard deviation in order to provide this coverage is tenned the Nonnality Adjustment Factor (NAF). lfno adjustment is required, the NAF is equal to one (I).

GNRO-2012/00096 Page 22 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 22 of 55 3.8. Time-Dependent Drift Analysis The component/loop drift calculated in the previous sections represented a predicted performance limit, without any consideration of whether the drift may vary with time between calibrations or component age. This section discusses the importance of understanding the time-related performance and the impact of any time-dependency on an analysis. Understanding the time dependency can be either important or unimportant, depending on the application. A time dependency analysis is important whenever the drift analysis results are intended to support an extension of calibration intervals.

3.8.1. Limitations of Time Dependency Analyses Reference 7.1.1 performed drift analysis for numerous components at several nuclear plants as part of the project. The data evaluated did not demonstrate any significant time-dependent or age-dependent trends. Time dependency may have existed in all of the cases analyzed, but was insignificant in comparison to other uncertainty contributors. Because time dependency cannot be completely ruled out, there should be an ongoing evaluation to verify that component drift continues to meet expectations whenever calibration intervals are extended.

3.8.2. Scatter (Drift Interval) Plot A drift interval plot is an XY scatter plot that shows the Final Data Set plotted against the time interval between tests for the data points. This plot method relies upon the human eye to discriminate the plot for any trend in the data to exhibit time dependency. A prediction line can be added to this plot which shows a "least squares" fit ofthe data over time. This can provide visual evidence of an increasing or decreasing mean over time, considering all drift data. An increasing standard deviation is indicated by a trend towards increasing "scatter" over the increased calibration intervals.

3.8.3. Standard Deviations and Means at Different Calibration Intervals (Binning Analysis)

This analysis technique is the most recommended method of determining time dependent tendencies in a given sample pool. (See Reference 7.1.1.) The test consists simply of segregating the drift data into different groups (Bins) corresponding to different ranges of calibration or surveillance intervals and comparing the standard deviations and means for the data in the various groups. The purpose of this type of analysis is to determine if the standard deviation or mean tends to become larger as the time interval between calibrations increases.

3.8.3.1. The available data is placed in interval bins. The intervals normally used at RBS or GGNS coincide with Technical Specification calibration intervals plus the allowed tolerance as follows:

a. 0 to 45 days (covers most weekly and monthly calibrations)

b. 46 to 135 days (covers most quarterly calibrations)

c. 136 to 230 days (covers most semi-annual calibrations)

d. 231 to 460 days (covers most annual calibrations)

e. 461 to 690 days (covers most 18 month refuel cycle calibrations)

f. 691 to 915 days (covers most extended refuel cycle calibrations)

g. > 915 days covers missed and forced outage refueling cycle calibrations.

Data will naturally fall into these time interval bins based on the calibration requirements for the subject instrument loops. Only on occasion will a device be calibrated on a much longer or shorter interval than that of the rest of the population within its calibration requirement group. Therefore, the data will naturally separate into groups for analysis.

GNRO-2012/00096 Page 23 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 23 of 55 3.8.3.2. Although not generally recommended, different bin splits could be used, but must be evaluated for data coverage, significant diversity in calibration intervals, and acceptable data groupings.

3.8.3.3. For each bin where there is data, the mean (average), standard deviation, average time interval and data count will be computed.

3.8.3.4. To determine if time dependency does or does not exist, the data must be distributed across multiple bins, with a sufficient population of data in each of two or more bins, to consider the statistical results for those bins to be valid. Normally the minimum expected distribution that would allow evaluation is defined below.

a. A bin is considered valid in the final analysis if it holds more than five data points and more than ten percent of the total data count.

b. At least two bins, including the bin with the most data, must be left for evaluation to occur.

The distribution percentages listed in these criteria are somewhat arbitrary, and thus engineering evaluation can modify them for a given situation.

The mean and standard deviations of the valid bins are plotted versus average time interval on a diagram. This diagram can give a good visual indication of whether or not the mean or standard deviation of a data set is increasing significantly over time interval between calibrations.

If the binning analysis plot shows an increase in standard deviation over time, the critical value of the F-distribution is compared to the ratio of the smallest and largest variances for the evaluated bins. If the ratio of variances exceeds the critical value, this result is indicative of time dependency for the random portion of drift. Likewise, a ratio of variances not exceeding the critical value is not indicative of significant time dependency.

NOTE: If multiple valid bins do NOT exist for a given data set, then the plot is not to be shown, and the regression analyses are not to be performed. The reasoning is that there is not enough diversity in the calibration intervals analyzed to make meaningful conclusions about time dependency from the existing data. Unless overwhelming evidence to the contrary exists in the scatter plot, the single bin data set is treated as moderately time dependent for the purposes of extrapolation of the drift value.

3.8.4. Regression Analyses and Plots Regression Analyses can often provide very valuable data for the determination of time dependency. A standard regression analysis within an EXCEL spreadsheet can plot the drift data versus time, with a prediction line showing the trend. It can also provide Analysis of Variance (ANOVA) table printouts, which contain information required for various numerical tests to determine level of dependency between two parameters (time and drift value). Note that regression analyses are only to be performed if multiple valid bins are determined from the binning analysis.

Regression Analyses are to be performed on the Final Data Set drift values and on the Absolute Value of the Final Data Set drift values. The Final Data Set drift values show trends for the mean of drift, and the Absolute Values show trends for the standard deviation over time.

GNRO-2012/00096 Page 24 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 24 of 55 Regression Plots The following are descriptions of the two plots generated by these regressions.

Drift Regression - an XY scatter plot that fits a line through the final drift data, plotted against the time interval between tests for the data points, using the "least squares" method to predict values for the given data set. The predicted line is plotted through the actual data for use in predicting drift over time. It is important to note that statistical outliers can have a dramatic effect upon the regression line.

Absolute Value Drift Regression - an XY scatter plot that fits a line through the Absolute Value of the final drift data, plotted against the time interval between tests for the data points, using the "least squares" method to predict values for the given data set. The predicted line is plotted through the actual data for use in predicting drift, in either direction, over time. It is important to note that statistical outliers can have a dramatic effect upon the regression line.

Regression Time Dependency Analytical Tests Typical spreadsheet software includes capabilities to include ANOVA tables with regression analyses. ANOVA tables give various statistical data, which can allow certain numerical tests to be employed, to search for time dependency. For each ofthe two regressions (drift regression and absolute value drift regression), the following ANOVA parameters are used to determine if time dependency of the drift data is evident. All tests listed should be evaluated, and if time dependency is indicated by any of the tests, the data should be considered as time dependent.

R Squared Test - The R Squared value, printed out in the ANOVA table, is a relatively good indicator of time dependency. If the value is greater than 0.09 (thereby indicating the R value greater than 0.3), then it appears that the data closely conforms to a linear function, and therefore, should be considered time dependent.

P Value Test - A P Value for X Variable I (as indicated by the ANOVA table for an EXCEL spreadsheet) less than 0.05 is indicative of time dependency.

Significance ofF Test - An ANOVA table F value greater than the critical F-table value would indicate a time dependency. In an EXCEL spreadsheet, the FINV function can be used to return critical values from the F distribution. To return the critical value of F, use the significance level (in this case 0.05 or 5.0%) as the probability argument to FINV, 2 as the numerator degrees of freedom, and the data count minus two as the denominator. If the F value in the ANOVA table exceeds the critical value of F, then the drift is considered time dependent.

NOTE: For each of these tests, if time dependency is indicated, the plots should be observed to determine the reasonableness of the result. The tests above generally assess the possibility that the function of drift is linear over time, not necessarily that the function is significantly increasing over time. Time dependency can be indicated even when the plot shows the drift to remain approximately the same or decrease over time. Generally, a decreasing drift over time is not expected for instrumentation, nor is a case where the drift function crosses zero. Under these conditions, the extrapolation of the drift term would normally be established assuming no time dependency, if extrapolation of the results is required beyond the analyzed time intervals between calibrations.

GNRO-2012/00096 Page 25 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 25 of 55 3.8.5. Additional Time Dependency Analyses

Instrument Resetting Evaluation - For data sets that consist of a single calibration interval the time dependency determination may be accomplished simply by evaluating the frequency at which instruments require resetting. This type of analysis is particularly useful when applied to extend quarterly Technical Specification surveillances to semi-annual.

However, this type of analysis is less useful for instruments such as sensors or relays that may be reset at each calibration interval, regardless of whether the instrument was already in calibration.

The Instrument Resetting Evaluation may be performed only if the devices in the sample pool are shown to be stable, not requiring adjustment (i.e. less than 5% of the data shows that adjustments were made). Care also must be taken when mechanical connections or flex points may be exercised by the act of checking calibration (actuation of a bellows or switch movement), where the act of checking the actuation point may have an effect on the next reading. Methodology for calculating the drift is as follows:

Quarterly As-Found/As-Left (As-Found Current Calibration - As-Left Previous Calibration) or AF I - AL2 (Ref. 7.1.1)

Semi-Annual As-Found!As-Left using Monthly Data (Ref. 7.1.1) 3.8.6. Age-Dependent Drift Considerations Age-dependency is the tendency for a component's drift to increase in magnitude as the component ages. This can be assessed by plotting the As-Found value for each calibration minus the previous calibration As-Left value of each component over the period of time for which data is available. Random fluctuations around zero may obscure any age-dependent drift trends. By plotting the absolute values of the As-Found versus As-Left calibration data, the tendency for the magnitude of drift to increase with time can be assessed. This analysis is generally not performed as a part of a standard Drift Calculation, but can be used, if desired, when establishing maintenance practices.

3.9. Calibration Point Drift For devices with multiple calibration points (e.g., transmitters, indicators, etc.) the Drift-Calibration Point Plot is a useful tool for comparing the amount of drift exhibited by the group of devices at the different calibration points. The plot consists of a line graph of tolerance interval as a function of calibration point. This is useful to understand the operation of an instrument, but is not normally included as a part of a standard Drift Calculation.

3.10. Drift Bias Determination If an instrument or group of instruments consistently drifts predominately in one direction, the drift is assumed to have a bias. When the absolute value ofthe calculated average for the sample pool exceeds the values in Table 4 for the given sample size and calculated standard deviation, the average is treated as a bias to the drift term. The application ofthe bias must be carefully considered separately, so that the overall treatment of the analyzed drift remains conservative. The values for Xcrit may be used directly from Table 4 or may be calculated, using the equation below the table. Refer to Example I below.

GNRO-2012/00096 Page 26 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 26 of 55 Table 4 - Maximum Values of Non-Biased Mean Sample Nonnal Deviate (t) Maximum Value or Non-Biased Mean (x.rit) For Given STDEV (s)

Size (n) @ 0.025 for 95%

Confidence s;:: s;:: s;:: s;:: s;:: s;:: s;:: s;:: s;::

0.10% 0.25% 0.50% 0.75% 1.00% 1.50% 2.00% 2.50% 3.00%

~5 2.571 0.115 0.287 0.575 0.862 1.150 1.725 2.300 2.874 3.449

~IO 2.228 0.070 0.176 0.352 0.528 0.705 1.057 1.409 1.761 2.114

~15 2.131 0.055 0.138 0.275 0.413 0.550 0.825 1.100 1.376 1.651

~20 2.086 0.047 0.117 0.233 0.350 0.466 0.700 0.933 1.166 1.399

~25 2.060 0.041 0.103 0.206 0.309 0.412 0.618 0.824 1.030 1.236

~O 2.042 0.037 0.093 0.186 0.280 0.373 0.559 0.746 0.932 1.118

~40 2.021 0.032 0.080 0.160 0.240 0.320 0.479 0.639 0.799 0.959

~60 2.000 0.026 0.065 0.129 0.194 0.258 0.387 0.516 0.645 0.775

~120 1.980 0.Q18 0.045 0.090 0.136 0.181 0.271 0.361 0.452 0.542

>120 1.960 (Values Above are Computed per Equation Below)

The maximum values of non-biased mean (Xcrit) for a given standard deviation (s) and sample size (n) is calculated using the following formula:

S x crit = t x .r;; (Ref. 7.3.2)

Where; X crit Maximum value of non-biased mean for a given s & n, expressed in %

Normal Deviate for at-distribution @ 0.025 for 95% Confidence s Standard Deviation of sample pool n Sample pool size Examples of determining and applying bias to the analyzed drift term:

I) Transmitter Group With a Biased Mean - A group of transmitters are calculated to have a standard deviation of 1.150%, mean of - 0.355% with a count of 47. From Table 4, the maximum value that a negligible mean could be is +/- 0.258%. Therefore, the mean value is significant, and must be considered. The analyzed drift term for a 95%/95% tolerance interval level is shown as follows.

DA = - 0.355% +/- 1.150% x 2.408 (TIF from Table 1 for 47 samples)

DA = - 0.355% +/- 2.769%

For conservatism, the DA term for the positive direction is not reduced by the bias value where as the negative direction is summed with the bias value.

DA = + 2.769%, - 3.124%.

GNRO-2012/00096 Page 27 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 27 of 55

2) Transmitter Group With a Non-Biased Mean - A group of transmitters are calculated to have a standard deviation of 1.150%, mean of 0.1 00% with a count of 47. From Table 4, the maximum value that a negligible mean could be is +/- 0.258%. Therefore, the mean value is insignificant, and can be neglected. The analyzed drift term for a 95%/95% tolerance interval level is shown as follows.

DA = +/- I.l50% x 2.408 (TIF from Table I for 47 samples)

DA=+/-2.769%

3.11. Time Dependent Drift Uncertainty When calibration intervals are extended beyond the range for which historical data is available, the statistical confidence in the ability to predict drift is reduced. The bias and the random portions of the drift are extrapolated separately, but in the same manner. Where the analysis shows slight to moderate time dependency or time dependency is indeterminate, drift is extrapolated using the Square Root of the Sum of the Squares (SRSS) method per Section 6.2.7 of Reference 7.1.2. This method assumes that the drift to time relationship is not linear. The formula below is used.

Rqd _ Calibration _ Interval DAExtended = DA x A vg _ Bin _ Time _ Interval Where: DAExtended = the newly determined, extrapolated Drift Bias or Random Term DA = the bias or random drift term from the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)

Avg_ Bin_Time_Interval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)

Rqd_Calibration_Interval = the worst case calibration interval, once the calibration interval requirement is changed Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation.

For those cases where no time dependency is apparent from the drift analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.

Where there is indication of a strong relationship between drift and time, drift is extrapolated using the linear method per Section 6.2.7 of Reference 7.1.2. The following formula may be used.

D'~Extended A = D' A [Rqd _ Calibration _ Interval]

~x ..

Avg _ Bm _ Time _ Interval Where the terms are the same as defined above.

Where it can be shown that there is no relationship between surveillance interval and drift, the drift value determined may be used for other time intervals, without change. However, for conservatism, due to the uncertainty involved in extrapolation to time intervals outside of the analysis period, drift values that show minimal or no particular time dependency are generally treated as moderately time dependent, for the purposes of the extrapolation.

Attachment 6 GNRO-2012/00096 Page 28 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 28 of 55 3.12. Shelf Life of Analysis Results Any analysis result based on performance of existing components has a shelf life. In this case, the term "shelf life" is used to describe a period of time extending from the present into the future during which the analysis results are considered valid. Predictions for future component/loop performance are based upon our knowledge of past calibration performance. This approach assumes that changes in component/loop performance occur slowly or not at all over time. For example, if evaluation of the last ten years of data shows the component/loop drift is stable with no observable trend, there is little reason to expect a dramatic change in performance during the next year. However, it is also difficult to claim that an analysis completed today is still a valid indicator of component/loop performance ten years from now. For this reason, the analysis results should be re-verified periodically through an instrument trending program in accordance with Reference 7.1.1. The Analyzed Drift values from the Drift Calculations are to be used by the trending program as thresholds, which will require further investigation if exceeded.

Depending on the type of component/loop, the analysis results are also dependent on the method of calibration, the component/loop span, and the M&TE accuracy. Any of the following program or component/loop changes should be evaluated to determine if they affect the analysis results.

Changes to M&TE accuracy

Changes to the component or loop (e.g. span, environment, manufacturer, model, etc.)

Calibration procedure changes that alter the calibration method

4. PERFORMING AN ANALYSIS As Found and As Left calibration data for the subject instrumentation is collected from historical calibration records. The collected data is entered into Microsoft Excel spreadsheets, grouped by manufacturer and model number. All data is also entered into an independent software program (such as IPASS, Lotus 1-2-3, or SYSTAT), for independent review of certain of the drift analysis functions. The drift analysis is generally performed using EXCEL spreadsheets, but can be performed using other software packages. The discussion provided in this section is to assist in setting up an EXCEL spreadsheet for producing a Drift Calculation. For IPASS analysis instructions, see the IPASS User's Manual (Reference 7.3.1).

Microsoft Excel spreadsheets generally compute values to an approximate 15 decimal resolution, which is well beyond any required rounding for engineering analyses. However, for printing and display purposes, most values are displayed to lesser resolution. It is possible that hand computations would produce slightly different results, because of using rounded numbers in initial and intermediate steps, but the Excel computed values are considered highly accurate in comparison. Values with significant differences between the original computations and the computations of the independent verifier are to be investigated to ensure that the Excel spreadsheet is properly computing the required values.

4.1. Populating the Spreadsheet

4. I. I. For a New Analysis

4. I .1.1. The Responsible Engineer determines the component group to be analyzed (e.g., all Rosemount pressure transmitters). The Responsible Engineer should determine the possible sub-groups within the large groupings, which from an engineering perspective, might show different drift characteristics; and therefore, may warrant separation into smaller groups. This determination would involve the manufacturer, model, calibration span, setpoints, time intervals, specifications, locations, environment, etc., as necessary.

4.1.1.2. The Responsible Engineer develops a list of component numbers, manufacturers, models, component types, brief descriptions, surveillance tests, calibration procedures and calibration information (spans, setpoints, etc.).

GNRO-2012/00096 Page 29 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 29 of 55 4.1.1.3. The Responsible Engineer determines the data to be collected, following the guidance of Sections 3.4 through 3.6 of this Design Guide.

4.1.1.4. The Data Entry Person identifies, locates and collects data for the component group to be analyzed (e.g., all Surveillance Tests for the Rosemount pressure transmitters completed to present).

4.1.1.5. The Data Entry Person sorts the data by surveillance test or calibration procedure if more than one test/procedure is involved.

4.1.1.6. The Data Entry Person sequentially sorts the surveillance or calibration sheets descending, by date, starting with the most recent date.

4.1.1.7. The Data Entry Person enters the Surveillance or Calibration Procedure Number, Tag Numbers, Required Trips, Indications or Outputs, Date, As-Found values and As-Left values on the appropriate data entry sheet.

4.1.1.8. The Responsible Engineer verifies the data entered.

4.1.1.9. The Responsible Engineer reviews the notes on each calibration data sheet to determine possible contributors for excluding data. The notes should be condensed and entered onto the EXCEL spreadsheet for the applicable calibration points. Where appropriate and obvious, the Responsible Engineer should remove the data that is invalid for calculating drift for the device.

4.1.1.10.The Responsible Engineer (via the spreadsheet) calculates the time interval for each drift point by subtracting the date from the previous calibration from the date of the subject calibration. (If the measured value is not valid for the As-Left or As-Found calibration information, then the time interval is not required to be computed for this data point.)

4.1.1.11. The Responsible Engineer (via the spreadsheet) calculates the Drift value for each calibration by subtracting the As-Left value from the previous calibration from the As-Found value of the subject calibration. (If the measured value is not valid for the As-Left or As-Found calibration information, then the Drift value is not computed for this data point.)

4.2. Spreadsheet Performance of Basic Statistics Separate data columns are created for each calibration point within the calibrated span of the device. The

% Span of each calibration point should closely match from device to device within a given analysis.

Basic statistics include, at a minimum, determining the number of data points in the sample, the average drift, the average time interval between calibrations, standard deviation of the drift, variance of the drift, minimum drift value, maximum drift value, kurtosis, and skewness contained in each data column. This section provides the specific details for using Microsoft Excel. Other spreadsheet, statistical or Math programs that are similar in function, are acceptable for use to perform the data analysis, provided all analysis requirements are met.

4.2.1. Determine the number of data points contained in each column for each initial group by using the "COUNT" function. Example cell format = COUNT(C2:C133). The Count function returns the number of all populated cells within the range of cells C2 through C133.

4.2.2. Determine the average for the data points contained in each column for each initial group by using the "AVERAGE" function. Example cell format = AVERAGE(C2:C133). The Average function returns the average of the data contained within the range of cells C2 through C133.

This average is also known as the mean of the data. This same method should be used to determine the average time interval between calibrations.

GNRO-2012/00096 Page 30 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 30 of 55 4.2.3. Determine the standard deviation for the data points contained in each column for each initial group by using the "STDEV" function. Example cell format =STDEV(C2:C133). The Standard Deviation function returns the measure of how widely values are dispersed from the mean ofthe data contained within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the standard deviation:

STD (Standard Deviation of the sample population): (Ref. 7.3.4)

Where; x - Sample data values (Xl, X2, X3, ..... )

S - Standard deviation of all sample data points n - Total number of data points 4.2.4. Determine the variance for the data points contained in each column for each initial group by using the "VAR" function. Example cell format =VAR(C2:C133). The Variance function returns the measure of how widely values are dispersed from the mean ofthe data contained within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the variance:

VAR (Variance of the sample population): (Ref. 7.3.4) 2 nI.x 2 _(I.x)2 S = n(n-l)

Where; x - Sample data values (XI, X2, X3, ..... )

S2 - Variance of the sample population n - Total number of data points 4.2.5. Determine the kurtosis for the data points contained in each column for each initial group by using the "KURT" function. Example cell format =KURT(C2:C133). The Kurtosis function returns the relative peakedness or flatness of the distribution within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the kurtosis:

KURT ={ (n - n(n+l) 1Xn - 2 Xn - 3)

I(X i -X)4}_

s 3(n-l)2 (n - 2 Xn - 3)

(Ref. 7.3.4)

Where; x - Sample data values (XI, X2, X3, .....)

n - Total number of data points s - Sample Standard Deviation GN RO-20 12/00096 Page 31 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 31 of 55 4.2.6. Detennine the skewness for the data points contained in each column for each initial group by using the "SKEW" function. Example cell fonnat =SKEW(C2:C133). The Skewness function returns the degree of symmetry around the mean of the cells contained within the range of cells C2 through C133. Fonnula used by Microsoft Excel to detennine the skewness:

SKEW = n(n+l)

(n -IXn - 2)

I(x s-x)3 i

(Ref. 7.3.4)

Where; x - Sample data values (XL, xz, X3, ... )

n - Total number of data points s - Sample Standard Deviation 4.2.7. Detennine the maximum value for the data points contained in each column for each initial group by using the "MAX" function. Example cell fonnat =MAX(C2:C133). The Maximum function returns the largest value of the cells contained within the range of cells C2 through C133.

4.2.8. Detennine the minimum value for the data points contained in each column for each initial group by using the "MIN" function. Example cell fonnat =MIN(C2:C133). The Minimum function returns the smallest value of the cells contained within the range of cells C2 through C133.

4.2.9. Detennine the median value for the data points contained in each column for each initial group by using the "MEDIAN" function. Example cell fonnat =MEDlAN(C2:C133). The median is the number in the middle of a set of numbers; that is, half the numbers have values that are greater than the median, and half have values that are less. If there is an even number of data points in the set, then MEDIAN calculates the average of the two numbers in the middle.

4.2.10. Where sub-groups have been combined in a data set, and where engineering reasons exist for the possibility that the data should be separated, analyze the statistics and component data of the sub-groups to detennine the acceptability for combination.

4.2.11. Perfonn a t-Test in accordance with step 3.5.4 on each possible sub-group combination to test for the acceptability of combining the data.

Acceptability for combining the data is indicated when the absolute value of the Test Statistic [t Stat] is greater than the [t Critical two-tail]. Example: t Stat for combining sub-group A & B may be 0.703, which is larger than the t Critical two-tail of 0.485. However, as a part of this process, the Responsible Engineer should ensure that the apparent unacceptability for combination does not mask time dependency. In other words, if the only difference in the groupings is that of the calibration interval, the differences in the data characteristics could exist because of time dependent drift. If this is the only difference, the data should be combined, even though the tests show that it may not be appropriate.

4.3. Outlier Detection and Expulsion Refer to Section 3.6 for a detailed explanation of Outliers.

4.3.1. Obtain the Critical Values for the t-Test from Table 2, which is based on the sample size of the data contained within the specified range of cells. Use the COUNT value to detennine the sample size.

4.3.2. Perfonn the outlier test for all the samples. For any values that show up as outliers, analyze the initial input data to detennine if the data is erroneous. If so, remove the data in the earlier pages of the spreadsheet, and re-run all of the analysis up to this point. Continue this process until all GNRO-2012/00096 Page 32 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 32 of 55 erroneous data has been removed.

4.3.3. If appropriate, if any outliers are stilI displayed, remove the worst-case outlier as a statistical outlier, per step 3.6.3. Once this outlier has been removed (if applicable), the remaining data set is the Final Data Set.

4.3.4. For transmitters, or other devices with multiple calibration points, the general process is to use the calibration point with the worst case drift values. This is determined by comparing the different calibration points and using the one with the largest error, determined by adding the absolute value of the mean to 2 times the standard deviation. The data set with the largest of those terms is used throughout the rest of the analysis, after outlier removal, as the Final Data Set. (Note that it is possible to use a specific calibration point and neglect the others, only ifthat is the single point of concern for application of the results of the Drift Calculation. If so, this fact should be stated boldly in the results! conclusions of the calculation.)

4.3.5. Recalculate the Average, Median, Standard Deviation, Variance, Minimum, Maximum, Kurtosis, Skewness, Count and Average Time Interval Between Calibrations for the Final Data Set.

4.4. Normality Tests To test for normality of the Final Data Set, the first step is to perform the required hypothesis testing. For Final Data Sets with 50 or more data points, the hypothesis testing can be performed with either the Chi-Square (Section 3.7.1) or the D-Prime Test (Section 3.7.3). The D-Prime Test is recommended. Ifthe Final Data Set has less than 50 data points, the W Test (Section 3.7.2) or Chi-Square Test may be used.

The W Test is recommended.

If used, the Chi Square test should generally be performed with 12 bins of data, starting from [-00 to (mean-2.5a)], and bin increments ofO.5a, ending at [(mean+2.5a) to +00]. (Since the same bins are to be used for the histogram in the coverage analysis, the work for these two tasks may be combined.)

If the assumption of normality is rejected by the numerical test, then a coverage analysis should generally be performed as described in Section 3.7.5. As explained above the for Chi Square test, the coverage analysis and histogram are established with a 12 bin approach unless inappropriate for the application.

If an adjustment is required to the standard deviation to provide a normal distribution that adequately covers the data set, then the required multiplier to the standard deviation (Normality Adjustment Factor (NAF>> is determined iteratively in the coverage analysis. This multiplier produces a normal distribution model for the drift, which shows adequate data population from the Final Data Set within the +/- 2a bounds of the model.

4.5. Time Dependency Testing Time dependency testing is only required for instruments for which the calibration intervals are being extended; however, the scatter plot is recommended for information in all Drift Calculations. Time dependency is evaluated through the use of a scatter (drift interval) plot, binning analysis, and regression analyses. The methods for each of these are detailed below.

4.5.1. Scatter Plot The scatter plot is performed under a new page to the spreadsheet entitled "Scatter Plot" or "Drift Interval Plot". The chart function of EXCEL is used to merely chart the data with the x axis being the calibration interval and the y axis being the drift value for the Final Data Set. The prediction line should be added to the chart, along with the equation of the prediction line. This plot provides visual indication ofthe trend of the mean, and somewhat obscurely, of any increases in the scatter of the data over time. Note: The trend line should NOT be forced to have a y-intercept value of 0, but should be plotted for the actual drift data only.

GNRO-2012/00096 Page 33 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 33 of 55 4.5.2. Binning Analysis The binning analysis is perfonned under a separate page of the EXCEL spreadsheet. The Final Data Set is split by bins 1 through 8 into the time intervals as defined in Section 3.8.3.1. A table is set up to compute the standard deviation, mean, average time interval, and count of the data in each time bin. Similar equation methods are used here as described in Section 4.2, when characterizing the drift data set. Another table is used to evaluate the validity of the bins, based on population per the criteria of Section 3.8.3.4. If multiple valid bins are not established, the time dependency analysis stops here, and no regression analyses are perfonned.

Ifmultiple valid bins are established, the standard deviations, means and average time intervals are tabulated, and a plot is generated to show the variation of the bin averages and standard deviations versus average time interval. This plot can be used to detennine whether standard deviations and means are significantly increasing over time between calibrations.

If the plot shows an increase in standard deviation over time, compare the critical value of the F-distribution of the ratio of the smallest and largest variances for the required bins.

Fca1c =-,

S, 2 s2-where:

SI = largest drift standard deviation value S2 = smallest drift standard deviation value The critical value ofF-distribution can be found, using the FINV function in Microsoft Excel:

Fctit = FINV (0.05, VI, V 2)

VI = number of samples minus I in bin with largest standard deviation V2 = number of samples minus I in bin with smallest standard deviation If the ratio of variances exceeds the critical value, this result is indicative oftime dependency for the random portion of drift. Likewise, a ratio of variances not exceeding the critical value is not indicative of significant time dependency.

4.5.3. Regression Analyses The regression analyses are perfonned in accordance with the requirements of Section 3.8.4, given that multiple valid time bins were established in the binning analysis. New pages should be created for the Drift Regression and the Absolute Value Drift Regression.

For each of the two Regression Analyses, use the following steps to produce the regression analysis output. Using the "Data Analysis" package under "Tools" in Microsoft EXCEL, the Regression option should be chosen. The Y range is established as the Drift (or Absolute Value of Drift) data range, and the X range should be the calibration time intervals. The output range should be established on the Regression Analysis page of the spreadsheet. The option for the residuals should be established as "Line Fit Plots". The regression computation should then be perfonned. The output of the regression routine is a list of residuals, an ANOVA table listing, and a plot ofthe Drift (or Absolute Value of Drift) versus the Time Interval between Calibrations. A prediction line is included on the plot.

Add a cell close to the ANOVA table listing which establishes the Critical Value of F, using the guidance of Section 3.8.4 for the Significance of F Test. This utilizes the FINV function of Microsoft EXCEL.

GNRO-2012/00096 Page 34 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 34 of 55 Analyze the results in the Drift Regression ANOVA table for R Square, P Value, and F Value, using the guidance of Section 3.8.4. Ifany of these analytical methods shows time dependency in the Drift Regression, the mean of the data set should be established as strongly time dependent if the slope of the prediction line significantly increases over time from an initially positive value (or decreases over time from an initially negative value), without crossing zero within the time interval ofthe regression analysis. This increase can also be validated by observing the results ofthe binning analysis plot for the mean of the bins and by observing the scatter plot and regression analysis prediction lines.

Analyze the results in the Absolute Value of Drift Regression ANOVA table for R Square, P Value, and F Value, using the guidance of Section 3.8.4. If any of these analytical means shows time dependency, the standard deviation of the data set should be established as strongly time dependent if the slope of the prediction line significantly increases over time. This increase can also be validated by observing the results of the binning analysis plot for the standard deviation of the bins, by observation of the results from the F distribution comparison within the binning plot, and by observing any discernible increases in data scatter, as time increases, on the scatter plot.

Regardless of the results of the analytical regression tests, if the plots tend to indicate significant increases in either the mean or standard deviation over time, those parameters should be judged to be strongly time dependent. Otherwise, for conservatism, the data is always considered to be moderately time dependent if extrapolation of the data is necessary, to accommodate the uncertainty involved in the extrapolation process, since no data has generally been observed at time intervals as large as those proposed.

4.6. Calculate the Analyzed Drift (DA) Value The first step in determining the Analyzed Drift Value is to determine the required time interval for which the value must be computed. For the majority of the cases for instruments calibrated on a refueling basis, the required nominal calibration time interval is 24 months, or a maximum of 30 months.

Since the average time intervals are generally computed in days, the most conservative value for a 30-Month calibration interval is established as 915 days.

The Analyzed Drift Value generally consists of two separate components - a random term and a bias term. If the mean of the Final Data Set is significant per the criteria in Section 3.10, a bias term is considered. If no extrapolation is necessary, the bias term is set equal to the mean of the Final Data Set.

If extrapolation is necessary, it is performed in one of two methods, as determined by the degree oftime dependency established in the time dependency analysis. If the mean is determined to be strongly time dependent, the following equation is used, which extrapolates the value in a linear fashion.

DA - Max Rqd Time Interval Extended.bias = x x A B' T' 1 vg _ m _L lme _ nterva I

If the mean is determined to be moderately time dependent, the following equation is used to extrapolate the mean. (Note that this equation is also generally used for cases where no time dependency is evident, because of the uncertainty in defining a drift value beyond analysis limits.)

Max _ Rqd _ Time _ Interval DAExtended.bias =x x Avg _Bin _Time _Interval GNRO-2012/00096 Page 35 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 35 of 55 Where: x = Mean of the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)

Avg_Bin_Time_Interval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)

Max_Rqd_Time_Interval = the maximum time interval for desired calibration interval. For instance, 915 days for a desired 24 month nominal calibration interval.

Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation.

For those cases where no time dependency is apparent from the drift analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.

The random portion of the Analyzed Drift is calculated by multiplying the standard deviation of the Final Data Set by the Tolerance Interval Factor for the sample size and by the Normality Adjustment Factor (if required from the Coverage Analysis). If extrapolation is necessary, it is performed in one of two methods, similar to the methods shown above for the bias term, depending on the degree of time dependency observed. Use the following procedure to perform the operation.

4.6.1. Use the COUNT value ofthe Final Data Set to determine the sample size.

4.6.2. Obtain the appropriate Tolerance Interval Factor (TIF) for the size of the sample set. Table 1 lists the 95%/95% TIFs; refer to Standard statistical texts for other TIF multipliers. Note: TIFs other than 95%/95% must be specifically justified.

4.6.3. For a generic data analysis, multiple Tolerance Interval Factors may be used, providing a clear tabulation of results is included in the analysis, showing each value for the multiple levels of TIF.

4.6.4. Multiply the Tolerance Interval Factor by the standard deviation for the data points contained in the Final Data Set and by the Normality Adjustment Factor determined in the Coverage Analysis (if applicable).

4.6.5. If the analyzed drift term calculated above is applied to the existing calibration interval, application of additional drift uncertainty is not necessary.

4.6.6. When calculating drift for calibration intervals that exceed the historical calibration intervals, use the following equations, depending on whether the data is shown to be strongly time dependent or moderately time dependent.

For a Strongly Time Dependent random term, use the following equation.

Max Rqd Time Interval DAExtended.random = cr x TIF x NAF x "

Avg _Bm _Time _Interval GN RO-20 12/00096 Page 36 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 36 of 55 For a Moderately Time Dependent random term, use the following equation. (Note that this equation is also generally used for cases where no time dependency is evident, because of the uncertainty in defining a drift value beyond analysis limits.)

Max _ Rqd Time Interval DAExtended.random = cr x TIF x NAF x Avg _ Bin _ Time _ Interval Where: a = Standard Deviation of the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)

TIF = Tolerance Interval Factor from Table I NAF = Normality Adjustment Factor from the Coverage Analysis (If Applicable)

Avg_Bin_Time_Interval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)

Max_Rqd_Time_Interval = the maximum time interval for desired calibration interval. For instance, 915 days for a desired 24 month nominal calibration interval.

Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation.

For those cases where no time dependency is apparent from the drift analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.

4.6.7. Since random errors are always expressed as +/- errors, specific consideration of directionality is not generally a concern. However, for bistables and switches, the directionality of any bias error must be carefully considered. Because of the fact that the As-Found and As-Left setpoints are recorded during calibration, the drift values determined up to this point in the Drift Calculation are representative of a drift in the setpoint, not in the indicated value.

Per Reference 7.1.2, error is defined as the algebraic difference between the indication and the ideal value of the measured signal. In other words, Error = indicated value - ideal value (actual value)

For devices with analog outputs, a positive error means that the indicated value exceeds the actual value, which would mean that if a bistable or switching mechanism used that signal to produce an actuation on an increasing trend, the actuation would take place prior to the actual variable reaching the value of the intended setpoint. As analyzed so far in the Drift Calculation for bistables and switches, the drift causes the opposite effect. A positive Analyzed Drift would mean that the setpoint is higher than intended; thereby causing actuation to occur after the actual variable has exceeded the intended setpoint.

A bistable or switch can be considered to be a black box, which contains a sensing element or circuit and an ideal switching mechanism. At the time of actuation, the switch or bistable can be considered an indication of the process variable. Therefore, a positive shift of the setpoint can be considered to be a negative error. In other words, if the switch setting was intended to be 500 psig, but actually switched at 510 psig, at the time of the actuation, the switch "indicated" that the process value was 500 psig when the process value was actually 510 psig. Thus, error = indicated value (500 psig) - actual value (510 psig) = -10 psig

Attachment 6 GNRO-2012/00096 Page 37 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 37 of 55 Therefore, a positive shift of the setpoint on a switch or bistable is equivalent to a negative error, as defined by Reference 7.1.2. Therefore, for clarity and consistency with the treatment of other bias error terms, the sign of the bias errors of a bistable or switch should be reversed, in order to comply with the convention established by Reference 7.1.2. In either case, the conclusions of the Drift Calculation should be clear enough for proper application to setpoint computations.

5. CALCULA nONS 5.1. Drift Calculations The Drift Calculations should be performed in accordance with the methodology described above, with the following documentation requirements.

5.1.1. The title includes the Manufacturer/Model number of the component group analyzed.

5.1.2. The calculation objective must:

5.1.2.1. describe, at a minimum, that the objective of the calculation is to document the drift analysis results for the component group, and extrapolate the drift value to the required calibration period (if applicable),

5.1.2.2. provide a list for the group of all pertinent information in tabular form (e.g. Tag Numbers, Manufacturer, Model Numbers, ranges and calibration spans), and 5.1.2.3. describe any limitations on the application of the results. For instance, if the analysis only applies to a certain range code, the objective should state this fact.

5.1.3. The method of solution should describe, at a minimum, a summary of the methodology used to perform the drift analysis outlined by this Design Guide. Exceptions taken to this Design Guide are to be included in this section including basis and references for any exceptions.

5.1.4. The actual calculation/analysis should provide:

5.1.4.1. A listing of data which was removed and the justification for removal 5.1.4.2. List of references 5.1.4.3. A narrative discussion ofthe specific activities performed for this calculation 5.1.4.4. Results and conclusions, including Manufacturer and model number analyzed Bias and random Analyzed Drift values, as applicable The applicable Tolerance Interval Factors (provide detailed discussion and justification if other than 95%/95%)

Applicable drift time interval for application Normality conclusion Statement of time dependency observed, as applicable Limitations on the use of this value in application to uncertainty calculations, as applicable Limitations on the application if the results to similar instruments, as applicable 5.1.5. Attachment(s) should be provided, including the following information:

5.1.5.1. Input data with notes on removal and validity GNRO-2012/00096 Page 38 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 38 of 55 5.1.5.2. Computation of drift data and calibration time intervals 5.1.5.3. Outlier summary, including Final Data Set and basic statistical summaries 5.1.5.4. Chi Square Test Results (As Applicable) 5.1.5.5. W Test or D' Test Results (As Applicable) 5.1.5.6. Coverage Analysis, Including Histogram, Percentages in the Required Sigma Band, and Normality Adjustment Factor (As Applicable) 5.1.5.7. Scatter Plot with Prediction Line and Equation 5.1.5.8. Binning Analysis Summaries for Bins and Plots (As Applicable) 5.1.5.9. Regression Plots, ANaVA Tables, and Critical F Values (As Applicable)

5. 1.5. 10. Derivation of the Analyzed Drift Values, With Summary of Conclusions 5.2. SetpointlUncertainty Calculations To apply the results of the drift analyses to a specific device or loop, a setpoint or loop accuracy calculation must be performed, revised or evaluated in accordance with References 7.2.1 and 7.2.2, as appropriate. Per Section 3.2.1.2, the Analyzed Drift term characterizes various instrument uncertainty terms for the analyzed device, loop, or function. In order to save time, a comparison between these terms in an existing setpoint calculation to the Analyzed Drift can be made. Ifthe terms within the existing calculation bound the Analyzed Drift term, then the existing calculation is conservative as is, and does not specifically require revision. If revision to the calculation is necessary, the Analyzed Drift term may be incorporated into the calculation, by replacing the appropriate terms for the analyzed devices with the Analyzed Drift term.

When comparing the results to setpoint calculations that have more than one device in the instrument loop that was analyzed for drift, comparisons can be made between the DA terms and the original terms on a device-by-device basis, or on a total loop basis. Care should be taken to properly combine terms for comparison in accordance with References 7.2.1 and 7.2.2, as appropriate.

When applying the Drift Calculation results ofbistables or switches to a setpoint calculation, the preparer should fully understand the directionality of any bias terms within DA and apply the bias terms accordingly. (See Section 0.)

Attachment 6 GNRO-2012/00096 Page 39 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 39 of 55

6. DEFINITIONS Standard statistics term meaning that the results have a 95% confidence (y) that at least 95%/95% Ref. 7.1.1 95% of the population wi1llie between the stated interval (P) for a sample size (n).

A term representing the errors determined by a completed drift analysis for a group.

Analyzed Drift Uncertainties that!!!!!£ be represented by the analyzed drift term are component (DA) reference accuracy, input and output M&TE errors, personnel-induced or human related Section 4.6 errors, ambient temperature and other environmental effects, power supply effects, misapplication errors and true component drift.

The condition in which a channel, or portion of a channel, is found after a period of As-Found (FT) Ref. 7.1.3 operation and before recalibration.

The condition in which a channel, or portion of a channel, is left after calibration or final As-Left (CT) Ref. 7.1.3 setpoint device verification.

Bias (B) A shift in the signal zero point by some amount. Ref. 7.1.1 Calibrated Span The maximum calibrated upper range value less the minimum calibrated lower range Ref. 7.1.1 (CS) value.

The elapsed time between the initiation or successful completion of calibrations or Calibration Interval calibration checks on the same instrument, channel, instrument loop, or other specified Ref. 7.1.1 system or device.

A test to determine if a sample appears to follow a given probability distribution. This Chi-Square Test Ref. 7.1.1 test is used as one method for assessing whether a sample follows a normal distribution.

Confidence Interval An interval that contains the population mean to a given probability. Ref. 7.1.1 An analysis to determine whether the assumption of a normal distribution effectively Coverage Analysis Ref. 7.1.1 bounds the data. A histogram is used to graphically portray the coverage analysis.

Cumulative An expression of the total probability contained within an interval from -00 to some Ref. 7.1.1 Distribution value, x.

A test to verify the assumption of normality for moderate to large sample sizes (50 or Ref. 7.1.1, D-Prime Test greater samples). 7.1.4 In statistics, dependent events are those for which the probability of all occurring at once is different than the product of the probabilities of each occurring separately. In setpoint Dependent Ref. 7.1.1 determination, dependent uncertainties are those uncertainties for which the sign or magnitude of one uncertainty affects the sign or magnitude of another uncertainty.

An undesired change in output over a period of time where change is unrelated to the Drift Ref. 7.1.2 input, environment, or load.

The algebraic difference between the indication and the ideal value of the measured Error Ref. 7.1.2 signal.

The set of data that is analyzed for normality, time dependence, and used to determine Final Data Set (FDS) Section 3.6.3 the drift value. This data has all outliers and erroneous data removed, as allowed.

Functionally Components with similar design and performance characteristics that can be combined Ref. 7.1.1 Equivalent to form a single population for analysis purposes.

Histogram A graph of a frequency distribution. Ref. 7.1.1 In statistics, independent events are those in which the probability of all occurring at once is the same as the product of the probabilities of each occurring separately. In Independent setpoint determination, independent uncertainties are those for which the sign or Ref. 7.1.1 magnitude of one uncertainty does not affect the sign or magnitude of any other uncertainty.

Attachment 6 GNRO-2012/00096 Page 40 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 40 of 55 An arrangement of components and modules as required to generate a single protective Instrument Channel action signal when required by a plant condition. A channel loses its identity where Ref. 7.1.2 single protective action signals are combined.

The region between the limits within which a quantity is measured, received or Instrument Range Ref. 7.1.2 transmitted, expressed by stating the lower and upper range values.

A characterization of the relative peakedness or flatness of a distribution compared to a Kurtosis normal distribution. A large kurtosis indicates a relatively peaked distribution and a Ref. 7.1.1 small kurtosis indicates a relatively flat distribution.

M&TE Measurement and Test Equipment. Ref. 7.1.1 Maximum Span The component's maximum upper range limit less the maximum lower range limit. Ref. 7.1.1 Mean The average value of a random sample or population. Ref. 7.1.1 The value of the middle number in an ordered set of numbers. Half the numbers have values that are greater than the median and half have values that are less than the Median Ref. 7.1.1 median. If the data set has an even number of values, the median is the average of the two middle values.

Any assembly of interconnected components that constitutes an identifiable device, Module instrument or piece of equipment. A module can be removed as a unit and replaced with Ref. 7.1.2 a spare. It has definable performance characteristics that permit it to be tested as a unit.

Normality Adjustment A multiplier to be used for the standard deviation of the Final Data Set to provide a drift Section 3.7.5 Factor model that adequately covers the population of drift points in the Final Data Set.

Normality Test A statistics test to determine if a sample is normally distributed. Ref. 7.1.1 Outlier A data point significantly different in value from the rest of the sample. Ref. 7.1.1 The totality of the observations with which we are concerned. A true population Population Ref. 7.1.1 consists of all values, past, present and future.

The branch of mathematics which deals with the assignment of relative frequencies of Probability occurrence (confidence) of the possible outcomes ofa process or experiment according Ref. 7.3.2 to some mathematical function.

Prob. Density An expression of the distribution of probability for a continuous function. Ref. 7.1.1 Function A type of graph scaled for a particular distribution in which the sample data plots as approximately a straight line if the data follows that distribution. For ex:;tmple, normally Probability Plot distributed data plots as a straight line on a probability plot scaled for a normal Ref. 7.1.1 distribution; the data may not appear as a straight line on a graph scaled for a different type of distribution.

A segment of a population that is contained by an upper and lower limit. Tolerance intervals determine the bounds or limits of a proportion of the population, not just the Proportion Ref. 7.3.2 sampled data. The proportion (P) is the second term in the tolerance interval value (e.g.

95%/99%).

Describing a variable whose value at a particular future instant cannot be predicted Random exactly, but can only be estimated by a probability distribution function. Ref. 7.1.1 As found minus As-Left calibration data used to characterize the performance of a Raw Data functionally equivalent group of components. Ref. 7.1.1 Reference Accuracy A number or quantity that defines a limit that errors will not exceed when a device is Ref. 7.1.2, (AC) used under specified operating conditions. 7.2.1, 7.2.2 Sample A subset of a population. Ref. 7.1.1

Attachment 6 GNRO-2012/00096 Page 41 of42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 41 of 55 The portion of an instrument channel that responds to changes in a plant variable or Sensor condition and converts the measured process variable into a signal; e.g., electric or Ref. 7.1.2 pneumatic.

One or more modules that perform signal conversion, buffering, isolation or Signal Conditioning Ref. 7.1.2 mathematical operations on the signal as needed.

Skewness A measure of the degree of symmetry around the mean. Ref. 7.1.1 Span The algebraic difference between the upper and lower values of a calibrated range. Ref. 7.1.2 Standard Deviation A measure of how widely values are dispersed from the population mean. Ref. 7.1.1 The elapsed time between the initiation or successful completion of a surveillance or Surveillance surveillance check on the same component, channel, instrument loop, or other specified Ref. 7.1.1 Interval system or device.

Time-Dependent The tendency for the magnitude of component drift to vary with time. Ref. 7.1.1 Drift Time-Dependent The uncertainty associated with extending calibration intervals beyond the range of Ref. 7.1.1 Drift Uncertainty available historical data for a given instrument or group of instruments.

Time-Independent The tendency for the magnitude of component drift to show no specific trend with time. Ref. 7.1.1 Drift Tolerance The allowable variation from a specified or true value. Ref. 7.1.2 Tolerance Interval An interval that contains a defined proportion of the population to a given probability. Ref. 7.1.1 A predetermined value for actuation of the final actuation device to initiate protective Trip Setpoint Ref. 7.1.2 action.

Turndown Factor The upper range limit divided by the calibrated span of the device. Ref. 7.1.2 (TDF)

For this Design Guide the t-Test is used to determine: I) if a sample is an outlier of a t-Test Ref. 7.1.1 sample pool, and 2) if two groups of data originate from the same pool.

The amount to which an instrument channel's output is in doubt (or the allowance made therefore) due to possible errors either random or systematic which have not been Uncertainty Ref. 7.1.1 corrected for. The uncertainty is generally identified within a probability and confidence level.

Variance A measure of how widely values are dispersed from the population mean. Ref. 7.1.1 Ref. 7.1.1, WTest A test to verify the assumption of normality for sample sizes less than 50.

7.1.4

Attachment 6 GNRO-2012/00096 Page 42 of 42 Engineering Report No. ECH-NE-08-00015 Revision 1 Page 42 of 55

7. REFERENCES 7.1. Industry Standards and Correspondence 7.1.1. EPRI TR-I 03335RI, "Statistical Analysis of Instrument Calibration Data - Guidelines for Instrument Calibration Extension/Reduction Programs," October, 1998 7.1.2. ISA-RP67.04.02-2000, "Recommended Practice, Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation" 7.1.3. ANSI/ISA-S67.04.01-2000, "American National Standard, Setpoints for Nuclear Safety-Related Instrumentation" 7.104. ANSI NI5.15-1974, "Assessment of the Assumption of Normality (Employing Individual Observed Values)"

7.1.5. NRC to EPRI Letter, "Status Report on the Staff Review ofEPRI Technical Report TR-103335, "Guidelines for Instrument Calibration Extension/Reduction Program"," Dated March 1994 7.1.6. REGULATORY GUIDE 1.105, Rev. 2, "Instrument Setpoints" 7.1. 7. GE NEDC 31336P-A "General Electric Instrument Setpoint Methodology" 7.1.8. US Nuclear Regulatory Commission Letter from Mr. Thomas H. Essig to Mr. R. W. James of Electric Power Research Institute, Dated December 1,1997, "Status Report on the Staff Review of EPRI Technical Report TR-I 03335, 'Guidelines for Instrument Calibration Extension /

Reduction Programs,' Dated March 1994" 7.2. Calculations and Programs 7.2.1. Engineering Department Guide EDG-EE-003, "Methodology for the Generation of Instrument Loop Uncertainty & Setpoint Calculations," Revision 0 7.2.2. Instrumentation and Control Standard GGNS-JS-09, "Methodology for the Generation of Instrument Loop Uncertainty & Setpoint Calculations," Revision 1 7.3. Miscellaneous 7.3.1. IPASS (Instrument Performance Analysis Software System), Revision 2.03, created by EDAN Engineering in conjunction with EPRI 7.3.2. Statistics for Nuclear Engineers and Scientists Part 1: Basic Statistical Inference, William 1.

Beggs; February, 1981 7.3.3. NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle" 7.304. Microsoft Excel for Microsoft Office 2003 (or Later Versions), Spreadsheet Program

Attachment 7 GNRO-2012/00096 Applicable Instrumentation GNRO-2012/00096 Page 1 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601A JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601B JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601C JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601D JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601E JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601F JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601G JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.1.1.12, Function 3.3.1.1-1.1.a 1C51K601H JC-Q1111-09001 General Electric 368X102BBG5 SR 3.3.8.1.2, Function 3.3.8.1-1.2.a 1A701-127-S3 JC-Q1111-09002 Basler Electric BE 1-27-A3E-E 1J-A1N6F SR 3.3.8.1.2, Function 3.3.8.1-1.2.a 1A701-127-S4 JC-Q1111-09002 Basler Electric BE 1-27-A3E-E 1J-A1N6F SR 3.3.8.1.2, Function 3.3.8.1-1.2.a 1A708-127-S1 JC-Q1111-09002 Basler Electric BE 1-27-A3E-E 1J-A1N6F SR 3.3.8.1.2, Function 3.3.8.1-1.2.a 1A708-127-S2 JC-Q1111-09002 Basler Electric BE 1-27-A3E-E 1J-A1N6F 1A701-127-S3 JC-Q1111-09003 SR 3.3.8.1.2, Function 3.3.8.1-1.2.b (Timing) Basler Electric BE 1-27-A3E-E 1J-A1N6F 1A701-127-S4 JC-Q1111-09003 SR 3.3.8.1.2, Function 3.3.8.1-1.2.b (Timinq) Basler Electric BE 1-27-A3E-E 1J-A1N6F 1A708-127-S1 JC-Q1111-09003 SR 3.3.8.1.2, Function 3.3.8.1-1.2.b (Timing) Basler Electric BE 1-27-A3E-E 1J-A1N6F 1A708-127-S2 JC-Q1111-09003 SR 3.3.8.1.2, Function 3.3.8.1-1.2.b (Timinq) Basler Electric BE 1-27-A3E-E 1J-A1N6F SR 3.3.8.1.2, Function 3.3.8.1-1.2.c 1A701-127-2A JC-Q1111-09004 ITE 211T4175 SR 3.3.8.1.2, Function 3.3.8.1-1.2.c 1A701-127-2B JC-Q1111-09004 ITE 211T4175 SR 3.3.8.1.2, Function 3.3.8.1-1.2.c 1A708-127-1A JC-Q1111-09004 ITE 211T4175 SR 3.3.8.1.2, Function 3.3.8.1-1.2.c 1A708-127-1B JC-Q1111-09004 ITE 211T4175 1A701-127-2A JC-Q1111-09005 SR 3.3.8.1.2, Function 3.3.8.1-1.2.e (Timing) ITE 211T4175 1A701-127-2B JC-Q1111-09005 SR 3.3.8.1.2, Function 3.3.8.1-1.2.e (Timinq) ITE 211T4175 1A708-127-1A JC-Q1111-09005 SR 3.3.8.1.2, Function 3.3.8.1-1.2.e (Timing) ITE 211T4175 1A708-127-1B JC-Q1111-09005 SR 3.3.8.1.2, Function 3.3.8.1-1.2.e (Timinq) ITE 211T4175 GNRO-2012/00096 Page 2 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003A-27A JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003B-27B JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003C-27C JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S0030-270 JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003E-27E JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003F-27F JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003G-27G JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.b 1C71 S003H-27H JC-Q1111-09006 ABB 411T4375-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003A-59A JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003B-59B JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003C-59C JC-Q1111-09007 ABB 411U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S0030-590 JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003E-59E JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003F-59F JC-Q1111-09007 ABB 411U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003G-59G JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.a 1C71 S003H-59H JC-Q1111-09007 ABB 411 U4175-L-HF SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71S003A-81A JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003B-81 B JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71S003C-81C JC-Q 1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S0030-81O JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003E-81 E JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003F-81 F JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003G-81 G JC-Q 1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003H-81 H JC-Q1111-09008 ABB 422B1275-L SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003A-62A JC-Q1111-09009 Allen Bradley 700-RTC00100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003B-62B JC-Q1111-09009 Allen Bradley 700-RTCOO 100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003C-62C JC-Q 1111-09009 Allen Bradley 700-RTC00100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S0030-620 JC-Q1111-09009 Allen Bradley 700-RTC00100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003E-62E JC-Q1111-09009 Allen Bradley 700-RTCOO 100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003F-62F JC-Q1111-09009 Allen Bradley 700-RTC00100U24 GNRO-2012/00096 Page 3 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003G-62G JC-Q1111-09009 Allen Bradley 700-RTC00100U24 SR 3.3.8.2.2, Function 3.3.8.2.2.c 1C71 S003H-62H JC-Q1111-09009 Allen Bradley 700-RTC00100U24 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71 N006A JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.4.1.3, Function 3.3.4.1.a.1 1C71 N006A JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006B JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71 N006C JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006D JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.4.1.3, Function 3.3.4.1.a.1 1C71N006D JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006E JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006F JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.4.1.3, Function 3.3.4.1.a.1 1C71 N006F JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006G JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.4.1.3, Function 3.3.4.1.a.1 1C71 N006G JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.1.1.12, Function 3.3.1.1-1.9 1C71N006H JC-Q1111-09011 Schaevitz PT-882-0005-200 SR 3.3.3.1.3, Function 3.3.3.1-1.7 1M71N605A JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.7 1M71N605B JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.7 1M71N605C JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.7 1M71N605D JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.8 1M71N607A JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.8 1M71N607B JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.8 1M71N607C JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.8 1M71N607D JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.11 1M71N627A JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.11 1M71N627B JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.11 1M71N627C JC-Q1111-09012 Bailey 740 Series SR 3.3.3.1.3, Function 3.3.3.1-1.11 1M71N627D JC-Q1111-09012 Bailey 740 Series SR 3.3.1.1.12, Function 3.3.1.1-1.8.a 1C11N012A JC-Q1111-09014 Gulton/Statham PD3218-100-38-12-36-XX-25 SR 3.3.1.1.12, Function 3.3.1.1-1.8.a 1C11N012B JC-Q1111-09014 Gulton/Statham PD3218-100-38-12-36-XX-25 SR 3.3.1.1.12, Function 3.3.1.1-1.8.a 1C11N012C JC-Q1111-09014 Gulton/Statham PD3218-100-38-12-36-XX-25 SR 3.3.1.1.12, Function 3.3.1.1-1.8.a 1C11N012D JC-Q1111-09014 Gulton/Statham PD3218-100-38-12-36-XX-25 GNRO-2012/00096 Page 4 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.1.1.12, Function 3.3.1.1-1.10 1C71N005A JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.4.1.3, Function 3.3.4.1.a.2 1C71N005A JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.1.1.12, Function 3.3.1.1-1.10 1C71N0058 JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-10 SR 3.3.4.1.3, Function 3.3.4.1.a.2 1C71N0058 JC-Q1111-09014 Gulton/Statham PG 3200-1 00-88-12-36-N 1-1 0 SR 3.3.1.1.12, Function 3.3.1.1-1.10 1C71N005C JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.4.1.3, Function 3.3.4.1.a.2 1C71N005C JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.1.1.12, Function 3.3.1.1-1.10 1C71N005D JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.4.1.3, Function 3.3.4.1.a.2 1C71N005D JC-Q1111-09014 Gulton/Statham PG3200-1 00-88-12-36-N 1-1 0 SR 3.3.5.1.5, Function 3.3.5.1-1.3.e 1E22N055C JC-Q1111-09014 Gulton/Statham PD-3218-100-38-12-36-40-XX SR 3.3.5.1.5, Function 3.3.5.1-1.3.e 1E22N055G JC-Q1111-09014 Gulton/Statham PD-3218-100-38-12-36-40-XX SR 3.3.5.2.4, Function 3.3.5.2-1.4 1E51N036A JC-Q1111-09014 Gulton/Statham PD-3218-100-38-12-36-40-XX SR 3.3.5.2.4, Function 3.3.5.2-1.4 1E51N036E JC-Q1111-09014 Gulton/Statham PD-3218-100-38-12-36-40-XX SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N606A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6068 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N612A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6128 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N613A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6138 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N614A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6148 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N615A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6158 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N616A JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N6168 JC-Q1111-09015 Rochester Instruments SC-3326W-SS 1 SR 3.3.5.1.5, Function 3.3.5.1-1.1.f 1E12N052A JC-Q1111-09016 Rosemount 1152DP3 SR 3.3.5.1.5, Function 3.3.5.1-1.2.e 1E12N0528 JC-Q1111-09016 Rosemount 1152DP3 SR 3.3.5.1.5, Function 3.3.5.1-1.2.e 1E12N052C JC-Q1111-09016 Rosemount 1152DP3 SR 3.3.5.1.5, Function 3.3.5.1-1.1.e 1E21N051 JC-Q1111-09016 Rosemount 1151DP3 SR 3.4.7.3, Function 3.4.7.a 1P45N451A JC-Q1111-09016 Rosemount 1153D83RG SR 3.4.7.3, Function 3.4.7.a 1P45N4518 JC-Q1111-09016 Rosemount 1153D83RG GNRO-2012/00096 Page 5 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.3.1.3, Function 3.3.3.1-1.3 1B21N044C JC-Q1111-09017 Rosemount 1153DD5RC SR 3.3.3.1.3, Function 3.3.3.1-1.3 1B21N044D JC-Q1111-09017 Rosemount 1153DD5RC SR 3.3.5.1.5, Function 3.3.5.1-1.3.a 1B21N073C JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.c 1B21N073C JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.e 1B21N073C JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.a 1B21N073G JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.e 1B21N073G JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.a 1B21N073L JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.c 1B21N073L JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.e 1B21N073L JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.a 1B21N073R JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.e 1B21N073R JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.1.d 1B21N075A JC-Q1111-09017 Rosemount 1152DP5-E22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.d 1B21N075B JC-Q1111-09017 Rosemount 1152DP5-E22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.d 1B21N075C JC-Q1111-09017 Rosemount 1152DP5-E22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.d 1B21N075D JC-Q1111-09017 Rosemount 1152DP5-E22-T0280-PB SR 3.3.1.1.12, Function 3.3.1.1-1.4 1B21 N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.5 1B21N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.3.1.3, Function 3.3.3.1-1.2 1B21N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.5.d 1B21N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.5.b 1B21 N080A JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.4 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.5 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.3.1.3, Function 3.3.3.1-1.2 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.5.d 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.5.b 1B21N080B JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 GNRO-2012/00096 Page 6 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.1.1.12, Function 3.3.1.1-1.4 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.5 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.3.1.3, Function 3.3.3.1-1.2 1B21 N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.5.d 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.5.b 1B21N080C JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.4 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.1.1.12, Function 3.3.1.1-1.5 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.3.1.3, Function 3.3.3.1-1.2 1B21 N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.5.d 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.5.b 1B21N080D JC-Q1111-09017 Rosemount 1153DB4RC-NOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.1.a 1B21N081A JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.2.a 1B21N081A JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.4.0 1B21N081A JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.2.5, Function 3.3.6.2-1.1 1B21N081A JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.4.5, Function 3.3.6.4-1.5 1B21N081A JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.1.a 1B21N081B JC-Q1111-09017 Rosemount 1152DP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.2.a 1B21N081B JC-Q1111-09017 Rosemount 1152DP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.4.0 1B21N081B JC-Q1111-09017 Rosemount 1152DP5N22T0280PB SR 3.3.6.2.5, Function 3.3.6.2-1.1 1B21N081B JC-Q1111-09017 Rosemount 1152DP5N22T0280PB SR 3.3.6.4.5, Function 3.3.6.4-1.5 1B21N081B JC-Q1111-09017 Rosemount 1152DP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.a 1B21N081C JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.2.a 1B21N081C JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.4.0 1B21N081C JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.2.5, Function 3.3.6.2-1.1 1B21N081C JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.4.5, Function 3.3.6.4-1.5 1B21 N081C JC-Q1111-09017 Rosemount 1153DB5RC SR 3.3.6.1.6, Function 3.3.6.1-1.1.a 1B21N081D JC-Q1111-09017 Rosemount 1152DP5N22T0280PB GNRO-2012/00096 Page 7 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.6.1.6, Function 3.3.6.1-1.2.a 1821N081D JC-Q1111-09017 Rosemount 1152DP5N22T0280P8 SR 3.3.6.1.6, Function 3.3.6.1-1.4.g 1821N081D JC-Q1111-09017 Rosemount 1152DP5N22T0280P8 SR 3.3.6.2.5, Function 3.3.6.2-1.1 1821N081D JC-Q1111-09017 Rosemount 1152DP5N22T0280P8 SR 3.3.6.4.5, Function 3.3.6.4-1.5 1821N081D JC-Q1111-09017 Rosemount 1152DP5N22T0280P8 SR 3.3.3.1.3, Function 3.3.3.1-1.2 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.a 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.a 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.a 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.a 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.2.4, Function 3.3.5.2-1.1 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.c 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.3 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.2 1821N091A JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.3.1.3, Function 3.3.3.1-1.2 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.a 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.a 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.a 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.a 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.2.4, Function 3.3.5.2-1.1 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.c 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.3 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.2 1821N0918 JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.3.1.3, Function 3.3.3.1-1.2 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.a 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.a 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.a 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.a 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.2.4, Function 3.3.5.2-1.1 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.c 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.3 1821N091E JC-Q1111-09017 Rosemount 1153DD5PC GNRO-2012/00096 Page 8 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.6.4.5, Function 3.3.6.4-1.2 1B21N091E JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.3.1.3, Function 3.3.3.1-1.2 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.a 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.a 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.a 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.a 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.2.4, Function 3.3.5.2-1.1 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.c 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.3 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.2 1B21N091F JC-Q1111-09017 Rosemount 1153DD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N095A JC-Q1111-09017 Rosemount 1153DD4PC SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N095A JC-Q1111-09017 Rosemount 1153DD4PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.d 1B21N095B JC-Q1111-09017 Rosemount 1153DD4PC SR 3.3.5.2.4, Function 3.3.5.2-1.2 1B21N095B JC-Q1111-09017 Rosemount 1153DD4PC SR 3.3.4.2.4, Function 3.3.4.2-1.1 1B21N099A JC-Q1111-09017 Rosemount 1151DP5A52TOOO3PB SR 3.3.4.2.4, Function 3.3.4.2-1.1 1B21N099B JC-Q1111-09017 Rosemount 1151DP5A52TOOO3PB SR 3.3.4.2.4, Function 3.3.4.2-1.1 1B21N099E JC-Q1111-09017 Rosemount 1151DP5A22T0141PB SR 3.3.4.2.4, Function 3.3.4.2-1.1 1B21N099F JC-Q1111-09017 Rosemount 1151DP5A52TOOO3PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N014A JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N014B JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N014C JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N014D JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N024A JC-Q1111-09017 Rosemount 1152DP5N22T2080PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N024B JC-Q1111-09017 Rosemount 1152DP5N22T2080PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N024C JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.1.1.17, Function 3.3.1.1-1.2.d 1B33N024D JC-Q1111-09017 Rosemount 1152DP5N22PB SR 3.3.5.1.5, Function 3.3.5.1-1.1.e 1E21NOO3 JC-Q1111-09017 Rosemount 1151DP5C22TOOO3PB SR 3.3.5.1.5, Function 3.3.5.1-1.3.g 1E22NOO5 JC-Q1111-09017 Rosemount 1151DP5C22TOOO3PB SR 3.3.5.1.5, Function 3.3.5.1-1.3.Q 1E22N056 JC-Q1111-09017 Rosemount 1153DB4RCNOO37 SR 3.3.6.4.5, Function 3.3.6.4-1.3 1E30NOO3A JC-Q1111-09017 Rosemount 1153DB5 GNRO-2012/00096 Page 9 of 15 Instrument Entergy IS Number Calc No. Manufacturer Model SR 3.3.6.4.5, Function 3.3.6.4-1.3 1E30NOO3B JC-Q1111-09017 Rosemount 11530B5 SR 3.3.3.1.3, Function 3.3.3.1-1.4 1E30NOO3C JC-Q1111-09017 Rosemount 11530B5 SR 3.3.6.4.5, Function 3.3.6.4-1.3 1E30NOO3C JC-Q1111-09017 Rosemount 11530B5 SR 3.3.3.1.3, Function 3.3.3.1-1.4 1E30NOO30 JC-Q1111-09017 Rosemount 11530B5 SR 3.3.6.4.5, Function 3.3.6.4-1.3 1E30NOO30 JC-Q1111-09017 Rosemount 11530B5 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N075A JC-Q1111-09017 Rosemount 11530B5-RC SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N075B JC-Q1111-09017 Rosemount 11520P5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N076A JC-Q1111-09017 Rosemount 11520P5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N076B JC-Q1111-09017 Rosemount 11520P5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N077A JC-Q1111-09017 Rosemount 11520P5-A22PB SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31N077B JC-Q1111-09017 Rosemount 11520P5-A22PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.a 1E31N083A JC-Q1111-09017 Rosemount 11520P5-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.a 1E31N083B JC-Q1111-09017 Rosemount 11520P5-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.i 1E31N084A JC-Q1111-09017 Rosemount 11520P5-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.i 1E31N084B JC-Q1111-09017 Rosemount 11520P5-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N086A JC-Q1111-09017 Rosemount 11520P7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N086B JC-Q1111-09017 Rosemount 11520P7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N086C JC-Q1111-09017 Rosemount 11530B7RC SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N0860 JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N087A JC-Q1111-09017 Rosemount 11520P7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N087B JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N087C JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N0870 JC-Q1111-09017 Rosemount 11520P7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N088A JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N088B JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N088C JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N0880 JC-Q1111-09017 Rosemount 1152DP7E22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N089A JC-Q1111-09017 Rosemount 11530B7RC SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N089B JC-Q1111-09017 Rosemount 1153DB7RC SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N089C JC-Q1111-09017 Rosemount 11530B7RC GNRO-2012/00096 Page 10 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.6.1.6, Function 3.3.6.1-1.1.c 1E31N089D JC-Q1111-09017 Rosemount 1153D87RC SR 3.3.3.1.3, Function 3.3.3.1-1.6 1M71N001A JC-Q1111-09017 Rosemount 1153D86 SR 3.3.3.1.3, Function 3.3.3.1-1.6 1M71N0018 JC-Q1111-09017 Rosemount 1153D86 SR 3.3.3.1.3, Function 3.3.3.1-1.10 1M71N002A JC-Q1111-09017 Rosemount 1153D85 SR 3.3.3.1.3, Function 3.3.3.1-1.10 1M71N0028 JC-Q1111-09017 Rosemount 1153D85 SR 3.3.3.1.3, Function 3.3.3.1-1.9 1M71N027A JC-Q1111-09017 Rosemount 1153D86 SR 3.3.3.1.3, Function 3.3.3.1-1.9 1M71N0278 JC-Q1111-09017 Rosemount 1153D86 SR 3.3.5.1.5, Function 3.3.5.1-1.3.b 1821N067C JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.1 1821N067C JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.b 1821N067G JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.1 1821N067G JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.b 1821N067L JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.1 1821N067L JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.3.b 1821N067R JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.1 1821N067R JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.b 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.b 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.b 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.b 1821N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.d 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.3.i 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.1 1821 N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.1 1821N094A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.b 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.b 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.b 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.b 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.d 1821 N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.3.i 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.1 1821N0948 JC-Q1111-09018 Rosemount 1153AD5PC GNRO-2012/00096 Page 11 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.6.4.5, Function 3.3.6.4-1.1 1B21N094B JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.b 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.b 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.b 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.b 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.d 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.3.j 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.1 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.1 1B21N094E JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.1.b 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.2.b 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.b 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.5.b 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.2.d 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.1.6, Function 3.3.6.1-1.3.j 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.1 1B21 N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.4.5, Function 3.3.6.4-1.1 1B21N094F JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.1.1.12, Function 3.3.1.1-1.7 1C71 N050A JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.2.b 1C71 N050A JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.5.d 1C71N050A JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.2.5, Function 3.3.6.2-1.2 1C71 N050A JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.4.5, Function 3.3.6.4-1.4 1C71N050A JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.1.1.12, Function 3.3.1.1-1.7 1C71N050B JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.2.b 1C71N050B JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.5.d 1C71N050B JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.2.5, Function 3.3.6.2-1.2 1C71N050B JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.4.5, Function 3.3.6.4-1.4 1C71N050B JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.1.1.12, Function 3.3.1.1-1.7 1C71N050C JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.2.b 1C71N050C JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.5.d 1C71N050C JC-Q1111-09018 Rosemount 1152AP5N22T0280PB GNRO-2012/00096 Page 12 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.6.2.5, Function 3.3.6.2-1.2 1C71N050C JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.4.5, Function 3.3.6.4-1.4 1C71N050C JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR3.3.1.1.12, Function 3.3.1.1-1.7 1C71N050D JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.2.b 1C71N050D JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.1.6, Function 3.3.6.1-1.5.d 1C71N050D JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.2.5, Function 3.3.6.2-1.2 1C71N050D JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.4.5, Function 3.3.6.4-1.4 1C71N050D JC-Q1111-09018 Rosemount 1152AP5N22T0280PB SR 3.3.6.3.5, Function 3.3.6.3-1.2 1E12N062A JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.2 1E12N062B JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.2 1E12N062C JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.6.3.5, Function 3.3.6.3-1.2 1E12N062D JC-Q1111-09018 Rosemount 1153AD5PC SR 3.3.5.1.5, Function 3.3.5.1-1.4.f 1E12N055A JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.5.e 1E12N055B JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.5.e 1E12N055C JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.4.f 1E12N056A JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.5.e 1E12N056B JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.5.e 1E12N056C JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.1.5, Function 3.3.5.1-1.4.e 1E21N052 JC-Q1111-09019 Rosemount 1152GP7E22T0280PB SR 3.3.5.1.5, Function 3.3.5.1-1.4.e 1E21N053 JC-Q1111-09019 Rosemount 1152GP7E22T0280PB SR 3.3.5.1.5, Function 3.3.5.1-1.3.d 1E22N054C JC-Q1111-09019 Rosemount 1153GB5RANOO37 SR 3.3.5.1.5, Function 3.3.5.1-1.3.d 1E22N054G JC-Q1111-09019 Rosemount 1153GB5RANOO37 SR 3.3.6.1.6, Function 3.3.6.1-1.3.c 1E31N085A JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.c 1E31N085B JC-Q1111-09019 Rosemount 1152GP7-N22-T0280-PB SR 3.3.5.2.4, Function 3.3.5.2-1.3 1E51N035A JC-Q1111-09019 Rosemount 1153GB5 SR 3.3.5.2.4, Function 3.3.5.2-1.3 1E51N035E JC-Q1111-09019 Rosemount 1153GB5 SR 3.3.6.1.6, Function 3.3.6.1-1.3.d 1E51N055A JC-Q1111-09019 Rosemount 1152GP6-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.d 1E51N055B JC-Q1111-09019 Rosemount 1152GP6-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.d 1E51N055E JC-Q1111-09019 Rosemount 1152GP6-N22-T0280-PB SR 3.3.6.1.6, Function 3.3.6.1-1.3.d 1E51N055F JC-Q1111-09019 Rosemount 1152GP6-N22-T0280-PB SR 3.3.4.2.4, Function 3.3.4.2.b 1B21N058A JC-Q1111-09020 Rosemount 1152GP9 GNRO-2012/00096 Page 13 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.4.2.4, Function 3.3.4.2.b 1821N0588 JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.2.4, Function 3.3.4.2.b 1821N058E JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.2.4, Function 3.3.4.2.b 1821N058F JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1821N062A JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1821N0628 JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.5.1.5, Function 3.3.5.1-1.1.d 1821N068A JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.2.d 1821N068A JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.5.3 1821N068A JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.1.d 1821N0688 JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.2.d 1821N0688 JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.5.3 1821N0688 JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.1.d 1821N068E JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.2.d 1821N068E JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.5.3 1821N068E JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.1.d 1821N068F JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.2.d 1821N068F JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.5.3 1821 N068F JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.1.6, Function 3.3.6.1-1.1.b 1821N076A JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.1.6, Function 3.3.6.1-1.1.b 1821N0768 JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.1.6, Function 3.3.6.1-1.1.b 1821N076C JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.6.1.6, Function 3.3.6.1-1.1.b 1821N076D . JC-Q1111-09020 Rosemount 1152GP9 SR 3.3.1.1.12, Function 3.3.1.1-1.3 1821N078A JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1821N078A JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.6.1.6, Function 3.3.6.1-1.5.c 1821 N078A JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.1.1.12, Function 3.3.1.1-1.3 1821N0788 JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1821N0788 JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.6.1.6, Function 3.3.6.1-1.5.c 1821N0788 JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.1.1.12, Function 3.3.1.1-1.3 1821N078C JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1821N078C JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.6.1.6, Function 3.3.6.1-1.5.c 1821 N078C JC-Q1111-09020 Rosemount 1153GD9 GNRO-2012/00096 Page 14 of 15 Instrument Entergy TS Number Calc No. Manufacturer Model SR 3.3.1.1.12, Function 3.3.1.1-1.3 1B21N078D JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.3.1.3, Function 3.3.3.1-1.1 1B21N078D JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.6.1.6, Function 3.3.6.1-1.5.c 1B21N078D JC-Q1111-09020 Rosemount 1153GD9 SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71 N052A JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N052A JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N052A JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N052A JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N052B JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N052B JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N052B JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N052B JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N052C JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N052C JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N052C JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N052C JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N052D JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N052D JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N052D JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N052D JC-Q1111-09020 Rosemount 1151GP9 SR 3.3.5.1.5, Function 3.3.5.1-1.3.f 1E22N051 JC-Q1111-09020 Rosemount 1153GB9 SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N652A JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N652A JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N652A JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N652A JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N652B JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N652B JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N652B JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N652B JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N652C JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N652C JC-Q1111-09021 Rosemount 510DU/710DU GNRO-2012/00096 Page 15 of 15 Instrument Entergy 15 Number Calc No. Manufacturer Model SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N652C JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N652C JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.1.1.14, Function 3.3.1.1-1.10 1C71N652D JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.1.1.14, Function 3.3.1.1-1.9 1C71N652D JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.4.1.5, Function 3.3.4.1.a.1 1C71N652D JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.4.1.5, Function 3.3.4.1.a.2 1C71N652D JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N603A JC-Q1111-09021 Rosemount 51 ODU/71 ODU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N603B JC-Q1111-09021 Rosemount 51 ODUl71 ODU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N622A JC-Q1111-09021 Rosemount 51 ODUl71 ODU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N622B JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N623A JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N623B JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N624A JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N624B JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N625A JC-Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N625B JC~Q1111-09021 Rosemount 510DUl710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N626A JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.3.1.3, Function 3.3.3.1-1.5 1M71N626B JC-Q1111-09021 Rosemount 510DU/710DU SR 3.3.8.1.2, Function 3.3.8.1-1.2.d 1A701-162-1 JC-Q1111-09022 Agastat ETR14D3NOO3 SR 3.3.8.1.2, Function 3.3.8.1-1.2.d 1A708-162-2 JC-Q1111-09022 Agastat ETR14D3NOO3 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K602A JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K602B JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K603A JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K603B JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K605A JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K605B JC-Q1111-09023 Bailey 750010AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K604A JC-Q1111-09024 Bailey 752410AAAE1 SR 3.3.6.1.6, Function 3.3.6.1-1.4.a 1E31K604B JC-Q1111-09024 Bailey 752410AAAE1

ML12277A081

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