ML20067D355

Amend 72 to License NPF-47,permits Extending Time to Perform Surveillance Testing of Certain Instrumentation,Valves & Electrical Equipment So That Testing Can Be Performed During Upcoming Refueling Outage

ML20067D355
Person / Time
Site:	River Bend
Issue date:	02/18/1994
From:	Black S Office of Nuclear Reactor Regulation
To:
Shared Package
ML20067D358	List: ML20067D355 ML20067D363
References
NUDOCS 9403080182
Download: ML20067D355 (59)

Text

.

p ** '8 4 t

UNITED STATES E) i s,%.(/

i NUCLEAR REGULATORY COMMISSION K..,...

WASHINGTON, D.C. 20555-0001 GULF STATES UTILITIES COMPANY **

CAJUN ELECTRIC POWER COOPERATIVE AND j

ENTERGY OPERATIONS. INC.

DOCKET N0. 50-458 BJVER BEND STATION. UNIT 1 AMENDMENT TO FACILITY OPERATIN3 LICR $1 Amendment No. 72 License No. NFF-47 1.

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

A.

The application for amendment by Gulf States Utilities * (the licensee) dated December 8,1993, as supplemented by letter dated February 3,1994, complies with the standards and reqeirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance:

(i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and

• E01 is authorized to act as agent for Gulf States Utilities Company, which has been authorized to act as agent for Cajun Electric Power Cooperative, and has exclusive responsibility and control over the physical construction, operation and maintenance of the facility.

• • Gulf States Utilities Company, which owns a 70 percent undivided interest in River Bend, has merged with a wholly owned subsidiary of Entergy Corporation.

Gulf States Utilities Company was the surviving company in the merger.

9403080182 94021e PDR ADOCK 05000458 P

PDR

i

. E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment; and Paragraph 2.C.(2) of Facility Operating License No. NPF-47 is-hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 72 and the Environmental. Protection Plan contained in Appendix B, are hereby incorporated in the license.

E01 shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

The license amendment is effective as of its date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION mwt_ O Gb Suzanne C. Black, Director-i Project Directorate IV-2 Division of Reactor Projects III/IV/V Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance:

February 18, 1994 l

I ATTACHMENT TO LICENSE AMENDMENT NO. 72 FACILITY OPERATING LICENSE NO. NPF-47 l

DOCKET NO. 50-458 l

Replace the following pages of the Appendix "A" Technical Specifications with the enclosed pages.

The revised pages are identified by Amendment number and contain vertical lines indicating the areas of change.

The overleaf pages are l

provided to maintain document completeness.

j REMOVE INSERT 3/4 3-1 3/4 3-1 3/4 3-6 3/4 3 6 1

3/4 3-7 3/4 3-7 3/4 3-8 3/4 3-8 3/4 3-9 3/4 3-9 3/4 3-11 3/4 3-11 3/4 3-24 3/4 3-24 3/4 3-25 3/4 3-25 3/4 3-26 3/4 3-26 3/4 3-27 3/4 3-27 3/4 3-29 3/4 3-29 3/4 3-30 3/4 3-30 3/4 3-30a 3/4 3-30a 3/4 3-40 3/4 3-40 3/4 3-41 3/4 3-41 3/4 3-42 3/4 3-42 3/4 3-43 3/4 3-43 3/4 3-59 3/4 3-59 3/4 3-63 3/4 3-63 3/4 3-64 3/4 3-64 3/4 3-76 3/4 3-76 3/4 3-80 3/4 3-80 3/4 3-81 3/4 3-81 3/4 3-84 3/4 3-84 3/4 3-107 3/4 3-107 3/4 3-111 3/4 3-111 3/4 6-31 3/4 6-31 3/4 6-33 3/4 6-33 3/4 6-34 3/4 6-34 3/4 6-35 3/4 6-35 3/4 6-36 3/4 6-36 3/4 6-37 3/4 6-37 3/4 6-47 3/4 6-47 3/4 8-15 3/4 8-15 3/4 8-16 3/4 8-16 3/4 8-18 3/4 8-18 3/4 8-35 3/4 8-35

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION llMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE with the REACTOR PROTECTION SYSTEM RESPONSE TIME as shown in Table 3.3.1-2.

APPLICABILITY: As shown in Table 3.3.1-1.

ACTION:

a.

With the number of OPERABLE channels less than required by the l

Minimum OPERABLE Channels per Trip System requirement for one trip l

system, place the inoperable channel (s) and/or that trip system in l

the tripped condition

• within one hour.

b.

With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.1-1.

SURVElllANCE RE0VIREMENTS 4.3.1.1 Each reactor arotection system instrumentation channel shall be l

demonstrated OPERABLE ay the performance of the CHANNEL CHECK, CHANNEL l

FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL l

CONDITIONS and at the frequencies shown in Table 4.3.1.1-1.#

l 4.3.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.***

4.3.1.3 The REACTOR PROTECTION SYSTEM RESPONSE TIME of each reactor trip l

functional unit shown in Table 3.3.1-2## shall be demonstrated to be within.

l its limit at least once per 18 months.

Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip system.

An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.

In these cases, the inoperable channel shall be restored to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or the ACTION required by Table 3.3.1-1 for that Trip function shall be taken.

I

• • The trip system need not be placed in the tripped condition if this would cause the Trip Function to occur. When a trip system can be placed in the tripped condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.

The requirement to place a trip system in the tripped condition does not apply to Functional Units 6 and 10 of Table 3.3.1-1.

• • • Logic System Functional Test period may be extended as identified by note

' p' on Table 4.3.1.1-1.

1. Channel Calibration period may be extended as identified by notes 'o' and

'q' on Table 4.3.1.1-1.

1. 1. Response Time test period may be extended as identified by note '##' on Table 3.3.1-2.

RIVER BEND - UNIT 1 3/4 3-1 Amendment No. 8,4h-72

TABLE 3.3.1-1 m

g REACTOR PROTECTION SYSTEM INSTRUMENTATION g

APPLICABLE MINIMUM i

z OPERATIONAL OPERABLE CHANNELS 7

FUNCTIONAL UNIT CONDITIONS PER TRIP SYSTEM (a)

ACTION 1.

Intermediate Range Monitors:

H a.

Neutron Flux - High 2

3 1

5(b)4 3

3 2

H 3

3 b.

Inoperative 2

3 1

3, 4 3

2 5

3 3

2.

Average Power Range Monitor (c);

a.

Neutron Flux - High, Setdown 2

3 1

,g 3(b)4 3

2 5

3 3

b.

Flow Biased Simulated Thermal Power - High 1

3 4

c.

Neutron Flux - High 1

3 4

d.

Inoperative 1, 2 3

1 3, 4 3

2 5

3 3

3.

Reactor Vessel Steam Dome Pressure - High 1, 2(d) 2 1

4.

Reactor Vessel Water Level - Low, Level 3 1, 2 2

1 5.

Reactor Vessel Water Level-High, Level 8 1(e) 2 4

6.

Main Steam Line Isolation Valve -

Closure 1(,)

4 10 7.

Main Steam Line Radiation -

High 1,2(d) 2 5

8.

'rywell Pressure - High 1,2(I) 2 1

TABLE 3.3.1-1 (Continued)

~

REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE NOTATIONS (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance without placing the trip system in the tripped condition provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

(b) Unless adequate shutdown margin has been demonstrated per Specification 3.1.1, the " shorting links" shall be removed from the RPS circuitry prior to and during the time any. control rod is withdrawn".

(c) An APRM channel is inoperable if there are less than 2 LPRM inputs per level or less than 11 LPRM inputs to an APRM channel.

(d) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(e) This function shall be automatically bypassed when the reactor mode switch is not in the Run position.

(f) This function is not required to be OPERABLE when DRYWELL INTEGRITY is not required.

(g) With any control rod withdrawn.

Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

(h) This function shall be automatically bypassed when turbine first stage pressure is < 187 psig,** equivalent to THERMAL POWER less than 40% of RATED THERMAI POWER, 1

"Not required for control rods removed.

• • To allow for instrumentation accuracy,per Specification 3.9.10.1 or 3.9.10.2.

calibration and drift, a setpoint of

$ 177 psig turbine first stage pressure shall be used.

)

RIVER BEND - UNIT 1 3/4 3-5

i 1

23 TABLE 3.3.1-2 M

=

REACTOR PROTECTION SYSTEM RESPONSE TIMES cn FUNCTIONAL UNIT RESPONSE TIME

_ (Seconds) z El 1.

Intermediate Range Monitors:

w a.

Neutron Flux - High NA b.

Inoperative NA 2.

Average Power Range Monitor *:

a.

Neutron Flux - High, Setdown MA b.

Flow Blased Simulated Thermal Power - High

<0. 09** ##

c.

Neutron Flux - High 70.09 ##

d.

Inoperative NA R

3.

Reactor Vessel Steam Dome Pressure - High

<0. 35 ##

I 4

Reactor Vessel Water Level - Low, level 3 71.05 Y

5.

Reactor Vessel Water level - High, Level'8 71.05 6.

Main Steam Line Isolation Valve - Closure 70.09 7.

Main Steam Line Radiation - High RA 8.

Drywell Pressure - High NA 9.

Scram Discharge Volume Water level - High a.

Level Transmitter NA b.

Float Switches MA 10.

Turbine Stop Valve - Closure

<0.06 11.

Turbine Control Valve Fast Closure Valve Trip System

~-

011 Pressure - Low

<0.07f 12.

Reactor Mode Switch Shutdown Position RA k 13.

Manual Scram NA E

R a

E

" Neutron detectors are exempt from response time testing.

Response time shall be measured from the detector output or from the input of the first electronic component in the cf annel.

z i

• • Not including simulated thermal power time constant specified in the COLR.

l; FMeasured from start of turbine control valve fast closure.

4

1. 1. Response Time testing may be performed during the fifth' refueling outage scheduled to begin April 16, 1994.

1

-. _ -. _ ~ _.

h TABLE 4.3.1.1-1 so

• 2 REACTOR P.tGTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS E

in CHANNEL

. OPERATIONAL T

CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH FUNCTIONAL UNIT CHECK TEST CALIBRATION (a)

SURVEILLANCE REQUIRED J

E 1.

Intermediate Range Monitors:

Z a.

Neutron Flux - High S/U,5,(b)

S/U(c),W R

2 s

S W

R 3,4,5 b.

Inoperative NA W

NA 2,3,4,5 III 2.

Average Power Range Monitor:

S/U(g).

a.

Neutron Flux - High, S/U,5,(b)

,W SA 2

Setdown S

W SA 3, 4, 5 b.

Flow Biased Simulated g(d)(e) SA( )(9) R(I)(9)1 l

Thermal Power - High 5,0(h) 3fy(c) y w

x c.

Neutron Flux - High S

S/U(c),y g(d), gg y

w 4

d.

Inoperative NA W

NA 1,2,3,4,5

(

3.

Reactor Vessel Steam Dome I9)IP)f9)

II) l Pressure - High S

M R

1, 2 4.

Reactor Vessel Water Level -

[

I9)

Low, Level 3 S

M R

1, 2 1

5.

Reactor Vessel Water Level -

I9)

[

High, Level 8 5

M R

1 i

g 6.

Main Steam Line Isolation g

Valve - Closure NA M

R 1

i 7.

Main Steam Line Radiation -

II)

High S

M R

1, 2 l

l I9)

III 8.

Drywell Pressure - High S

M R

1, 2 r

j i

TA8LE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS 7

1. m OPERATIONAL CHANNEL CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR 14fICH CHECK TEST CALIBRATION SURVEILLANCE REQUIRED Q

i O

FUNCTIONAL UNIT 9.

Scram Discharge Volume Water i"

Level - High g(9)(P) 1, 2, 5(k) a.

Level Transmitter 5

M l

]

1, 2, $(k) b.

Float Switch NA q

R S ")

M(")

R(8)(a) 1 I

i

10. Turbine Stop Valve - Closure

- 11. Turbine Control Valve Fast I

IU)I")

1 Closure, Trip 011 M ")

R S ")

I i

Pressure - Low 12.

Reactor Mode Switch

)

Shutdoun Position MA R

NA-1,2,3,4,5

[

w Y

13. Manual Scram NA M

NA 1,2,3,4,5 Neutron detectors may be excluded from CHANNEL CALIBRATION.

on (a)

The IRM and SM channels shall be determined to overlap for at least 1/2 decade during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to (b) overlap for at least 1/2 decade during each controlled shutdown, if not performed within the previous 7 days.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to startup, if not performed within the previous 7 days.

This calibration shall consist of the adjustment of the APRM channel to conform to the power values (c)

(d) calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER >255 of RATED Adjust the APRM channel if the absolute difference is greater tien 2% of RATED THERMAL THERMAL POWER.

p Any APRM channel gain adjustment made in compliance with Specification ~3.2.2 shall not be POWER.

ro included in determining the absolute difference.

E This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a.

(e) l 5

calibrated flow signal.

5 f-PJ 1

j 1

1

TABLE 4.3.1.1-1 (Continued)

B REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS Ri E5 (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) using the TIP system.

gg (g) Calibrate Rosemount trip unit setpoint at least once per 31 days.

rg (h) Verify measured drive flow to be less than or equal to established drive flow at the existing flow control valve position.

(i) This calibration shall consist of verifying the simulated thermal power time constant is within the limits specified in the COLR.

(j) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specification 3.10.1.

(k) With any control rod withdrawn.

Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.7.

(1) This function is not required to be OPERABLE when DRYWELL INTEGRITY is not required per Specifica-tion 3.10.1 R

(m) Verify the Turbine Bypass Valves are closed when THERMAL POWER is greater than or equal to 40% RATED FbHCTIONALTESTandCHANNELCALIBRATIONshallincludetheturbinefirststagepressure (n) T ANN e

instruments.

(o) The CHANNEL CALIBRATION shall exclude the flow reference transmitters; these transmitters shall be calibrated at least once per 18 months, except that this test may be performed during the fifth (p). refueling outage scheduled to begin April 16, 1994.

This period may be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

(q) CHANNEL CALIBRATION may be performed during the fifth refueling outage scheduled to begin April 16, 1994.

N a

ae E

INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICABILITY:

As shown in Table 3.3.2-1.

ACTION:

a.

With an isolation actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b.

With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel (s) and/or that trip system in the tripped i

I condition

• within one hour.

c.

With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system ** in the tripped condition within one hour and take the ACTION required by Table 3.3.2-1.

• An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur.

In these cases, the inoperable channel shall be restored to OPERABLE status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

• • The trip system need not be placed in the tripped condition if this would cause the Trip Function to occur.

When a trip system can be placed in the tripped condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip system in the tripped condition.

RIVER BEND - UNIT 1 3/4 3-10 Amendment No. 47

INSTRUMENTATION SURVEILLANCE RE0VIREMENTS 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.**

l 4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.*

4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months.***

Each test shall include at least one channel per trip l

system such that all channels are tested at least once every N times 18 months,*** where N is the total number of redundant channels in a specific l

isolation trip system.

l l

I I

Logic System Functional Testing period may be extended as identified by note c on Table 4.3.2.1-1.

l

• • Channel Calibration period may be extended as identified by note 'd' on Table 4.3.2.1-1.

• • • Response Time test period may be extended as identified by note 'c' on Table 3.3.2-3.

RIVER BEND - UNIT 1 3/4 3-11 Amendment No. Br 72

B TABLE 3.3.2-1 h

ISOLATION ACTUATION INSTRUMENTATION to m

E VALVE GROUPS MINIMUM APPLICA8LE OPERATED BY OPERABLE CHANNELS OPERATIONAL i

TRIP FUNCTION SIGNAL *** PER TRIP SYSTEM (a)

CONDITION ACTION k

1.

PRIMARY CONTAIPMENT ISOLATION a.

Reactor Vessel Water Level-1,7,'8,9(b)(c)(j),

low Low, Level 2 15, 16 2

1,2,3 20 l

b.

Drywell Pressure - High 1,3,8(b)(c)(j) 2 1,2,3 20 Containment Purge 8

1 1,2,3 21 c.

Isolation Radiation -

High 2.

MAIN STEAM LINE ISOLATION i

R a.

Reactor Vessel Water Level-Low Low Low, Level 1 6

2 1,2,3 20 T

b.

Main Steam Line M

Radiation - High 6,9(d) 2 1,2,3 23 c.

Main Steam Line Pressure - Low 6

2 1

24 d.

Main Steam Line Flow - High 6-2/MSL 1, 2, 3 -

23 e.

Condenser Vacuum - Low 6

2 1, 2**, 3**

23 f.

Main Steam Line Tunnel Temperature - Higt 6.

2 1,2,3 23 i

g.

Main Steam Line Tunnel g

A Temperature - High 6

2 1,2,3 23

=>

h.

Main Steam Line

[

Area Temperature

,o High (Turbine Building) 6 2/ area 1, 2, - 3 23 m

m.

-- )

TABLE 3.3.2-2 (Continued)

EQ ISOLATION ACTUATION INSTRUMENTATION SETPOINTS t

en E

TRIP FUNCTION TRIP SETPOINT VALUE ALLOWABLE

[

6.

RHR SYSTEM ISOLATION

- ja; (Cont'd)

H e.

Reactor Vessel (RHR Cut-in Permissive) Pressure - High 5 135 psig i 150 psig w

f.

Drywell Pressure - High 5 1.68 psig 5 1.88 psig 7.

MANUAL INITIATION NA NA

{

• See Bases Figure B 3/4 3-1.

Y "w

4 4

b T

1 2

I t

M 5

I N

N i

l

i TABLE 3.3.2-3

. ISOLATION SYSTEM INSTRURENTATION RESPONSE-TIME

~

l TRIP FUNCTION RESPONSE TIME (Seconds)#

1.

PRIMARY CONTAINMENT ISOLATION a.

Reactor Vessel Water Level - Low Low Level 2

< 10(a)(c) b.

Drywell Pressure - High 710(a) (c)

Containment Purge Isolation Radiation - High(b)

RA c.

2.

MAIN STEAM LINE ISOLATION a.

Reactor Vessel Water Level - Low Low Low Level 1

< 1.0 */< 10(a),, (c) b.

Main Steam Line Radiation - High(b) 7 1. 0 *R 10(a), c )

I 1.0 */7 10((a).. c) c.

Main Steam Line Pressure - Low 7 0.5

• R 10 a).. c) d.

Main Steam Line Flow - High e.

Condenser Vacuum - Low RA

~

f.

Main Steam Line Tunnel Temperature - High NA g.

Main Steam Line Tunnel a Temperature - High NA h.

Main Steam Line Area Temperature - High (Turbine Bldg)

NA 3.

SECONDARY CONTAINMENT ISOLATION a.

Reactor Vessel Water Level - Low Low Level 2

< 10(a)(c) b.

Drywell Pressure - High I 10(a)(c)

Fuel Building Ventilation Exhaust Radiation - High(b)

NA c.

d.

Reactor Building Annulus Ventilation Exhaust Radiation - High(b)

NA 4.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High

< 10(a)M (c) l b.

A riow Timer RA Ec.ipment Area Temperature - High NA c.

d.

Equipment Area a Temperature - High NA e.

Reactor Vessel Water Level - Low Low Level 2

< 10(8)(c) f.

Main Steam Line Tunnel Ambient

~

Temperature - High NA g.

Main Steam Line Tunnel a Temperature - High NA h.

SLCS Initiation NA i

5.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a.

RCIC Steam Line Flow - High

< 10(*)

• b.

RCIC Steam Line Flow-High Timer HA c.

RCIC Steam Supply Pressure - Low

< 10(a) d.

RCIC Turbine Exhaust Diaphragm Pressure - High RA RCIC Ecuipment Room Ambient Temperature - High NA e.

f.

RCIC Equipment Room a Temperature - High NA g.

Main Steam Line Tunnel Ambient Temperature - High NA h.

Main Steam Line Tunnel a Temperature - High NA RIVER BEND - UNIT 1 3/4 3-24 Amendment No.72

y TABLE 3.3.2-3 (Continued) i ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME RESPONSE TIME (Seconds)#

TRIP FUNCTION NA i.

Main Steam Line Tunnel Temperature Timer NA 1

j.

RHR Equipment Room Ambient Temperature - High NA k.

RHR Equipment Room a Temperature - High 1.

RHR/RCIC Steam Line Flow - High NA NA Drywell Pressure - High m.

n.

Manual Initiation NA 6.

RHR SYSTEM ISOLATION RHR Equipment Area Ambient Temperature - High NA a.

NA b.

RHR Equipment Area a Temperature - High

< 10(,)

Reactor Vessel Water Level - Low Level 3 c.

~

d.

Reactor Vessel Water Level - Low Low Low

< 10(a)(c) l Level 1 Reactor Vessel (RHR Cut-in Permissive) e.

NA Pressure - High NA f.

Drywell Pressure - High NA 7.

MANUAL INITIATION (a)

Isolation system instrumentation response time specified includes'the diesel generator starting and sequence loading delays.

(b)

Radiation detectors are exempt from response time testing.

Response

time shall be measured from detector output or the input of the first electronic component in the channel.

(c)

Response Time testing may be performed during the fifth refueling outage scheduled to begin April 16, 1994.

Isolation system instrumentation response time for MSIVs only. No diesel generator delays assumed.

Isolation system instrumentation response time for associated valves except MSIVs.

Isolation system instrumentation response time specified for the Trip Function actuating each valve group shall be added to isolation time shown in Tables 3.6.4-1 and 3.6.5.3-1 for valves in each valve group to obtain ISOLATION SYSTEM RESPONSE TIME for each valve.

Time delay of 45-47 seconds.

Time delay of 3-13 seconds.

RIVER BEND - UNIT 1 3/4 3-25 Amendment No. 72

TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL m

E CHANNEL FUNCTIONAL CHANNEL-CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED E

1.

PRIMARY CONTAllWENT ISOLATION

" ~

a.

Reactor Vessel Water Level -

Low Low level 2 S

M R(b) 1, 2, 3 l

bc Drywell Pressure - High

'S M

R(b)

, 2, 3 c.

Containment Purge Isolation Radiation - High 5

M R

1,2,3 2.

MAIN STEAM LINE ISOLATION a.

Reactor Vessel Water Level -

R Low Low Low Level 1 5

M R(b) 1, 2, 3 l

s b.

Main Steam Line Radiation -

w4 High 5

M R

1,2,3 l

m c.

Main Steam Line Pressure --

Low

-5 M

R(b) y d.

-Main Steam Line Flow - High S

M R(b) 1, 2, 3

['

e.

Condenser Vacuum - Low S

M R(b) 1, 2**, 3**

f.

Main Steam Line Tunnel R

1,2,3 Temperature - High S

M Main Steam Line tunnel g.

A Temperature - High S

M R

1,2,3 h.

Main Steam Line Area S

M R(b) 1, 2, 3 hg Temperature-High (Turbine Building) 5

.=

e*

e a

e

_----_.,._-__.___------_-._________-----.-___----._---_-_-___--------___--_-_-__.----__A

1 TABLE 4.3.2.1-1 (Continued)

=g 4

9 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS m

E CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH

' TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED 3.

SECONDARY CONTAINMENT ISOLATION 4

.a a.

Reactor Vessel Water Level - Low Low Level 2 S

M R

1, 2, 3

[

b.

Drywell Pressure - High S

M R

1,2,3 c.

Fuel Building Ventilation Exhaust Radiation - High S

M R

d.

Reactor Building Annulus Ventilation Exhaust Radiation - High 5

M R

1, 2, 3 I

54.

REACTOR WATER CLEANUP SYSTEM ISOLATION a.

A Flow - High S

M R(c) 1, 2, 3

,Y b.

A Flow Timer NA M

Q(C) 1, 2, 3 c.

Equipment Area Temperature -

R(c) 1,2,3 1

High S

M d.

Equipment Area R(c) 1,2,3 A Temperature - High S

M I

e.

Reactor Vessel Water R(b)(c)

- 1,2,3 Level - Low Low level 2 S

M f.

Main Steam Line Tunnel Ambient Temperature - High 5

M R

1,2,3 g.

Main Steam Line Tunnel R(C 1,2,3

~

2 a Temperature.- High 5

M M(a)

NA(c) 1, 2, 3 y

h.

SLCS Initiation NA i

?.

i a

~

a l

PJ 1

(

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRtAENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL

=

CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH asQ TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED E

5.

REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION OI a.

RCIC Steam Line Flow - High 5

M R

1,2,3 b.

RCIC Steam Line Flow-High Timer NA M

Q 1, 2, 3 c.

RCIC Steam Supply Pressure -

R(b) 1, 2, 3 Low S

M d.

RCIC Turbine Exhaust Diaphragm R(b) 1, 2, 3 Pressure - High 5

M e.

RCIC Equipment Room Ambient Temperature - High M

R 1, 2, 3 j

w D

f.

RCIC Equipment Room Y

A Teaperature - High S

M R

1, 2, 3 5

Main Steam Line Tunnel Ambient g.

i Temperature - High S

M R

1,2,3 h.

Main Steam Line Tunnel A Temperature - High S

M R

1,2,3 1.

Main Steam Line Tunnel Temperature Timer NA

'M Q

1, 2, 3 j.

RHR Equipment Room Adfent Temperature - High S

M R

1,2,3 k.

RHR Equipment Room a Temperature - High 5

M R

1, 2, 3 1.

RHR/RCIC Steam Line Flow-High S

M R

1,2,3 l

ID}

Drywell Pressure-High 5

M R

1,2,3 m.

Manual Initiation MA R

NA 1,2,3 n.

TABLE 4.3.2.1-1 (Continued) h ISOLATION ACTUATION INSTRUMENTATIOF SURVEILLANCE REQUIREMENTS E

m CllANNEL OPERATIONAL 9

CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH o

TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE kEQUIRED 6.

RHR SYSTEM ISOLATION c-5 a.

RHR Equipment Area Ambient

]

Temperature - High S

M R

1,2,3 b.

RHR Equipment Area A Temperature - High S

M R

1, 2, 3 c.

Reactor Vessel Water Level -

ID)

Low Level 3 S

M R

1, 2, 3 d.

Reactor Vessel Water level -

Low Low Low Level 1 S

M R(b) 1, 2, 3 l

e.

Reactor Vessel (RHR Cut-in (C)Id)

Permissive) Pressure - High S

M R

1, 2, 3 f.

Drywell Pressure - High S

M.

R 1,2,3 y

7.

MANUAL INITIATION NA M

NA 1,2,3 0

• When handling irradiated fuel in the Fuel Building.

• • When the reactor mode switch is in Run and/or any turbine stop valve is open.

(a) Each train or logic channel shall be tested at least every other 31 days.

(b) Calibrate trip unit setpoint at least once per 31 days.

(c) May be performed during the fifth refueling outage scheduled to begin April 16, 1994.

(d) CHANNEL CALIBRATION may be performed durina the fifth refueling outane scheduled to g

begin April 16, 1994.

E n

,M w

9 i

JNSTRUMENTATION 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3 The emergency core cooling system (ECCS) actuation instrumentation channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints l

set consistent with the values shown in the Trip Setpoint column of Table 3.3.3-2 and with EMERGENCY CORE COOLING SYSTEM RESPONSE TIME as shown in Table 3.3.3-3.

APPLICABILITY: As shown in Table 3.3.3-1.

ACTION:

a.

With an ECCS actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.3-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted i

consistent with the Trip Setpoint value, b.

With one or more ECCS actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.3-1.

c.

With either ADS trip system "A" or "B" inoperable, restore the inoperable trip system to OPERABLE status:

1.

Within 7 days, provided that the HPCS and RCIC systems are OPERABLE, or 2.

Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, provided either the HPCS or the RCIC system is inoperable.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor steam dome pressure to less than or equal to 100 psig within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE RE0VIREMENTS 4.3.3.1 Each ECCS actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.3.1-1.##

I 4.3.3.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.##

l

1. 1. Channel Calibration and Logic System Functional testing period may be extended as identified by note b on Table 4.3.3.1-1.

RIVER BEND - UNIT 1 3/4 3-30 Amendment No. b72

... =

INSTRUMENTATION 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.3.3 At least once per 18 months ##, the ECCS RESPONSE TIME of each ECCS l

trip function shown in Table 3.3.3-3 shall be demonstrated to be within the limit.

Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months ##, where N is l

j the total number of redundant channels in a specific ECCS trip system.

j l

1. 1. ECCS Response time testing period may be extended as identified by note A on Table 3.3.3-3.

RIVER BEND - UNIT 1 3/4 3-30a Amendment No. 9 72 7

TABLE 3.3.3-2 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS 9

oo ALLOWABLE jj TRIP FUNCTION TRIP SETPOINT VALUE O.

LOSS OF POWER (continued) c-25 2.

Division III

-d a.

4.16 kv Standby Bus Undervoltage a.

4.16 kv Basis -

(Sustained Undervoltage) 3045 i 153 volts 3045 1 214 volts b.

3 1 0.3 sec. time 3 1 0.33 sec. time delay delay b.

4.16 kv Standby Bus Undervoltage a.

4.16 kv Basis -

(Degraded Voltage) 3777 1 30 volts 3777 i 75 volts b.

60 1 6 sec. time 60 1 6.6 sec. time delay delay (w/o LOCA) u, c.

3 0.3 sec. time 3 1 0.33 sec. time delay

);

delay (w/LOCA)

Y a

• See Bases Figure B 3/4 3-1.

• • (Bottom of CST is at EL 95'1".)

The levels are measured from the instrument zero level of ci s8's".

1. (Bottom of suppression pool is at EL 70'.)

The levels are measured from the instrument zero level of EL 89'9".

1. 1. These are inverse time delay voltage relays or instantaneous voltage relays with a time delay. The voltages shown are the maximum that will not result in a trip.

Lower voltage conditions will result-in decreased trip times.

TABLE 3.3.3-3 EMERGENCY CORE COOLING SYSTEM RESPONSE TIMES d

EE[S RESPONSE TIME (Seconds) 1.

LOW PRESSURE CORE SPRAY SYSTEM s 37(^)

l 2.

LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM a.

Pumps A and B s 37(")

b.

Pump C s 37(*)

3.

AUTOMATIC DEPRESSURIZATION SYSTEM NA 4.

HIGH PRESSURE CORE SPRAY SYSTEM s 27(^)

l 5.

LOSS OF POWER NA

)

i i

(*) Response time testing may be extended to the completion of the fifth i

refueling outage scheduled to begin April 16, 1994.

RIVER BEND - UNIT 1 3/4 3-40 Amendment No. 72

TABLE 4.3.3.1-1 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS cm CHANNEL

.0PERATIONAL E

CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED E

A.

DIVISION I TRIP SYSTEM Z

1.

RHR-A (LPCI MODE) AND LPCS SYSTEM w

a.

Reactor Vessel Water Level -

R((a)

Low Low Low Level 1 S

M a) 1, 2, 3, 4*, 5*

b.

Drywell Pressure - High 5

M R

1, 2, 3 c.

LPCS Pump Discharge Flow-Low S

M R

1, 2, 3, 4*, 5*

d.

Reactor Vessel Pressure-Low S

M R

1, 2, 3, 4*, 5*

(LPCS/LPCI Injection Valve Permissive) e.

LPCI Pump A Start Time Delay Relay NA M

Q 1, 2, 3, 4*, 5*

g)

R f.

LPCI Pump A Discharge Flow-Low S

M R

1, 2, 3, 4*, 5*

g.

LPCS Pump Start Time Delay NA M

Q 1, 2, 3 4 *, 5

• Y Relay h.

Manual Initiation NA R(b)

NA 1, 2, 3, 4*, 5*

2.

AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#

a.

Reactor Vessel Water Level -

Rfa Low Low Low level 1 S

M 1, 2, 3 R,

1,2,3 b.

Drywell Pressure-High S

M c.

ADS Timer NA M

Q 1,2,3 d.

Reactor Vessel-Water Level -

Low Level 3 S

M R(a) 1, 2, 3

[

e.

LPCS Pump Discharge R ")

I Pressure-High S

M s

1, 2, 3 k

f.

LPCI Pump A Discharge R *I-1,2,3 I

g Pressure-High S

M 2

g.

ADS Drywell Pressure Bypass NA M

Q 1,2,3 Timer o

h.

ADS Manual Inhibit Switch NA M

NA' 1, 2, 3 g

1.

Minual Initiation NA R

NA 1,2,3 l

w

l TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURIEILLANCE REQUIREMENTS co CHANNEL OPERATIONAL E

CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH y

TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED 3.

DIVISION II TRIP SY3 TEM

~

1.

RHR B AND C (LPCI MODE) a.

Reactor Vessel Water Level -

l Low Low Low Level 1 5

M R

1, 2, 3, 4*, 5*

l b.

Drywell Pressure - High S

M R(,)

1, 2, 3 i

c.

Reactor Vessel Pressure-Low S

M R

1, 2, 3, 4 *, 5*

(LPCI Injection Valve Permissive) d.

LPCI Pump B Start Time Delay Relay NA M

Q

)

1, 2, 3, 4*, 5*

5:'

e.

LPCI Pump Discharge Flow-Low S

M R

1, 2, 3, 4*, 5*

f.

LPCI Pump C Start Time Delay NA M

Q 1, 2, 3, 4*, 5*

't' Relay d

C g.

Manual Initiation NA R(b)

NA 1, 2, 3, 4*, 5*

1 i

2.

AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#

i a.

Reactor Vessel Water Level -

Rfa*

Lew Low Low Level 1 S

M 1,2,3 b.

Drywell Pressure-High 5

M

.R 1,2,3 c.

ADS Timer NA M

Q 1, 2, 3 d.

Reactor Vessel Water Level -

f Low Level 3 S

M R(*)

1, 2, 3 e.

LPCI Pump B and C Discharge

=

l k

Pressure-High 5

M

'R(a) 1, 2, 3

)

g f.

ADS Drywell Pressure Bypass j

Timer NA M

Q 1, 2, 3 z

.o g.

ADS Manual Inhibit Switch NA M

NA 1,2,3 7

h.

Manual Initiation NA R

NA 1,2,3 Y

a

l l

l l

TABLE 4.3.3.1-1 (Cortinued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE RE E

CHANNEL DPERATIONAL CHANNEL FUNCTIONAL CHA MEL

. CONDITIONS FOR WHICH TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED e

C.

DIVISION III TRIP SYSTEM zZ 1.

HPCS SYSTEM a.

Reactor Vessel Water Level -

Rfa 1, 2, 3, 4 *, 5*

Low Low Level 2 5

M b.

Drywell Pressure-High S

M R

c.

Reactor Vessel Water Level-High 1, 2, 3 Level 8 S

M Rg d.

Condensate Storage Tank Level -

1, 2, 3, 4*, 5*

Low S

M Rg,)

e.

Suppression Pool Water 1, 2, 3, 4*, 5*

Level - High 5

N R

1, 2, 3, 4*, 5*

w1 f.

Pump Discharge Pressure-High S

M R(a)(b) 1, 2, 3, 4*, 5*

w g.

HPCS System Flow Rate-Low S

M R

1, 2, 3, 4 *, 5*

l g

h.

Manual Initiation NA R

NA 1, 2, 3, 4*, 5*

D.

LOSS OF POWER 1.

Divisions I and II 1

1 a.

4.16 kv Standby Bus Under-S M

R 1, 2, 3, 4**, 5**

voltage (Sustained Under-voltage) b.

4.16 kv Standby Bus Under-S M

R(b) g voltage (Degraded Voltage) 1, 2, 3, 4**,

5**

2.

Division III i

k a.

4.16 kv Standby Bus Under-S NA R

3 voltage (Sustained Under-1, 2, 3, 4**, 5**

voltage) 2o b.

4.16 kv Standby Bus Under-

?

voltage (Degraded Voltage)

S M

R 1, 2, 3, 4**, 5**

U Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

3 When the system is required to be OPERABLE per Specification 3.5.2.

• • Required when ESF equipment is required to be OPERABLE.

a) Calibrate trip unit setpoint at least once per 31 days.

4 b) May be extended to the completion of the fifth refueling outage, scheduled to begin April 16, 1994.

l 4

INSTRUMENTATION 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint 1

column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

ACTION:

a.

With an ATWS-RPT system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of I

Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b.

With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems, restore the inoperable channel to OPERA 8LE status within 30 days or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.,

c.

Otherwise, restore at least one inoperable channel in each trip system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.3.4.1.1 Each ATWS-RPT system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CNECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.4.1-1.

4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.

1 l

RIVER BEND - UNIT 1 3/4 3-44 l

l l

l

i INSTRUMENTATION i

3/4.3.6 CONTROL R0D BLOCK INSTRUMENTATION i

i LIMITING CONDITION FOR OPERATION 3.3.6 The control rod block instr'umentation channels shown in Table 3.3.6-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.6-2.

I 1

]

APPLICABILITY: As shown in Table 3.3.6-1.

a ACTiuN:

1 l

a.

With a control rod block instrumentation channel trip setpoint less conservative than the value shown in the A%able Values column of Table 3.3.6-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted l

consistent with the Trip Setpoint value, i

b.

With the number of OPERABLE channels less than required by the i

j Minimum OPERABLE Channels per Trip Function requirement, take the ACTION required by Table 3.3.6-1.

SURVEILLANCE REOUTREMENTS 1

i 4'.3.6 Each of the above required control rod block trip systems and j

instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations j

for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.6-1.#

l 1

i 5

1. Channel Calibration period may be extended as identified by notes 'c' and

'g' on Table 4.3.6-1.

RIVER BEND - UNIT 1 3/4 3-59 Amendment No. 72

TABLE 3.3.6-1 4

j d

CONTROL ROD BLOCK INSTRUMENTATION MINIMUM APPLICABLE m

OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION PER TRIP FUNCTION CONDITIONS ACTION i

1.

ROD PATTERN CONTROL SYSTEM E

a.

Low Power Setpoint 2

1, 2 60 Z

b.

High Power Setpoint 2

1 60 2.

APRM a.

Flow Biased F 2 ron Flux -

e Upscale 6

1 61 b.

Inoperative 6

1, 2, 5 61 c.

Downscale 6

1 61 d.

Neutron Flux - Upscale, Startup 6

2, 5 61 3.

SOURCE RANGE MONI'DRS Detector not full in(a) 3 2

61 R

a.

2**

5 62 l

di b.

Upscale (b) 3 2

61 f

2**

5 62 i

Inoperative (b) 3 2

61 l

c.

2**

5 62 i

d.

Downscale(C) 3 2

61 2**

5 62 i

4.

INTERMEDIATE RANGE MONITORS a.

Detector not full in 6

2, 5 61 f

b.

Upscale 6

2, 5 61 c.

Inoperative 6

2, 5 61 d.

Downscale(d) 6 2, 5 61 5.

SCRAM DISCHARGE VOLUME a.

Water Level-High 2

1, 2, 5*

62 6.

REACTOR COOLANT SYSTEM RECIRCULATION FLOW a.

Upscale 2

1 62 6

e

3 TABLE 4.3.6-1 Q

CONTROL ROO 8 LOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS

=

g CHANNEL OPERATIONAL o

CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST CALIBRATION (a)

SURVEILLANCE REQUIRED E

1.

ROD PATTERN CONTROL SYSTEM CI)

'}

a.

Low Power 'Setpoint S

S/U N

SA,

.1, 2 III Sg()b)(e) b.

High Power Setpoint S

M SA 1**

2.

APRM t

t a.

Flow Biased Neutron Flux -

IS)

Upscale NA S/U

,M SA 1

,g b.

Inoperative NA S/U M

NA 1, 2, 5 S/U(g)),M b

c.

Downscale NA SA 1

4 d.

Neutron Flux - Upscale, Startup NA S/U

.N SA 2, 5 j

3.

SOURCE RANGE MDNITORS d

b)

S/U(b),W l

a.

Detector not full in MA

~

NA 2, 5 S/U(

,W SA' 2, 5 b.

Upscale NA c.

Inoperative NA S/U

,W

' NA 2, 5 d.

Downscale NA S/U

,W SA 2, 5 i

4.

INTERMEDIATE RANGE MONITORS I

a.

Detector not full in NA' S/U(b) W NA 2, 5 g

b.

Upscale NA S/U

,W SA 2, 5 i

l

=

c.

Inoperative NA S/Ug),W-NA 2, 5 j

g d.

Downscale NA S/U

,W SA 2, 5 i

S, 5.

SCRAM DISCHARGE VOLUME l

g a.

Water Level-High NA M

R 1, 2, 5*

l j

. {

6.

REACTOR COOLANT SYSTEM RECIRCULATION FLOW h

a.

Upscale NA S/U(b) g

,3g(g) 1 m

)

t4 i

i

^

1 TABLE 4.3.6-1 (Continued)

CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE RE0VIREMENTS NOTES:

a.

Neutron detectors may be excluded from CHANNEL CALIBRATION.

b.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to startup, if not performed within the previous 7

days, c.

CHANNEL CALIBRATION may be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

d.

[ DELETED]

e.

Includes reactor manual control multiplexing system input.

f.

Verify the Turbine Bypass valves are closed when THERMAL POWER is greater than 20% RATED THERMAL POWER.

g.

The CHANNEL CALIBRATION shall exclude the flow reference transmitters; these transmitters shall be calibrated at least once per 18 months, except.that this test may be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

With any control rod withdrawn.

Not applicable to control rods iemoved per Specification 3.9.10.1 or 3.9.10.2.

Calibrate trip unit setpoint once per 31 days.

With THERMAL POWER greater than low power setpoint.

)

RIVER BEND - UNIT 1 3/4 3-64 Amendment No. W72

TABLE 4.3.7.3-1 METEOROLOGICAL MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION a.

Wind Speed

'1.

Elev. 30 ft.

D SA l

2.

Elev. 150 ft.

D SA b.

Wind Direction 1.

Elev. 30 ft.

D SA 2.

Elev. 150 ft.

D SA

\\

c.

Air Temperature Difference 1.

Elev. 30/150 ft.

D

.SA i

4 RIVER BEND - UNIT 1 3/4 3-75 P

---m'-g y

• ye rf m

• 4

=r a -ve, ww-

--e--gre

->'w-+m v-w--+w v

e-weiruri-N--

• r9 c -

-gw v m w ev y F

INSTRUMENTATION REMOTE SHUTDOWN MONITORING INSTRUMENTATION AND CONTROLS LIMITING CONDITION FOR OPERATION 3.3.7.4 The remote shutdown monitoring instrumentation channels and controls shown in Table 3.3.7.4-1 and 3.3.7.4-2 shall be OPERABLE.

APPLICABillTY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

a.

With the number of OPERABLE remote shutdown monitoring instrumentation channels less than required by Table 3.3.7.4-1, restore the inoperable channel (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

b.

With the number of OPERABLE remote shutdown system controls less than required by Table 3.3.7.4-2, restore the inoperable control (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

c.

The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE RE0VIREMENTS 4.3.7.4.1 Each of the above required remote shutdown monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.7.4-1.#

l 4.3.7.4.2 Each of the above required remote shutdown system control circuits shall be demonstrated OPERABLE by verifying, at least once per 18 months, its capability to perform its intended function (s).

1. Channel Calibration may be extended as identified by note 'a' on Table 4.3.7.4-1.

RIVER BEND - UNIl 1 3/4 3-76 Amendment No. 72

k-TABLE 3.3.7.4-2 (Continuad) i REMOTE SHUTOOWN SYSTEM CONTROLS

~

I MINIMUM CHANNELS OPERABLE RSP1 RSP2 i

l 22.

RHR Shutdown Cooling MOV 2(*)

NA (1E12*MOVF006A, 68) i 23.

RHR Outboard Shutdown Isolation MOV 1

NA (1E12*MOVF008) 24.

RHR Inboard Shutdown Isolation MOV 1

NA (1E12*MOVF009) 25.

RHR Hx Flow to Suppression Pool MOV 1

1 l

(1E12*MOVF011A,B)

]

26.

RHR Reactor Head Spray MOV 1

NA (1E12*MOVF023) 27.

RHR Test Line MOV 1

1 (1E12*MOVF024A, B) 28.

Deleted l

1 29.

RHR Injection Shutoff MOV 1

1 (1E12*MOVF027A, 8) 30.

RHR Upper Pool Cooling Shutoff MOV 1

1 (1E12*MOVF037A, B) 31.

RHR Injection MOV 1

2(,)

(1E12"MOVF042A, B, C) 32.

RHR Hx Shell Side Inlet MOV 1

1 (1E12*MOVF047A, B)

33. 'RHR Hx Shell Side Bypass MOV 1

1 (1E12*MOVF048A, B) 34.

RHR Discharge to Radwaste MOV 1

NA (1E12*MOVF040) 35.

Deleted i

36.

RHR Injection MOV 1

1 (1E12*MOVF053A, B) 37.

RHR Pump Minimum Flow MOV 1

I2 *)

(1E12*MOVF064A, B C) 38.

RHR Hx Water Discharge MOV 1

1 (IE12*MOVF068A,B) 39.

Safety Relief Valves 3(a) 3(a)

(1821*RVF051C, G. D) 40.

SSW Pump 1

2(a)

(ISWP*P2A, 2C,(b) 28, 20) 41.

Normal Service Water Isolation MOV 1

1 (1SWP*MOV96A, B)

42. - SSW Cooling Tower Inlet MOV 1

1 (ISWP*MOV55A,B) 43.

SSW Component Cooling Water Inlet MOV 1

1 (1SWP*MOV510A, B) 44.

SSW Component Cooling Water Outlet MOV 1

1 (ISWP*MOV504A,8)

(a) One per control equipment.

(b) SSW pump ISWP*P2C is provided on panel 1EGS*PNL4C.

RIVER BEND - UNIT 1 3/4 3-79 AMEN 0 MENT NO. 52

5 TABLE 4.3.7.4-1 h

REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL i

INSTRUMENT CHECK CALIBRATION C

1.

Reactor Vessel Pressure M

R (a) l 2.

Reactor Vessel Water Level M

R (a)

[

3.

Safety / Relief Valve Demand Position M

NA 4.

Suppression Pool Water Level M-R 5.

Suppression Pool Water Temperature M

R

{

6.

Drywell Pressure M

R 7.

Drywell Temperature M

R 8.

RHR System Flow:

Loop A M

R Loop B M

R Loop C M

R 9.

RHR Hx Cooling Water System Flow:

Loop A M

R Loop 8 M

R 10.

RCIC System Flow M

R i

11.

RCIC Turbine Speed M

R 5

f (a) May be extended to be performed during the fifth refueling outage scheduled to begin April 16, 1994.

aw l

I l

i a

1 I

INSTRUMENTATION ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDIT10N FOR OPERATION j

3.3.7.5 The accident monitoring instrumentation channels shown in Table 3.3.7.5-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3.7.5-1.

l ACTION:

With one or more accident monitoring instrumentation channels inoperable, take the ACTION required by Table 3.3.7.5-1.

l i

l SURVEILLANCE REQUIREMENTS 4.3.7.5 Each of the above required accident monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION operations at the frequencies shown in Table j

2

{

4.3.7.5-1.#

l 1

i

,l i

1 4l 5

l i

1. Channel Calibration period may be extended as identified by note (a) on Table 4.3.7.5-1.

RIVER BEND - UNIT 1 3/4 3-81 Amendment No. 72

TABLE 3.3.7.5-1 ACCIDENT MONITORING INSTRUMENTATION E

MININUM APPLICABLE REQUIRED NUMBER CHANNELS OPERABLE l

[

INSTRUMENT OF CHANNELS 09ERABLE CONDITIONS ACTION i

5

-4 1.

Reactor Vessel Pressure 2

1 1,2,3 80 w

2.

Reactor Vessel Water Level

a.. Wide Range 2

1 1,2,3 80 b.

Fuel Zone 2

1 1,2,3 80 3.

Suppression Pool Water Level 2

1 1,2,3 80 4.

Suppression Pool Water Temperature 2/ sector 1/ sector 1,2,3 80 5.

Primary Containment Pressure 2

1 1,2,3 80 6.

Drywell Pressure 2

1 1,2,3 80 7.

Drywell Air Temperature 2

1 1,2,3 80 8.

Drywell and Pr 5 'ary Containment Hydrogen Concentration 2

1 1,2,3 80 Y

Analyzer and Area Radiation,Moniter 9.

T a.

Primary Containment Area 2

1 1,2,3 81 E

b.

Drywell Area 2

1 1,2,3 81 L

1. High range gross gamma monitors.

6

~ -

l Table 3.3.7.5-1 (Continued)

ACCIDENT MONITORING INSTRUMENTATIONS ACTION STATEMENTS i

ACTION 80 -

a.

With the number of OPERABLE accident monitoring instrumenta-i tion channels less than the Required Number of Channels shown in Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b.

With the number of OPERABLE accident monitoring instrumenta-tion channels less than the Minimum Channels OPERABLE require-ments of Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

ACTION 81 -

With the number of OPERABLE Channels less than required by the Minimum Channels OPERABLE requirement, either restore the inoper-able Channel (s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or:

a.

Initiate the preplanned alternate method of monitoring the appropriate parameter (s), and b.

Prepare and submit, within 14 days following the event, a i

Special Report to the Commission, pursuant to Specifica-tion 6.9.2, outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

4 RIVER BEND - UNIT 1 3/4 3-83

TABLE 4.3.7.5-1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 9

as APPLICABLE E

CHANNEL CHANNEL OPERATIONAL y

INSTRUMENT CHECK CALIBRATION CONDITIONS 1.

Reactor Vessel Pressure M

R (a) 1, 2, 3 l

ej'i 2.

Reactor Vessel Water Level a.

Wide Range M

R 1,2,3 b.

Fuel Zone M

R 1,2,3 1

3.

Suppression Pool Water Level H

R 1,2,3 4.

Suppression Pool Water Temperature M

R 1,2,3 5.

Primary Containment Pressure M

R 1, 2, 3 6.

Drywell Pressure M

R 1,2,3 7.

Drywell Air Temperature M

R 1, 2, 3 8.

Drywell and Primary Containment Hydrogen Concentration M

Q*

1, 2, 3 Analyzer and Area Radiation, Monitor 9.

w1 a.

Primary Containment Area M

R** (a) 1, 2, 3 b.

Drywell Area M

R**

1, 2, 3 l

w I

"Using sample gas containing:

a.

One volume percent hydrogen, balance nitrogen.

b.

Four volume percent hydrogen, balance nitrogen.

• • The CHANNEL CALIBRATION shall consist of an electronic calibration of the channel, not including the g

detector, for range decades above 10 R/hr and a one point calibration check of the detector below 10 R/hr m,

with an installed or portable gamma source.

g i

8-High range gross gamma monitors.

ro S

(a)May be extended to be performed during the fifth refueling outage scheduled to begin April 16, 1994.

k i

d I

INSTRUMENTATION 3/4,3.9 PLANT SYSTEMS ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.9 The plant systems actuation instrumentation channels shown in Table 3.3.9-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.9-2.

APPLICABILITY: As shown in Table 3.3.9-1.

ACTION:

a.

With a plant system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoperable and take the ACTION required by Table 3.3.9-1.

b.

With one or more plant systems actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.9-1.

SURVEILLANCE RE0VIREMENTS 4.3.9.1 Each plant system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.9.1-1.#

l 4.3.9.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed at least once per 18 months.#

l

1. Channel Calibration and Logic System Functional test period may be extended l

as identified by note (b) on Table 4.3.9.1-1.

RIVER BEND - UNIT 1 3/4 3-107 Amendment No. Br 72

TABLE 3.3.9-1 i3 g

PLANT SYSTEMS ACTUATION INSTRUMENTATION g

MINIMUM APPLICABLE g

OPERABLE CHANNELS OPERATIONAL TRIP FUNCTION PER TRIP SYSTEM CONDITIONS ACTION 1.

PRIMARY CONTAINMENT VENTILATION SYSTEM -

-i UNIT COOLER A AND 8 w

a.

Drywell Pressure-High 2

1,2,3 150 b.

Containment-To-Annulus AP High 3

1,2,3 151 c.

Reactor Vessel Water Level-Low Low Low Level 1 2

1,2,3 150 d.

Timers 1

1,2,3 152 2.

FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM

[

a.

Reactor Vessel Water Level-High Level 8 3

1 153 E

l e

d I.

=

TABLE 4.3.9.1-1 j

PLANT SYSTEMS ACTUAT70N INSTRUMENTATION SURVEILLANCE REQUIREMENTS m

to E

CHANNEL OPERATIONAL CHANNEL FUNCTIONAL EWitt CONDITIONS IN WHICH TRIP FUNCTION CHECK TEST

' CALIBRATION SURVEILLANCE REQUIRED i

C h

1.

PRIMARY CONTAIMENT VENTILATION SYSTEM -

p UNIT COOLER A AND 8 s

Rfa)#

a.

Drywell Pressure-High D

M 1,2,3 R *)

1, 2, 3 b.

Containment-to-Annulus AP-High D

N 4

c.

Reactor Vessel Water Level-Low Low Low Level 1 D

M R(a)#

1,2,3 l

j d.

Timer NA M

R 1, 2, 3 2.

FEEDWATER SYSTEM / MAIN TUR8INE TRIP SYSTEM ws 4

a.

Reactor Vessel Water Level-High i

l

't' Level 8 D

M R(b)

U w

i i

(*) Calibrate trip unit setpoint once per 31 days.

l (b)May be performed during the fifth refueling outage scheduled to begin April 16, 1994.

l The specified 18 month interval during the first operation cycle may be extended to coincide with completion of the first refueling outage, scheduled to begin 9-15-87.

g O

I.

r+

i e

hJ l

TABLE 3.6.4-1 (Continued) h CONTAINMENT AND DRYWELL ISOLATION VALVES E

ea E

MAXIMUM SECONDARY PENETRATION VALVE ISOLATION TIME CONTAINMENT U)

SYSTEM VALVE NUMBER NUMBER GROUP (Seconds)

BYPASS PATH E

(Yes/No)

-e e

a.

Automatic Isolation Valves 1.

Primary Containment *)

(Continued)

I RWCU Disch. to Condenser #

1G33*MOVF028 IKJB*Z4 15 20.9 Yes RWCU Return to FW#

1G33*MOVF040 IKJB*26 15 24.2 No RWCU Pump Suction #

1G33*MOVF001(b)

IKJB*Z7 16 19.8 No RWCU Pump Disch. #

1G33*MOVF053 IKJB*Z129 15 5.5 No g)

RWCU Disch. to Condenser #

1G33*MOVF034 IKJB*Z4 15 20.9 Yes w1 RWCU Return to FW #

1G33*MOVF039 IKJB*Z6 15 24.2 No t

RWCU Pump Suction #

IG33*MOVF004 IKJB*Z7 7

6.6 No J,

RWCU Pump Disch. #

1G33*MOVF054 IKJB*Z129 15 5.5 No (I)

RWCU Backwash Disch. #

1WCS*MOV178 IKJB*ZS 1

12.1 Yes II)

RWCU Backwash Disch. #

IWCS*MOV172 1KJB*Z5 1

12.6 Yes HPCS Test Return-Supp. Pool 1E22*MOVF023(j)

IKJB*Z11 1

50 No RHR A Return-Supp. Pool IE12*MOVF024A(j)

IKJB*Z24A 10 63.8 No RHR A Hx Dump-Supp. Pool IE12*MOVF011A(j) 1KJB*Z24A 10 34.1 No LPCS Test Return-Supp. Pool 1E21*MOVF012(j) 1KJB*Z24A 10 57.2 No RHR 8 Return-Supp. Pool IE12*MOVF024B(j)

IKJB*Z248 10 63.8 No RHR B Hx Dump-Supp. Pool IE12*MOVF011B(j) 1KJB*Z248 10 30.8 RHR C Return-Supp. Pool IE12*M0VF021(j)

IKJB*Z24C 10 97.9 No No Fuel Pool C&C Disch.

ISFC*MOV119 1KJB*Z26 1

68 No Fuel Pool C&C Suction ISFC*MOV120 IKJB*Z27 1

62.7 No Fuel Pool C&C Suction ISFC*MOV122 1XJB*Z27 1

63.8 No k

Fuel Pool Purif. Suction ISFC*MOV139 1KJB*Z28 1

39.6 No Fuel Pool Purif. Suction ISFC*MOV121 1KJB*Z28 1

39.6 No 2

3 if:

Go

1 l

l TABLE 3.6.4-1 (Continued)

=

CONTAINMENT AND DRYWELL ISOLATION VALVES E

. MAXIMUM SECONDARY PEMETRATION VALVE ISOLATION TIME CONTAINMENT II)

SYSTEM VALVE NUMBER NUPEER GROUP (Seconds)

BYPASS PATH E

(Yes/No) p i

a.

Automatic Isolation Valves w

1.

Primary Containment (*) (Continued) 1 R W 102 @)

Floor Drain Disch.

1KJB*Z35, 1

N/A No 1DRB*Z36 Floor Drain Disch.

1DFR*A0V101(b) 1KJB*Z35, 1

N/A No IDRB*Z36 ID)

Equip. Drain Disch.

1 DER *A0V127 1KJB*Z38, 1

N/A No w) 1DRB*Z39 Equip. Drain Disch.

1 DER *A0V126(b) 1KJB*Z38, 1

N/A No l

1DRB*Z39 5

Yes(II)

1. )

j Fire Protection Hdr.

IFPW*MOV121 1KJB*Z41 1

34.1 Service Air Supply ISAS*MOV102 1KJB*Z44 1-22.0 Yes II)

Instr. Air Supply 11AS*MOV106 IKJB*Z46 1

18.7 Yes RPCCW Supply ICCP*MOV138 IKJB*Z48 1

22.0 No RPCCW Return-ICCP*MOV158 IKJB*Z49 1

23.1 No RPCCW Return

'ICCP*MOV159 1KJB*Z49 1

24.2-No i

Service Water Return ISWP*MOVSA IKJB*Z53A 1

50.6 No Service Water Return ISWP*MOV58 IKJB*Z538 -

1 53.9 No i

II) i Vent. Chilled Water Rtn.

1HVN*MOV102 IKJB*Z131 1

31.9 Yes II)

Vent. Chilled Water Rtn.

1HVN*MOV128 IKJB*Z131 1

28.6 YesII)

Vent. Chilled Water Sup.

1HVN*MOV127 IKJB*Z132 1

27.5 Yes(I) j Condensate Makeup Supply ICNS*MOV125 1KJB*Z134 1

22.0 Yes g

8 i

• i I

4

TABLE 3.6.4-1 (Continued)

$h CONTAINMENT AND DRYWELL ISOLATION VALVES E

03 52 MAXIMUM SECONDARY c'

PENETRATION VALVE ISOLATION TIME CONTAINMENT I)

SYSTEM VALVE NUMBER HUMBER GROUP (Seconds)

BYPASS PATH SE (Yes/No)

Z a.

Automatic Isolation Valves

,2 Primary Containment (a) (Continued) 1.

1E51*MOVF063(b) 1KJB*Z15 2

9.9 No RHR & RCIC Steam Sup.

1E51*MOVF076(b)(m) 1KJB*Z15 2

13.4 No RHR & RCIC Steam Sup.

RHR & RCIC Steam Sup.

1E51*MOVF064 1KJB*Z15 2

9.9 No RCIC Pump Suc.-Supp. Pool IE51*MOVF031 y)

IKJB*Z16 2

30.5 No g

RCIC Turbine Exh.-Supp. Pool IE51*MOVF077 1KJB*Z17 3

14.2 Na u,

];

RCIC Turbine Exh. Vac. Bkrs.

1E51*MOVF078 1KJB*Z188,C 3

16.5 No Cont./Drywell Purge Sup.

1HVR*A0V165 IKJB*Z31 8

3 No o,

J, Cont./Drywell Purge Sup.

1HVR*A0V123 IKJB*Z31 8

3 No Cont./Drywell Purge Outlet 1HVR*A0V128 IKJB*Z33 8

3 No on Cont./Drywell Purge Outlet 1HVR*A0V166 IKJB*233 8

3 No Post-Accident Samp. Sup.

ISSR*SOV130 1KJB*Z601B 10 3

No Post-Accident Samp. Sup.

ISSR*SOV131 IKJB*Z601B 10 3

No a

2 P.

F 3

i TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES 9

cm SE MAXIMUM SECONDARY l

c' PENETRATION VALVE ISOLATION TIME CONTAINMENT II)

SYSTEM VALVE NUMBER NUMBER GROUP (Seconds)

BYPASS PATH EE (Yes/No)

U a.

Automatic Isolation Valves 2.

Drywell(k)

Cont./Drywell Purge Sup.

1HVR*A0V147 1DRB*Z32 1

3 No 3

RPCCW Supply ICCP*MOV142 1DRB*Z50 1

30 No RPCCW Return ICCP*MOV144 1DRB*ZS1 1

30 No i

RPCCW Return ICCP*MOV143 1DR8*Z51 1

30 No l

Service Water Supply ISWP*MOV4A IDRB*Z54 1

52.8 No 3:

Service Water Supply 1SWP*MOV4B 1DRB*Z54 1

51.7 No Service Water Return 1SWP*MOV5A 1DRB*Z55 1

50.6 No i

Service Water Return ISWP*MOV5B IDRB*Z55 1

53.9 No S$

Recirc. Flow Control IRCS*HOV58A 1DRB*Z152 1

11.0 No Recirc. Flow Control IRCS*MOV59A 1DR3*Z153 1

10.6 No Recirc. Flow Control IRCS*MOV60A 1DRB*2154 1

6.3 No l

Recire. Flow Control IRCS*MOV61A 1DRB*Z155 1

8.6 No t

Recirc. Flow Control IRCS*MOV58B 1DRB*Z156 1

10.6 No l

Recirc. Flow Control IRCS*MOV59B 1DRB*Z157 1

10.8 No i

Recirc. Flow Control IRCS*MOV60B 1DRB*Z158,

1 6.38 No Recirc. Flow Control 1RCS*MOV61B IDRB*Z159 1

8.9 No Cont./Drywell Purge Sup.

1HVR*A0V125 1DRB*Z32 1

3 No Cont./Drywell Purge Rtn.

1HVR*A0V126 1DRB*Z34 1

3 No Cont./Drywell Purge Rtn.

1HVR*A0V148 IDRB*Z34 1

3 No g

it 4

e n

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES 9

MAXIMUM SECONDARY PENETRATION VALVE ISOLATION TIME -CONTAINMENT U)

SYSTEM VALVE NUMBER NUMBER GROUP (Seconds)

BYPASS PATH E

(Yes/No)

Q g

a.

Automatic Isolation Valves 2.

Drywell(k) (Continued)

Hydrogen Mixing Line Inlet ICPM*MOV2A IDRB*ZS7A 10 33 No Hydrogen Mixing Line Inlet ICPM*MOV4A 1DRB*Z57A 10 33 No Hydrogen Mixing Line Inlet ICPM*MOV2B IDRB*Z57B 10 33 No Hydrogen Mixing Line Inlet ICPM*MOV4B IDRB*Z578 10 33 No Hydrogen Mixing Line Exhaust ICPM*MOV3A 1DRB*Z58A 10 33 No w)

Hydrogen Mixing Line Exhaust ICPM*MOVIA IDRB*Z58A 10 33 No Hydrogen Mixing Line Exhaust ICPM*MOV3B 1DRB*Z588 10 33 No m

J, Hydrogen Mixing Line ICPM*MOV1B 1DRB*Z58B 10 33 No Reactor Plant Sampling 1833*A0VF019 IDRB*Z449 9

5 No Reactor Plant Sampling 1833*A0VF020 1DRB*Z449 9

5 No 5

e a-O

-._._m._.._.._.___

t 4

TABLE 3.6.4-1 (Continued) k CONTAINMENT AND DRYWELL ISOLATION VALVES 9

es SECONDARY E

PENETRATION CONTAINMENT SYSTEM VALVE NUISER NUMBER BYPASS PATH (Yes/No)

EZ w

b.

Manual Isolation W ives Primary Containment ')

I 1.

LPCI A to Reactor IE12*F099A 1KJ8*Z21A No 1KJ8*Z218 No LPCI B to Reactor 1E12*F0g Reactor Plant Vent. AP Trans.

1HVR*V8 1KJB*Z602A No 1HVR*V10 "))

I 1KJB*Z6028 No Reactor Plant Vent. AP Trans.

I PVLCS Pressure Transmitter ILSV*V64 1KJ8*Z6020 No 1HVR*V12(k) 1KJB*Z602F No R

Reactor Plant Vent. AP Trans.

Cont. Leakage Monitor Press.

ILMS*V14 1KJ8*Z603A' No i

Cont. Leakage Monitor Press.

ILMS*V12 1KJB*Z603A No i

5 Cont. Leakage Monitor Press.

ILMS*V7 1KJB*Z603C No i

1KJ8*Z603C No _

Cont. Leakage Monitor Press.

1LMS*V1fk) 1KJ8*2605A No Cont. Monitor Press. Sensing ICMS*V2(k)

Cont. Monitor Press. Sensing ICMS*V3 1KJB"Z6058 No 4

Ig IKJ8*Z606A No Reactor Plant Vent..AP Trans.

1HVR*V14(I) 1KJB*Z6068 No Reactor Plant Vent. AP Trans.

1HVR*V16(k)

-Cont. Monitor Press. ' Sensing ICMS*V16(k) 1KJ8*Z606C No-Cont. Monitor Press. Sensing -

ICMS*V15 1KJB*Z6060 No fN)

PVLCS Pressure Transmitter ILSV*V65 1KJB*Z606E No II)

Reactor Plant Vent. AP Trans.

1HVR*V18 IKJB*Z606F No LPCI A to Reactor 1E12*VF044A' IKJ8*Z21A No LPCI 8 to Reactor IE12*VF0448 IKJ8*Z218 No I

1KJB*Z53A No ISWP*SOVS22A '))

SW.Rtn Vacuum Release I

1KJB*Z538 No SW Rtn Vacuum Release 1SWP*SOV5228 )

I 1KJB*Z53A No i

SW Rtn Vacuum Release 1SWP*SOV522C ')

I SW Rtn Vacuum Release ISWP*SOVS22D 1KJB"Z538 No l

e s

m

TABLE 3.6.4-1 (Continued) h CONTAINMENT AND DRYWELL ISOLATION VALVES

!G h

NOTES o

(a) Subject to a Type C leak rate test at a test pressure of 7.6 psig except as otherwise noted.

Ey (b) Also isolates the drywell.

(c) Testable check valve.

(d) Isolates on MS-PLCS air line high flow or MS-PLCS air line header to Main Steam Line low differential pressure.

(*) Receives a remote manual isola' ion signal.

II) This line is sealed by the penetration valve leakage control system (PVLCS).

The combined leakage from

,g valves sealed by the PVLCS is not included in 0.60 La Type B and C test total.

i (9) This valve sealed by the main steam positive leakage control system (MS-PLCS). Valves sealed by the O

MS-PLCS are tested in accordance with Surveillance Requirement 4.6.1.3.f to verify that leakage does not exceed the limit specified in Specification 3.6.1.3.c.

This leakage is not included in the 0.60 La Type B and C test total.

(h) Not subject to Type C leakage tests. Valve (s) will be included in the Type A test.

(3) Valve is hydrostatically leak tested at a test pressure of 8.36 psig (1.1 Pa).

The leakage from hydrostatically tested valves is not included in the 0.60 La Type B and C test total.

( ) Not subject to a Type A, B, or C leak rate test.

[

f ) Valve groups listed are designated in Table 3.3.2-1.

3

(*) Value IE51*MOVF076 is not required to be OPERABLE through October 4,1986.

a

1. The specified 18 month automatic isolation valve actuation may be performed during the fifth refueling z

outage scheduled to begin April 16, 1994.

CONTAINMENT SYSTEMS 3/4.6.5 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY - OPERATING LIMITING CONDITION FOR OPERATION 3.6.5.1 SECONDARY CONTAINMENT INTEGRITY - OPERATING shall be maintained.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

Without SECONDARY CONTAINMENT INTEGRITY - OPERATING restore SECONDARY CONTAINMENT INTEGRITY - OPERATING within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVEILLANCE REQUIREMENTS 4.6.5.1 SECONDARY CONTAINMENT INTEGRITY - OPERATING shall be demonstrated by:

a.

Verifying at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> that the pressures within the Shield Building annulus, the Auxiliary Building and the Fuel Building are less than or equal to 3.0, 0.00, and 0.00 indhes of vacuum water gauge, respectively.

b.

Verifying at least once per 31 days that:

1.

All secondary containment equipment hatch covers are installed.

2.

The door in each access to the secondary containment is closed, except during normal entry and exit.

3.

All secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers and required to be c!csed during accident conditions are closed by valves, blind flanges, or deactivated automatic dampers / valves securer: in position.

O)

RIVER BEND - UNIT 1 3/4 6-48

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ELECTRICAL POWER SYSTEMS l

SURVEllLANCE REQUIREMENTS (Continued)

I b.

At least once per 92 days, and within 7 days after a battery discharge with battery terminal voltage below 110 volts or after a battery overcharge with battery terminal voltage above 144 volts, by verifying that:

1.

The parameters in Table 4.8.2.1-1 meet the Category B limits, 2.

There is no visible corrosion at either terminals or connectors, or the connection resistance of these items is less than 150 x 10~6 ohms, and l

3.

The average clectrolyte temperature of at least one out of six connected cells is above 60*F.

c.

At least once per 18 months # by verifying that:

l 1.

The cells, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration, 2.

The cell-to-cell and terminal connections are clean, tight, free of corrosion and coated with anti-corrosion material, 3.

The resistance of each cell-to-cell and terminal connection is less than or equal to 150 x 10'6 ohms and 4.

The battery charger will supply at least 300 amperes for chargers 1A and 18 and 50 amperes fer charger 1C at a minimum i

of 130.2 volts for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

d.

At least once per 18 months #, during shutdown, by verifying that l

either:

1 1.

The battery capacity is adequate to supply and maintain in OPERABLE status all of the actual emergency loads for the design duty cycle when the battery is subjected to a battery service test, or 2.

The battery capacity is adequate to supply a dummy load of the following profile in accordance with IEEE 450 while maintaining the battery terminal voltage greater than or equal to 105 volts.

a)

Division I 2 671 amperes for the first 60 seconds l

2 270 amperes for the next 9 minutes l

2 336 amperes for the next 60 seconds 2 270 amperes for the next 228 minutes 2 451 amperes for the last 60 seconds

1. May be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

RIVER BEND - UNIT 1 3/4 8-15 Amendment 'a. 72 i

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIRF,MENTS (Continued) b)

Division II 2 502 amperes for the first 60 seconds 2 261 amperes for the next 9 minutes 2 327 amperes for the next 60 seconds 2 261 amperes for the next 228 minutes 2 327 amperes for the last 60 seconds c)

Division III 2 53.2 amperes for the first 60 seconds 2 15.4 amperes for the next 119 minutes e.

At least once per 60 months ## by verifying during shutdown that the l

battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test.

Once per 60 month interval, this performance discharge test may be performed in lieu of the battery service test.

f.

At least once per 18 months, during shutdown, performance discharge tests of battery capacity shall be given to any battery that shows signs of degradation or has reached 85% of the service life expected for the application.

Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its average on previous performance tests, or is below 90% of the manufacturer's rating.

1. 1. For Division III, may be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

RIVER BEND - UNIT 1 3/4 8-16 Amendment No. 72

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TABLE 4.8.2.1-1 BATTERY SURVEILLANCE REQUIREMENTS l

CATEGORY A(1)

CATEGORY B (2)

Parameter Limits for each Limits for each A11owable(3) designated pilot connected cell value for each cell connected cell Electrolyte

> Minimum level

> Minimum level Above top of Level indication mark indication mark plates and < h" above and < " above and not maximum level maximum level overflowing i

indication mark indication mark Float Voltage 1 2.13 volts

> 2.13 volts (c) 2.07 volts Specifig

> 1.200 (Div. I&II) > 1.195 (Div. I&II)

Not more than

{

Gravity,)

2 1.195 (Div. III) 2 1.190 (Div. III)

.020 below the average of all

{

connected cells 1

Average of all Average of all-connected cells connected cells

> 1.205 (Div. I&II)

>-1.195 (Div.I&II)

_> 1.200 (Div. III)

> 1.190 (Div. III)

(a) Corrected for electrolyte temperature and level.

(b) Or battery charging current is less than 2 amperes when on float charge.

(c) May be corrected for average electrolyte temperature.

(1) For Category A parameters outside the limits shown, the battery may be considered OPERABLE provided that within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> all the Category B measurements are taken and found to be within their allowable values, and provided all Category A and B parameters are restored to within limits within the next 6 days.

(2) For Category B parameters outside the limits shown, the battery may be considered OPERABLE provided that the Category B parameters are within their allowable values and provided the Category B parameters are restored to within limits within 7 days.

(3) Any Category B parameter not within its allowable value indicates an inoperable battery.

R.VER BEND - UNIT 1 3/4 8-17

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j ELECTRICAL POWER SYSTEMS j

D.C. SOURCES - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.8.2.2 As a minimum, division I or division II and, when the HPCS system is required to be OPERABLE, division III, of the D.C. electrical power sources shall be OPERABLE with.

a.

Division I consisting of-1.

125 volt battery 1A.

l 2.

125 volt full capacity Class lE source charger.

j l

b.

Division II consisting of:

1.

125 volt battery 18.

2.

125 volt full capacity Class lE source charger.

c.

Division III consisting of:

1.

125 volt battery 10.

2.

125 volt full capacity Class IE source charger.

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and *.

ACTION:

a.

With less than the division I and/or division II battery and/or charger of the above required D.C. electrical power sources OPERABLE, suspend CORE ALTERATIONS, handling of irradiated fuel in the primary containment or Fuel Building, and operations with a potential for draining the reactor vessel.

b.

With division III battery and/or charger of the above required D.C.

electrical power sources inoperable, declare the HPCS system and the C SSW pump inoperable and take the ACTION required by Specifications 3.5.2, 3.5.3 and 3.7.1.1.

c.

The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.2.2 At least the above required battery and charger shall be demonstrated OPERABLE per Surveillance Requirement 4.8.2.1.#

l

• When handling irradiated fuel in the primary containment or Fuel Building.

1. May be extended as identified by notes

'#' and '##' in Surveillance Requirement 4.8.2.1.

l RIVER BEND - UNIT 1 3/4 8-18 Amendment No. 72

ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRIC POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.3 Two RPS electric power monitoring channels for each in-service RPS MG set or alternate power supply shall be OPERABLE.

APPLICABILITY: At all times.

ACTION:

a.

With one RPS electric power monitoring channel for an in-service RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

b.

With both RPS electric power monitoring channels for an in-service RPS MG set or alternate power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.

SURVEILLANCE REQUIREMENTS 4.8.4.3 The above specified RPS electric power monitoring channels shall be j

determined OPERABLE:

1 a.

By performance of a CHANNEL FUNCTIONAL TEST each time the unit is in COLD SHUTDOWN for a period of more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless performed within the previous six months, and b.

At least once per 18 months

• by demonstrating the OPERABILITY of l

over-voltage, under-voltage and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

1.

Over-voltage s 132 VAC, Bus A and B, 2.

Under-voltage 2115 VAC, Bus A and B, and 3.

Under-frequency 57 Hz, + 2, - 0%, Bus A and B.

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• May be extended to the completion of the fifth refueling outage scheduled to begin April 16, 1994.

RIVER BEND - UNIT 1 3/4 8-35 Amendment No. 72

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ELECTRICAL POWER SYSTEMS A.C. CIRCUITS INSIDE CONTAINMENT LIMITING CONDITION FOR OPERATION 3.8.4.4 At least the following A.C. circuits inside containment shall be j

de energized *:

Equipment ID Location Device i

1MHR*CRN1 1EJS*LDC2A ACB022 1F42-PNLP003 ISCA-PNL8C1 Circuit Breaker 1 1F42-D002H 1SCA-PNL8C1 Circuit Breaker 15 1SFT-PNL106 ISCA-PNL882 Circuit Breaker 2

)

ISFT-PNL106 ISCA-PNL882 Circuit Breaker 10 1HVR*UC1AH ISCV*PNL2A2 Circuit Breaker 5 1HVR*UC1BH ISCV*PNL2B2 Circuit Breaker 12 1HVR-UCICH ISCA-PNL2C1 Circuit Breaker 9 i

1HVR-FN1AH ISCA-PNL2A2 Circuit Breaker 3 1HVR-FN1BH 1SCA-PNL2F1 Circuit Breaker 6 i

1HVR-FNICH ISCA-PNL2E1 Circuit Breaker 1

~

1HVR-FN1DH ISCA-PNL2B1 Circuit Breaker 6 1DRS-UC1AH ISCA-PNL2E1 Circuit Breaker 2 1

1DRS-UC1BH ISCA-PNL2F1 Circuit Breaker 3 1DRS-UCICH ISCA-PNL2E1 Circuit Breaker 2 1DRS-UCIDH ISCA-PNL2F1 Circuit Breaker 3 1DRS-UC1EH ISCA-PNL2E1 Circuit Breaker 2 1DRS-UCIFH 1SCA-PNL2F1 Circuit Breaker 3 l

1WCS-PSAH ISCA-PNL2E1 Circuit Breaker 4 j

1WCS-P5BH ISCA-PNL2F1 Circuit Breaker 2 APPLICABILITY:

OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

With any of the above required circuits energized, trip the associated circuit breaker (s) in the specified location within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

t SURVEILLANCE REQUIREMENTS 4.8.4.4 Each of the above required A.C. circuits shall be determined to be de-energized by verifying at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ** that the associated circuit breakers are in the tripped condition.

1

• Except during entry into the containment.

• • Except at least once per 31 days if locked, sealed or otherwise secured in the tripped condition.

RIVER BEND - UNIT 1 3/4 8-36