ML20213H140

Proposed Tech Specs,Extending Surveillance Interval to First Refueling Outage Scheduled to Begin on 870915

ML20213H140
Person / Time
Site:	River Bend
Issue date:	05/11/1987
From:	GULF STATES UTILITIES CO.
To:
Shared Package
ML20213H127	List: ML20213H140 RBG-25917, Application for Amend to License NPF-47,extending Surveillance Interval to First Refueling Outage Scheduled to Begin on 870915.Fee Paid
References
TAC-65397, NUDOCS 8705190160
Download: ML20213H140 (55)

Text

ENCLOSURE 8705190160 870511 PDR ADOCK 05000458 P PDR

CONTAINMENT SYSTEMS.

PENETPATION VALVE LEAKAGE CONTROL SYSTEM LIMITING CONDITIGN FOR OPERATION 3.6.1.10 Two independent penetration valve leakage control system (PVLCS) divisions shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

With one PVLCS division inoperable, restore the inoperable division 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 />.

SURVEILLANCE REQUIREMENTS 4.6.1.10 Each PVLCS division shall be demonstrated OPERABLE:

a. At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying division PVLCS accumulator pressure greater than or equal to 101 psig.

b. During each COLD SHUTDOWN, if not performed within the previous 92 days, by cycling each motor-operated valve through at least one complete cycle of full travel.

c. At least once per 1E fnonths by performance of a functional test which includes simulated actuation of the system throughout its operating sequence, and verifying that each automatic valve actuates to its correct position and that a sealing pressure greater than or equal to 22 psig is established in each sealing valve.

d. By verifying the operating instrumentation to be OPERABLE by performance of a:

1. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

2. CHANNEL CALIBRATION at'least once per 18 months.

• - This frequency may be extended to coincide with the refueling outage for the first cycle only. Not to exceed 09/1S/87.

4 RIVER BEND - UNIT 1 3/4 6-16

ATTACHMENT 2'

~ GULF STATES UTILITIES COMPANY RIVER BEND STATION DOCKET 50-458/ LICENSE NO. NPF-47 Reactor Protection System Instrumentation LICENSING DOCUMENT INVOLVED: TECHNICAL SPECIFICATICNS 4.3.1.1 Page 3/4 3-1 4.3.1.2 3/4 3-1 4.3.2.1 3/4 3-11 4.3.2.2 3/4 3-11 REASON FOR REQUEST:

The River Bend Station (RBS) Technical Specifications require many surveillance tests be performed every eighteen (18) months (plus a msximum extension defined by Specification 4.0.2). This proposed change is a request to extend the interval for the subject Surveillance Requirements for 21 days to the scheduled refueling outage (09-15-87).

A one time extension is being requested in accordance with 10CFR50.92.

Gulf States Utilities Company (CSU) has and will make a good faith effort to conduct this surveillance on the current frequency if an outage of sufficient duration occurs. In order to test this component, the plant must be in a shutdown condition. To require the plant to shutdown solely to perform surveillances would cause an unnecessary thermal transient on the plant. GSU requests to amend the subject Technical Specifications contained in Appendix A to the River Bend Station (RBS) Operating License, as discussed below, to perform the subject test during a scheduled refueling outage. Should these proposed changes not be granted in a timely manner, CSU will be forced to implement an unnecessary outage during the first cycle.

' DESCRIPTION High radiation in the vicinity of the main steam lines may indicate a gross fuel failure in the core. High radiation detectors provide a radiation signal to a Logarithmic Radiation Monitor (LRM) which actuates computer and annunciator alarms initiates, a scram through the Reactor Protection System (RPS), and initiates containment isolation through the Containment and Reactor Vessel luolation Control System (CRVICS) . The System design and function are discussed in Final Safety Analysis Report (FSAR) Chapters 7.3.1 and 7.2.1 and evaluated by the Nuclear Regulatory Commission (NRC) in Safety Evaluation Report (SER) Chapter ~7.6.3.

System design functions, operation and trip'setpoints are not modified by this change. Extension of this surveillance period by 11 days to September 15, 1987 will not affect the intent of the test period or the probability of the test failing the acceptance criteria for continued operation.

A calibration surveillance is required by Technical Specification Table 4.3.1.1-1 item 7 (page 3/4 3-7 Reactor Protection Instrumentation) and Table 4.3.2.1-1 item 2.b (Isolation Actuation) which specifies that the surveillance for Main Steam Line Radiation-High (MSLRH) it.olation actuation instrumentation channel calibration must be performed at least once every 18 months. Technical Specification 3.3.1 requires a minimum number of instrumentation channels to be operable in applicable operational modes 1 and 2. FSAR Section 7.2.2.3 in conformance to Regulatory Guide (RG) 1.22 states that the calibration testing requirements could be performed during full power operation by removing the individual monitors and inserting them into a calibration source.

However, CSU's past experience indicates that there is a high probability of an RPS and Engineered Safety Feature (ESP) actuation due to the system design and required test procedure. Additionally, working with these detectors has shown that the equipment is easily damaged while performing the surveillance. It is GSU's opinion that even if the calibration could be completed without a RPS or ESF actuation, the signal cable connectors of at least one of the detectors would be damaged. In this case, repair would generally take approximately six to eight hours with a corresponding half scram and half isolation for four to six hours as required by Technical Specifications.

Isolation actuations from MSLRH are not used for inputs to the 10CFR100 calculations. No practical credit is taken for the Main Steam Isolation Valve (MSIV) closure as a result of the detectors. The Control Rod Drop Accident (CRDA) Analysis takes no credit for the MSLRH instrumentation in the design (licensing) basis, but relies on the Neutron Monitoring System (APRM) which senses a neutron high flux and issues the scram logic trip signals. No credit for this instrumentation is taken in any other FSAR analysis. FSAR Appendix 15A, Nuclear Safety Operational Analysis (NS0A), presents the MSLRH isolation actuation as part of a comprehensive, best estimate analysis. Extension of the calibration frequency to the first cycle refueling outage has been evaluated by CSU with vendor concurrence and found not to reduce the margin of safety as previously analyzed.

A Logic System Functional Test (LSFT) is required by Technical Specification Sections 4.3.1.2 and 4.3.2.2. This ISFT is accomplished, in accordance with RG 1.118 and Institute of Electrical and Electronic Engineers (IEEE) 338-1977, by overlap testing with the channel calibration from the detector to the logarithmic radiation monitor (LRM). The LSFT will input a test signal to each channel and verify that the scram pilot solenoid valves status lights and the main steam line pilot solenoid status lights operate and that the reactor water sample logic de-energizes. This test will confirm the scram, main steam isolation and reactor sample line isolation signals are available.

The surveillance interval was analyzed probabilistically for the effects of an extension from 18 months to 24 months on MSIV Isolation and RPS logic systems and was found by GSU to not result in any appreciable increase in the probability for failure. Both the MSIV isolation logic and the RPS logic implement "one out of two taken twice" and " fail-safe" (trip) logic design for a high degree of reliability. A downscale or

inoperative trip circuit for each LRM actuates the RPS and MSIV trip logic signals and an instrument trouble alarm. The results of an industry Nuclear Plant Reliability Data System (NPRDS) data search also indicated a very low probability for equipment failures with regard to manual switches and auxiliary relays during the requested extension to the surveillance period.

GSU will perform a monthly channel functional test on the portion of the instrument loop that may exhibit instrument related drift, the logarithmic radiation monitors. A review of the present operation indicates that all LRMs are operational and within calibration. LRM calibration was necessary only 8 times during the past 48 channel functional tests covering the recent 12 months.

A review of the RBS SER and FSAR, the SRP, and applicable IEEE standards indicates that the extension to the surveillance period is within the criteria. The instruments and system design are not sensitive to this change and the performance of the system and its components remains consistent with the design bases and the FSAR.

SIGNIFICANT IUiZARDS CONSIDERATION As discussed in 10CFR50.92, the following is provided to the NRC in support of a "no significtnt hazards considerations".

1. No significant increase in the probability or the consequences of an accident previously evaluated results from this change because:

The system design, function and configuration are not changed or affected. The detector channels cor.tinue to be checked each shift. This check will identify any drift or degradation of the system. Drift associated with the detector would be insignificant when compared to the radiation levels associated with a failed fuel event. The logarithmic radiation monitor, which is the primary source of drift will continue to receive the current 30 day surveillance testing. With the change in the surveillance interval for the MSLRH isolation actuation instrumentation, the loop remains fully operable and responds with the necessary accuracy to detect high radiation and initiate an isolation actuation. There is no significant increase for the probability of failure of the tested components with the change to the surveillance interval. There is no increase in the probability or consequences of an accident previously evaluated because the system will continue to respond as designed.

2. This change would not create the possibility of a new or different kind of accident from any accident previously evaluated because:

The design response of the instrumentation and the system remains the same and is unaffected. No change is made in the design operation or configuration of the instrumentation therefore, previous analysis and evaluations remain valid. No credit is taken for the MSLRH instrumentation in any design basis FSAR analysis.

3. This change would not involve a significant reduction in the margin of safety because:

The functional response of the system will remain as designed during the extended surveillance period because of the redundant design and the reliability of the components. As discussed in the justification above, the detectors have been found to not drift a significant amount during this extended surveillance period and will continue to receive functional testing each month of operation. A review of the equipment design, FSAR and SER commitments, and system performance requirements has confirmed the surveillance extension is within the component capability and does not conflict with present system requirerents. Since the design and performance is not sensitive to the requested change and the response of the system will remain as designed and as described in the safety analysin report the margin of safety has not been significantly reduced.

The proposed amendment, as discussed above, has not changed the system design, function and operation centained in the FSAR and therefore will not increase the probability or the consequences of a previously evaluated event and will not create a new or different event. Also the results of the change are clearly within all acceptable criteria with respect to system components and design requirements, no a result the ability to perform as described in the FSAR is maintained and therefore the proposed change does not result in a significant reduction in the margin of safety. GSU proposes that no significant hazards considerations are involved.

REVISED TECHNICAL SPECIFICATION As indicated above, River Bend Station is currently in compliance with the applicable Technical Specification. This Technical Specification revision is required prior to September 3, 1987 to avoid a unit outage to conduct the required surveillance test discussed above.

NOTIFICATION OF STATE PERSONNEL A copy of the amendment application and this submittal has been provided to the State of Louisiana, Department of Environmental Quality - Nuclear Energy Division.

ENVIRONMENTAL IMPACT APPRAISAL Revision of this Technical Specification does not result in an environmental impact beyond that previously analyzed. Therefore, an approval of this amendment does not result in a significant environmental impact nor does it change any previous environmental impact statements for River Bend Station.

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^- 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OFERATION 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 Mini-mum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel (s) and/or that trip system in the tripped condition

• within one hour. The provisions of Specification 3.0.4 are not applicable.

b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requiremint 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. ,

SURVEILLANCE REQUIREMENTS r

4.3.1.1 Each reactor protection system instrumentation channel shall be demon-strated 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 4.3.1.1-1.

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

4.3.1.3 The REACTOR PROTECTION SYSTEM RESPONSE TIME of each reactor trip functional unit shown in Table 3.3.1-2 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel par 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.

• • 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 ,

j 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' l on table 4.3.1.1-1. -

nturn nrun - ilNIT 1 _ _3/4 3-1 l

TABLE 4.3.1.1-1 B

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS g

CHANNEL OPERATIONAL 5 CHANNEL FUhCTIONAL- CHANNEL CONDITIONS IN WHICH E TEST CALIBRATION (,) SURVEILLANCE REQUIRED

, FUNCTIONAL UNIT CHECK b 1. Intermediate Range Monitors:

-* a. Neutron Flux - High S/U,5,(b) S/U(c) ,W R 2

• 5 W R 3,4,5 Inoperative NA W NA 2,3,4,5 b.

2. Average Power Range Monitor: II)

a. Neutron Flux - High, S/U S,(b) S/U(C),W SA 2 W SA 3,4,5 Setdown S W Id)I') , SA, R II) m b. Flow Biased Simulated IC) ,W 1 Thermal Power - High 5,D(h) S/U 1

Neutron Flux - High S/U(c) ,y y(d) , SA 1 4 c. S W NA 1,2,3,4,5

d. Inoperative NA

3. Reactor Vessel Steam Dome R I91 - 1, 2 II)

Pressure - High S M

4. Reactor Vessel Water Level - I9) 1, 2 M R Low, Level 3 S ..

5. Reactor Vessel Water Level - R(9) 1 High, Level 8 S M

6. Main Steam Line Isolation R 1 Valve - Closure NA M

7. Main Steam Line Radiation -

M

~

R (P) y,p(j) l High S M R f9) 1, 2(I)

8. Drywell Pressure - High 5

~

i TABLE 4.3.1.1-1 (Continued)

$ REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS E

, =

I

$ (f) The LPRMs shall be calibrated at least once per 1000 effective full power hours (EFPH) using,.1he.JIP system. - .

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

5 (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 to be less -

than 6.6 seconds.

I (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 3.9.10.2.

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

(a) Verify the Turbine Bypass Valves are closed when THERMAL POWER is greater than or equal to 40% RATED N THERMAL POWER.

[ (n) The CHANNEL FUNCTIONAL TE!! and CHANNEL CALIBRATION shall include the turbine first stage pressure l

instruments. .

(o) The CHANNEL CALIBRATION shall exclude the flow reference transmitters; these transmitters shall be calibrated at least once per 18 months.

1 (p) This period may be extended to the first refueling outage, not to exceed 9-15-87.

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.E N

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

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 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 isolation trip system.

• Isolation System Response Time and Logic System Functional testing period may be extended as identified by notes C and D on Table 4.3.2.1-1.

RIVER BEND - UNIT 1 3/4 3-11

TABLE 4.3.2.1-1 5 .

g ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS

=

g CHANNEL OPERATIONAL i

g CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH

, TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED l

h 1. PRIMARY CONTAINMENT ISOLATION

[ a. Reactor Vessel Water Level -

Low Low Level 2 S M R(b) 1,2,3

b. Drywell Pressure - High S M R(b) 1, 2, 3

c. Containment Purge Isolation j Radiation - High S M R 1, 2, 3

2. MAIN STEAM LINE ISOLATION f

l m a. Reactor Vessel Water Level - )

Low Low Low Level 1 5 M R 1, 2, 3

}

iw b. Main Steam Line Radiation -

h High 5 M R(c) 1, 2, 3 i c. Main Steam Line Pressure - I) l Low S M R 1

d. Main Steam Line Flow - High 5 M . . . R I) , 1, 2, 3

e. Condenser Vacuus - Low S M R( } 1, 2**, 3**

l f. Main Steam Line Tunnel i Temperature - High S M R ,,

1, 2, 3 i g. Main Steam Line Tunnel a Temperature - High S M R 1, 2, 3 j

I 1, 2, 3

h. Main Steam Line Area S M R Temperature-High i (Turbine Building) i .

l

)

l I

1

TA8LE 4.3.2.1-1 (Continued)

B ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CHANNEL CONDITIONS IN WHICH CHANNEL FUNCTIONAL 5 CHECK TEST CALIBRATION SURVEILLANCE REQUIRED

. TRIP FUNCTION E 6. RHR SYSTEM ISOLATION O a. RHR Equipment Area Ambient 1, 2, 3 Temperature - High S M R

b. RHR Equipment Area 1, 2, 3 M R a Temperature - High S

c. Reactor Vessel Water Level -

Low Level 3 5 M R(b) 1, 2, 3

d. Reactor Vessel Water Level - ~

IDI 1, 2, 3 Low Low Low Level 1 S M R

e. Reactor Vessel (RHR Cut-in I 1, 2, 3 Permissive) Pressure - High 5 M w

5 M R(DI R

b) 1, 2, 3 1 f. Drywell Pressure - High M MA 1, 2, 3

7. MANUAL INITIATION NA

• 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.

(c1 May be extended to the first refueling outage, not to exceed 9-15-87.

ATTACHMENT 3 GULF STATES UTILITIES COMPANY RIVER BEND STATION DOCKET 50-458/ LICENSE NO. NPF-47 ELECTRICAL POWER SYSTEMS /

A.C. SOURCES LICENSING DOCUMENT INVOLVED: TECHNICAL SPECIFICATIONS ITEMS: 1. 4.3.2.2 PAGE 3/4 3-11

2. 4.3.3.2 3/4 3-30

3. 4.3.3.3 3/4 3-30 ,

4. 4.3.9.2 3/4 3-107 '

5. 4.5.1 3/4 5-4 l 6. 4.6.3.2 3/4 6-29 l 7. 4.6.4.2 3/4 6-31 l

8. 4.6.5.3 3/4 6-52

9. 4.6.5.4 3/4 6-55 l 10, 4.6.5.5 3/4 6-57 3/4 6-59,60

11. 4.6.5.6

12. 4.7.1.1 3/4 7-2

13. 4.7.2 3/4 7-6

14. 4.8.1.1 3/4 8-6,7,8,9 REASON FOR REQbEST:

kiver Bend Station (RBS) Technical Specifications requires that surveillance test procedures 309-0601 (0602), Division I(II) 18 month Emergency Core Cooling Systems (ECCS) Tests, be performed at an 18 month interval with the provisions of specification 4.0.2 allowed to extend the surveillance time interval by an additional 25%. With the survefilances having been performed last in October 1985, the expiration time for performance, as required by technical specifications, occurs in August 1987. To preclude an unscheduled shutdown to perform these tests, it is requested that the Technical Specifications associated with performance of these two surveillances (the enclosure contains the affected Technical Specifications) be extended on a one time bases until completion of the first refueling outage; currently scheduled to commence on September 15, 1987.

A one-time change is being requested in accordance with 10CFR50.92.

Culf States Utilities (CSU) has and will make a good faith effort to conduct this surveillance on the current frequency if an outage of sufficient duration occurs. In order to test this component, the plant must be in a shutdown condition. To require the plant to shutdown solely to perform surveillances would cause an unnecessary thermal transient on the plant. GSU requests to amend the subject Technical Specifications contained in Appendix A to the River Bend Station (RBS)

Operating License, as discussed below, to perform th) subject test during a scheduled refueling outage. Should these proposed changes not be granted in a timely manner, CSU will be forced to implement an unplanned outage during the first cycle.

DESCRIPTION As is typical in the industry for first cycle plants, the requirement for a power ascension test program and the need for more frequent outages to repair unexpected material or design problems, causes the first cycle to extend beyond the nominal 18 months. This station has experienced these type problems and, therefore requests a one-time relief from the current specification requirements so as to maximize utilization of fuel and to minimize required outage time. As will be shown in the following pages, the request for a one time extension can be justified by both an extensive test program conducted prior to commercial operation (June 1986) as well as frequent performance of other surveillances currently being conducted. GSU does not consider the requested extensions to the Technical Specifications in the Enclosure to pose a significant hazards.

The affected surveillance test are described as follows:

(1) 4.3.2.2 Table 4.3.2.1-1, Items 6.d and 6.f (Partial)

For the Isolation Actuation Instrumentation, Logic System Functional tests and simulated automatic operation of all channels shall be performed at least once per 18 months.

6.d. Reactor Vessel Water Level - Low Low Low Level 1 6.f. Drywell Pressure - High For the following valves:

6.f. IE12*MOVF024A lE12*MOVF024B IE12*MOVF0llA lE12*MOVF011B IE21*MOVF012 lE12*MOVF021 IE12*MOVF037A 1E12*MOVF037B (2) 4.3.3.2 Logic System Functional Tests and simulated automatic operation of all channels shall be performed.

Table 4.3.3.1-1, Item A.1 DIV 1 TRIP SYSTEM LPCI MODE AND LPCS SYSTEMS

n. Reactor Vessel Water Level - Low Low Low Level i

b. Drywell Pressure - liigh

c. LPCS Pump Discharge Flow - Low

d. Reactor Vessel Pressure - Low

e. LPCI Pump A Start Time Delay Relay

f. LPCI Pump A Discharge Flow - Low

g. LPCS Pump Start Time Delay Relay

h. Manual Initiation

l' Table 4.3.3.1-1, Item B.1

DIVISION II TRIP SYSTEM LPCI B AND LPCI C SYSTEMS

a. Reactor Vessel Water Level-Low, Low, Low, Level 1

! b. Drywell Pressure - High

c. Reactor Vessel Pressure - Low

d. LPCI Pump B Start Time Delay Relay

e. LPCI Pump Discharge Flow - Low

f. LPCI Pump C Start Time Delay Relay

g. Manual Initiatica Table 4.3.3.1-1, Item D.1 DIVISION I AND DIVISION II LOSS OF POWER

a. 4.16 Kv Standby Bus Undervoltage (Sustained Undervoltage)

b. 4.15 Kv Standby Bus Undervoltage (Degraded Voltage) l (3) 4.3.3.3 The ECCS RESPONSE TIME of each ECCS trip function shall be

! demonstrated to be within the limit. Each test shall include at l least one channel per trip system such that all channels are tested at least once per every N times 18 months where N is the total number of redundant channels in a specific ECCS trip aystem.

1. LOW PRESSUkE CCRE SPRAY SYSTEM

, 2. LOW PRESSURE COOLANT INJECTION MODE OF RHR SYSTEM

a. Pumps A and B

b. Pump C l

(4) 4.3.9.2 Table 4.3.9.1-1. Items 1.a and 1.c Logic System Functional Tests and simulated automatic operation of all channels shall be performed.

i l PRIMARY CONTAINMENT VENTILATION SYSTEM - UNIT COOLER A and B j a. Drywell Pressure - High ,

c. Reactor Vessel Water Lesel - Low Low Low Level 1 l (5) 4.5.1 l

For the LPCS pump, LPCI A pump, LPCI B pump, and LPCI C pump, perform a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verify that each automatic valve in the flow path actuates to its correct position. Actual injection of coolant into the reactor vessel may be excluded from this test.

l

(6) 4.6.3.2.c At least once per 18 months the Containment Unit Coolers shall be demonstrated OPERABLE by performance of a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each pressure relief and backdraft damper in the flow path actuates to its correct position.

(7) 4.6.4.2 Table 3.6.4-1 (Partial)

Each automatic isolation valve per Table 3.6.4-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING by verifying that, on an isolation test signal, each automatic isolation valve actuates to its isolation position.

(8) 4.6.5.3.b Each secondary containment ventilation system automatic isolation damper shown in Table 3.6.5.3-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING by verifying that on a containment isolation test signal, each isolation damper actuates to its isolation position.

(9) 4.6.5.4, Items d.1.a and d.3.b d.1.a - Each standby gas treatment system shall be demonstrated OPERABLE by performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for a Loss of Coolant Accident (LOCA).

d.3.b -

Each standby gas treatment system shall be demonstrated OPERABLE by verifying that the filter train starts and isolation dampers open on a simulated automatic initiation signal.

(10) 4.6.5.5, Items b.1.a and b.3.b b.1.a - Each Shield Building Annulus Mixing subsystem shall be demonstrated OPERABLE by performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operation sequence for the LOCA.

b.3.b Each Shield Building Annulus Mixing subsystem shall be demonstrated OPERABLE by verifying the subsystem starts and isolation dampers open on a simulated automatic initiation signal.

(11) 4.6.5.6, Items e.l.a and e.3.b e.l.a - Each Fuel Building Ventilation Charcoal Filtration subsystem shall be demonstrated OPERABLE by performing a system functionni test which includes simulated automatic actuation of the system throughout its emergency operating sequence for a LOCA.

l l

l I

e.3.b - Each Fuel Building Ventilation Charcoal Filtration subsystem shall be demonstrated OPERABLE by verifying that the subsystem starts and isolation dampers actuate to isolate the normal flow path and to divert flow through the charcoal filters on a simulated automatic initiation signal.

(12) 4.7.1.1.b The Standby Service Water subsystem shall be demonstrated OPERABLE by verifying that each automatic valve actuates to the correct position and each pump starts on a normal service water low pressure signal.

(13) 4.7.2.e.2.a Each Main Control Room Air Conditioning subsystem shall be demonstrated OPERABLE by verifying that on a LOCA emerger.cy mode actuation test signal, the subsystem automatically switches to the emergency code of operation, the isolation valves close within 30 seconds, and the control room is maintained at a positive pressure relative to the outsfde atmosphere during subsystem operation at a l flow rate less than or equal to 4,000 CFM.

(14) 4.8.1.1.2, Item f 2.f.2 - Verifying the diesel generator's capability to reject a load of greater than or equal to 917.5 Kw while maintaining engine speed less than nominal plus 75% of the difference between nominal speed and the overspeed trip setpoint or 15% above nominal, whichever is less.

2.f.3 - Verifying the diesel generator's capability to reject a load of 3030-3130 Kw without tripping. The generator voltage shall not exceed 4784 volts during and following the load rejection.

2.f.4.a.1 -

Simulating a loss of offsite power itself and verifying de-energization of the emergency busses and load shedding from the emergency busses.

2.f.4.a.2 -

Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto connected loads through the sequencing logic and operates for greater than or equal to 5 minutes while its generator is loaded with the loads. After energization, the study state voltage and frequency of the emergency busses shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

2.f.5 - Verifying that on an ECCS actuation test signal, without loss Of offsite power, the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to 5 minutes. The generator voltage and frequency shall be

4160 1 470 volts and 60 1 1.2 Hz within 10 seconds after the auto-start signal; the steady state generator voltage and frequency shall be maintained within these limits during this test.

2.f.6.a - Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:

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

2. Verifying the diessi generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto connected loads through the sequencing logic and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 1 420 volts a and 60 1 1.2 Hz during this test.

2.f.7 - Verifying that all automatic diesel generator trips are automatically bypassed upon an ECCS actuation test signal except:

a. Engine Overspeed

b. Generator Differential Current 2.f.9 -

Verifying that the auto-connected loads to Diesel Generator 1A and IB do not exceed 3130 Kw.

2.f.10 - Verifying the Diesel Generator 1A and IB capability to:

Synchronize with the offsite power source while the generator is loaded with its emergency locds upon a simulated restoration of offsite power.

Transfer its loads to the offsite power source and be restored to its standby status.

2.f.11 - Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by:

a. returning the diesel generator to standby operation and

b. automatically energizes the emergency loads with offsite power.

2.f.12 - Verifying that the automatic load sequency timers- are OPERABLE with the interval between each load block within i 10% of its design interval for Diesel Generator 1A.

The Division I and Division 11 18 month ECCS surveillance tests involve testing the ability of the plant's safety related systems to respond to a Loss of Offsite Power (LOP), to a LOCA and to a combined LOP /LOCA.

Division III's response to these same events will not require a surveillance extension since it has been determined that this division can be tested without requiring a plant outage. Also, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> full load testing of the Division I and II Diesel Generators which are included in these surveillances will not require a surveillance time extension. This testing was recently completed in September and October of 1986. Included in the surveillances as a part of the LOP /LOCA testing to be extended are the measured responses of vital bus loading and load shedding, diesel full load rejection, times for system initiations, verification of system isolations and initiations, and partial satisfaction of Logic System Functional Tests for ECCS and Plant Isolation / Initiation Instrumentation. It should be noted, however, that during performance of Startup Test (ST)-31 (Loss of Offsite Power Test) during the power ascension test phase, load sequencing and load shedding was verified for numerous items that are included in the 18 month ECCS test. In addition, no loads have been added since the last test performance to the vital busses; hence the diesels are not expected to exceed the 3130 KW maximum load capacity listed in Technical Specifications. Control Room Ventilation performance data listed in the Technical Specifications requiring extension should also not be expected to change due to the passive nature of the building structure. These requirements include maintaining ccntrol building pressure at greater than 1/8 inch pressure with ventilation flow less than 4000 CFM. The Technical Specification bases do not discuss the frequency of these surveillance tests. Discussions in both the Final Safety Analysis Report (FSAR) and Safety Analysis Report (SER) identify the need to test ECCS at 18 months to ensure reliability of performance in meeting General Design Criteria 37. When these items are included with the previously mentioned indepth testing, the risk factors associated with allowing an extension in the performance of these surveillances is insignificant.

PREVIOUS TEST HISTORY Prior to commercial operation (June 16, 1986), this station underwent a period of extensive testing the response for the ECCS systems included in the surveillances for which an extension has been requested.

Starting in April 1985, after individual preoperational ECCS system testing was completed in accordance with the requirements of Regulatory Guide 1.68, a major integrated preoperational ECCS test was conducted that involved actual simulation of a series of design bases accidents including a complete station Loss of Offsite Power (LOP), a simulated Loss of Coolant Accident (LOCA) and a concurrent LOP /LOCA to all three safety related ECCS divisions. This was a once-per-plant-life test requiring all three ECCS divisions to respond simultaneously with actual injection into the vessel. Also included in the test was a challenge to the ECCS systems with a safety division in a complete de-energized / inoperable status as well as a test measuring the response of the safety divisions battery capacity under design LOP /LOCA conditions. With the exception of the Regulatory Guide 1.41 position to test redundant on-site electrical power sources for proper load group

assignments, there was no regulatory requirement 'to test the ECCS systems under the conditions tested in the integrated ECCS test pre-op.

Other test procedures were conducted during this same time frame to verify other paths which could result in full scale ECCS initiations.

Included in these tests was the diesel generators' response to a LOCA condition when in a surveillance mode as well as a test that demonstrated the plant's response to load shedding and load sequencing under LOP /LOCA conditions.

As a result of industry experience, extensive modifications were performed to reassign the Division I and II Emergency Diesel load group and sequencing assignments on the safety related divisions in an effort to reduce the loading on the diesels. In addition to the extensive inspections that followed, another test was conducted during the summer of 1985 after the load grcuping modifications was completed. This verified the divisional independence (Regulatory Guide 1.41) and also that the maximum loading on the Division I and II diesels was below the newly established limit of 3130 KW. From August to October 1985 the surveillances that are being requested for extension were performed to satisfy the technical specification requirements for entry into an operational mode to allow fuel loading and initial criticality.

During the power ascension test program a Loss of Offsite Power Test was conducted (December 1985) to satisfy Regulatory Guide 1.68 positions (with reactor power at 10 to 20 percent). This test demonstrated the plant response to a Main Generator Load Reject concurrent with a Loss of Offsite Power. The expected frequency of an event simulated by this test is classified as an " incident of moderate frequency"; or as an

" expected operational transient" (occurring once in a one to twenty year cycle). The plant demonstrated its response during this test with all equipment, including the three emergency diesels, responding as designed with no major equipment failures or damage (A " level one failure" did result due to a chilled water pump failing to start. This was later dispositioned as acceptable since the pumps failure to start was attributed to the redundant divisions chill water pump already being sensed as running).

On January 1, 1986 this station experienced an unexpected complete Loss of Offsite Power. The event was later attributed to actuation of the tonal relay transfer trip system (a redundant protective trip system for the Main, Preferred and Normal Station breakers) most probably induced by operation of a hand-held radio transmitter. Extensive corrective action was taken to prevent a recurrence of this event (see LER 86-002, Attachment 2, for details of actions taken). The relevant aspect of this event however, is that all plant systems responded as designed including all three Emergency Diesels which started and carried the vital busses for the duration of the LOP. Some equipment failures occurred during this event: A power line conditioner fuse blew which de-energized a 120 VAC distribution panel. This prevented the Division I Control and Fuel Building ventilation systems from starting. The problem was later extensively investigated and modifications to all power line conditioners at this plant have been made to prevent a recurrence.

The challenges made to this station's ECCS systems has been quite extensive as evidenced by the indepth testing during the preoperational and power ascension test phase and as evidenced during the site LOP of January 1986. The response to these challenges and tests by the plants systems has been more than adequate and has given the operating staff of this station confidence in these systems response to any required demand for operation.

In addition to the extensive testing conducted prior to commercial operation, there is a considerable amount of testing that continues to be conducted to meet the Technical Specification System / Component requirements for operability. Some of this testing includes performance of channel checks, channel calibrations, and response time measurements for all ECCS and Plant Isolation / Initiation Instrumentation. In addition, partial Logic System Functional Tests are performed simulating LOP /LOCA conditions to verify response of relaying required for initiations and isolations for many of these same instruments.

Quarterly Inservice Inspection Pump and Valve tests are performed to measure pump and valve performance in accordance with Section 4.0.5 of Technical Specifications and ASME Code XI. These tests determine a pump or valve's ability to perform to design conditions and will cause an item that shows a trend toward sudden degradation to be tested on a more frequent bases to ensure its continued operability. All of the ECCS injection and spray systems are tested in this fashion. Similar testing occurs for HVAC equipment required for safe shutdown and includes monthly operability checks on such components as Standby Gas Treatment, Annulus Mixing, Containment Unit Coolers, Fuel Building Ventilation, and Control Building Ventilation. The Division I Diesel Generator, having shown a questionable start reliability, has had an increase in its surveillance frequency such that it is now tested weekly. Division II Diesel Generator however, continues to be tested monthly. These tests include starting the diesels from a standby condition and measuring its ability to come up to fully rated speed and voltage in a strict time requirement. The diesels are then fully loaded for at least one hour and monitored for system leaks and performance. The result of this testing is that all systems required to support the plant during a LOP or LOCA are maintained in a maximum state of readiness exclusive of the 18 month ECCS tests. The reliability of these systems due to surveillance testing are greatly enhanced in their ability to perform in such an event.

As was stated earlier, a LOP event is classified as an " expected operational transient"; an event that actually occurred during this operating cycle (See LER-86-002). The systems required to support safe shutdown of the plant during that event performed well. The cause for initiating the event has been corrected reducing considerably the probability of a recurrence. A LOCA event however, is described as a limiting fault. This is an incident that is not expected to occur but is postulated because the consequences may result in the release of significant amounts of radioactive material. This type of event is referred to as a " design basis (postulated) accident". The probability of the occurrence of such an event is given as less than one tenth of one percent over a 40 year cycle of the plant. This low probability is based on leak detection syster, which would reveal a crack in any pire

before it propagates to a size which could cause through-wall fracture.

In addition, the inservice material inspection program that exists at this station is designed to locate and prevent faults that are above an allowable size from propagating or threatening the ability of lines to handle large loads.

An indepth series of preoperational and power ascension testing was only recently completed by the licensee. As was earlier described, the ECCS systems were thoroughly tested and performed well under all forms of test conditions designed to ensure adequate core cooling under the most limiting conditions. In addition, an extensive system of surveillance testing exists to ensure operability and to measure performance of systems that are tested in the 18 month ECCS test.

The low probability of occurrence of an event such as a LOP /LOCA when coupled with the re31 ability of the systems designed to minimize the effects of such an event, as proven during the test program, removes the possibility of causing a significant hazards concern by extending the Division I and II 18 month ECCS surveillances to the end of the first refueling. Failure to be provided relief to extend these surveillances will force an extended early outage because of having to perform these surveillances in a shutdown condition.

SIGNIFICANT RAZARDS CONSIDERATION As discussed in 10CFR50.92, the following discussions are provided to support the NRC Staff in its determination of "no significant hazards considerations".

1. No significant increase in the probability or the consequences of an accident previously evaluated results from this change because:

Previous testing recently conducted at this facility during the preoperational test phase and during the power ascension test phase demonstrated indepth, the reliability and performance capability of the ECCS systems during various initiating modes of a LOP /LOCA event. In addition, an extensive surveillance program exists at this plant to demonstrate continued operability and performance of the ECCS systems required to mitigate the occurrence of such an event. Due to the reliability proven by the previous testing and the continued proven operability obtained by frequent ongoing surveillance testing, extension of the 18 month ECCS surveillances will not result in a significant increase in the probability or consequences of a LOP /LOCA event.

2. This change would not create the possibility of a new or different kind of accident from any accident previously evaluated because:

This change allows one time extension in the allowed interval for which the surveillance is to be performed. This extension therefore, does not introduce a new mode of operation. Since no new or different kinds of accidents are introduced by extending the surveillance interval, then the possibility ot creating an accident not previously evaluated does not exist.

'3. 'This change would not involve a significant reduction in the margin of safety because:

The demonstrated reliability caused by recently conducted testing during the start-up phase of this plant, as well as extensive ongoing surveillance testing designed to determine operability and to measure performance of ECCS systems, ensures a margin of safety is maintained to offset the effects that would be caused if a LOP /LOCA event occurred. In addition, recent changes made to the plants protective tonal trip system resulting from the January 1986 LOP event, has reduced significantly the possibility of a similar event happening again. A LOCA event, being classified as a limiting fault condition, maintains a probability of less than one tenth of one percent chsnce of occurring over the 40 year cycle of this plant. Leak detection systems and ISI inspection programs exist to detect and prevent pipe and vessel failures which could allow a LOCA event to occur. Extending the performance date of the 18 month ECCS surveillance until after commencement of refueling would therefore, not impose a measurable reduction in the margin of safety.

This change is not considered, as stated above, to increase the probability or consequences of a previously analyzed accident or reduce safety margins; further the results of the change are clearly within all acceptable criteria with respect to the system or components specified.

The basis for this conclusion is the requested frequency will not effect the ability of the system to perform as discussed in the justification.

Therefore, the criteria for system performance as discussed in the FSAR have not been affected.

Since the proposed amendment does not change any previously revised and approved description or analysis described in the FSAR, the proposed amendment does not create the possibility of a new or different type of accident, and the proposed change does not involve a significant reduction in a margin of safety. GSU proposes that no significant hazards considerations are involved.

REVISED TECHNICAL SPECIFICATION The requested revision is provided in the Enclosure.

SCHEDULE FOR ATTAINING COMPLIANCE As indicated above, River Bend Station is currently in compliance with the applicable Technical Specification. This Technical Specification revision is required prior to August 1987 to avoid a unit outage to conduct the required surveillance test as discussed above.

NOTIFICATION OF STATE PERSONNEL A copy of the amendment application and this submittal has been provided to the state of Louisiana, Department of Environmental Quality - Nuclear Energy Division.

ENVIRONMENTAL IMPACT APPRAISAL Revision of this Technical' Specification does not result' in an environmental impact. beyond that previously analyzed. Therefore, the approval of this amende;ent ~ does not result in a significant environmental impact nor does it change any previous environmental f impact statements for River Bend Station.

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ENCLOSURE I

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l INSTRUMENTATION guRVEILLANCEREQUIREMENTS 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.

4.3.2.2 LOGICSYSTEMFUNCTIONALTESTSandsimulatedautema}icoperationof all channels shall be performed at least once per 18 months.. l 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 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 isolation trip system. .

m

• Isolation System Response Time and Logic System Functional testing period may be extended as identified by notes C and D on table 4.3.2.1-1. .

RIVER BEND - UNIT 1 3/4 3-11 _

') D

)

TABLE 4.3.2.1-1 (Continued)

M ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL E CHANNEL CONDITIONS IN WHICH FUNCTIONAL 5 CHANNEL CHECK TEST CALIBRATION SURVEILLANCE REQUIRE 0

. TRIP FUNCTION E 6. RHR SYSTEN ISOLATION Z a. RHR Equipment Area Ambient Temperature - High S M R 1,2,3 s

I b. RHR Equipment Area a Temperature - High S M R 1,2,3

c. Reactor Vessel Water Level -

Low Level 3 S M R IU) 1, 2, 3

d. Reactor Vessel, Water Level - R(byd) '

5 M 1, 2, 3 Low Low Low Level 1

e. Reactor Vessel (RHR Cut-in 1, 2, 3 w Permissive) Pressure - High S M R byd)

Drywell Pressure - High 5 M R 1,2,3 i f.

NA M NA 1,2,3

7. MANUAL INITIATION J

• When handling irradiated fuel in the Fuel duilding.

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

(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.

(d) May be extended to the completion of the first refueling outage.

1

INSTRUMENTATION, 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 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.

ACTI0tp

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 consistent with the Trip Setpoint value. '

b. WithonebrmoreECCSactuationinstrumentationchannelsinoperable, 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 REQUIREMENTS 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.

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

4.3.3.3 At least once per 18 months',# the ECCS RESPONSE TIME of each ECCS trip b 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 l-channels are tested at least once every N times 18 month Pwhere N is the total i number of redundant channels in a specific ECCS trip system.

1. 1. Logic System Functional and ECCS Response time testing period may be extended as identified by note C on Table 4.3.3.1-1.

RIVER BEND - UNIT 1 3/4 3-30

TABLE 4.3.3.1-1 1

i iS

< EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQU~

E CHANNEL OPERATIONAL

, g CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH g CHECK _ TEST CALIBRATION SURVEILLANCE REQUIRED

, TRIP FUNCTION h A. DIVISION I TRIP SYSTEM

• 1. RHR-A (LPCI MODE) AND LPCS SYSTEM w a. Reactor Vessel Water Level - (c) 1, 2, 3, 4*, 5*

Low Low Low Level 1 S M R((,,))(c) 1, 2, 3

b. Drywell Pressure - High S M R(,)(c) 1, 2, 3, 4*, 5*

l

c. LPCS Pump Discharge Flow-Low S M R(,)(c) 1,2,3,4*,5*

l S M R l d. Reactor Vessel Pressure-Low (LPCS/LPCI Injection Valve l

Permissive)

e. LPCI Pump A S, tart Time Delay 1, 2, 3, 4*, Sa NA M Q(,)((C) w Relay M R Cl 1,2,3,4*,5*

LPCI Pump A Discharge Flow-Low 5 1, 2, 3, 4*, 5*

} f.

M Q (C)

LPCS Pump Start Time Delay NA m

g.

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

NA R(c) l 0 h. Manual Initiation

! 2. AUTOMATIC DEPRESSURIZATION SYSTEM

! TRIP SYSTEM " A"#

Reactor Vessel Water Level -

a. 1, 2, 3 I

i Low Low Low Level 1 S M M

R((**))

R 1, 2, 3 Drywell Pressure-High S

b. Q 1,2,3 NA M

c. ADS Timer

d. Reactor Vessel Water Level - M R("I 1,2,3 i

5

' Low Level 3

e. LPCS Pump Discharge M

R(,) 1,2,3 Pressure-High S

f. LPCI Pump A Discharge M

R ,) 1, 2, 3 Pressure-High S 1,2,3 NA M Q

g. ADS Drywell Pressure Bypass .

Timer NA 1,2,3 NA M 1,2,3

h. ADS Manual Inhibit Switch R NA NA

1. Manual Initiation

TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS 5 CHANNEL OPERATIONAL 5 CHANNEL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH e TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED B. DIVISION II TRIP SYSTEM

" 1.

4 RHR B AND C (LPCI MODE)

a. Reactor Vessel Water Level -

Low Low Low Level 1 S M R(a)(c) g 1, 2, 3, 4*, 5*

b. Drywell Pressure - High S M R(,))

a (c1(c) le 2. 3

c. Reactor Vessel Pressure-Low S M R 1, 2, 3, 4*, 5*

(LPCI Injection Valve Permissive) .

J

d. LPCI Pump B Start Time Delay Iw Relay NA M 1, 2, 3, 4*, 5*

2 e. LPCI Pump Discharge Flow-Low S M Q(a)((c)

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

w f. LPCI Pump C Start Time Delay NA M Q (c) 1, 2, 3, 4*, 5*

1 1

Relay 1, 2, 3, 4*, 5*

g. Manual Initiation NA R (C) NA

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#

, a. Reactor Vessel Water Level -

Low Low Low Level 1 M y, p, 3

b. Drywell Pressure-High S

S M R((a)

R a) 1, 2, 3

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. LPCI Pump B and C Discharge Pressure-High S M Rg ,) 1,2,3

f. ADS Drywell Pressure Bypass .

Timer NA M Q 1,2,3 NA 1, 2, 3

g. ADS Manual Inhibit Switch NA M .

i

h. Manual Initiation NA R NA 1,2,3 i

i

-(c) M y be extended to the completion of the first refueling outage.

TABLE 4.3.3.1-1 (Continued) h EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS E CHANNEL OPERATIONAL FUNCTIONAL CHANNEL CONDITIONS FOR WHICH g CHANNEL TEST CALIBRATION SURVEILLANCE REQUIRED g TRIP FUNCTION CHECK

[ C. DIVISION III TRIP SYSTEM h 1. HPCS SYSTEM H a. Reactor Vessel Water Level - 1, 2, 3, 4*, 5*

Low Low Level 2 S M R Drywell Pressure-High S M R 1,2,3 b.

c. Reactor Vessel Water Level-High M R(*) 1, 2, 3, 4*, 5*

Level 8 S

d. Condensate Storage Tank Level -

S M R(*) 1, 2, 3, 4*, 5*

Low

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

I Level - High S M R w M R 1, 2, 3, 4* , 5*

y f. Pump Discharge Pressure-High S g) 1, 2, 3, 4*, 5*

a HPCS System Flow Rate-Low 5 M R g g. 1, 2, 3, 4*, 5*

NA

h. Manual Initiation NA R l

LOSS OF POWER lD.

1. Divisions I and II 4.16 kv Standby Bus Under- S M R(c) 1, 2, 3, 4**, 5**

l a.

voltage (Sustained Under-voltage) 4.16 kv Standby Bus Under- S M R(c) 1, 2, 3, 4**, 5**

b.

I voltage (Degraded Voltage) l l

2. Division III 4.16 kv Standby Bus Under- S NA R 1, 2, 3, 4**, 5**

j a.

voltage (Sustained Under-i voltage)

b. 4.16 kv Standby Bus Under-M 1, 2, 3, 4**, 5**

voltage (Degraded Voltage) S R

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

• 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.

,_, 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 chinnel trip setpoint less conservative than the value shown in the AlTowable 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 REQUIREMENTS f"~'

4.3.9.1 Each plant system actuation instrumentation channel shall be demon-strated 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.

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

f I

1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

RIVER BEND - UNIT 1 3/4 3-107

. ) -

I TA'BLE 4.3.9.1-1

! PLANT SYSTEMS ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS Y

=

9 C'

CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH

! TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED E

1 1. PRIMARY CONTAINMENT VENTILATION SYSTEM -

g UNIT COOLER A AND 3

a. Drywell Pressure-High 0 M 1, 2,~3

b. Containment-to-Annulus AP-High 0 M Rf"8 R 1,2,3

c. Reactor Vessel Water Level-Low Low Low Level 1 D M RI ")a 1, 2, 3  ;

d. Timer NA M R 1,2,3

2. FEEDWATER SYSTEM / MAIN TURBINE TRIP SYSTEM M

, a. Reactor Vessel Water Level-High Y Level 8 D M R 1 M

~'

j (a) Calibrate trip unit setpoint once per 31 days.

1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

4

I EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 ECCS division I, II and III shall be demonstrated OPERABLE by:

a. At least once per 31 days for the LPCS, LPCI and HPCS systems:

1. Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.

2. Verifying that each valve (manual, power operated or automatic),

in the flow path, that is not locked, sealed, or otherwise secured in position, is in its correct position.

b. Verifying that, when tested pursuant to Specification 4.0.5, each:

1. LPCS pump develops a flow of at least 5010 gpm with a pump differential pressure greater than or equal to 281 psid.

2. LPCI pump develops a flow of at least 5050 gpa with a pump differential pressure greater than or equal to 100 psid.

3. HPCS pump develops a flow of at least 5010 gpm with a pump -

differential pressure greater than or equal to 399 psid.

c. At least once per 18 months, for the LPCS*,* LPCI*hnd HPCS systems, performing a system functional test which includes simulated

automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual injec-tion of coolant into the reactor vessel may be excluded from this test.

. d. At least once per 18 months, for the HPCS system, verifying that the suction is automatically transferred from the condensate storage tank to the suppression pool on a condensate storage tank low water level signal and on a suppression pool high water level signal, and verifying that the HPCS system will automatically restart on Reactor Vessel Water Level - Low Low Level 2.

I l

• • May be extended t e completion of the first refueling outage, i RIVER BEND - UNIT 1 3/4 5-4

CONTAINMENT SYSTEMS PRIMARY CONTAINMENT UNIT COOLERS LIMITING CONDITION FOR OPERATION 3.6.3.2 Both primary containment unit coolers shall be OPERABLE and capable of rejecting heat to the Standby Service Water System.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

a. With one of the primary containment unit coolers inoperable, restore the inoperable unit cooler 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 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 both primary containment unit coolers inoperable, restore at least one unit cooler to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-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 />.

,_s SURVEILLANCE REQUIREMENTS 4.6.3.2 Both primary containment unit coolers shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each pressure relief and backdraft damper, in the flow path, that is not locked, sealed or otherwise secured in position, is in its correct position.

b. At least once per 92 days, by verifying that each of the required unit coolers develops a flow of at least 50,000 cfm on recirculation flow through the unit cooler, l

c. At least once per 18 monthf by performance of a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each pressure relief and backdraft damper in the flow path actuates to its correct position.

1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

RIVER BEND - UNIT 1 3/4 6-29

d

' ~ CONTAINMENT SYSTEMS 3/4.6.4 PRIMARY CONTAINMENT AND ORYWELL ISOLATI -

-LIMITING CONDITION FOR OPERATION in Table 3.6.4-1 3.6.4 The primary containment and drywell isolation valvesequal to th shall be OPERABLE with isolation times less than or Table 3.6.4-1.

OPERATIONAL CONDITIONS 1, 2, and 3.

APPLICABILITY:

l ACTION:

Ilisolationvalvesshown With one or more of the primary containment or dryweisolation valve O each affected penetration that is open and, w tin Ta a.

Restore the inoperable valve (s) to OPERABLE status, or deactivated ,

Isolate each affected penetration by use et at least one

• or

b. automatic valve secured in the isolated position, closed manual c.

Isolate each affected penetration by use of at least one valve or blind flange.* ble provided d.

The provisions of Specification 3.0.4dance arewith stem, not ACTIONapplica if applicable,

,-s that the affected penetration is isolated int accor t ments for that l

b. or c. above,- and provided that the assoc system are performed.

t 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Otherwise, be in at least HOT SHUTOOWN within the nex COLD SHUTOOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.  :

P SURVEILLANCE REQUIREMENTS be demonstrated fter maintenance, repair or 4.6.4.1 Each isolation valve shown in Table 3.6.4-1.s OPERABLE prior to returning the valve its associated actuator, control to one service, a cycle of h at least complete replacement work is performed on the i valve time. or or power circuit, by cycling the valve througfull 6 4 1 shall be demon- tra l

Each automatic isolation valve shown in Table 3. . -R 4.6.4.2 strated OPERABLE during COLD SHUT l 00WN each automatic or isolation valve by verifying that, on an isolation test signa ,

actuates to its isolation position. t matic valve shown in The isolation time of each power i operated or au oits limit 4.6.4.3 l Table 3.6.4-1 shall be determined to be with n to Specification 4.0.5.

i ments may be reopened on an ded

" Isolation valves closed to satisfy these requ r i<

refueling outage, l #The specified 18 month interval duringwith completion of the l ' to coincide RIVER BEND - UNIT 1

TABLE 3.6.4-1 5 ,

CONTAINMENT AND DRYWELL ISOLATION VALVES g

a MAXIMUM SECONDARY g PENETRATION ISOLATION TIME COMAINMENT

, VALVE (j)

NUMBER GROUP (Seconds) BYPASS PATH SYSTEM VALVE NUMBER e (Yes/No)

-4 H a. Automatic Isolation Valve _s

1. Primary Containment (a) 1KJB*Z1A 6 5 No MSIV IB21*A0VF022A((b)(g) b)(g) 5 No 1821*A0VF022B 1KJB*Z18 6 MSIV I No 1KJB*Z1C 6 5 MSIV MSIV IB21*A0VF022C(D)f9) 1821*A0VF022D b)(g) 1KJB*Z10 6 5 No 1KJB*Z1A 6 5 No MSIV 1821*A0VF028A m 1KJB*Z18 6 5 No

} MSIV 1821*A0VF028B(g) No 1KJB*Z1C 6 5

. MSIV 1821*A0VF028C(9) No

' IB21*A0VF028D 1KJB"Z10 6 5 MS*V I U 1KJB*ZIA 6 17.8 No Turbine Plant Misc. Drains # 1821*MOVF067A(9) 9) 16.1 No 1KJB*Z1B 6 l Turbine Plant Misc. Drains" 1821*MOVF067B f9) 6 15.9 No Turbine Plant Misc. Drains" 1821*MOVF067C 1KJB*Z1C IU 1KJB*Z10 6 19.8 No Turbine Plant Misc. Drains # 1821*MOVF067D )() ) 16.5 No Turbine Plant Misc. Drains" 1B21*MOVF016(b g 1KJB*Z2 6 1821*MOVF019 f9) 1KJB*Z2 .6 17.6 No Turbine Plant Migc. Drains # 5 18.7 No RHR Return to FW# 1E12*MOVF053A 1KJB*Z3A 1KJB*Z38 5 18.7 No RHR Return to FW 1E12*MOVF053g) 36.3 No RHR/RCIC Head Supply # 1E12*MOVF023 IKJB*Z19, 5 l

IDRB*Z13 ..

RHR Shutdown Cooling Supply 1KJB*Z20 5 29.7 No 1E12*MOVF008(b) IKJB*Z20 5 25.3 No RHR Shutdown Cooling Supply 1E12*MOVF009 1E12*MOVF037A 1KJB*Z21A 14 73.7 No LPCI A to Reactor' 14 74.8 No LPCI B to Reactor" 1KJB*Z218 1E12*MOVF037B 1E33*MOVF008(d

)(k) 1KJB*Z1A,B,C,0 4 14.5 No MS-PLCS Line t

i

1

)

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES m

G MAXIMUM SECONDARY

' PENETRATION VALVE ISOLATION TIME CONTAINMENT SYSTEM VALVE NUMBER NUMBER GROUP (I) (Seconds) BYPASS PATH E (Yes/No)

Z g a. Automatic Isolation Valves

1. Primary Containment (*) (Continued)

RWCU Disch. to Cogdenser" 1G33*MOVF028 1KJB*Z4 15 20.9 Yes II)

RWCU Return to FW 1KJB*Z6 15 24.2 No RWCU Pump Suctign' 1G33*MOVF040(b) 1G33*H0VF001 1XJB*Z7 16 19.8 No RWCU Pump Disch. 1G33*MOVF053 IKJB*Z129 15 5.5 No RWCU Disch. to Condenser # 1G33*MOVF034 1KJB*Z4 15 20.9 Yes II) m RWCU Return to FW# 1G33*MOVF039 IKJB*Z6 15 24.2 No

) RWCU Pump Suction 8 IG33*MOVF004 1KJB*Z7 7 6.6 No

. RWCU Pump Disch/ 1G33*M0VF054 1KJB*Z129 15 5.5 No J, RWCU Backwash Disch. # 1WCS*MOV178 1KJB*Z5 1 12.1 Yes II)

" RWCU Backwash Disch.# IWCS*MOV172 IKJB*Z5 1 12.6 Yes(I)

HPCS Test Return-Supp. Pool # IE22*MOVF023(j) IKJB*Z11 1 50 No RHR A Return-Supp. Pool # 1E12*MOVF024A(j) 1XJB*Z24A .. 10 . 63.8 No ,

RHR A Hx Dump-Supp. Pool # IE12*MOVF011A(j) 1KJB*Z24A 10 34.1 No I LPCS Test Return-Supp. Pool # 1E21*MOVF012(j) 1KJB*Z24A 10 57.2 No I RHR B Return-Supp. Pool # IE12*MOVF0248(j) 1KJB*Z24B 10 63.8 No I RHR B Hx Dump-Supp. Pool # IE12*MOVF011B(j) 1KJB*Z24B- 10 -

30.8 No ,

RHR C Return-Supp. Pool 8 IE12*MOVF021(j) 1KJB*Z24C 10 97.9 No Fuel Pool C&C Disch.# ISFC*MOV119 IKJB*Z26 1 68 No  !

Fuel Pool C&C Suction # ISFC*MOV120 1KJB*Z27 1 62.7 No {

a Fuel Pool C&C Suction # ISFC*MOV122 1KJB*Z27 1 63.8 No Fuel Pool Purif. Suction 8 ISFC*MOV139 IKJB*Z28 1 39.6 No Fuel Pool Purif. Suction # ISFC*MOV121 1KJB*Z28 1 39.6 No ,

_.se a _ _

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES co E MAXIMUM SECONDARY PENETRATION

• ISOLATION TIME CONTAINMENT SYSTEM VALVE NUMBER NUMBER VALVE GROUP (I) (Seconds) BYPASS PATH j E (Yes/No)

-A e c. Automatic Isolation Valves 4 1. Primary Containment (a) (Continued) 1DFR*A0V102 ID)

Floor Drain Disch.# 1KJB*Z35, 1 N/A No 1DRB*Z36 Floor Drain Disch.# 1DFR*A0V101(b) 1KJB*Z35, 1 N/A No 1DRB*Z36 Equip. Drain Disch.# 1 DER *A0V127(b) 1KJB*Z38, 1 N/A No

> M 1DRB*Z39 Equip. Drain Disch.8 1 DER *A0V126(b) 1KJB*Z38, 1 N/A No i 1DRB*Z39

% Fire Protection Hdr.# 1FPW*MOV121 1KJB"Z41 1 34.1 Yes(I)

1. ISAS*MOV102 1KJB*Z44 1 22.0 Yes II)

Service Air Supply # IKJB*Z46 18.7 Yes II)

Instr. Air Supply IIAS*MOV106 1 RPCCW Supply # 1CCP*MOV138 1KJB*Z48 1 22.0 No RPCCW Return 8 1CCP*MOV158 IKJB*Z49 1 23.1 No RPCCW Return # 1CCP*MOV159 1KJB*Z49 -1 -

24.2 No Service Water Return # ISWP*MOV5A 1KJB*Z53A 1 50.6 No Service Water Return # ISWP*MOV5B 1KJB*Z53B 1 53.9 No Vent. Chilled Water Rtn.# 1HVN*MOV102 1KJB*Z131 1 31.9 Yes II)

~'

28.6 I Vent. Chilled Water Rtn.# 1HVN*MOV128 1KJB*Z131 1 Yes(I)

Vent. Chilled Water Sup.# IKJB*Z132 1 27.5 Condensate Makeup Supply #

1HVN*MOV127 1CNS*MOV125 IKJB*Z134 1 22.0 Yes(I)

Yes }

. 1 I t

! TABLE 3.6.4-1 (Continued) x CONTAINMENT AND DRYWELL ISOLATION VALVES E MAXIMUM SECONDARY PENETRATION VALVE ISOLATION TIME CONTAINMENT 7 gj) BYPASS PATH

e SYSTEM VALVE NUMBER NUMBER GROUP (Seconds)

$ (Yes/No) l H a. Automatic Isolation Valves

1. Primary Containment (a) (Continued) 1 RHR & RCIC Steam Sup. 1KJB*Z15 2 9.9 No .

RHR & RCIC Steam Sup. IE51*MOVF063((b) 1E51*MOVF076 b) 1KJB*Z15 2 13.4 No RHR & RCIC Steam Sup. 1E51*MOVF064 IKJB*Z15 2 9.9 No RCIC Pump Suc.-Supp. Pool IE51*MOVF031 fI) 1KJB*Z16 2 30.5 No RCIC Turbine Exh.-Supp. Pool 1E51*MOVF077 IKJB*Z17 3 14.2 No ,

w IKJB*Z18B,C 16.5 No RCIC Turbine Exh. Vac. Bkrs. IE51*MOVF078 3

} Cont./Drywell. Purge Sup." 1HVR*A0V165 1KJB*Z31 ,,8 3 No

, ' I Cont./Drywell Purge Sup. # 1HVR*A0V123 1KJB*Z31 8 3 No J, No m Cont./Drywell Purge Outlet 8 1HVR*A0V128 1KJB*Z33 8 3 l

8 3 No

. Cont./Drywell Purge Outlet 8 1HVR*A0V166 1KJB*Z33 Post-Accident Samp. Sup.# ISSR*S0V130 1KJB*Z601B 10 . . 3 No 1

1 Post-Accident Samp. Sup.# 1SSR*SOV131 1KJB*Z601B 10 3 No .

4

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

A MAXIMUM SECONDARY 5 PENETRATION ISOLATION TIME CONTAINMENT

. NUMBER VALVE GROUP (I) (Seconds) BYPASS PATH SYSTEM VALVE NUMBER c (Yes/No) 3

--4 e c. Automatic Isolation Valves

2. Drywell(k) l Cont./Drywell Purge Sup.8 1HVR*A0V147 1DRB*Z32 1 3 No .

RPCCW Supply # 1CCP*MOV142 1DRB*Z50 1 30 No RPCCW Return 8 1CCP*M0V144 IDRB*Z51 1 30 No

. RPCCW Return 8 1CCP*MOV143 IDRB*Z51 1 30 No Service Water Supply 8 ISWP*MOV4A 1DRB*Z54 1 52.8 No R Service Water Supply 8 ISWP*MOV4B 1DRB*Z54 1 51.7 No Service Water Return 8 ISWP*MOVSA 1DRB*Z55 1 50.6 No i Service Water Return # ISWP*MOV5B IDRB*Z55 1 53.9 No

$ Recirc. Flow Contro18 1RCS*MOV58A 1DRB*Z152 1 11.0 No Recirc. Flow Contro18 1RCS*MOV59A 1DRB*Z153 1 10.6 No Recirc. Flow Control # 1RCS*MOV60A 1DRB*Z154 1 6.3 No Recirc. Flow Contro18 1RCS*MOV61A IDRB*Z155 1 8.6 No Recirc. Flow Control # 1RCS*MOV588 1DRB*Z156 .1 . 10.6 No

Recirc. Flow Contro1 8 1RCS*MOV598 1DRB*Z157 1 10.8 No Recirc. Flow Control" 1RCS*MOV608 1DRB*Z158 1 6.38 No Recirc. Flow Contro18 1RCS*MOV61B 1DRB*Z159 1 8.9 No 1DRB*Z32 1 3 No Cont./Drywell Purge Sup.8 IHVR*A0V125 1DRB*Z34 1 3 No Cont./Drywell Purge Rtn.# 1HVR*A0V126 1DRB*Z34 1 3 No Cont./Drywell Purge Rtn.8 1HVR*A0V148 e

\

TABLE 3.6.4-1 (Continued)

>$ < CONTAINMdNT AND DRYWELL ISOLATION VALVES

, ES cn SECONDARY MAXIMUM EE CONTAINMENT PENETRATION ISOLATION TIME VALVE GROUP (I) (Seconds) BYPASS PATH VALVE NUMBER NUMBER SYSTEM (Yes/No)

[

w ea a. Automatic Isolation Valves

2. Drywell(k) (Continued) 10 33 No Hydrogen Mixing Line Inlet # 1 CPM *MOV2A 1DR8*Z57A

10 33 No Hydrogen Mixing Line Inlet # 1 CPM *MOV4A 10RB*Z57A 10 33 No 10RB*Z578

Hydrogen Mixing Line Inlet # ICPM*MOV2B 10 33 No 1DRB*Z578 i Hydrogen Mixing Line Inlet 8 1 CPM *MOV4B 10 33 No Hydrogen Mixing Line Exhaust # 1 CPM *MOV3A 10RB*Z58A 10 33 No

,, 1DR8*Z58A

! ;; Hydrogen Mixing Line Exhaust 8 1 CPM *MOV1A 10 33 No Hydrogen Mixing Line Exhaust # ICPM*MOV3B 10RB*Z58B 10 33 No ICPM*MOV1B 1DRB*Z588 a Hydrogen Mixing Line Exhaust # 9 5 No Reactor Plant Sampling # 1833*A0VF019 10RB*Z449 w 5 No 1DRB*2449 9 Reactor Plant Sampling # 1833*A0VF020 j ..

1 i

l l

J I

1 1

I

, )

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

'l 9 to NOTES

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

{

w (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 isolation signal.

I ) 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.

T (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.

j

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

(d) 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.

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

1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage. .

s.

~'

e

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. Atleastonceper18 months!#during COLD SHUTOOWN or REFUELING, by verifying that, on a containment isolation test signal, each isolation damper actuates to its isolation position.

c. By verifying the isolation time to be within its limit when tested pursuant to Specification 4.0.5.

i

f. }'

/ .

m

-\ 4 4

t t

t

1. 1. 1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

i i

RIVER BEND - UNIT 1 ,

3/4 6-52

CONTAINMENT SYSTEMS - -

SURVEILLANCE REQUIREMENTS (Continuyd)

c. After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation, by verifying, within 31 days after removal, that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%.

d. At least once per 18 months by: '

1. Performing a system functional test which' includes simulated automatic actuation of the system throughout its' emergency operating sequence for the: *

• a) LOCA, and ,

b) Annulus ventilation exhaust high radiation signal.

2. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 8 inches water gauge while the filter train is operating at a flow rate of 12,500 cfm i 10%. ~

3. Verifying that the filter train starts and isolation dampers open on each of the following test signals:

a) Manual initiation from the control room, and

• b) Simulated automatic initiation signal.

4. Verifying that the filter cooling bypass dampers can be manually opened and the fan can be manually' started.

5. Verifying that the heaters dissipate > 61 kw when tested in accordance with ANSI N510-1980 at the design supply voltage.

f

e. Verifying, after each complete or partial replacement of a HEPA filter bank, that the HEPA filter bank satisfies the inplace penetration and bypass leakage testing acceptance criterion of less than 0.05% in accordance with ANSI N510-1980 while operating the system at a flow rate of 12,500 cfm i 10%.

f. Verifying, after each complete or partial replacement of a charcoal j adsorber bank, that the charcoal adsorber bank satisfies the inplace penetration and bypass leakage testing acceptance criterion of less than 0.05% in accordance with ANSI N510-1980 for a halogenas_J hydrocarbon refrigerant test gas while operating the system at a flow rate of 12,500 cfm i 10%.

'* The specified 18 month interval during the first operating cycle may be extended

' to coincide with completion of the first refueling ~ outage.

RIVER BEND - UNIT 1 3/4 6-56

- . - . _ . = . . - - - .._. _- --. ._ _ _ - .. .__~ .. ~ .

s CONTAINMENT SYSTEMS SHIELD BUILDING ANNULUS MIXING SYSTEM LIMITING CONDITION FOR OPERATION _ _

.3.6.5.5 Two independent Shield Building Annulus Mixing subsystems shall be-OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3.

ACTION:

4 With one Shield Building Annulus Mixing subsystem inoperable, restore the inoperable subsystem 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 i hours.

SURVEILLANCE REQUIREMENTS 4.6.5.5 Each Shield Building Annulus Mixing subsystem shall be demonstrated

, OPERABLE:

a. At least once per 31 days by initiating the subsystem from the control i room and verifying that the subsystem operates for at least 15 minutes and

b. At least once per 18 months by:

1. Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for the:

a) LOCA, and b) Annulus ventilation exhaust high radiation signal.

2. Verifying that each ' subsystem has a flow rate of 52,500 cfm i 10%.

3. Verifying that the subsystem starts and isolation dampers open on each of the following test signals:

a) Manual initiation from the control room, and

• • Simulated automatic initiation signal.

b)

• • May be extended to the completion of the first refueling outage. l f

i RIVER BEND - UNIT 1 3/4 6-57  ;

-- - . - . . , -4,4 -

- . . . - - , - , , , . . . - - . - - - .r---. ...~,e.-,- ,, , - > .,-, - , - --- -, . -.. . .t-e- r- ye---e-- - - ' - * - *---e---e- - - *

• CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. At least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings or (2) following painting, fire or chemical release in any ventilation zone communi-cating with the subsystem, by:

1. Verifying that the subsystem satisfies the in place penetration and bypass leakage testing acceptance criterion of less than 0.05%, using the test procedure guidance in Regulatory Positions C.S.a C.S.c and C.S.d of Regulatory Guide 1.52, Revision 2, March 1978, and a system flow rate of 10,000 cfm i 10L

2. Verifying within 31 days after removal.that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%; and

3. Verifying a subsystem flow rate of 10,000 cfm i 10% during system operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation, by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175L

e. At least once per 18 months by:

1. Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence for the:

• • a) LOCA, and b) Fuel Building ventilation exhaust high radiation signal.

2. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 8 inches water gauge while the filter train is operating at a flow rate of 10,000 cfm i 10L

3. Verifying that the subsystem starts and isolation dampers actuate to isolate the normal flow path and to divert flow f tiyrough the charcoal filters on each of the following test signals:

• • The specified 18 month interval during the first operating cycle may be extended to coincide with the completion of the first refueling outage.

RIVER BE..D - UNIT 1 3/4 6-59

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) a) Manual' initiation from the control room, and

" b) Simulated automatic initiation signal.

4. Verifying that the filter cooling bypass dampers can be manually opened and the fan can be manually started.

5. Verifying that the heaters dissipate >49 kw when tested in accordance with ANSI N510-1980 at the design supply voltage.

f. Verifying, after each complete or partial replacement of a HEPA filter bank, that the HEPA filter bank satisfies the inplace penetration and bypass leakage testing acceptance criterion of less than 0.05% in accordance with ANSI N510-1980 while operating the system at a flow rate of 10,000 cfm i 10%. .

g. Verifying, after each complete or partial replacement of a charcoal adsorber bank, that the charcoal adsorber bank satisfies the inplace penetration and bypass leakage testing acceptance criterion of le.ss than 0.05% in accordance with ANSI N510-1980 for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 10,000 cfm i 10%.

" The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage. l RIVER BEN 0 - UNIT 1 3/4 6-60

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

4. With both SSW subsystems otherwise inoperable, 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 />.

c. With only one SSW pump and its associated flow path CPERABLE, restore at least two pumps with at least one flow path 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:

1.- In OPERATIONAL CONDITION 4 or 5, declare the associated equipment inoperable and take the ACTION required by Specif.ications 3.4.9.2, 3.5.2, 3.8.1.2, 3.9.11.1, and 3.9.11.2. -

2. In Operational Condition *, verify adequate cooling for the diesel generators required to be OPERABLE:or declare the associ-ated diesel generator inoperable and take'the ACTION required by Specification 3.8.1.2. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS .

4.7.1.1 At least the above required standby service water system subsystem (s) shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying that each valve in the flow path, that is not locked, sealed or otherwise secured in position, is in its correct position.

b. At least once per 18 months'during shutdown by verifying that each l automatic valve actuates to the correct position and each pump starts on a normal service water low pressure signal.

l 1

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

• • Whenever both RHR shutdown cooling mode loops are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant 1 temperature as low as practical by use of alternate heat removal methods.

1. The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

RIVER BEND - UNIT 1 3/4 7-2

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) t

c. At'least once per 18 months or (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation z9ne communi-cating with the subsystem by:

1. Verifying that the subsystem satisfies the in placq penetration and bypass leakage testing acceptance criterion of :less than 0.05% and uses the test procedure guidance in Regulatory Posi-tions C.S.a. C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 4000 cfm a 10%.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Reguletory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%; and

3. Verifying a subsystem flow rate of 4000 cfm i 10% during sub-system operation when tested in accordance with ANSI N510-1980.

d.

After every 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Posi-ton C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978, for a methyl iodide penetration of less than 0.175%.

e. At least once per 18 months by: -

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 8 inches water gauge while operating the subsystem at a flow rate of 4000 cfm i 10%.

2. Verifying that on each of the below emergency mode actuation test signals, the subsystem automatically switches to the emergency mode of operation, the isolation valves close within 30 seconds, and the control room is maintained at a positive pressure of > 1/8 inch water gauge relative to the outside atmosphere during subsystem operation at a flow rate less than or equal to 4,000 cfm:

• • a) LOCA, and b) Local air intake radiation monitor - High.

3. Verifying that the heaters dissipate 23 1 2.3 kw when tested in accordance with ANSI N510-1980, at the design supply voltage.

• • The specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

RIVER BEND - UNIT 1 3/4 7-6

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

3. By verifying within 31 days of obtaining the sample that the other properties specified in Table 1 of ASTM D975-81 are met when tested in accordance with ASTM 0975-81, except that the analysis for sulfur may be performed in accordance with ASTM D1552-79 or ASTM D2622-82.

e. At least once every 31 days by obtaining a sample of fuel oil from the storage tanks in accordance with ASTM D2276-78 and verifying that total particulate contamination is less than 10 mg/ liter when checked in accordance with ASTM D2276-78, Method A.

f. At least once per 18 months #, during shutdown, by:

1. Subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service.

2.### Verifying the diesel generator capability to reject a load of greater than or equal to 917.5 kw for diesel generator 1A, greater than or equal to 509.2 kw for diesel generator 18, and greater than or equal to 1995 kw for diesel generator 1C while maintaining engine speed less than nominal plus 75% of the dif-ference between nominal speed and the overspeed trip setpoint or 15% above nominal, whichever is less.

3.### Verifying the diesel generator capability to reject a load of 3030-3130 kw*** for diesel generators 1A and 18 and 2500-2600 kw***

for diesel generator 1C without tripping. The generator voltage shall not exceed 4784 volts for diesel generator 1A and 18 and 5400 volts for diesel generator 1C during and following the load rejection.

4.### Simulating a loss of offsite power by itself, and:

a) For divisions I and II:

1) Verifying deenergization of the emergency busses and load shedding from the emergency busses.

i

1. For any start of a diesel, the diesel must be operated with a load in accordance with the manufacturer's recommendations.

• • • Momentary transients due to changing bus loads shall not invalidate the test.

1. 1. 1. Fo'r Divisions I and II the specified 18 month interval during the first operating cycle may be entended to coincide with completion of the first refueling outage.

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. ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2) Verifying the diesel generator starts ** on the auto start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected loads through the sequencing logic, and oper-a,tes for greater than or equal to 5 minutes while its generator is loaded with the loads. After energization, the steady-state voltage and frequency of the emergency busses shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

b) For division III:

1) Verifying de-energization of the emergency bus.

2) Verifying the diesel generator starts ** on the auto start signal, energizes the emergency bus with the permanently connected loads within 10 seconds, energizes the auto-connected loads through the sequence logic, anc oper-ates for greater than or equal to 5 minutes while its generator is loaded with the loads. After energiza-tion, the steady-state voltage and frequency of the emergency bus shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

- 5.### Verifying that, on an ECCS actuation test signal without loss of  !

offsite power, the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to 5 minutes. For diesel generator 1A and IB,. the generator voltage and frequency shall be 4160 1 420 volts and 60 1 1.2 Hz within 10 seconds after the auto-start signal. For diesel generator IC, the generator voltage and frequency shall not exceed a maximum of 5400 volts and 66.75 Hz and shall be greater than 3740 volts and 58.8 Hz within 10 seconds and 4160 1 420 volts and 60 1 1.2 Hz within 13 seconds. T,he steady-state generator voltage and fre-quency shall be maintained within these limits during this test.

6.# # # Simulating a loss of offsite power in conjunction with an ECCS I actuation test signal and:

a) For divisions I and II:

1) Verifying deenergization of the emergency busses and load shedding from the emergency busses.

2) Verifying the diesel generator starts ** on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds, energizes the auto-connected loads through the sequencing logic, and

• • All diesel generator starts for the purpose of this surveillance test may be preceded by an engine prelube period. Further, all surveillance tests, with

< the exception of once per 184 days, may also be preceded by warmup procedures and may also include gradual loading (> 150 sec) as recommerded by the manufac-turer so that the mechanical stress and wear on the diesel engine is minimized.

1. 1. 1. For Divisions I and II the specified 18 month interval during the first operating b te RIVER BEN [- UkfT pded to coincide gh g cympletion of the first refueling outage.

-###For Divisions I and II the specified 18 month interval during the first l operating cycle may be extended to coincide with completion of the first refueling outage.

l, ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.

After energization, the steady state voltage and frequency of the emergency busses shall be maintained at 4160 1 420 volts and 60 i 1.2 Hz during this test.

b) For division III:

1) Verifying de-energization of the emacgency bus.

2) Verifying the diesel generator starts ** an the auto-start signal, energizer the emergency bus with its permanently connected loads within 10 seconds, ener-gizes the auto-connected loads through the sequencing logic, and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads. After energization, the steady-state voltage and frequancy of the emergency bus shall be maintained at 4160 1 420 volts and 60 1 1.2 Hz during this test.

7.### Verifying that, upon an ECCS actuation signal, all automatic diesel generator trips are automatically bypassed except engine overspeed and generator diffeiential current.

8. Verifying the diesel generator operates for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Diesel generators 1A and 13 thall be loadr.d to 3030-3130 kw***

for the duration of the test. Diesel generator 1C shall be loaded to 2750-2850 kw*** for the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of the test and tu 2500-2600 kw*** for the remaining 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> of the test. For diesel generator 1A and 1B, the generator voltage and frequency shall be 4160 1 420 volts and 60 1 1.2 Hz within 10 seconds after the start signal. For diesel generator IC, the generator voltage and frequency shall not exceed a maximum of 5400 volts and 66.75 Hz and shall be greater than 3740 volts and 58.8 Hz within 10 seconds and 4160 1 420 volts and 60 1 1.2 Hz within 13 seconds.

The steady-state generator voltage and frequency shall be main-tained within these limits during this test. Within 5 minutes after completing this 24-hour test, perform Surveillance Require-ment 4.8.1.1.2.f.4.a)2) and b)2)##.

9### Verifying that the auto-connected loads to each diesel generator l do not exceed 3130 kw for diesel generator 1A ar.d 18 and 2600 kw for diesel generatcr 1C.

• • All diesel generator starts for the purpose of this surveillance test may be preceded by an engine prelube pericd. Further, all surveillance tests, with the exception of once per 184 days, may also be preceded by warmup orocedures and may also include gradual loading (> 150 sec) as recommended by the manufac-turer so that the mechanical stress and wear on the diesel cogine is ninimized.

I *** Momentary transients due to changing bus loids shall not invalidate the test.

1. 1. If Surveillance Requirements 4.8.1.1.2.f.4.a)2) and b)2) are not satisfactorily completed, it is not necessary to repeat the preceding 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> test. Insteaa, perform Surveillance Requirement 4.8.1.1.2.a.5 prior to repeating Surveillance Requirements 4.8.1.1.2.f.4.a)2) and b)2) for the appropriate diesel.

RIVER BEND - UNIT 1 3/4 8-8

r

.- ###For Divisions I and II the specified 18 month interval during the first operating cycle may be extended to coincide with completion of the first refueling outage.

ELECTRICAL POWER SYSTEMS

\ ,

i- SURVEILLANCE REQUIREMENTS (Continued)

[

/ 10.### Verifying the diesel generator's capability to:

a) Synchronize with the offsite power source, while the gener-ator is loadeJ with its emergency loads, upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, and c) Be restored to its standby status.

11.###V erifying that, with thn diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by (1) returning the diesel generator to standby operation and (2) automati'cally energizing the emer-gency loads with offsite power.

12.### Verifying that the automatic load sequence timers are OPERABLE with the interval between each load block within 10% of its design interval for diesel generators 1A, 18 and IC.

13. Verifying that the following diesel generator lockout features prevent diesel generator starting only when required:

a) For Diesel Generators 1A and 18:

1) Loss of control power to diesel control panel.

2) Starting air pressure below 150 psi.

3) Stop-solenoid energized.

4) Diesel in the maintenance mode (includes barring device engaged).

5) Overspeed trip device actuated.

6) Generator backup protection lockout relay tripped.

b) For Diesel Generator IC:

1) Diesel generator lockout relays not reset.

2) Diesel engine mode switch not in "AUT0" position.

3) Diesel generator output breaker closed before start of diesel.

4) Diesel generator output breaker in racked-out position.

5) tDiesel generator regulator mode switch not in "AUT0" position.

6) Insufficient starting air pressure.

7) Loss of dc power to d'hel generator controls.

g. By verifying the Division III diesel generator ambient room temperature to be _> 40 F:

1. At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with the last repcrted room temperature

, > 50*F, or

• tItem 5) does not electrically block diesel generator from emergency starting; however, it will affect the loading and operation of the diesel.

RIVER BEND - UNIT 1 3/4 8-9 ,

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