ML20059G818

Proposed Tech Specs Re Surveillance Test Interval & Allowed Outage Time Extension Request

ML20059G818
Person / Time
Site:	River Bend
Issue date:	01/14/1994
From:	ENTERGY OPERATIONS, INC.
To:
Shared Package
ML19311B360	List: ML20059G818 ML20059G843 ML20059G846 RBG-39895, Application for Amend to License NPF-47,extending Allowable Outage Times of Instruments Involved & Increase Channel Functional Surveillance Test Interval from Monthly to Quarterly Requirement.Proprietary Rept Encl
References
NUDOCS 9401250319
Download: ML20059G818 (106)

Text

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Entergy Operations, Inc.

RIVER BEND STATION DOCKET 50-458/ LICENSE NO. NPF-47 j

SURVEILLANCE TEST INTERVAL ,

AND ALLOWED OUTAGE TIhfE  !

EXTENSION REQUEST l (LAR 93-06) ,

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LICENSING DOCUhfENT INVOLVED:

The LICENSING DOCUMENT INVOLVED includes the following sections, pages, and/or Tables l of the Technical Specification and the applicable Bases Sections:

3.3.1 " Reactor Protection System Instrumentation",

Page 3/4 3-1, Table 3.3.1-1, and Table 4.3.1.1-1, s Bases 3/4.3.1, 3.3.2 " Isolation Actuation Instrumentation",

Page 3/4 3-10, Table 3.3.2-1, and Table 4.3.2.1-1, Bases 3/4.3.2, 3.3.3 " Emergency Core Cooling System Actuation Instr.",

Table 3.3.3-1 and Table 4.3.3.1-1, Bases 3/4.3.3, ,

3.3.4.1 "ATWS Recirculation Pump Trip System Instr.",

Table 3.3.4.1-1 and Table 4.3.4.1-1, Bases 3/4.3.4,

• 3.3.4.2 "End-of-Cycle Pecirculation Pump Trip System Instr.",

Page 3/4 3-48, Table 3.3.4.2-1, and Table 4.3.4.2.1-1, ,

Bases 3/4.3.4, 3.3.5 "RCIC System Actuation Instrumentation",

Table 3.3.5-1 and Table 4.3.5.1-1, Bases 3/4.3.5, 3.3.6 " Cont.ol Rod Block Instrumen'.ation",

Table 3.3.6-1 and Table 4.3.6-1, Bases 3/4.3.6 ,

3.3.7 " Monitoring lustrumentation", j Table 4.3.7.1-1  :

3.3.9 " Plant System Actuation Instrumentation",

l Table 3.3.9-1 and Table 4.3.9.1-1, Bases 3/4.3.9 3.4.2.1 " Safety / Relief Valves",

Page 3/4 4-8 r

g I 9401250319 940114 j PDR ADOCK 05000458 - <

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3.4.2.2 " Safety / Relief Valves Low-Low Set Function" '

Page 3/4 4-9 .

Bases 3/4.4.2  ;

i Included in this Attachment, reference Part I through Part VI, is an itemized listing of all changes ,

made to each section of the Technical Specification listed above.  ;

REASON FOR REOUEST: -

I During late 1983, the BWR Owner's Group (BWROG) established a Committee for a Technical l Specification Improvement Program (TSIP), of which River Bend Station (RBS) is a member. This e committee established a program for the development of reli bility analysis to justify improvements to surveillance test intervals (STIs) and allowable outage times (AOTs) for instrumentation specified in the BWR Standard Technical Specifications. The primary objective of this program was to minimize, for applicable instrumentation, unnecessary testing and to lengthen excessively restrictive ,

AOTs that could potentially degrade overall plant safety and availability. Examples of some of the problems experienced with the current Technical Specification requirements are: inadvertent scrams or engineered safety feature actuations due to frequent testing; AOTs which are not long enough to i perform repairs on a reasonable basis; excessive actuation of equipment for testing contributing to wear-out; and unnecessary radiation exposure to personnel performing Technical Specification _r' required testing.

Within the same time frame, the NRC Staff issued NUREG-1024, " Technical Specifications -

Enhancing the Safety Impact", which recommended that surveillance test requirements and Technical Specification Action Statements be reviewed to assure that they have an adequate technical basis and do indeed minimize plant risk. Use of reliability analysis to support engineering judgement was ,

recognized as a primary basis for improving the Technical Specification requirements. NUREG-1024 i thus reinforced the BWROG's program objectives and implementation methodology.

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4 To this end, the BWROG submitted a series of Licensing Topical Reports addressing the Technical  !

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Specification instrumentation requirements for the Reactor Protection System (NEDC-30851P),

Emergency Core Cooling Systems (NEDC-30936P), the Control Rod Block System (NEDC-30851P, '

Supplement 1), and for the Isolation Actuation Instrumentation (NEDC-30851P Supplement 2 and ,

NEDC-31677P). Each of these Licensing Topical Reports has been reviewed and approved by the NRC. In addition, the BWROG has submitted a Licensing Topical Report (GENE-7704)6-1) and its 1 Addendum (GENE-770-06-2), which address Technical Specification requirements for other instruments which are similar to those addressed in the Licensing Topical Reports previously reviewed  ;

and approved by the NRC. 4 As a member of the BWROG Technical Specification Conunittee, RBS is requesting that the results f of the BWROG Licensing Topical Reports on Technical Specification improvements be applied to f River Bend Station.  ;

i This submittal also addresses the NRC Staff's concern regarding " Loss-of-Function" conditions for i the AOT changes provided in the BWRCG Topical Reports. The " Loss of-Function" issue was  ;

specifically addressed during the development of the Improved Standard Technical Specifications .

(NUREG-1434).' As a result, the Action Statements in NUREG-1434 for instrumentation (that i provide automatic actuation function) contain checks to ensure that a Loss-of-Function condition does  !

not exist. NUREG-1434 was issued by the NRC for implementation by utilities on September 29, 1992 and was utilized as the " standard" for the propcsed changes addressed herein.

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DESCRH' TION- I l

For convenience in reviewing this request, it has been divided into six separate parts addressing the ,

functional areas and associated BWROG Licensing Topical Report (s). Each part contains its own  :

description of proposed changes, justification, and Basis for No Significant Hazards Consideration. i Included 'n Attachment 2 are marked up copies of pages from the current RBS Technical Specifict tions including the combined effect of the changes requested in each Part of this attachment. r Althoul$ not a formal part of the Technical Specifications (as described in 10CFR50.36), Bases  ;

changes are also provided in Attachment 2.

The evaluations provided in Part I through Part VI are consistent to the greatest degree possible with i the evaluations provided in the Perry Nuclear Power Plant Amendment Request previously suomitted.

Due to the similarity between the plant designs, it was felt that the review process would be less  !

complicated and could be completed in a more expeditious manner if both amendment requests were as identical as possible.

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Attachment 1  :

Page 4 Part I - Reactor Protection System (RPS)

Description of Proposed Channs The following changes to Techt ical Specification 3/4.3.1, " Reactor Protection System Instrumentation", are proposed:

1. ACTIONS a. and b. have been revised to provide a repair allowable outage time (AOT) of either 1,6, or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, depending upon the degree of redundancy remaining in the other trip channels for that Functional Unit, as well as incorporating a check for loss of function into the ACTIONS and their footnotes.

2. The surveillance AOT of Note (a) to Table 3.3.1-1 is being increased from two hours to six hours.

3. The surveillance test interval (STI) for CHANNEL FUNCTIONAL TEST's specified on Technical Specification (TS) Table 4.3.1.1-1, " Reactor Protection System Instrumentation Surveillance Requirements" is being increased from Weekly (W) or Monthly (M), as applicable, to Quarterly (Q) for the following Functional Units:

a. item 2.b, Average Power Range Monitor (APRM) Flow-Biased Simulated Thermal Power - High,

b. item 2.c, APRM Neutron Flux - High,

c. item 2.d, APRM Inoperative,

d. item 3, Reactor Vessel Steam Dome Pressure - High,

e. item 4, Reactor Vessel Water Level - Low, Level 3,

f. item 5, Reactor Vessel Water Level - High, Level 8,

g. item 6, Main Steam Line Isolation Valve - Closure,

h. Item 7, Main Steam Line Radiation - High,

i. item 8, Drywell Pressure - High,

j. item 9.a, Scram Discharge Volume Water Level - High, Level Transmitter,

k. item 10, Turbine Stop Valve - Closure, and I. item 11,7urbine Control Valve Fast Closure. Trip Oil Pressure - Low

4. The STI for CHANNEL FUNCTIONAL TEST's specified in TS Table 4.3.1.1-1 item 13, Manual Scram is being revised from Monthly (M) to Weekly (W).

5. The analog trip module calibration interval specified by footnote (g) to TS Table 4.3.1.1-1 is being increased from 31 days to 92 days.

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Attachment 1 l Page 5 i

Justirication for Proposed Chanzes 1 On May 31,1985 the BWROG submitted Licensing Topical Report NEDC-30851P, " Technical Specification Improvement Analysis for BWR Reactor Protection System", for review, This Topical i Report provides justification for the proposed changes identified as 1 thru 5 above. The analyses documented in NEDC-30851P utilized fault tree modeling to estimate the impact of the proposed .

changes on the average Reactor Protection System (RPS) failure frequency. ~!

The average RPS failure frequency is a function of the frequency of scram demands and the probability that the RPS is unavailable when demanded. The initiating events which require successful operation of the RPS for ensuring safe reactor shutdown are identified and their annual occurrence frequencies were estimated. The initiating events were divided into three groups based on the number  ;

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of diverse sensors that initiate the scram for that event.

For each initiating event, a top-level failure event was identified using the success criteria described '

below. For each top failure event a fault tree was developed which modeled the components needed for generation and processing of the RPS signals including the sensors, analog trip modules, logic  !

cards, load drivers, and ram solenoids. The common cause failure of these components was also  !

modeled. A fault +re: analysis was then performed using the WAM series computer code,  ;

WAMCUT, to obtain the major failure cut sets that contribute to the top failure event probability.

The failure cut sets obtained were then analyzed using the FRANTIC III computer code to determine the average RPS system unavailability upon demand.

The average RPS unavailability was calculated for each initiating event group based on inputs which meluded component failure rates (time and demand related), common cause failure rates, human error rates, testing intervals, and test repair times. Sensitivity studies were conducted by changing the input parameters by factors of 2,5, and 10 (and 30, where appropriate) to determine the resultant impact on the average RPS unavailability and the total RPS failure frequency. The STIs and AOTs were then  !

varied to determine the resulting effect on the average RPS failure frequency.

The scram success criteria used for this analysis is defined below for two specific failure modes:

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a. Failure Mode A: One or more RPS electrical control rod groups fail to insert into the core. l The success criteria for this failure mode was that two of the total four rod groups must fully insert.

b. Failure Mode B. One or more control rods in a random pattern fail to insert. The success criteria for this failure mode was that, if the control rods are inserted in a random manner, 69% of all the rods must fully insert to achieve success.

The acceptance guideline used by the BWROG for the proposed changes is based on a net change in risk. The net change in risk is the difference between the increase in risk that would result from the proposed changes and the decrease in risk that would result from the reduced likelihood ofinadvertent scrams. If the net change in risk is determined to be insignificant, the BWROG considered the proposed changes to be acceptable.

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' The BWROG concluded that the overall effect of the proposed RPS TS changes provides a net .(

increase in safety and improves plant operation. The improvement is achieved by reducing the ,

potential for: a) unnecessary plant scrams (reduced challenges to plant shutdown systems and  :

improved plant availability); b) excessive test cycles on equipment (reduced wear-out potential); and ~

c) diversion of plant personnel and resources on unnecessary testing (potential safety and operational l improvement). The BWROG report concluded that the calculatet, average RPS failure frequency-  :

increases from 4.6x10'*/ year to 5.4x10 */ year with a reduction in inadvertent scrams from an average ,

of 0.56 scrams / year to 0.23 scrams / year with incorpoeion of the proposed RPS Technical Specification changes.

By letter from Ashok C. Thadani (NRC) to Terry A. Pickins (BWROG) dated July 15,1987s the _

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NRC provided their Safety Evaluation Report of NEDC-30851P. The NRC concluded in their Safety.

Evaluation Report that NEDC-30851P applies to plants employing a relay RPS system such as RBS

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and that the proposed changes would have a negligible impact on plant risk. On this basis, the NRC j determined that these proposed changes are acceptable. However, the staff identified three - 'j requirements for any applicant who wished to reference this document for proposed Technical i Specification changes. These three requirements are discussed below, i

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1. Confirm the aonlicability of the ceneric analysis for NEDC-30851P to its plant.

'i A BWR-6 RPS relay model plant was used for the generic analysis for NEDC-30851P. RBS -

is a BWR-6 with a standard RPS relay system. Therefore, the generic analysis employed by i NEDC-30851P is applicable to RBS. In addition, General Electric did perform a RBS plant  !'

specific analysis which is discussed below for requirement 3. This analysis confirmed the applicability of the generic analysis for NEDC-30851P to RBS.

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2. Demonstrate by use of current drift information provided by the eouinment vendor or )

plant-specific data that the drift characteristics for instrumentation used in the RPS channels .  !

in the plant are bounded by the assumptions used in NEDC-30851P when the ftmetional test j interval is extended from monthly to ouarteriv.

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With respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the RPS instrumentation setpoint calculations at RBS include the effects of instrument drift '  :

over 18 months for all instrument loop components. As a result, RBS has concluded that '

lengthening the CH ANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable, for the RPS instruments from weekly or monthly to quarterly _will not ,

result in excessive instrument drift relative to the current established setpoints. In addition, ,

a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with .

redundant channels. These routine CHANNEL CHECKS will help identify excessive drift  :

of the RPS instrumentation.

3. Confirm that the differences between the RPS in the plant and the RPS of the ceneric analysis clant were included in the olant specific analysis usine the procedures of Appendix-K of NEDC-30851P. l A plant specific analysis was performed by General Electric using the procedure in Appendix - j K of NEDC-30851P. The results of this analysis are documented in Enclosure 1. The l analysis determined four differences existed which required either further engineering assessment or analysis. The resulting evaluation of these differences concluded that they did not significantly affect the improvements in plant safety obtained through the Technical  !

Specification changes evaluated in NEDC-30851P. ,

i In addition to the four identified differences stated above, the previous evaluation did not include site specific information regarding Surveillance Test Procedures (STP), reference Section II.H in Appendix K of NEDC-30851P. The original analysis performed by GE assumed that the response to each question was identical to the generic model and therefore no discrepancies were noted or evaluated. A subsequent review of RBS specific Surveillance Test Procedures using the procedure in Appendix K of NEDC-30851P has been completed and the results included in a Supplement to Enclosure 1. This assumption previously made '

j in the original analysis has proven to be conservative as compared to actual practices at RBS and does not alter the original conclusion. -l l

The generic analysis was also compared against the RBS Individual Plant Examination (IPE) for Generic Letter 88-20. The fault tree models and the generic data generally agreed with.the plant specific models for RBS. Therefore, RBS agrees with the magnitude of the numbers reported and i the percent increase in failure probability. However, the actual numbers in this report may be different than those reported in the IPE submittal due to the uncertainty in this analysis and in the plant specific IPE.

With respect to NRC approval of plant-specific changes to the RPS Technical Specifications based l upon NEDC-30851P, RBS understands that the NP.C has expressed concern that the specific changes to the ACTIONS proposed in NEDC-30851P would allow continued plant operation for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 4

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with a combination 'of failures which could prevent a particular reactor scram function from i completing its logic when called upon. This could occur for a relay-type plant (with ,

one-out-of-two-twice logic) if, for example, both channels of the high reactor pressure function were inoperable in one trip system [this is one of the two RPS scram functions that are assumed to mitigate  ;

the Pressure Regulator Failure-Increasing transient (see Table F-1 of NEDC-30851P)]. Actions l

3.3.1.a and 3.3.1.b and their footnotes have therefore been revised to eliminate this concern. . A letter .;

clarifying the Technical Specification changes to 3.3.1.a and 3.3.1.b was submitted to NRC Staff by l the GE BWROG on November 4,1992 (Enclosure 5). This letter, BWROG-92102, has been '

incorporated into the changes being submitted by this request.  :

For 3.3.1.a, with one channel required by Table 3.3.1-1 inoperable in one or more Functional Unit (s) '

(i.e., any number of Functional Units having only one inoperable channel in each Functional Unit),

the entire RPS scram capability remains intact, assuming no additional single failure. The action which allows continued operation for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> was evaluated and the reliability of the system shown l to be acceptable in NEDC-30851P. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> the inoperable channels and/or trip system must I be placed in the tripped condition. This action restores the RPS capability to accommodate a single failure and allows operation to continue with no further restrictions. If the inoperable channel (s) and/or trip system is not placed in the tripped condition within the allowed time, then the ACTION .l required by Table 3.3.1-1 must be taken to place the plant in a condition that obviates any need for l that inoperable channel's function.

For 3.3.1.b, with two or more_ channels inoperable in any Functional Unit, the RPS may not be ,

I capable of performing its intended function (e.g., a " loss of scram function" may exist, depending on which two (or more) channels are inoperable). In this condition, during the period allowed to place - I the inoperable channels and/or trip system in the tripped condition, if a valid trip signal was received, ,

a failure to automatically scram could result. In order to reduce the probability of this occurrence,

• the ACTION for this condition requires that steps be taken to ensure each required Functional Unit i maintains trip capability.within I hour. This time period allows the operator time to evaluate, to repair or to trip the channels. This time period is reasonable considering the diversity of sensors available to provide trip signals, and the low probability of an event requiring the initiation of a -

scram. This time period is also consistent with the current Technical Specifications which address ,

this condition.

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Attachment 1 Page 9 In addition, ifit has been verified that a loss of scram function situation does not exist, an allowance of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is provided in order to restore a level of RPS reliability equivalent to that provided by ACTION a. The requirement to place the inoperable channel (s) in one Trip System.(or one entire  !

Trip System), in the tripped condition limits the time the RPS scram logic for any Functional Unit >

would not accommodate a single failure in either Trip System. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> time period is considered 1 acceptable based on the remaining capability to trip, the diversity available to provide trip signals, the  ;

low probability of extensive numbers of inoperabilities affecting all diverse functions, and the low  !

probability of an event requiring the initiation of a scram. By'the end of the six hour period, each i Functional Unit will either have all required channels OPERABLE, or at least one Trip System will ,

have its inoperable channels placed into the tripped condition. This provides a similar level of RPS reliability as found in ACTION a, above, and evaluated in NEDC-30851P to be acceptable for a 12 :

hour allowable outage time. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, all the inoperable channels in the other trip system will i have been restored to operable status, or else the inoperable channels will be placed in trip; For all i of the proposed ACTIONS, if the inoperable channels are not placed in trip within the allowed time, .

then the ACTION required by Table 3.3.1-1 must be taken, which places the plant in a condition that obviates any need for the inoperable channels' function.

Basis for No Sienificant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specification) ,

involves no significant hazards considerations if operation of the facility in accordance with the proposed change would not: 1) involve a significant increase in the probability or consequences of any ,

accident previously evaluated, or 2) create the possibility of a new or different kind of accident from  !'

any accident previously evaluated, or 3) involve a significant reduction in a margin of sMety. The proposed RPS Technical Specification changes are evaluated against each of these criteria below, i

1. These proposed changes do not involve a change to the plant design or operation, they I simply involve the frequency at which testing of the RPS instrumentation is performed and the allowable outage time (AOT) for instruments. Failure of the RPS instrumentation itself j cannot create an accident. As a result, these proposed changes cannot increase the probability  ;

of occurrence of any design basis accident previously evaluated.

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Attachment 1 Page 10 As identified in NEDC-30851P, these proposed changes increase the average RPS failure frequency from 4.6x10'*/ year to 5.4x10'*/ year. This increase (8x10flyear)is considered to be insignificant. As identified in the NRC Staff's Safety Evaluation Report of NEDC-30851P, this increase in average RPS failure frequency would contribute to a very small increase in core-melt frequency. The small increase in average RPS failure frequency is offset by safety benefits such as a reduction in the number of inadvertent test-induced.

scrams, a reduction in wear due to excessive equipment test cycling, and better optimization of plant personnel resources. Hence, the net change in risk resulting from these proposed changes would be insignificant. Therefore, these proposed changes do not-result in a significant increase in either the probability or the consequences of any accident previously evaluated.

2. The proposed changes do not result in any change to the plant design or operation, only -

to the AOT and frequency at which testing of the RPS instrumentation is performed. Since failure of the RPS instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated

3. As identified above, these proposed changes increase the average RPS failure frequency from 4.6x10-6/ year to 5.4x10-6/ year. The NRC Staff's Safety Evaluation Report of NEDC-30851P concluded that this small average RPS failure frequency increase would contribute to a very small increase in core-melt frequency. 'Ihis small increase in average RPS failure frequency would be offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams, a reduction on wear due to excessive equipment test cycling, and better optimization of plant personnel resources. Hence, the net change in risk resulting from these proposed changes would be insignificant. In addition, RBS has confirmed that the proposed changes to the functional test intervals will not result in excessive instrument drift relative to the current established setpoints. Therefore, these proposed changes do not result in a significant reduction in a margin of safety.

Based upon the foregoing, RBS concludes that these proposed changes do not involve a significant hazards consideration.

Attachment 1 Page 11 Part II - Emergency Core Cooline System (ECCS)

Description of Proposed Chances The following changes to Technical Specification 3/4.3.3, " Emergency Core Cooling System Actuation Instrumentation", are proposed *:

1. The surveillance AOT of footnote (a) to Technical Specification Table 3.3.3-1 is being increased from two to six hours.

2. The repair allowable outage times (AOTs) of Technical Specification Table 3.3.3-1,

" Emergency Core Cooling System Actuation Instrumentation", ACTION 32 is being increased from one hour to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; ACTION 33 is being increased from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3. The surveillance test interval (STI) for CHANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.3.1-1, " Emergency Core Cooling System Actuation Instrumentation Surveillance Requirements", is being increased from Monthly (M) to Quarterly (Q) for the following Trip Functions:

a. item A.l.a, Division 1 Trip System, RHR-A (LPCI Mode) and LPCS System, Reactor Vessel Water Level - Low Low Low Level 1,

b. item A.I.b, Drywell Pressure, High,

c. Item A.l.c, LPCS Pump Discharge Flow - Low,

d. item A. l .d, Reactor Vessel Pressure - Low (LPCS/LPCI Injectica Valve Permissive),

e. item A.l.e, LPCI Pump A Start Time Delay Relay, f, item A.I.f, LPCI Pump A Discharge Flow - Low,  :

g. item A.I.g, LPCS Pump Start Time Delay Relay,

h. item A.2.a, Division 1 Trip System, Automatic Depressurization System Trip System "A", Reactor Vessel Water Level - Low Low Low Level 1,

i. item A.2.b, Drywell Pressure - High,

j. item A.2.c, ADS Timer,

k. item A.2.d, Reactor Vessel Water Level - Low Level 3, l

1. item A.2.e, LPCS Pump Discharge Pressure - High,  !

m. item A.2.f, LPCI Pump A Discharge Pressure - High, ,

n. item A.2.g, ADS Drywell Pressure Bypass Timer, J

o. item A.2.h, ADS Manual Inhibit Switch, l

p. item B.l.a, Division 2 Trip System, RHR B and C (LPCI Mode), Reactor Vessel Water Level - Low Low Low Level 1,

q. item B.I.b, Drywell Pressure - High,

r. item B.I.c, Reactor Vessel Pressure - Low (LPCI Injection Valve Permissive),

s. item B.l.d, LPCI Pump B Start Time Delay Relay,

t. item B.I.e, LPCI Pump discharge Flow - Low,

u. item B.l.f, LPCI Pump C Start Time Delay Relay,

v. item B.2.a, Division 2 Trip System, Automatic Depressurization System Trip System "B", Reactor Vessel Water Level - Low Low Low Level 1,

w. item B.2.b, Drywell Pressure - High,

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x. item B.2.c, ADS Timer, ,

y. item B.2.d, Reactor Vessel Water Level - Low Level 3,  ;

z. item B.2.e, LPCI Pump B and C Discharge Pressure - High, aa. item B.2.f, ADS Drywell Pressure Bypass Timer, bb. item B.2.g, ADS Manual Inhibit Switch, cc. item C.I.a, Division 3 Trip System, HPCS System, Reactor Vessel Water Level -  :

Low Low Level 2 dd. item C.I.b, Drywell Pressure - High, ee. item C.I.c, Reactor Vessel Water Level - High Level 8, ff. item C.I.d, Condensate Storage Tank Level - L,ow, gg. item C.l.e, Suppression Poci Nater Level - High, i hh. item C.I.f, Pump Discharge Pressure - High, and ii. item C.I.g, HPCS System Flow Rate - Low. .

4. The analog trip module calibration interval specified by footnote (a) to Technical Specification Table 4.3.3.1-1 is being increased from 31 days to 92 days.

Additional changes to Technical Specification 3/4.3.3 are proposed in Part VI of this l Submittal. -!

1 Justification for Proposed Channes  !

On July 23,1987 the BWROG submitted Licensing Topical Report NEDC-30936P, "BWR Owners' Group Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentation) Part 2", for NRC review. This report provides justification for the proposed changes identified as 1 through 4 above. Similar to the RPS report discussed in part I of this submittal, the analysis documented in NEDC-30936P (Part 2) utilized fault tree modeling (based upon a BWR-5/6 relay plant design) to estimate the impact of the proposed changes on the average water injection function failure frequency.

The calculation of average water injection failure frequency depends on two sets of parameters. The first set consists ofinitiating events which eventually call for water injection. The second set consists of the probability that the water injection function is unavailable given a demand for injection.

Depending on each initiating event, the number of components that are needed for successful completion of the water injection function varies. Therefore, the water injection unavailability for a given initiating event may differ from that of another initiating event.

A function fault tree was developed for each initiating event in order to quantify the water injection unavailability per demand. The function fault tree modeled the logical relationship of the faults that contribute to the water injection unavailability. The function fault tree was used to estimate the water injection unavailability based upon the current Technical Specification requirements and the effect of proposed changes. The results were considered acceptable by the BWROG if the proposed changes resulted in less than a 4% increase in the average water injection failure frequency.

i Attachment 1 i

_Page 13  ;

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r The 4% increase in the average water injection frequency is well within the uncertainty of this  ;

analysis and is thus a very conservative limit for justifying the changes to AOTs and STIs. A change ,

in water injection frequency of 4% will cause a change in core damage frequency (CDF) of no more ,

than 4%. This change in CDF is insignificant compared to the uncertainty factor of +/-4 for the I plant specific IPE and an even higher uncertainty factor for this analysis.  ;

The only initiating events studied in this analysis were loss of offsite power (LOOP) initiating events.

The LOOP event was chosen for consideration because, based on prior Probabilistic Risk Assessment calculations, LOOP events contribute from 40% to 90% of the calculated core damage frequency for most BWRs. Also, the LOOP analysis is a more severe test of ECCS actuation instrumentation than other accident sequences such as turbine trip, loss of feedwater, and recirculation pump failure. f Therefore, the effect of the proposed changes on water injection unavailability and failure frequency -l for the LOOP initiating event will dominate contributions for all initiating events.  ;

By letter of Charles E. Rossi (NRC) to Donald N. Grace (BWROG) dated December 9,1988, the  !

NRC provided their Safety Evaluation Report of NEDC-30936P (Part 2). The NRC concluded in ,

their Safety Evaluation Report that the methods and acceptance criteria provided in NEDC-30936P i (Part 2) are acceptable for implementation on a plant-specific basis. However, the NRC's Safety  ;;

Evaluation Report states that in order for a licensee to use the generic analysis provided in  :

NEDC-30936P (Part 2), the licensee must confirm the applicability of the generic analysis to the plant and confirm that any increase in instrunwnt drift due to the extended surveillance intervals is properly.

accounted for in the setpoint calculation methodology.

In addition to NEDC-30936P (Part 2), two letters clarifying the ECCS Actuation Instrumentation .

Technical Specification changes have been issued. The first letter dated August 7,1989, OG-90-749-32D, provides a markup of the entire ECCS Actuation Instrumentation subsection of the .j Technical Specification (Enclosure 6). The second letter, OG-90-319-32D, was submitted to the NRC staff by the GE BWROG on March 22,1990 and is included in Enclosure 2 of this submittal.' Each .

letter has been used to formulate the changes being submitted.  ;

A generic BWR-5/6 relay plant was modeled in NEDC-30936P (Part 2). In addition, Section 5.5 of NEDC-30936P (Part 2) documented the analysis of three other enveloping cases to model known differences in either instrumentation logic or support system configuration. General Electric ,

conducted a RBS plant specific ECCS review to determine the extent of differences between RBS and i the generic model. This review was documented in RE-029, February 1987 " Technical Specification  !

Improvement Analysis for the Emergency Core Cooling System Actuation Instrumentation for River  !

Bend Station, Unit 1", (Enclosure 3). The results of this review are noted in Section 3 of Enclosure.' l 3 and indicate there were four differences between the generic model and RBS. Two enveloping  !

cases (Cases 5B and 5C) in Section 5.5 of NEDC-30936P (Part 2) were determined to bound the RBS differences. Therefore, the generic analysis is applicable to RBS. As indicated in Tables 5-5 and 5 of NEDC-30936P (Part 2), the water injection function failure frequency for Case 5B and 5C with .} '

the current Technical Specification is 1.952x104 and 1.386x104 per year, respectively. When the STis are increased to quarterly, test AOTs increased to six hours, and repair AOTs increased to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, the water injection function failure frequency for Case 5B changes to 1.992x104 per year (2.0% increase) and Case SC changes to 1.40lx10d per year (1.1 % increase). These small increases j in failure frequencies are within the acceptability guidelines of NEDC-30936P (Part 2).

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1 Attachment I  ;

Page 14 i

With respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the ECCS actuation instrumentation setpoint calculations at RBS include the effects of instrument drift over 18 months for all instrument loop components. As a result, RBS has concluded that lengthening i the CHANNEL FUNCTIOMAL TEST interval and analog trip module calibration interval, as  !

applicable, for the ECCS Actuation instruments from monthly to quarterly will not result in excessive ,

instrument drift relative to the current, established setpoints. In addition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with redundant channels. These routine CH ANNEL CHECKS will he!p identify excessive drift of the ECCS actuation instrumentation.

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Attachment i Page 15 Basis for No Sinnificant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specification) involves no significant ha7ards considerations if operation of the facility in accordance with the proposed change would not: 1) involve a significant increase in the probability or consequences of any accident previously evaluated, or 2) create the possibility of a new or different kind of accident from any accident previously evaluated, or 3) involve a significant reduction in a margin of safety. The proposed ECCS actuation instrumentation Technical Specification changes are evaluated against each of these criteria below.

1. These proposed changes do not involve a change to the plant design or operation, they simply involve the frequency at which testing of the ECCS actuation Instrumentation is performed and the allowable outage time (AOT) for instruments. Failure of the ECCS actuation instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of occurrence of any design basis accident previously evaluated.

As identified in NEDC-30936P (Part 2), these prop ,' changes increase the calculated average water injection failure frequency from 1.952x104 to 1.992x104 per year for Case 5B and from 1.386x10' to 1.40lx104 per year for Case 5C. This represents an increase of 4x107 for Case 5B (2.0%) and 1.5x10* for Case 5C (1,1 %), which are well within the acceptance criteria (4 %) provided in NEDC-30936P (Part 2). The small increase in average water injection failure frequency is offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams, a reduction in wear due to excessive equipment test cycling, and better optimization of plant personnel resources. Hence, the net change in risk resulting from these proposed changes would be insignificant. Therefore, these proposed changes do not result in a significant increase in either the probability or the consequences of any accident previously evaluated.

2. The proposed changes do not result in any change to the plant design or operation, only to the AOT and frequency at which testing of the ECCS actuation instrumentation is performed. Since failure of the ECCS actuation instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated.

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Attachment 1 l Page 16  !

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3; As identified above, these proposed changes increase the calculated average water  !

injection failure frequency from 1.952x10-5 to 1.992x104 pei year for Case 5B and from i 1.386x104 to 1.40lx104 per year for Case SC. This increase is well within the acceptance criteria found acceptable in the NRC Staff's Safety Evaluation Report for NEDC-30936P (Part-2). This small increase in average ECCS actuation failure frequency would be offset by safety benents such as a reduction in the number of inadvertent test-induced scrams, a -

reduction on wear due to excessive equipment test cycling, and better optimization of plant personnel resources. Hence, the net change in risk resulting from these proposed changes l would be insignificant. In addition, RBS has confirmed that the proposed changes to the -l' functional test intervals will not result in excessive instrument drift relative to the current, established setpoints. Therefore, the proposed changes do not result in a significant reduction  :

in a margin of safety. l; c

Based upon the foregoing, RBS concludes that these proposed changes do not involve a significant  ;

hazards consideration. '

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E Attachment 1 Page 17 I

r Part III - Control Rod Block ,

Description of Proposed Changes The following changes to Technical Specification 3/4.3.6, Control rod Block Instrumentation", are proposed *:

1. The CHANNEL FUNCTIONAL TEST interval specified on Technical Specification Table 4.3.6-1, " Control Rod Block Instrumentation Surveillance Requirements", is being increased from Monthly (M) to Quarterly (Q) for the following Trip Functions:

a. item 1.a. Rod Pattern Control System, Low Power Setpoint, ,

b. item 1.b, Rod Pattern Control System, High Power Setpoint,

c. item 2.a, APRM Flow Biased Neutron Flux - Upscale,

d. item 2.b, APRM Inoperative,

e. item 2.c, APRM Downscale,

f. item 2.d, APRM Neutron Flux - Upscale, Startup,

g. item 5.a, Scram Discharge Volume, Water Level - High, and

h. item 6.a, Reactor Coolant System Recirculation Flow, Upscale

2. The analog trip module calibration interval specified by footnote # to Technical Specification Table 4.3.6-1 is being increased from 31 days to 92 days, ,

i Additional changes to Technical Specification 3/4.3.6 are proposed in Part V and VI of this submittal. i Justification for Proposed Changes On June 23,1986 the BWROG submitted Licensing Topical Report NEDC-30851P, Supplement 1,

" Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation", for NRC review. This report provides justification for each of the proposed changes identified above.

Unlike the analysis discussed in Parts I and II of this submittal, no specific fault trees were developed for the Control Rod Block Instrumentation. Instead, the impact on the average Control Rod Block failure rate was estimated based upon the results of the RPS Instrumentation analysis presented in Part I of this submittal. This approach was taken because the RPS and Control Rod Block functions share common instrument inputs.

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. Attachment 1 Page 18 ~

i The BWROG report determined that the average Control rod Block failure rate _would increase less than 104/ year (0.06%) from the current failure rate of 0.16/ year (based on industry experience).

NEDC-30851P, Supplement I states that the benefits associated with the proposed changes to the RPS ,

and Control Rod Block Instrumentation offset any potential negative impact of extending the Control Rod Block Instrumentation test intervals. '

a By letter from Charles E. Rossi (NRC) to Donald N. Grace (BWROG) dated September 22,1988,-

the NRC provided their Safety Evaluation Report of NEDC-30851P, Supplement 1. The NRC ,

concluded in their Safety Evaluation Report that NEDC-30851P, Supplement 1 provides an acceptable  ;

basis for implementing the above proposed Control Rod Block Instrumentation changes. However, ,

the NRC's Safety Evaluation Report states that in order for a licensee to use the generic analysis [

provided in NEDC-30851P, Supplement 1, the licensee must confirm the applicability of the generic _  !

analysis to the plant and confirm that any increase in instrument drift due to the extended intervals is properly accounted for in the setpoint calculation methodology.

1 RBS has confirmed that the Control Rod Block Instrumentation configuration (described m j NEDC-30851P and Supplement 1 as the Rod Control and Information System) is identical to that at RBS. As a result, the analysis presented in NEDC-30851P, Supplement 1 is directly applicable to R.BS.

With respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the Control Rod Block instrumentation setpoint calculations at RBS include the effects ofinstrument drift l over 18 months for all instrument loop components. As a result, RBS has concluded that lengthening -l the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable, for the Control Rod Block instruments from monthly to quarterly will not result in excessive instrument drift relative to the current, established setpoints. _In addition, a CHANNEL  !

CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with redundant channels. These  !

routine CHANNEL CHECKS will help identify excessive drift of the Control Rod Block ,

instrumentation. 'I Basis for No Sienificant Ugzards Consideration i

in accordance with 10CFR50.92, a proposed change to the operating license (Technical Specification)  !

involves no significant hazards considerations if operation of the facility in accordance with the  !

proposed change would not: 1) involve a significant increase in the probability or consequences of any j accident previously evaluated, or 2) create the possibility of a new or different kind of accident from any accident previously evaluated, or 3) involve a significant reduction in a margin of safety. The _

proposed Control Rod Block instrumentation Technical Specification changes are evaluated against I I

each of these criteria below.

1. These proposed changes do not involve a change to the plant design or operation, only the Allowable Outage Time (AOT) and frequency at which testing of the Control Rod Block Instrumentation is performed. Failure of the Control Rod Block instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of occurrence of any design basis accident previously evaluated.

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Attachment 1 Page 19 As identified in NEDC-30851P, Supplement 1, these proposed changes increase the average Control Rod Block failure frequency less than 0.06%. As provided in the NRC Staff's Safety Evaluation Report of NEDC-30851P, Supplement 1, this increase is very slight and is offset by the safety benefits associated with the proposed changes to the RPS and Control Rod Block Instrumentation. As a result, the combined effect of the changes proposed for the RPS and Control Rod Block Instrumentation requirements should result in an overall improvement in l

plant safety. Therefore, these proposed changes do not result in a significant increase in either the probability or the consequences of any accident previously evaluated.

2. The proposed changes do not result in any change to the plant design or operation, only to the AOT and frequency at which testing of the Control Rod Block instrumentation is performed. Since failure of the Control Rod Block instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated

3. As identified above, these proposed changes increase the average Control Rod Block failure frequency less than 0.06%. This increase is very slight and is offset by the safety benefits associated with the proposed changes to the. RPS and Control Rod Block Instrumentation. As a result, the combined effect of the changes proposed for the RPS and Control Rod Block Instrumentation requirements should result in an overall improvement in plant safety. In addition, RBS has confirmed that the proposed changes to the functional test intervals will not result in excessive instrument drift relative to the current, established setpoints. Therefore, the proposed changes do not result in a significant reduction in a margin of safety.

Based upon the foregoing, RBS concludes that these proposed changes do not involve a significant hazards consideration.

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. Attachment 1 Page 20 Part IV - Isolation Actuation Instrumentation f

Descrintion of Proposed Chances l

The following changes to Technical Specification 3/4.3.2, " Isolation Actuation Instrumentation", are proposed:

1. ACTIONS b and c have been revised to provide a repair Allowable Outage Time (AOT) of [

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Trip Functions common to RPS (Trip Functions 1.b,2.b,3.b. 6.c,6.e and 6.f),  !

and of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Trip Functions not common to RPS (Trip Functions other than 1.b. 2.b,  !

3.b, 6.c, 6.e, and 6.f).

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2. The Surveillance AOT identified in footnote (a) to Technical Specification Table 3.3.2-1, i

" Isolation Actuation Instrumentation", is being increased from two hours to six hours.

3. The CHANNEL FUNCTIONAL TEST interval specified on Technical Specification Table 4.3.2.1-1, " Isolation Actuation Instrumentation Surveillance Requirements", is being i increased from Monthly (M) to Quarterly (Q) for the following Trip Functions:

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a. item 1.a. Primary Containment Isolation, Reactor Vessel Water Level - Low Low  ;

Level 2, '

b. item 1.b, Drywell Pressure - High, '

c. item 1.c, Containment Purge Isolation Radiation - High,  !

d. item 2.a. Main Steam Line Isolation, Reactor Vessel Water Level - Low Low Low ,

Level 1,

e. item 2.b, Main Steam Line Radiation - High, l

f. item 2.c, Main Steam Line Pressure - Low,

g. item 2.d, Main Steam Line Flow - High, l

h. item 2.e, Condenser Vacuum - Low, l

i. item 2.f, Main Steam Line Tunnel Temperature - High, ,

j. item 2.g, Main Steam Line Tunnel Delta Temperature - High ,

k. item 2.h, Main Steam Line Area Temperature - High (Turbine Building),  ;

1. item 3.a, Secondary Containment Isolation, Reactor Vessel Water Level - Low Low 4 Level 2, ,

m. item 3.b, Drywell Pressure - High,

n. item 3.c, Fuel Building Ventilation Exhaust Radiation - High,

o. item 3.d, Reactor Building Annulus Ventilation Exhaust Radiation - High, j

p. item 4.a, Reactor Water Cleanup System Isolation, Delta Flow - High, l

q. item 4.b, Delta Flow Timer,

r. item 4.c, Equipment Area Temperature - High, .

s. item 4.d, Equipment Area Delta Temperature - High,

t. item 4.e, Reactor Vessel Water Level - Low Low Level 2,

u. Item 4.f, Main Steam Line Tunnel Ambient Temperature - High,

v. item 4.g, Main Steam Line Tunnel Delta Temperature - High, i !

w. item 4.h, SLCS Initiation,  ;

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Attachment I i

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x. item 5.a, Reactor Core Isolation Cooling System Isolation - RCIC Steam Line Flow

- High,

y. item 5.b, RCIC Steam Line Flow - High Timer, j

z. item 5.c, RCIC Steam Supply Pressure - Low, ,

aa. item 5.d, RCIC Turbine Exhaust Diaphragm Pressure - High, bb. item 5.e, RCIC Equipment Room Ambient Temperature - High, -

cc. item 5.f, RCIC Equipment Room Delta Temperature - High, dd. item 5.g, Main Steam Line Tunnel AmSient Temperature - High,- ,

ee. item 5.h, Main Steam Line Tunnel Delta Temperature - High, i ff. item 5.i, Main Steam Line Tunnel Temperature Timer, i gg. item 5.j, RHR Equipment Room Ambient Temperature - High, j hh. item 5.k, RHR Equipment Room Delta Temperat- .; - High, ii. item 5.1, RHR/RCIC Steam Line Flow - High, l jj. item 5.m, Drywell Pressure - High,  ;

kk. item 6.a. RHR System Isolation, RHR Equipment Area Ambient Temperature -  ;

High, -l

11. item 6.b, RHR Equipment Area Delta Temperature - High, -

mm. Item 6.c, Reactor Vessel Water Level - Low Level 3, ,

nn. item 6.d, Reactor Vessel Water Level - Low Low Low Level 1, j oo. item 6.e. Reactor Vessel (RHR Cut-in Permissive) Pressure High, pp. item 6.f, Drywell Pressure - High, and ,

qq. item 7, Manual Initiation.

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4. The test interval specified by footnote (a) to Technical Specification Table 4.3.2.1-1 is being increased from 31 days to 92 days.

5. The analog trip module calibration interval specified by footnote (b) to Technical Specification Table 4.3.2.1-1 is being increased from 31 days to 92 days.

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Attachment I f Page 22 -

.Instification For Proposed Channes: '

On August 29,1986 the BWROG submitted Licensing Topical Report NEDC-30851P, Supplement l 2, " Technical Specification improvement Analysis for BWR isolation Common to RPS and ECCS -

Instrumentation", for NRC review. On June 27,1989 the BWROG submitted Licensing Topical Report NEDC-31677P, " Technical Specification improvement Analysis for BWR Isolation Actuation Instrumentation", for NRC review. The combination of the results from these two reports provides justi6 cation for the proposed changes identified as 1 through 6 above.

As stated in NEDC-30851P, Supplement 2, Technical Specification requirements for isolation instrumentation were originally established largely on the basis of RPS and ECCS requirements. That i is, the surveillance test intervals and allowable outage times generally do not need to be more ,

i stringent for isolation instruments than for RPS or ECCS instruments. Even though isolation is a safety function, failure to isolate would not of itself result in an accident. The overall containment  ;

and reactor vessel isolation function is made up of several subfunctions, each of which must operate upon demand during an accident. Failure of an isolation subfunction during an accident could potentially increase the offsite release risks.

The analysis presented in NEDC-30851P, Supplement 2 applies only to those Isolation Actuation  ;

instruments which are common to the RPS or ECCS actuation instruments. Similar to the analysis .;

discussed in parts I and II of this submittal, fault trees were developed for the instruments in each of -!

the common isolation Trip Functions. These fault trees were then evaluated probabilistically to ,

determine the impact of the proposed changes on isolation unavailability. The proposed change for -[

the repair allowable outage time is 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments common to RPS, and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for i instruments common to ECCS. Other proposed changes are consistent with those discussed in both i the RPS and ECCS topical reports. As provided in NEDC-30851P, Supplement 2, the impact on the average isolation unavailability for the affected isolation instruments due to the proposed changes to 'l' surveillance test intervals was determined to be negligible (an increase of less than 1%) when combined with the individual valve failure probabilities. The analysis demonstrates that the individual valve failure probabilities dominate the overall isolation failure probability. NEDC-30851P, Supplement 2 also determined that extending the AOTs has less than a 2% effect on the probability  ;

of failure of the isolation function given the demand.

By letter from Charles E. Rossi (NRC) to Donald N. Grace (BWROG) dated January 6,1989, the i NRC provided their Safety Evaluation Report of NEDC-30851P, Supplement 2. The NRC concluded in their Safety Evaluation Report that the methods and results provided in NEDC-30851 P, Supplement -

2 are acceptable for implementation on a plant-specific basis. However, the NRC's Safety Evaluation j Report states that in order for a licensee to use the generic analyses provided in NEDC-30851P, -- l Supplement 2, the licensee must confirm the applicability of the generic analyses to the plant and  !

confirm that any increase in instrument drift due to the extended surveillance intervals is properly '!

accounted for in the setpoint calculation methodology.

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Attachment 1 .

Page 23 With respect to the NRC Staff's concern about confirming the plant-specific applicability of NEDC-30851P, Supplement 2, the RBS configuration for Isolation Actuation Instrumentation Common to RPS and ECCS is essentially the same as the generic configuration modeled in '!

NEDC-3085IP, Supplement 2 (identified as BWR 5/6 Relay Plant). Any differences are within those . j noted in Section 3.2 of Supplement 2. Therefore, the generic results are directly applicable to RBS.

With respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the ~

Isolation Actuation instrumentation setpoint calculations at RBS include the effects ofinstrument drift over 18 months for all instrument loop components. As a result, RBS has concluded that lengthening the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable, for the Isolation Actuation instrumentation common to RPS and ECCS from monthly to quarterly will not result in excessive instrument drift relative to the current, established setpoints.

As an additional justification to this change for channels that require CHANNEL CHECKS, the -

CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with redundant channels. These routine CHANNEL CHECKS will help identify excessive drift of the Isolation Actuation instrumentation.

The analysis presented in NEDC-31677P applies to the remaining Isolation Trip Functions (i.e., those isolation Actuation instruments which are nel common to RPS or ECCS actuation instrumentation).

Similar to previous analyses discussed above, the analyses presented in NEDC-31677P are based upon l fault trees which were evaluated to determine the impact of the proposed changes on the average  :

isolation failure fre-quency. In this case, the average isolation failure frequency is defined as the product of the accident initiating event frequency (such as a pipe break or high radiation event) and  !

the probability of failure of the isolation function given a demand. The proposed changes were

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considered acceptable by the BWROG if the proposed changes results in less than a 10% increase in the ave. rage isolation failure frequency or if the average failure frequency was calculated to be less than 1.0x10 7/ year.

The results for the BWR 5/6 relay plant demonstrate that these proposed changes only slightly ,

increase the overall average isolation failure frequency for these instruments. As identified in Table 5-2 of NEDC-31677P, the calculated average isolation failure frequency actually decreases by 1.97x10*/ year and hence clearly meets the above acceptance criteria.  !

i' By letter from Charles E. Rossi (NRC) to S. D. Floyd (BWROG) dated June 18, 1990, the NRC provided their Safety Evaluation Report of NEDC-31677P. The NRC concluded in their Safety Evaluation Report that the methodology and acceptance criteria provided in NEDC-31677P are ')

acceptable for implementation on a plant-specific basis. However, the NRC's Safety Evaluation l Report states that in order for a licensee to use the generic analysis presented in NEDC-31677P, the licensee must confirm the applicability of the generic analysis to the plant and confirm that any increase in instrument drift due to the extended surveillance intervals is properly accounted for in the setpoint calculation methodology.

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Attachment i Page 24 l 1 With respect to the NRC Staff's request to confirm the plant-specific applicability of NEDC-31677P,-

section 5.5 of the NEDC discusses the application of the review to other plants, and provides Appendix C which indicates the plant specific requirements. As can be seen in Appendix C, RBS is one of the plants included in this Table. RBS has verified that the Table is accurate and therefore the  ;

conclusions given in Section 5.5 of NEDC-31677P document that the proposed STI and AOT changes are applicable to RBS and are acceptable.

With respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the  ;

Isolation Actuation instrumentation setpoint calculations at RBS include the effects ofinstrument drift l

over 18 months for all instrument loop components. As a result, RBS has concluded that lengthening )

the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as ]

applicable, for the Isolation Actuation instrumentation not common to RPS and ECCS from monthly to quarterly will not result in excessive instrument drift relative to the current, established setpoints. l As an additional ju;tification to this change for the channels that require CHANNEL CHECKS, a l CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with redundar.t 1 channels. These routine CHANNEL CHECKS will help identify excessive drift of the Isolation i Actuation instrumentation.

ACTION statements 3.3.2.b and 3.3.2.c have been revised to meet the intent of the changes described to the NRC Staff in a letter from the BWROG to the NRC Staff, OG-90-579-32A dated June 25,1990 1'

$nclosure 4). RBS has changed the proposed ACTION statements to meet the intent of the referenced letter, but has rearranged the wording to add clarification, and to be more consistent with the format of the RPS Instrumentation Specification proposed in Attachment 3, pages I and 2.

The differences between this proposal and the example contained in the June 18,1990 NRC SER are as follows* i l

1. The example markup of the 3.3.2 Specification in the June 18, 1990 NRC SER i incorporated the

• footnote into ACTIONS b.1 and b.2. Enclosure (4) recommended that the other footnote of Specification 3.3.2 also be incorporated into the- ACTION statements.  !

However, RBS has proposed keeping the footnotes, and rewording them to be consistent with I the oroposed wording of the footnotes in the RPS Instrumentation section. This will provide clarity and maintain consistency between these Specifications. ,

2. ACTIONS b.1 and b.2 have been combined into one action, ACTION b. As stated in  !

Enclosure (4), the primary reason why two AOTs had been created in the Topical Report markup was to retain the current Technical Specification format while incorporating the footnotes into the ACTIONS, and there is no strong technic'al reason for retaining two AOT conditions. In combining ACTIONS b.1 and b.2 into one action, the six hour repair AOT is  !

no longer used since the analysis in NEDC-31677P supports the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> AOTs j for RPS and non-RPS instruments respectively, regardless of whether placing the inoperable l instrument in trip would cause the trip function to occur. Therefore, the intent of the l

recommendations of Enclosure (4) have been incorporated into this proposal. '

I l

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Attachment 1 Page 25

3. Enclosure (4) recommended changes to ACTION c of Specification 3.3.2 that were not included in the example. used in the June 18, 1990 NRC SER. The reason for the recommendation is to provide a more appropriate action when inoperable instruments are '

discovered in both trip systems. Presently the actions specified in the SER example require that at least one trip system be placed in the tripped condition within one hour for this condition. However, placing a trip system in the tripped condition would in almost all cases isolate an important system, and therefore may not be the best action to take. A more appropriate action may be to trip the inoperable channel (s) without tripping the system. The RBS proposed change therefore requires that the inoperable channel (s) in one trip system, and/or that trip system, be placed in the tripped conditions within one hour, and that the .

inoperable channel (s) in the other trip system be placed in the tripped condition within 12 l hours or 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for RPS and non-RPS instrumentation respectively. These proposed RBS ,

actions are consistent with *the intent of Enclosure (4), but the wording has been changed to be consistent with that being proposed in the RPS Instrumentation section.

Ilasis For No Sienificant IIazards Consideration

?

In accordance with 10CFR50.92, a proposed change to the operating licence (Technical Specification) <

involves no significant hazards considerations if operation of the facm.y in accordance with the proposed change would not: 1) involve a signi5 cant increase in the probability or consequences of any '

accident previously evaluated, or 2) create the possibihty of a new or different kind of accident from ,

any accident previous;y evaluated, or 3) involve a significant reduction in a margin of safety. The proposed Isolation Actuation instrumentation Technical Specification changes are evaluated against each of these criteria below.

1. These proposed changes do not involve a change to the plant design or operation, only the Allowable Outage Time (AOT) and frequency at which testing of the Isolation Actuation instrumentation is performed. Failure of the Isolation Actuation instrumentation itself cannot create an accident. As a result, these proposed changes cannot increase the probability of occurrence of any design basis accident previously evaluated.

As identified in NEDC-30851P, Supplement 2, these proposed changes to the surveillance I test interval requirements for the Isolation Actuation instruments which are common to RPS or ECCS have a negligible (less than 1 %) impact on the average isolation unavailability when combined with the individual valve failure probability, and that the changes to the AOTs has less than a 2% impact. The analyses demonstrate that the individual valve failure probabilities dominate the overall isolation failure probability. As provided in the NRC Staff's Safety Evaluation Report of NEDC-30851P, Supplement 2, these proposed changes would have a very small impact on plant risk. As a result, overall plant safety is not reduced by these proposed changes. I i

l l

as

Attachment 1 Page 26 r

As identified in NEDC-31677P, the proposed changes to the requirements for Isolation Actuation instrumentation not common to RPS or ECCS result in a small decretse of 1.97x10*/ year in the average isolation failure frequency. As identified in the NRC Staff's J Safety Evaluation Report of NEDC-31677P, the NRC agreed that these proposed changes are :

acceptable because the failure frequency impact is minimal. As a result, overall plant safety is not reduced by these proposed changes.

l The small increase in the average failure frequency of the ' instruments common to RPS or ECCS due to the proposed changes to the Isolation Actuation instrumentation requirements is offset by safety benefits such as a reduction on the number of inadvertent test-induced scrams and engineered safety feature actuations, a reduction in wear due to excessive test cycling, and better optimization of plant personnel resources. Hence, the net change in risk '

resulting from these proposed changes would be insignificant. Therefore, these proposed l

changes do not result in a significant increase in either the probability or the consequences -

of any accident previously evaluated.

2. The proposed changes do not result in any change to the plant design or operation, only to the AOT and frequency at which testing of the Isolation Actuation instrumentation ir j

4 performed. Since failure of the Isolation Actuation instrumentation itself cannot create an accident, these proposed changes can at most affect only accidents which have been previously - i evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated

3. As identified above, the proposed changes to the requirements for Isolation Actuations instruments common to RPS or ECCS have a negligible impact on the average isolation unavailability when combined with the individual valve failure probability. The analyses demonstrate that the individual valve failure probabilities dominate the overall isolation failure probability. The proposed changes to the requirements for Isolation Actuation instruments not common to RPS or ECCS decrease their average isolation failure frequency approximately 1.97x10 8/ year.

The small increase in average Isolation Actuation instrumentation failure frequency of the instruments common to RPS or ECCS are offset by the safety benefits such as a reduction on the number of inadvertent test-induced scrams and engineered safety feature actuations, a reduction in wear due to excessive test cycling, and better optimization of plant personnel .

resources. As a result, the NRC Staff's Safety Evaluation Reports for these BWROG reports concluded that these proposed changes wot.ld have a very small impact on plant risk. In addition, RBS has confirmed that the proposed changes to the functional test intervals will not result in excessive instrument drift relative to the current, established setpoints. Therefore, the proposed changes do not result in a significan' reduction in a margin of safety.

Based upon the foregoing, RBS concludes that these proposed changes do not involve a significant hazards consideration.

-l Attachment 1 Page 27 Part V - Other Technical Specification Instrumentation Desedption of Proposed Chances The following changes are proposed *:

1. Technical Specification 3/4 3.4.1. " ATWS Recirculation Pumn Trin System Instnimentation"

a. The surveillance allowable outage time (AOT) of footnote (a) to Technical Specification Table 3.3.4.1-1, "ATWS Recirculation Pump Trip System -

Instrumentation", is being increased from two ilours to six hours.

b. The surveillance test interval (STI) for CH ANNEL FUNCTION AL TEST's specified on Technical Specification Table 4.3.4.1-1, "ATWS Recirculation Pump Trip Actuation Instrumentation Surveillance Requirements", is being increased from hionthly (hi) to Quarterly (Q) for the following Trip Functions:

(a) item 1, Reactor Vessel Water Level - Low Low Level 2, and (b) item 2, Reactor Vessel Pressure - High.

c. Footnote (a) is added to Technical Specification Table 4.3.4.1-1 to (1) clarify the frequency of the trip unit calibration (per SR 4.3.4.1.1) and (2) change the analog trip module calib.ation interval from 31 days to 92 days.

]

2. Technical Snecification 3/4.3.4.2. "End-of-Cycle Recirculation Pumn Trin System Instrumentation"

a. The repair AOTs of Technical Specification 3.3.4.2 ACTIONS b and c.1 are being increased from one hour to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

.he surveillance AOT of footnote (a) to Technical Specification Table l l

3.3.4.2-1, "End-of-Cycle Recirculation Pump Trip System instrumentation", is bemg i l increased from two hours to six hours.

J

c. 'de STI for CH ANNEL FUNCTIONAL TESTS specified on Technical Specification l Table 4.3.4.2.1-1, "End-of-Cycle Recirculation Pump Trip System Instrumentation Surveillance Requirements", is being increased from hionthly (hi) to Quarterly (Q) j for the following Trip Functions:

(a) item 1, Turbine Stop Valve - Closure, and (b) item 2, Turbine Control Valve - Fast Closure.

d. The analog trip module calibration interval specified by footnote "#" to Technical Specification Table 4.3.4.2.1-1 is being increased from 31 days to 92 days.

1

Attachment 1 Page 28 -

3. Technical Spe.; fication 3/4.3.5. " Reactor ' Core Isolation Cooline System Actuation instrumentation"

a. The surveillance AOT of footnote (a) to Technical SpeciGcation Table 3.3.5-1 is being increased from two hoars to six hours.

b. The repair AOTs of Technical Specification Table 3.3.5-1, " Reactor Core Isolation Cooling System Actuation Instrumentation", ACTION 53 is being increased from eight hours to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; and the allowable outage time of ACTION 51 is being identified as 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. The STI for CH ANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.5.1-1, " Reactor Core Isolation Cooling System Actuation Instrumentation Surveillance Requirements", is being increased from Monthly (M) to Quarterly (Q) for the following Functional Units:

(a) item a, Reactor Vessel Water Level - Low Low Level 2, (b) item b, Reactor Vessel Water Level - High Level 8, (c) item c. Condensate Storage Tank Level - Low, and (d) item d, Suppression Pool Water Level - High.

d. The analog trip module calibration interval specified by footpate (a) to Technical Specification Table 4.3.5.1-1 is being increased from 31 days *.o 92 days.

Additional changes to Technical Speci6 cation 3/4.3.5 are proposed in Part VI of this submittal.

4. Technical Specificatipn 3/4.3.6. " Control Rod Block Instrumentation"

a. Footnote (e) is being added to Technical Specification Table 3.3.6-1 to allow Control Rod Block instrumentation channels to be inoperable for up to six hours for surveillance test AOTs.

b. The repair AOT of Technical Specification Table 3.3.6-1 ACTION.63 (new)is being increased from one hour to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Additional changes to Technical Specification 3/4.3.6 are proposed in Part III and Part VI of this Submittal.

5. Technical Soecification 3/4.3.7. "Monitorine Instrumentation"

a. The STI for CH ANNEL FUNCTIONAL TESTS specified on Technical Specification Table 4.3.7.1-1, " Monitoring Instrumentation Surveillance Requirements", is being increased from Monthly (M) to Quarterly (Q) for the following Instrumentation:

-1 i

1

' Attachment 1 i Page 29 (a) item 1.a, Main Control Room Ventilation Radiation Monitor - Local Intake, ;1 (b) item 1.b, Main Control Room Ventilation ~ Radiation -Monitor - Remote -  !

Intake.

6. Technical Specification 3/4.3.9. " Plant Systems Actuation Instrumentation" i l

a. Footnote (a) is being added - to Technical Specification Table 3.3.9-1 to allow j Plant Systems Actuation instrumentation channels to be inoperable for up to six hours l for surveillance test AOTs. )

b. The repair AOT - of Technical Specification Table 3.3.9-1, ' Plant Systems Actuation Instrumentation", ACTION 150.a is being increased from one hour to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, l

c. The STI for CH ANNEL FUNCTIONAL TESTS specified on Technical Specification - j Table 4.3.9.1-1, " Plant Systems Actuation' Instrumentation Surveillance l Requirements", is being increased from Monthly (M) to Quarterly (Q) for the i following Trip Functions: j (a) item 1.a Primary Containment Ventilation System - Unit Cooler A and B, ]'

Drywell Pressure - High, (b) item 1.b, Primary Containment Ventilation System - Unit Cooler A and B, Containment-to-Annulus Delta Pressure - High, i (c) item 1.c, Primary Containment Ventilation System - Unit Cooler A and B, Reactor Vessel Water Level - Low Low Low Level 1,' .

l (e) item 1.d, P;imary Containment Ventilation System - Unit Cooler A and B, .

I Timer, and 1 (d) item 2.a, Feedwater System / Main Turbine Trip System, Reactor Vessel' '

Water Level - High Level 8.

d. The analog trip module calibration interval specified by footnote (a) to Technical Specification Table 4.3.9.1-1 is being increased from 31 days to 92 days.

7. Technical Specification 3/4.4.2.1. "Safetv/ Relief Valves"

a. The STI . for CHANNEL FUNCTIONAL TESTS contained in Surveillance Requirements 4.4.2.1.1.a and 4.4.2.1.2.a are being increase from 31 days to 92 days.

b. Footnote (**) is being added to Technical Specification 4.4.2.1.1 and 4.'4.2.1.2

to allow Safety Valve instrumentation channels to be inoperable for up to six hours for surveillance test AOTs.

l-l 8. Technical Specification 3/4.4.2.2. "Safetv/ Relief Valves Low-Low Set Function" l

l a. The STI for CHANNEL FUNCTIONAL TESTS contained in Surveillance l

\

l i;  !

Attachment 1 Page 30 Requirements 4.4.2.2.1.a is being increased from 31 days to 92 days.

b. Footnote (**) is being added to Technical Specification 4.4.2.2.1 to allow Low-Low Set Function Pressure Actuation instrumentation channels to be inoperable for up to six hours for surveillance test AOTs.

.lustification for Proposed Chances On February 19, 1991 the BWROG submitted Licensing Topical Report GENE-770-06-01, " Bases for Changes to Surveillance Test Intervals and Allowed Outage Times for Selected Instrumentation Technical Speci6 cations" for NRC review. This report provides the justification for the proposed changes identified above. An addendu.n .o this Report was also submitted concurrently (GENE-770-06-02) which provided additional information to support the changes to the RCIC System Actuation Instrumentation.

As noted in GENE-770-06-01, the primary purpose for requesting these changes is to. ensure consistency with the changes proposed for the RPS, ECCS Acturtion Instrumentation, and Isolation Actuation Instrumentation. The instrumentation affected by the proposed changes in Part V of this request consist of either the same or similar instrumentation as that addressed in Parts I through IV of this request. The primary difference is the safety function performed by the instrumentation.

As also noted in GENE-770-06-01, a detailed analysis of the proposed changes that are associated with instrumentation that is common to previously analyzed instrumentation was not performed since the analyses discussed in Parts I through IV bound them. The remaining proposed changes involve instruments which are of similar type to the instruments included in the analyses discussed in Parts I through IV. Existing redundancy of this instrumentation is either comparable to or more extensive ,

than the redundancy of the instruments discussed in Parts I through IV. Further, analyses have generally shown that the most significant contributor to safety function failure probability is associated with the actuated device (such as valves) rather than associated with the actuation instrumentation.

Therefore, the analyses discussed in Parts I through IV of this request can be used to justify the proposed changes identified in this part.

By letter from Charles E. Rossi (NRC) to R. D. Binz (BWROG) dated July 21, 1992, the NRC provided their Safety Evaluation Report of GENE-770-06-01 and by letter from Charles E. Rossi l (NRC) to G. J. Beck (BWROG) dated September 13,1991, the NRC provided their Safety Evaluation Report of GENE-770-06-02. The NRC concluded in each Safety Evaluation Report that the methods 1 and results provided in GENE-770-06-01 and GENE-770-06-02 are acceptable for implementation on i a plant-specific basis. However, each Safety Evaluation Report states that in order for a licensee to i use the generic analyses, the licensee must confirm the applicability of the generic analyses to the plant and confirm that any increase in instrument drift due to the extended surveillance intervals is I properly accounted for in the setpoint calculation methodology. i

i i

Attachment 1 Page 31 l.

With respect to the NRC Staff's concern about confirming the plant-specific applicability of $

GENE-770-06-01 and GENE-770-06-02, the basis for RBS's determination that each of these proposed changes are bounded by the analyses discussed in Parts I through IV of this request are discussed below for each of the affected systems. '*

1. Technical Specification 3/4.3.4.1. " ATWS Rxirculation Pumo Trio System Instrumentation" l The ATWS-RPT instrumentation is part of the mitigation system that initiates in the unlikely event of a scram failure. The trip function is initiated by either high reactor pressure or low reactor water level (Level 2). The ATWS-RPT logic for RBS is two-out-of-two channels per trip system for each Trip Function. Each of the two trip systems initiates a trip of both '

recirculation pumps. The effect of the proposed changes to the ATWS-RPT instrumentation requirements on the reactivity shutdown failure frequency is negligible based on the low average RPS failure frequency (5.4x10-*/ year from NEDC-30851P, page 5-29) and the small change in overall ATWS-RPT function unavailability due to the proposed changes (less than lx102/ demand calculated from failure rates of similar instruments as given in Appendix B and C of NEDC-30851P). .

The Footnote (a) is being added as a clarification to the existing requirements denoted in SR 4.3.4.1.1. The existing trip unit setpoints are currently calibrated on a 31 day frequency.

The footnote is consistent with other Technical Specifications that denote trip unit calibrati9 n frequencies, t

2. Technical Specification 3/4.3.4.2. "End-of-Cycle Recirculation Pumo Trio System  !

Instrumentation" ,

The EOC-RPT is initiated by signals and instrumentation common to the RPS (Turbine Stop Valve closure and Turbine Control Valve low hydraulic pressure). The proposed changes for -

this instrumentation were evaluated in NEDC-30851P for the RPS function. Although the EOC-RPT trip functions were not explicitly identified in NEDC-30851P, these proposed ,

changes can be considered bounded by that analysis. The basis for this conclusion is similar to the basis established in NEDC-30851P, Supplement 2 for the Control Rod Block instrumentation common to RPS. That is, although the Minimum Critical Power Ratio l (MCPR) limit (similar to the consequences of an unmitigated rod withdrawal error), the slight  ;

increase in risk of an MCPR violation due to the proposed EOC-RPT changes is offset by the i safety benefits associated with the proposed changes for the RPS instrumentation.-

3. Technical Specification 3/4.3.5. " Reactor Core isolation Cooline System Actuation f

instrumentation" ,

f The proposed changes to the RCIC system actuation instrumentation were evaluated in the i BWROG analysis of ECCS actuation instrumentation (NEDC-30936P (Part 2)). The RCIC fault tree models and input data were developed for the RBS design (BWR-5/6 Relay). In .j NEDC-30936P (Part 2), the water injection function failure frequency was analyzed as a function of the STIs and AOTs for the ECCS (including RCIC) actuation instrumentation. j i

Attachment 1 Page 32 The RCIC actuation instrumentation surveillance test interval (STI) was changed from one to three months and the associated AOT was changed from one to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for repair and from two to six hours for test. The analysis results are summarized in NEDC-30936P (Part 2);

however, model Technical Specification changes for the RCIC actuation instrumentation were not specifically included in NEDC-30936P (Part 2). These model Technical Specification changes for the RCIC actuation instrumentation were later provided in GENE-770-06-01 and were further discussed in its Addendum GENE-770-06-02.

An analysis was conducted to demonstrate the specific effect of individual changes to the RCIC actuation instrumentation STis on the overall average water injection function unavailability. As noted above, the analysis was performed using the models and input data developed and documented in NEDC-30936P (Parts 1 and 2). In order to determine the specine effect of the STI change on the RCIC actuation instrumentation, the RCIC actuation instrumentation STI was held constant (i.e., STI - one month) while the STI for other ECCS actuation instrumentation was changed to three months. This calculation demonstrated that there is a very small change in the calculated average water injection function unavailability (less than 1 %) for this case when compared with the results of NEDC-30936P (Part 2). The NEDC-30936P (Part 2) analysis results indicated that the effect of AOT changes is significantly less than STI changes. On this basis, a similar negligible change in average water injection function unavailability can be expected when the RCIC actuation instrumentation AOTs (one hour repair and two hours for test) are held constant. Therefore, it can be concluded that the STI and AOT changes to the RCIC actuation instrumentation are justified based on the small effect on the calculated average water injection function unavailability and consistency with comparable changes to the actuation instrumentation for the ECCS subsystems.

The RBS RCIC System was analyzed as part of the plant-specific analysis performed by GE in RE-029, February 1987 (Enclosure 3). As discussed in Part II above, the results of this review indicated there were a total of four differences between RBS's ECCS and RCIC design and those of the generic plant discussed in the topical report. The plant-specific analysis concluded that the differences were bounded by the original analyses performed. Therefore, the generic analysis is applicable to RBS.

4. Technical SpeciGcation 3/4.3.6. " Control Rod Block Instrumentation" NEDC-30851P, Supplement 1 provides the bases for changing the STis for the Control Rod Block instrumentation from one month to three months. Although the above changes to the repair and test AOTs were not explicitly identified in NEDC-30851P, Supplement 1, the same bases used for changing the STis applies to the AOT changes. He reason for this is because analysis indicates that the effect of AOT changes is significantly less than the effect of STI changes. The proposed changes to the AOTs for the Control Rod Block instrumentation are therefore supported by the basis provided in NEDC-30851P, Supplement 1.

r i

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Attachment 1 Page 33

5. Rcimical Specification 3/4.3.7. "Monitorine instrumentation" The Main Control Room Ventilation Local and Remote Radiation Monitoring actuation instrumentation is similar to the Isolation Actuation Instrumentation discussed in NEDC-30851P, Supplement 2 and NEDC-31677P. In addition, the actuation function performed (i.e., closing and opening selected valves) is similar to the function performed by the isolation and ECCS actuation instrumentation. The dominant contributor to the unavailability for this type of function is valve unavailability. Therefore, the analysis of Isolation Actuation Instrumentation provided in NEDC-30851P, Supplement 2 and NEDC-31677P supports similar STI changes to the Main Control Room Ventilation Local and Remote actuation instrumentation.

6. Technical Specification 3/4.3.9. " Plant Systems Actuation Instrumentation" This Technical Specification addresses the requirements for those instruments that provide automatic actuation of the Primary Containment Ventilation System - Unit Cooler A and B and the Feedwater System / Main Turbine Trip System. Each of thme systems are discussed separately below.

a. Primarv Containment Ventilation System - Unit Cooler A and B The Primary Containment Ventilation System actuation instrumentation contains instrumentation common to the ECCS actuation instrumentation, in addition, the actuation function performed (i.e., closing and opening selected valves) is similar to the function performed by the isolation and ECCS actuation instrumentation. The dominant contributor to the unavailability for this type of function is valve unavailability. Therefore, the analysis of Isolation Actuation Instrumentation provided in NEDC-30851P, Supplement 2 and NEDC-31677P supports similar STI and AOT changes to the Primary Containment Ventilation System actuation instrumentation,

b. Feedwater System / Main Turbine Trio System The BWR-6 plant design incorporates a direct scram from High Reactor Vessel Water Level (Level 8) trip instrumentation (included in the RPS instrumentation). The bases for changes to the STIs and AOTs for the reactor vessel water level 8 tnp instrumentation associated with the Feedwater System / Main Turbine Trip System are therefore boundM by the changes to the RPS Reactor Vessel Water Level 8 trip instrumentation p%vided in NEDC-30851P.

't e .,

e f

i

+ .

C' Attachment i Page 34 ,

7. Technical Specification 3/4.4.2.L "Safetv/ Relief Valves" ,

t For RBS, four of the 16 Safety / Relief Valves (SRVs) are required to open in the relief mode (actuated by ADS reactor steam dome pressure logic) and five are required to open in the safety mode (actuating against spring pressure) to prevent reactor vessel overpressurization. r SRV safety mode actuation is diverse from the relief mode actuation. The relief function of the SRVs is performed by three separate sets of logic. Each logic group is actuated by one of two, two-out-of-two reactor steam dome pressurelogic combinations. The first logic group controls the relief function of one valve, the second logic group controls eight valves, and the third logic group controls seven valves. If a relief function logic group should fail (which-requires at least two channel failures), overpressure protection can be provided by the  ;

remaining relief logic groups in combination with SRV actuations in the safety mode.

Based on the level of redundancy, unavailability of the relief valve pressure actuation function is a small contributor to the overall SRV function unavailability. Changes to the STI for the SRV pressure actuation instrumentation will therefore have an insignificant effect on the probability of failure to prevent reactor overpressurization. The STI changes will also be consistent with the STI changes to similar instrumentation iu the ECCS and Isolation Systems.

8. Technical Specification 3/4.4.2.2. " Safety / Relief Valves Low-Low Set Function" The Low-Low Set (LLS) logic for RBS consists of three individual LLS circuit groups which  :

control five LLS SRVs. This logic is designed so that no more than one SRV reopens following a reactor vessel isolation event, ensuring that the containment design basis is met.

After a LLS SRV initially opens in the relief mode, the associated LLS logic is activated and SRV's closing setpoint is lowered such that the SRV stays open longer than without LLS.

Two of LLS circuit groups each control an individual SRV. These two logic circuit groups also lower the SRV's reopening setpoint such that the SRV will open prior to activating additional SRVs in the relief mode. The third logic circuit group controls a group of four LLS SRVs and only lowers their closure setpoints, without affecting their reopening setpoints. j The LLS function can normally be performed by either of the first two LLS logic groups. i Because energization of either SRV solenoid pilot valve results in opening the SRV, both solenoid pilot valves must be de-energized for the SRV to close. Opening of the first two LLS logic groups is accomplished by actuation of one of the two, two-out-of-two SRV relief mode logic trains. Subsequent closure and reopening of these two LLS logic groups is .

accomplished by actuation of a one-out-of-one logic for each solenoid pilot valve. The third LLS logic group opens upon actuation of one of two, two-out-of-two logic trains and recloses upon deactivation of both two-out-of-two logic trains.

Although the LLS logic has an important safety function, its function is not as critical to overall plant safety as the water injection or isolation functions. Therefore, changes to the STis for the LLS pressure actuation instrumentation will have less risk impact on overall plant 3 safety than ECCS and Isolation Actuation STI changes. Existing analyses of ECCS and I Isolation Actuation Instrumentation STI changes can be applied to the LLS logic based on the i

Attachment 1 '

Page 35 use of the same or similar type of components (i.e., relays, transmitters, trip units, etc.),

designed redundancy, and safety significance of the LLS logic. The extensive redundancy-in the LLS circuit logic is comparable with the logic redundancy in the ECCS and Isolation Actuation Instrumentation. Based on this redundancy, similarity of components, and safety function significance of the LLS logic, it can be concluded that the effect of changm for the LLS logic STis is bounded by the basis established for similar STI changes for the ECCS and Isolation Actuation Instrumentation.

%ith respect to the Staff's concern about instrument drift over a 3 month (quarterly) period, the instrument setpoint calculations at R'8S include the effects of instrument drift over 18 months for all instrument loop components. As a result, RBS has concluded that lengthening the CHANNEL FUNCTIONAL TEST interval and analog trip module calibration interval, as applicable, for the affected instrumentation from monthly to quarterly ' vill not result in excessive instrument drift relative to the current, established setpoints. In addition, a CHANNEL CHECK is required at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for those instruments with redundant channels. These routine CHANNEL CHECKS will help identify excessive drift of the Isolation Actuation instrumentation.

Basis For No Sienificant Ilazards Consideration in accordance with 10CFR50.92, a proposed change to the operating license (Technical Specification) '

involves no significant hazards considerations if operation of the facility in accordance with the proposed change would not: 1) involve a significant increase in the probability or consequences of any i accident previously evaluated, or 2) create the possibility of a new or different kind of accident from any accident previously evaluated, or 3) involve a significant reduction in a margin of safety. The proposed Isolation Actuation instrumentation Technical Specification changes are evaluated against

• each of these criteria below. i

1. These proposed changes do not involve a change to the plant design or operation, only <

the Allowable Outage Time (AOT) and frequency at which testing of the associated instrumentation is performed. These instruments are designed to mitigate the consequences j of previously analyzed accidents. Failure of these instruments cannot increase, and is independent of, the probability of occurrence of such accidents. As a result, these proposed changes cannot increase the probability of any accident previously evaluated. As identified ,

in GENE-770-06-01, although not specifically analyzed, these proposed changes are bounded l by the results of the analyses discussed in Perts I through IV of this request. Such analyses have shown that the safety function failure frequency is not significantly impacted by similar proposed changes, in addition, any increase in the probability of failure of these instruments to perform their required functions would be offset by safety benefits such as a reduction in ,

the number of insdvertent test-induced scrams and engineered safety features actuations, a .

reduction in wear due to excessive equipment test cycling, and better optimization of plant l personnel. resources. Therefore, these proposed changes do not result in a significant increase in the probability or the consequences of any accident previously evaluated.

l

L I

Attachment i Page 36

2. The proposed changes do not result in any change to the plant design or operation, only. l to the AOT and frequency at which testing of the associated instrumentation is performed, j As a result, these proposed changes can at most affect only accidents which have been previously evaluated. Therefore, these proposed changes cannot create the possibility of a new or different kind of accident from any accident previously evaluated.  !

3. As identified in GENE-7704)6-01, although not specifically analyzed, these proposed changes are bounded by the results of the analyses discussed in Parts I through IV of this -

l request. Such analyses have shown that the safety function failure frequency is not significantly impacted by similar proposed changes. In addition, any increase in the probability of failure of these instruments to perform their required functions would be offset by safety benefits such as a reduction in the number of inadvertent test-induced scrams and ,

engineered safety features actuations, a reduction in wear due to excessive equipment test -

cycling, and better optimization of plant personnel resources. As a result, these proposed changes will reduce overall plant risk. In addition, RBS has confirmed that the proposed ,

changes to the functional test intervals will not result in excessive instrument drift relative to --

the current, established setpoints. Therefore, these proposed changes do not involve a significant reduction in a margin of safety.

Based upon the foregoing, RBS has concluded that these proposed changes do not involve a significant j hazards consideration.

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Attachment 1 Page 37 Part VI - Technical Specification Chances Relatine to Loss-of-Function issues Description of Proposed Changes The following changes are proposed *:

1. Technical Specification 3/4.3.3. "Emercency Core Cooline System Actuation Instrumentation"

a. The Action Statement of Trip Functions A.I.c, A.I.f, and B.I.e of Table 3.3.3-1 is being revised from ACTION 33 to ACTION 38.

b. The Action Statement of Trip Function A.2.d and B.2.d of Table 3.3.3-1 is being revised from ACTION 31 to ACTION 30.

c. The Action Statement of Trip Function C.I.c of Table 3.3.3-1 is being revised from AGION 31 to ACTION 33.

d. The Action Statement of Trip Function C.I.f and C.l.g of Table 3.3.3.-l is being revised from ACTION 33 to ACTION 39.

c. Table 3.3.3-1, Footnote (e) is being deleted. This footnote is associated with Trip Functions C.1.a and C.1.b.

f. Table 3.3.3-1, ACTIONS 30, 31, 34, and 35 are being revised and new ACTIONS 38 and 39 are being proposed in order to incorporate "Leass-of-Function" checks.

Additional changes to Technical Specification 3/4.3.3 are proposed in Part II of this submittal.

2. Technical Snecification 3/4.3.5. " Reactor Core Isolation Cooline System Actuation Instrumentation" .

a. Table 3.3.5-1, Footnote (b)is being deleted. This footnote is associated with Reactor Vessel Water Level - Low Low Level 2 Trip Function.

b. Table 3.3.5-1, ACTIONS 50 and 52 are being revised in order to incorporate

" Loss-of Function" checks.

Additional changes to Technical Specification 3/4.3.5 are proposed in Part V of this submittal.

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3. Technical Specification 3/4.3.6. "Ccatrol Rod Block Instrumentation"

a. The Action Statement of Trip Functions 5.a and 6.a of Table 3.3.6-1 is being revised from ACTION 62 to ACTION 63.

1 l b. Table 3.3.6-1, ACTION 63 is being proposed in order to incorporate

" loss-of-function" checks.

! Additional changes to Technical Specification 3/4.3.6 are proposed in Part 111 and i Part V of this submittal.

Justification for Proposed Chances In a letter dated July 26,1991, the NRC Staff expressed a concern to the BWROG regarding the proposed generic model Technical Specifications. The changes to repair AOTs as provided in the BWROG Topical Reports (and as generically approved by the NRC) would allow, with certain instrument channels inoperable, a plant configuration which does not have the capability to automatically actuate the respective system / valve (s) to exist for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. During review of proposed changes to individual plants' technical specifications to implement the BWROG Topical Reports, the NRC identified the potential for a loss of scram capability for certain events to exist for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> based on the changes proposed to the Act on Statements for RPS by the BWROG. ,

The NRC concluded that permitting a " loss-of-function" condition to exist for a period of time was unacceptable and that this issue be resolved prior to further approval of proposed changes to RPS repair AOTs on individual plants' dockets.

During the development of the Improved Standard Technical Specifications (NUREG-1434),

loss-of-function was an issue that was specifically addressed. As a result, the Action Statements in NUREG-1434 for instrumentation (that provide automatic actuation function) contain checks to ensure that a loss-of-function condition does not exist. NUREG-1434 was issued by the NRC for implementation by utilities on September 29,1992.

As a result, RBS has completed a review of each of the repair AOT changes proposed herein to identify and eliminate where loss-of-function conditions may be permitted to exist for more than one hour. Additionally, these proposed changes are consistent with the loss-of-function conditions identified in NUREG-1434.

1. Technical Snecification 3/4.3.3. "Emercency Core Cooline System ' Actuation lastrumentation" ACTION 30 has been revised to require a verification, within one hour, that a sufficient number of channels remain operable or are in the tripped condition to maintain automatic actuation capability of either Division I or Division II ECCS and either ADS Trip System 'A' or Trip System 'B'. This will ensure that a loss-of-function condition does not exist. The revised ACTION 30 will require the inoperable channel (s) to be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or it is not desirable to place

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the inoperable channel (s) in the tripped condition, the associated system (s) must be declared inoperable. ACTION 30 currently applies to ECCS and ADS Trip Functions A.I.a, A.I.b,  ;

A.I.d, (MODES 1,2,3), A.2.a, A.2.b, B 1.a. B.I.b, B.I.c (MODES 1,2,3), B.2.a, and  ;

B.2.b. The ADS Reactor Vessel Water Level - Low Level 3 permissive Trip Functions (A.2.d and B.2.d) currently reference ACTION 31. As proposed, ACTION 31 does not ,

provide the option of placing the inoperable channel in the tripped condition. This should be i an acceptable alternative to declaring the associated ADS trip system inoperable. The level 3 signal is provided only as a confirmatory signal to ensure that a low reactor vessel water level condition actually exists. Placing the inoperable channel in the tripped condition should still require receipt of a level I signal to initiate ADS, and placing the channel in the tripped '  !

condition is allowed by NUREG-1434. As a result, the reference . Action for the Reactor Vessel Water Level - Low Level 3 Trip Functions is being changed from ACTION 31 to t ACTION 30. '

ACTION 31 currently applies to Trip Functions A.I.e, A.I.g, A.2.c through A.2.g, B.l.d, ,

B.I.f, B.2.c through B.2.f, and C.I.c. This Action Statement has been revised to require, l within one hour, a verification that a suf6cient number of channels remain operable or are in the tripped condition to maintain automatic trip capability of either Division I or Division 11 ECCS and either ADS Trip System 'A' or Trip System 'B'. This will ensure that a loss-of-function condition does not exist. The revised ACTION 31 will require the inoperable channel (s) to be restored to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or the inoperable channel (s) cannot be restored to operable status, the associated system (s) must be declared inoperable. As identined above, ACTION 31 currently applies to the HPCS Reactor Vessel Water Level - High L.evel 8 Trip Function (C.I.c). However, NUREG-1434 does not require a loss-of-function check to be performed for this Trip Function. As a result, the referenced Action for this Trip Function is being changed to revised ACTION 33 which is consistent with ACTION 31 with the exception that it does not require a loss-of-function check.

ACTION 33 currently applies to Trip Functions A.I.c, A.I.f, A.I.h, A.2.h, A.2.i, B.I.e, B.I.g, B.2.g, B.2.h, C.I.f C.I.g, and C.I.h. As proposed ACTION 33 does not require a loss-of-function check to be performed. Additionally, ACTION 33 does not provide the option of placing an inoperable channel in the tripped condition. However, consistent with NUREG-1434, Trip Functions A.I.c, A.I.f, and B.I.e do require loss-of-function checks.

~

As a result, the referenced Action for these Trip Functions is being changed to a new ACTION 38. This Action will require a veri 6 cation, within one hour, that a suf6cient number of channels remain operable or are in the tripped condition to maintain automatic actuation capability of either Division I or Division II ECCS. This will ensure that a loss-of-function condition does not exist. The new ACTION 38 will require the inoperable channel (s) to be restored to operable status within 7 days. If a loss-of-function condition exists or the inoperable channel (s) cannot be restored to operable status, the associated system (s) must be declared inoperable. The new ACTION 38 is consistent with NUREG-1434 for the associated Trip Functions.

Attachment 1 I

Page 40 i

The current ACTION 33 required the associated ADS valve or ECCS to be declared inoperable if the inoperable channel could not be returned to an operable status. Consistent ,

with NUREG-1434, Trip Functions C.1.f and C.I.g, do not require a loss-of-function check i but would need to require the HPCS system to be declared inoperable if the inoperable'^

channel could not be returned to an operable status. As a result, the referenced Action for j these Trip Functions is being changed to a new ACTION 39. This Action will require the j inoperable channel (s) to be restored to operable status within 7 days. If the inoperable <

channel (s) cannot be restored to operable status, the HPCS system must be declared .

inoperable. The new ACTION 39 is consistent with NUREG-1434 for the associated Trip i Functions.

ACTION 34 has been revised to require a verification, within one hour, that a sufficient number of channels remain operabit or are in the tripped condition to maintain automatic HPCS actuation capability. This will ensure that a loss-of-function condition does not exist.

The revised ACTION 34 will require the inoperable channel (s) to be placed in the tripped i condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or it is not desirable to place the inoperable channel (s) in the tripped condition, the HPCS system must be declared inoperable. ACTION 34 currently applies to HPCS Trip Functions C.I.a and C.1.b. I ACTION 35 has been revised to require a verification, within one hour, that the HPCS pump suction is either aligned or is capable of automatically realigning to the suppression pool.

This will ensare that a loss-of-function condition does not exist. The revised ACTION 35  ;

will require at least one inoperable channel to be placed in the tripped condition (which will automatically realign the HPCS pump suction to the suppression pool) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If.

a loss-of-function condition exists or it is not desirable to place an inoperable channel in the j tripped condition (or realign the HPCS pump suction to the suppression pool), the HPCS system must be declared inoperable. ACTION 35 currently applies to HPCS Trip Functions C.I.d and C. I.e.

Footnote (e) to Table 3.3.3-1 is being deleted. The footnote clarifies the trip system boundary for the four reactor vessel water level (Trip Function C.I.a) and high drywell pressure (Trip Function C.l.b) inputs to the HPCS actuation logic. This footnote was added to ensure that the corresponding Action Statements are implemented properly when one or 1 more channels are declared inoperable. This footnote was necessary because the . I corresponding Action Statement (ACTION 34) currently prescribes the action to be taken.

based on the number of trip systems affected. However, the revised ACTION 34 proposed j herein eliminates the dependence of the action to be taken on the number of trip systems j affected. As a result, this footnote is not longer necessary and is proposed to be deleted.

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2. Technical Specincation 3/4.3.5. " Reactor Core Isolation Cooline System Actuation Instrumentation" The Action Statements provided for RCIC Actuation Instrumentation in NUREG-1434 require  :

a loss-of-function check to be performed when a RCIC automatic initiation instrument -

becomes inoperable. (This applies to the Reactor Vessel Water Level - Low Low Level 2, the Condensate Storage Tank Water Level - Low, and the Suppression Pool Water Level -

High Trip Functions.) ,

ACTION 50 has been revised to require a verification, within one hour, that a sufHcient number of low reactor vessel water level channels remain operable or are in the tripped '

condition to maintain automatic RCIC system actuation capability. This will ensure that a -  !

loss-of-function condition does not exist. The revised ACTION 50 will require the inoperable ,

channel (s) to be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or it is not desirable to place the inoperable channel (s) in the tripped i condition, the RCIC system must be declared inoperable. This Action Statement currently applies to the Reactor Vessel Water Level - Low Low Level 2.

ACTION 52 has been revised to require a verification, within one hour, that the RCIC pump suction is either aligned or is capable of automatically realigning to the suppression pool.

This will ensure that a loss-of-function condition does not exist. The revised ACTION 52 will require at least one inoperable channel to be placed in the tripped condition (which wil1 ;j automatically realign the RCIC pump suction to the suppression pool) within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or it is not desirable to place an inoperable channel in the  !

tripped condition (or realign the RCIC pump suction to the suppression pool), the RCIC system must be declared inoperable. This Action Statement currently appli.:s to the Condensate Storage Tank Water Level - Low and the Suppression Pool Water Level - High Trip Functions.  ;

1 Footnote (b) to Table 3.3.5-1 is being deleted. The footnote clarifies the trip system I boundary for the four low reactor vessel water level inputs to the RCIC actuation logic. This footnote was added to ensure that the corresponding Action Statement was implememed properly when one or more channels were declared inoperable. This footnote was necessary because the corresponding Action Statement (ACTION 50) currently prescribes the action to be taken based on the number of trip systems affected. However, the revised ACTION 50 proposed herein eliminates the dependence of the action to be taken on the number of trip systems affected. .As a result, this footnote is no longer necessary and is proposed to be  ;

deleted. Li

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3. Technical Speci6 cation 3/4.3.6. " Control Rod Illock Instrumentation" I

NUREG-1434 does not provide any specific Action Statements for the individual inputs to the Rod Withdrawal Limiter. However, loss-of-function checks are being proposed for the Scram Discharge Volume Water Level - High and the Reactor Coolant System Recirculation Flow

- Upscale Trip Functions. A new Action Statement (ACTION 63) is being proposed to -

require a verification, within one hour, that a sufficient number of channels remain operable to initiate a rod block by the associated Trip Function. This will ensure that a ,

loss-of-function condition does not exist. The revised ACTION 63 will require at lease one '

inoperable channel to be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If a loss-of-function condition exists or it is not desirable to place the inoperable channel in the tripped condition, a rod block must be initiated.

Basis For No Sienificant Hazards Consideration In accordance with 10CFR50.92, a proposed change to the operating license (Technical Specification) involves no significant hazards considerations if operation of the facility in accordance with the proposed change would not: 1) involve a signiDeant increase in the probability or consequences of any accident previously evaluated, or 2) create the possibility of a new or different kind of accident  !

from any accident previously evaluated, or 3) involve a significant reduction in a margin of safety. '

The proposed Technical Specification changes are evaluated against each of these criteria below.

1. The proposed changes associated with the " loss-of-function" checks ensure a plant -

con 6guration which would have the capability to automatically actuate the respective ,

system / valve (s). These instruments are designed to mitigate the consequences of previously analyzed accidents. Failure of these instruments cannot increase, and is independent of, the probability of occurrence of such accidents. As a result, the proposed changes cannot increase the probability of any accident previously evaluated. The proposed changes do not 3

involve a change to the plant design or operation and do not degrade the capability of the i system (s) to perform its required function. Further, these functions or tripped channel (s) in an isolation logic are not considered as initiators for any accidents previously analyzed. l Therefore, these changes do not signi6cantly increase the consequences of any accident  !

previously evaluated. l l

2. The proposed changes do not result in any change to the plant design and no new mode of plant operation is introduced. As a result, the proposed changes can at most affect only- l accidents which have been previously evaluated. Therefore, the proposed changes do not l create the possibility of a new or different kind of accident from any accident previously evaluated.

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t Attachment 1 Page 43

3. The proposed changes do not involve a significant reduction in a margin of safety since the  ;

required safety function of the inoperable channel (s) will be fulfilled. The allowable Outage ~

Time (AOT) for several trip functions have been increased but only in conjunction with the ,

incorporation of the loss-of-function check which ensures a plant configuration which would - +

have the capability to automatically actuate the respective system / valve (s). Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based upon the foregoing, RBS has concluded that these proposed changes do not involve a significant hazards consideration.

Revised Technical Snecification l The requested revisions are provided in Attachment 2.

Schedule for Attaininz Comnliance River Bend Station is currently in compliance with this specification. The modifications to the license will be implemented within 60 days after receiving the approved amendment.

Notification of State Personnel ,

A copy of this amendment request has been provided to the State of Louisiana, Department of Environmental Quality - Radiation Protection Division.

Environmental Impact Apprnisal Entergy Operations, Inc. (EOI) has reviewed the proposed license amendment request against the criteria of 10CFR51.22 for emiromental considerations. The proposed changes do not involve a '

significant hazards consideration, nor increase the types and amounts of effluents that may be released offsite, nor significantly increase individual or cumulative occupational radiation exposures. Thus, EOI concludes that the proposed change meets the criteria given in 10CFR51.22(c)(9) for a  ;

categorical exclusion fromo the requirement for an Environmental Impact Statement.

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

APPLICA8ILITY: As shown in Table 3.3.1-1.

ACTION: ,

. Wit the number f OPERA 8L hannels le than tred by t Nini-mum RA8LE Chan is per Tr Systes req frement one trip stem, place t inoperabl channel (s nd/or the trip sys in the tr ped ndition within one our.

. With .he n r of OPE channels ess than uired by Minimum OPERA Chan s per Trip stes requ nt for th trip stems, _

place at east o trip sys

• in the ipped con ion with one ur and t a the TION requi by Table .3.1-1.

SURVEILLANCE REQUIREMENTS 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.***

4.3.i.3 The REACTOR PROTECTION SYSTEM RESPONSE TIE 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 la months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific reactor trip systes.. j "An ino le channel M not be laced in the ripped co ition who this \

ould ca Trip F ion to oc r. In these ases, the urable annel.

s 11 be to status thin 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> r the ACT I requir y, Tab 3.3.1- that Trip unction s 1 be taken.

• • The t a system not be p ed in the ipped cond on if thi would cause t Trip F fon to When a t system can plac.ed the-fpped e ition w causing Trip F tion to oce place t trip sy with most rable c is in the ipped cond on; if bo sys have same r of inope le channo place el trip sys in the ripped ition. requi t to place trip sys n the trinned ndition loes not ly to Funct w al Units 10 of T le 3.3.1-1.

• • • Logic Systes Funct onal Test period may be extenose as ioentities oy note 'p' on Table 4.3.1.1-1.

RIVER BEND - UNIT 1 3/4 3-1 Amendment No.8, 47

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INSERTI  :

a. With one channel required by Table 3.3.1-1 inoperable in one or more Functional Units, place the inoperable channel and/or that Trip System in the tripped condition * '

within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

b. With two or more channels required by Table 3.3.1-1 inoperable in one or more Functional Units; i

1. Within one hour, verify sufficient channels remain OPERABLE or tripped * ,

to maintain trip capability in the Functional Unit, and i

2. Within six hours, place the inoperable channel (s) in one Trip System and/or that Trip System ** in the tripped condition *, and

3. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, restore the inoperable channels in the other Trip System to an OPERABLE status or tripped *.

Otherwise, take the ACTION required by Table 3.3.1-1 for tbc Functional Unit.

INSERT 2 An inoperable channel or Trip System need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, if the inoperable channel is not restored to OPERABLE status within the required time, the ACTION  ;

required by Table 3.3.1-1 for that Functional Unit shall be taken.

This ACTION applies to that Trip System with the most inoperable channels; if both Trip Systems have the same number of inoperable channels, the ACTION can be applied to either Trip System.

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i TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRLMENTATION i

TABLE NOTATIONS

- b (a) A channel any be placed in an inoperable. status for up to urs for  ;

required surveillance without placing the trip system in tripped ,

condition provided at least one OPERABLE channel in the same trip systes  !

is monitoring that parameter.

(b) Unless adequate shutdown margin has been demonstrated per Specificatio'n .

3.1.1, the " shorting links" shall be removed from the RPS circuitry prior i to and during the t<me any control red is withdrawn".

(c) An APM channel is inoperable if there are less than 2 LP M inputs per  !

. level or less than 11 LPM inputs to an APM channel. ,

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

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

(f) This function is not required to be OPERABLE when ORYWELL INTEGRITY is (  :

not required. '

(g) With any control rod withdrawn. Not appitcable to control rods removed  !

per Specification 3.9.10.1 or 3.9.10.2.

(h) This function shall be automatically bypassed when turbine first stage  !

pressure is < 147 psig,"* equivalent to THERMAL POWER less than 405 of  !

. RATED THERM d POWER.

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i "NotrequiredforcontrolrodsremovedperSpedification3.9.10.1er3.9.10.2.

• • Te allow for instrumentation accuracy, calibration and drift, a setpoint of i 177 psig turhine.first stage pressure shall be used.

RIVER BEIS - UNIT 1 3/4 3-5

TABLE 4.3.1.1 i .

6 PROTECTION stSTEM 1etSTRtNENTATION SURVEILLANCE RE0u!REENTS se CHAf01EL OPERATIONAL 3 y FWCTIONAL WIT CNANNEL t.MECK FUNCTIONAL TEST CHANNEL CALIBRATION I *I CONDITIONS IN WHICH SURVEILLABICE REQUIRED

, E 1. Intemodiete Neage Monitors: gC)

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s W R 3, 4, 5

b. Insperative MA W MA 2,3,4,5

2. Averses Power Rampe Nealter: IU gg)

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Setdeun S W SA 3,4,5 4

b. Flow Bleoed slaulated ,-

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d. Insperative NA @Q M

3. h eel Steam b R(g)(p) 1,2(j)

Pmesure - Nigh 5 @Q

4. Reacter Wessel Water. Level - A(g)

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5. Reacter Wessel Water Level - R(g) '

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i w

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t, t e s o.

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I W Ml m eE l

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cil a h T T f -

)) )) )

e ab cd WS 9

. 8 1 1 1 A 3 1 (( (( ( -

h Y" fso ,,g , EU w .

TABLE 4.3.1.1-1 (Continued)

.e REACTOR-PROTECTION SYSTEM INSTRtmENTATION SURVEILLANCE REQUIREMENTS

2- .

j5 (f) The LPWes shall be calibrated at least once per 1000 ef fective full power hours (EFPH) using the TIP syst e.. .

i (g) . Calibrate Rosemount unit setpoint at least once per days. g g

j (h) Verify asesured to be less than or equal to es 11shed drive flow at the existing flow /

.. control valve post (1) This calibretten shall coasist of verifying the simulated thermal power time constant is within the lietts specified la the COLA.

(j) This function is not required to be OPERABLE when the reactor pressure vessel head is removed per Specificatten 3.18.1.  ;

(k) With asqy control ved withdraun. IIst applicable to control rods removed per Specificatten 3.9.10.1 or -

3.9.10.2.

(1) This functlanlls not required to be.0PERABLE when ORYWELL INTEGRITY is not required per Specifica-tien 3.18.1 (c) _ Verify the Turtlas typass Valves are closed when THEW 44L POWER is greater than or equal.to 40% RATED

. THEMIAL peter..

. (a) The CHAISEL FINICTI9NAL TEST and CHAleIEL CALIBRATION shall include the turbine first stage pressure - '

- instruments.

(o) The CHAlgEL CALIBRATIost shall exclude the flow reference transeitters; these transeitters shall be calibrated at least once per 18 months. .

. (p) This period agy he extended to the first refueling outage, not to exceed 9-15-87. .

4 t

e 4

4

_ . . . . _ . .. _ . . _ - . . . . .. . . . . -- . . _ _ ....._..; ..._.,..;, _ . _ _ . .~-...___.._.-.../

INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CON 0! TION FOR OPERATION ,

i 3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1  !

shall be OPERA 8LE with their trip setpoints set consistent with the values shown  !

in the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICAPILITY: As shown in Table 3.3.2-1.

ACTION:

a. With an isolation actuation instrumentation channel trip setpoint  !

less conservative than the value shown in the Allowable Values column of Table 3.3.2-2, declare the channel inoperable until the channel is restored to OPERA 8LE status with its trip setpoint adjusted .

consistent with the Trip Setpoint value. Nsan S

. With he numb of OPE LE chan  : less n requ bytheKinimum\

OPE E Channe per Tr Systes utremen for one rip sys place t inopera la chann (s) a that tr systes n the tr ed

, conditio within hour.

c. W h the n r of OP LE cha is less requ by t Minimum OP 8LE Chan is per ip Syst requir t for bo trip s tems, plac at least ne trip stes** i the trip condit n withi one hour a take ACTION. quired b Table 3. -1.

2 N

be plac in the this

\

inoper le 1 need ipped co ition wo 1d ca the Trip unttion occur. In these ses, inoperabl channel sha be to LE s tus with 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> r the ON requi by Table .3.2= that p Fune on shall taken.

The tri systes not placed the tr cond fon if s would c e Trip- fan occur. When a ip sys can be p ad in tripped-co ition thout ing the Trip F tion to , p1 the tri system wit the st i rable is i tho'tri condi on; if sys have the same ro inoper e channe , place ither t system the tr condit n.

)

RIVER 8END - UNIT 1 3/4 3-10 Amendment No. 47

I 5

INSERT 3

b. With the number of OPERABLE Channels less than required tiy the Minimum OPERABLE Channels per Trip System requirements for one Trip System, .

1. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Trip Functions 1.b,2.b,3.b,6.c,6.e, and 6.f, and

2. Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Trip Functions other than 1.b,2.b, 3.b,6.c,6.e, and -

6.f, place the inoperable channel (s) and/or that Trip System in the tripped condition *

c. With the number of OPERABLE Channels less than required by the Minimum OPERABLE Channels per Trip System requirements for both Trip Systems,

1. Within one hour, place the inoperable channel (s) in one Trip System and/or -

that Trip System ** in the tripped condition *, and

2. Within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Trip Functions 1.b, 2.b, 3.b, 6.c, 6.e, and 6.f, and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Trip Functions other than 1.b,2.b,3.b,6.c,6.e, and 6.f, place the inoperable channel (s) in the other Trip System in the tripped condition

• An inoperable channel or Trip System need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, if the inoperable channel is not restored to OPERABLE status within the required time, the ACTION required by Table -

3.3.2-1 for that Trip Function shall be taken.

• • I This ACTION applies to that Trip System with the most inoperable channels; if both Trip ;

Systems have the same number of inoperable channels, the ACTION can be applied to either  ;

Trip System.  ;

i I

i

'l l

I l

l

4 TA8LE 3.3.2-1 (Continued).

' IS01.ATION ACTUATION INSTRUMENTATION ACTEON NOTES '

• • When handling irradiated fuel in the Fuel Building. '

May be bypassed with reactor mode switch not in Run and all turbine stop valves closed.

The valve groups Ifsted are designated in Tables 3.6.4-1 .6.5.3-1.

(a) A channel may be placed in an inoperable status for up to urs for.

required surveillance without placing the trip system in tripped condition provided at least one other OPERA 8LE channel in the same trip systes is monitoring that parameter. -

(b) Also actuates the standby _ gas treatment system.

(c) Also actuates the sain control room air conditioning system in the emergency mode of operation.

(d) Also trips and isolates the air removal pumps.

(e) Also actuates secondary containment ventilation isolation dampers per 4 Table 3.6.5.3-1. -

(f) Manual initiation of SLCS pump C0018 closes 1G33*MOVF001, and manual initiation of SLCS pump C001A closes 1G33*MOVF004.

(g) Requires RCIC system steam supply pressure-low coincident with drywell pressure-high.

(h) Also starts the Fuel Building Exhaust Filter Trtins A and B.

(i) Also starts the Annulus Mixing Systaa. .

(j) Also actuates the containment hydrogen analyzer / monitor recorder.- 4 (k) Manual initiation isolates the outboard steam supply isolation valve only and only following a manual or. automatic initiation of the RCIC system.

(1) Valve 1E22*M0VF023 does not isolate on the manual initiation. ,

l a

'I I

1 9

a-1 RIVER REMO - UNIT 1 3/4 3-18

TABLE 4.3.2.1-1 m

j 150LATIONACTUATIONINSTEMNTATIONSURVEILLANCEREQUIREMENTS n

CHA M L OPERATIONAL

e. "

FUNCTIONAL CHAlelEL CONDITIONS IN WHICH g CHA801EL CHECK. TEST CALIBRATION SURVEILLANCE REQUIRED TRIP FtBICTION

1. PRIMRY CSRF T I m ATION

']

• e. Reacter Wessel tinter Level -

" Law Law tavel 2 5

~

@Q R(b)(c) 1, 2, 3

b. Brywell Pressure,- Nigh 5 @Q R(b) 1, 2, 3

c. Centatament P"'To Isolatten Radletten - mgh 5 @G A 1, 2, 3

2. MAIN STEAM LIIE ISOLATIst

a. Reacter Wessel 1Anter Level -

y Law Law Law Level 1 5 @Q R(b)(c) 1, 2, 3 i ~.,, b. Noin Steen Line Radiatten -

Nigh 5 @Q RI '} 1,2,3 g

c. l'ain Steen Line Pr:ssure -

Low 5 7Q R(b) y

d. Main Steen Line Flow - Nigh 5 7Q R(b)(c) 1, 2, 3 1, 2**, 3**

e. Condenser Vacuus - Low S 7G R(b)

Main Steam Line Tunnel f.

Temperature - High 5 [G -

R 1, 2, 3

g. Main Steen Line funnel

& Temperateen - Nigh 5 @O R 1,2,3 f h. Moln Stesa Line Aree S @G R(b) 1, 2, 3

& Temperature-Nigh I (Turbine entidine) f.

?

e 6

g TABLE 4.3.2.1-1 (Continued)

.c '

E ISOLATICII ACTMTIOld INSTMBENTATION SURVEILLANCE REQUlWUTS

=

Q CNMBEL OPERATIONAL CNMRIEL FUNCTIONAL CHANNEL COMITIONS IN WICH TRIP FWICT10ll CNECE TEST CALISRATION SgRvEILLANCE E 9fIK O l

3. SECNBARY CONTAIIeWT ISOLATIGII g l w e. Reacter Wessel Water G

Level - Law Law Level 2 5 1, 2, 3 l

b. Brywell Pressere - Mgh 5 Q R((b)(c)

R b) 1, 2, 3

c. Feel telldlag Youtilatten d.

Eshaust Badletten - Nip Reacter Building Ansolus 5 @G R *  !

Weatiletten Enhoust tedletten - Nigh 5 @Q R 1,2,3

54. REACTOR WTER CLEAlar SYSTBI 150LAT10N Y e. A Flow - Nigh 5 @Q R 1,2,3

b. A Flow Tiene m FQ Q 1, 2, 3

c. Egslyment Area Temperatore -

Nigh 5 FG R 1,2,3

d. Egelpment Area A Temperature - Nigh 5 7G R 1, 2, 3

e. Reacter Wessel teater IbIIcI Level - Law Law Level 2 5 hG -

R 1, 2, 3

f. Anta 5tmas Llas Tunnel Ambient Temperature - Nip 5. @Q R 1,2,3

g. Rela Steen Line Tunnel E A Temperature - Nigh 5 G R 1,2,3 i ,,. SLc5 i.itiette. . @& am. 1,27

? .

_- ___________________.-.--4 . . . _ _ _ _ _ . . _ _ _ - _ _ . - _ - - , . , . . - _,.- _ . - e.,._. - . . _ _ . _ - . _ , . _ - . . -- . . _ _ -- _ _ _ ~ _ . _ - - _ _ _ . - . - ,

(

55 I j'mI ill 5 5 5 5.:: ::  :: : :: :::::: .

'i ll t . t t . . . . . . .tt .

ll e e er y_1 e e e e e l

hk b th @e efpgk@@eebhQ fa .gllg .

1

+

3 a l . . .. l

{

1;5 yg igl 1 e i . l v ii i 11 l

!i l aIj  !

i l

1 1.

I.  :

!:i ,. p" l j 1 . 1.=

11 . 1 i"13j.  !.

h, t"5 i

I 1 Ajs

[

5 i:lli s 1111111 e  :

1111i-1i11iiIll 3

,,,a. l If.,a , , c . ,

4 t 3/4 3-28 RIVER BEND - UNIT 1 Y  :

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION' INSTRWENTATION SURVEILLANCE REQUIROENTS '

h CHANNEL OPERATIONAL CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WICH TRIP FW CTION CHECK TEST CAL 1BRATION SURVEILLANCE REQUIRED l ,

6. NN SYSTEN Im .-

! a. _ E-speset Area Ambient

@O i

-* Temperature - Nigh 5 R 1,2,3

b. AMR Egelpment Area c.

A Temperature - Nigh Reactor Vessel teater Level -

5 ,

@O R 1,2,3  ;

Low Level 3 5 hO R Ib) 1, 2, 3  ;

d. Reacter Vessel Water Level -

Law Law Law Level 1 5 70 R ID)(dI 1, 2, 3

e. Reacter Wessel (Nat Cut-in Permissive) Pressure - High 5 G R(b)(c) * '

y f. Dryuell Pressure - High 5 Q R(b)(d) 1, 2, 3 l y

=

7. MANUAL INITIATION NA hG MA 1,2,3

• When hand 11mg irradiated fuel in the Fuel'Suilding.

• • When the reacter made switch is in Run anWer any turbine step v is apen.

(a) Each train er logic channel she11 he tested at t. r (b) Calibrate trip unit setpoint at least once per -

(c) May be entended to the first refueling estage, s 1 begin 9-1 .

(d) May be extended to the completten of the first refueling outage, scheduled te begin 9-15-87.

e 6

. ~ , . _ . . _ . . . _ _ _ , _ _ . . _ _ . - , _ . . . . . . . , . _ . .. _ . . . . _ . _ _ . _ _ _ _ - . _ , _ _ _ _ _ . . . . . . . _ _ . , _ . . _ - _ . . _ _ , . . . . - _ . , _ . _ . . . . . .__.,.,__,._,_.......____m._ _ _ . _ _ _ _ . . _ ,

, my TA8tE 3.3.3-1 0 .

g EMERGENCY CORE CbOLING SYSTEM ACTUATION INSTRUMENTATION E . MINIMUM OPERA 8LE APPLICA8tE

$ CHANNELS PER I *)

OPERATIONAL *

. TRIP FUNCTION' . TRIP FUNCTION CONDITIONS ACTION A. DIVISION I TRIP SYSTBI H- 1. RHR-A (LPCI ISOE) & LPCS SYSTEM

a. Reacter Wessel idater Level - Low Low Low Level 1 2 1, 2, 3, 4*, 5* 30

b. Drywell Pressure - High 2 1,2,3 g

c. LPCS Pump Discharge Flow-Low (8ypass) 1 1, 2, 3, 4*, 5*

d. -Reacter Wessel Pressure-Low (LPCS/LPCI Injection 4 1,2,3

, Valve Permissive) 4*, Sa 32

e. -LPCI Pump A Start Time Delay Relay 1 1, 2, 3, 4* , 5* 31 g

'w f. LPCI Pump A Discharge Flow-Low (Bypass) 1 1, 2, 3, 4 * , 5*

). g.

h.

'LPCS Pump Start Time Delay Relay Manual Initiation 1

1/ system 1, 2, 3, 4* , 5" 1, 2, 3, 4", 5* 33 w

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A"#

a. Reactor Vessel idater Level - Low Low Low Level 1- 2 1,2,3 30

h. Drywell Pressure - High 2 1, 2,- 3 30

c. ADS Timer .

I 1, 2, 3

d. Reactor Vessel Water Level - Low Level 3.(Permissive) 1 1,2,3

e. LPCS Pump Discharge Pressure-High (Permissive) 2 1,2,3 q

f. LPCI-Pump A Discharge Pressure-High (Permissive) 2 1,2,3 31 .'

g. ADS Drywe11 Pressure Bypass Timer 2 1,'2, 3- 31

h. ADS Manual Inhibit' Switch. I 1,2,3 33

1. Manual Initiation 2/ system 1, 2, 3 33 e

h'

TABLE 3.3. 3-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION as HINIMUM OPERA 8LE APPLICABLE E CHANNELS PER OPERATIONAL TRIP FUNCTION I "I CONDITIONS ACTION 7 TRIP FUNCTION 8: DIVISION II TRIP SYSTEM w 1. RHR B & C (LPCI N00E)

IDI 5* 30

a. Reactor Vessel Water Level - Low Low Low Level 1 2 ID) 1, 2, 3, 4*,

b. Drywell Pressure - High 2 1, 2, 3 30

c. Reactor Vessel Pressure-Low (LPCI In.jection Valve 4 1,2,3 30 Permissive) 4*, 5* 32

d. LPCI Pump B Start Time Delay Relay 1 1,2,3,4*,$^ 1 g

e. LPCI Pump Discharge Flow - Low (Bypass) 1/ pump 1, 2, 3, 4*, 5*

f. LPCI Pump C Start Time Delay Relay 1 1,2,3,4*,5*

g g. Manual Initiation 1 1, 2, 3, 4 * , 5* 33 Y 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"#

M '

a. Reactor Vessel Water Level - Low Low Low Level 1 2 1,2,3 30

b. Drywell Pressure - High 2 1,2,3 30

c. ADS Timer 1 1,2,3 1 Reactor Vessel Water Level - Low Level 3 (Permissive) 1,2,3 D

d. 1

e. LPCI Pump B and C Discharge Pressure - High (Permissive) 2/ pump 1, 2, 3 31

f. ADS Drywell Pressure Bypass Timer 2 1,2,3 31

g. ADS Manual Inhibit Switch 1 1,2,3 33

h. Manual Initiation 2/ system 1, 2, 3 33 I

)

TABLE 3.3.3-1 (Continued)

ENERGENCY CORE COOLING SYSTEM ACTUATION INSTRLSIENTATION to MINIMlat OPERA 8LE APPLICABLE CNAIOGELS PER OPERATIONAL h_ g) ColelTIONS ACTIO98 TRIP FUNCTIO 18 TRIP FLNICTION .

g C. OlVISIO11 III TRIP $YSTEM U 1. HPCS SYSTEM

" a. Reacter Wessel nieter Level - Lou Low Level 2 4 II 1, 2, 3, 4*, $*

b. Drywell Pressure - High 4(b)

C 1, 2, 3

c. Reacter Wessel Water Level-High Level 8 2 1, 2, 3, 4*, 5*

d. Condensate Storage Tank Level-tow 1, 2, 3, 4*, 5* 35 2(d 2

d) 1, 2, 3, 4*, 5* 35

e. Seppression Peel ideter Level-High

f. Pump Bischarge Pressure-High'(Sypass) 1 1,2,3,4*,5*

g. HPCS System Flow Rate-Law (Permissive) 1 1, 2, 3, 4*, 5*

h. Manuel Initiatten 1 1,2,3,4*,5* 33 U

• HINIORDI APPLICABLE TOTAL NO. CHA000ELS OPERABLE OPERATIONAL y ,

0F CHAfeIELS TO TRIP CHA000ELS CoselTIONS ACTION w

D. LOSS OF POWER

1. Divisions I and II

. 4.16 kw Staney. Sus 3/ bus 2/ bus 3/ bus 1,'2, 3, 4**, 5** 36 a.

underveltage (Sustsined Underveltage) 36 2/ bus 3/ bus 1, 2, 3, 4**, 5**

b. 4.15 kw Stoney Bus Under- 3/ bus voltage (Dograded Voltage) .

2. Division III 1/ bus 2/ bus 1, 2, 3, 4**, 5** 37

a. 4.16 kw Staney Bus under- 2/ bus l.

weitage (Sustained

' underveltage)- 5** 36 2/ bus 2/ bus 1, 2, 3, 4**,

b. 4.16 kw Staney Bus Under- 2/ bus voltage,(Oegraded Voltage) ,

i,

-See footnotes en'next page l.

j . .

o

s.

TA8tE 3.3.3-1 (Continued)

EMERGEdY CORE COOLING SYSTEM ACTUAUON INSTRtMENTATION (a) -A channel may be placed in an inoperable statss for up to during periods of required

$ survalliance without placing the trip function in the tripped condition provided at least one other OPERABLE channel in the same trip function is monitoring that parameter.

e (b) Also actuates the associated division diesel generator.

3 H

(c) Provides signal to close- HPCS injection valves only.

(d)- Provides signal to apen NPCS suppression pool suction valve only. _ ..

idhen the syssaus Tu regulred to De DPERABLE per Specif' canon 3.5.7 or 3.3.J.

Required when ESF equipeent is required to be OPERABLE.

Not required to be OPERABLE when reytor steg, M pressure js less than or equal to 100 psig.

w '

Y Y

=

l

i TABLE 3.3.3-1 (Continued) ]

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION i I

ACTION ACT. ION 30 - With.

Mini number OPERA 8 OPERA 8L Channels er Trip unctio requir channel less th n requ ed by nt:

e ') j l

l l  ;

%ft.M.e a. With o channel i perabl , place 'ino rable c annel r g 1 p in the ripped c ition thin o hour

• or deci e the. .;

y,g 4 3

_U '.b assoc tad syst

-With sy- as inope re the one che el i 1e.

inoper l e'.

rabl e', clare e ass iated t

ACTION 31 - W1 t n ro OPE LE' nne s le than quTre by th  !

(tipm M i ERA 8 Cha is er Tr p Fu tion utr t, d a I a ss 5t /.

wim ated sy ten EC inope ble. - I i v ereT 5 -

A ION 32 -

With the number of OPERABLE channels less than the Minimum CPERABLE ,

Channels per Trip Function requirr ent, g the inoperable -  ;

channel in the tripped condition within ---r-g ACTION 33 - With the number of OPERABLE channels less than required by the .

Minimum OPERABLE Channels per Trip Function requirement, restore l the inoperable channel to OPERA 8LE status within urs or #

declare the associated ADS valve or ECCS inoperab1

~ - - .__ _

g

• ACTION 34 - With the. r f OPE LE c is le than utred y the Mi em ERA 8 Chan s per ip F ion uiremen :

A T*4 . F r one rip'sy , p1 ce tha trip s tem in he tri pod r* or 1 %gg.T (, inope ondi on with one lace the HPC syst

~

able

.b For th tr _

sys _ _ _, dec1 re the PCS sys ino erabi . l

~

2 _

is 1 ss TION 35 - W1 e of OPERAS c n - 1rea t  !

gp i LE hannel per ip F ti requ n , p1 e i<  ;

t st i rabl chan 'in t ondi on w hin'

_ro __ 1ere .sys 1- rabl .

7 .___, _ _

{

Action 34 - With the.neber of OPERABLE channels one less than the Total Nueber of Channels, place the inoperable channel in the tripped -

conditten within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> *; operation may then continue until per- ,

formance of the next required CNANNEL FUNCTIONAL TEST. 'Otherwise,.

declare the associated emergency diesel.' generator inoperable and take the ACTION required by Specification-3.4.1'.1 or 3.8.1.2.'as. .

appropriate.

• ACTION 37 - With the number of OPERABLE channels less than the Total Number. l of Channels, declare the associated emergency diesel generator ,

inoperable and take the ACTION required by Specification 3.8.1.1

• E ' ** ***?' * ** * ~

--- ~ -

e _ _

-_ ._ _ )  ;

"The provisions of Specification 3.0.4 are not applicable.  ;

RIVER BEND - UNIT 1 3/4 3-35

• r I

w- -

INSERT 4 ACTION 30 - With the number of OPERABLE channels less than required by the Minimurn j OPERABLE Channels per Trip Function requirement, verify within one hour that a sufficient number of channels remain OPERABLE or are in the tripped condition to maintain automatic actuation capability of either Division I or Division II ECCS and either ADS Trip System "A" or Trip System "B", and place the inoperable channel (s) in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />'. Otherwise declare the associated system (s) inoperable.

INSERT 5 ACTION 31 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that a sufficient number of channels remain OPERABLE or are in the tripped condition to maintain automatic actuation capability of either Division I or Division II ECCS and either ADS Trip System "A" or Trip System "B", and restore the inoperable channel (s) to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Otherwise declare the associated ADS trip system (s) or ECCS inoperable.

INSERT 6 ACTION 34 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that a sufficient number of channels remain OPERABLE or are in the tripped condition to maintain automatic HPCS actuation capability, and place the inoperable channel (s) in the tripped condition within 24 houts . Otherwise, declare the HPCS system inoperable.

INSERT 7 ACTION 35 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that the HPCS pump suction is either aligned or is capable of automatically realigning to the suppression pool, and place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />'. Otherwise, declare the HPCS system inoperable.

JNSERT 8 ACTION 38 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that a sufficient number of channels remain OPERABLE or are in the tripped condition to maintain automatic actuation capability of either Division I or Division II ECCS, and restore the inoperable channel (s) to OPERABLE status within 7 days. Otherwise declare the associated system (s) inoperable.

INSERT 9 ACTION 39 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel (s) to OPERABLE status within 7 days. Otherwise declare the HPCS system inoperable.

f .

t TABLE 4.3.3.1-1 -

l n l

$n DERGENCY CORE C00LIIIG'#SYSTEN ACTUATION INSTRUNENTATION SURVEILLANCE REQUIREMENTS I

e. CHAISIEL

! OPERATIONAL Q CHAlelEL FUNCTIONAL CHANNEL CONDITIONS FOR tellCH TRIP FWICTION CHECK TEST CALIC2ATION

, SURVEILLAflCE REQUIRED E A. DIVISIGIl I 1 RIP SYSTBI .

M 1. _ A (Isu.a .___J AIS LPCS SYSTEM e a. Neocter Wessel IInter Level -

Law Low Law Level 1 S G R(a)(b) 1,2,3,4*,5*

b. Dryuell Pressure - High S Q R(a)(b) 1, 2, 3

c. LPCS Pimp Stocharge Fleir-Low S Q R I 1,2,3,4*,5*

d. Descter Wessel Pressure-Low 5 Q R II 1,2,3,4*,5*

(LPCS/LPCI Injection Valve Permissive)

e. LPCI Pump A Start Time Delay -

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

t' f. LPCI Pimp A Discharge Flow-Lew 5 Q Q(a))(b)

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

• g. LPCS Pump Start Time Delay NA Q q(b) 1,2,3,4*,5*

Y Delg  !

$ h. Manuel Initiation MA R(b) NA 1, 2, 3, 4*, 5* ,

2. AUTWETIC DEPRESSURIZATION SYSTEM IRIP 3Y3stps "A"# ,

s. Bernster Vessel Water Level -

Law Law Low Level 1 S. @ RI *I 1,2,3

b. Drywell Pressure-Migh S Q RI ") 1, 2, s

c. ADS Tlear NA -

Q 1, 2,

d. Reacter Wessel Water Level - *

(g e.

Lou Level 3 LPCS Pump Discharge 5 hQ R(*) 1, 2 '5

3 f.

Pressure-High LPCI Pimp A Discharge S

[ Q- RI ") 1,2,k c

a Pressure-Migh 5 O RI ") 1, 2

g. ADS Drywell Pressure Bypass MA G q 1, 2, 3 E Tleer h h.

1.

ADS Manuel Inhibit Switch Manuel Initiation NA MA

@G R

MA NA 1, 2, 3

' 1, 2, 3

/

s

___.____________.__________-._______._________.___________m_________m_______.___m __..__________.__._.__.___.____.a-.-

__ .m4-,.,m - - , . - - . - - . _ , . _ - . ~ .

a

=

TA8LE 4.3.3.1-1-(Continued) ve- E V CDRE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL g CHAletEL FUNCTIONAL CHANNEL CONDITIONS FOR ndHICH g CHECK TEST CAL 18 RATION SURVEILLANCE REGUIRED TRIP Ft31CTION -

E 8. DIVISION II TRIP SYSTBI m -

w 1. WW 8 AIS C (LPCI IRIBE) ,

a. Anector Wessel tinter Level - O Rf*, 1,2,3,4*,5* i S

Law Osw Law Level 1 Q 1, 2, 3

b. Drywell Pressure - Nigh S R(,)(g 1, 2, 3, 4* , 5*

c. Deacter Wessel Presserw-Lew 5 G R (LPCI Indoction Velve Permissive)

, d. LPCI Pump B Start Time Delay Q Q(g 1, 2, 3, 4*, 5*

NA Relay 5 G R a 1, 2, 3, 4* , 5*

4:'

e.

f.

LPCI Pump Bischarge Flow-Low LPCI Pump C start Tlee Delay MA Q Ql(b) 1,2,3,4*,5*

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

MA R(b) 2 g. Manual Initiation

2. - AUTWSTIC OEPRESSURIZATICII SYSTEM IRIr 3Y35tR e e

a. Reacter Wessel % Aster Level - O R(g,)3 1, 2, 3 S 8 Law Law Law Level 1 & -

R 1,2,3 Drywell Pressure-Migh 5 i b.

c. ADS Timer

- NA a Q 1, 2, 3

d. Reector Wessel lister Level - RI ,I 1,2,3 f Law Level 3 5 @Q g e. LPCI Pump 8 and C Discharge R(,) 1, 2, 3 g Pressure-Migh 5 @Q ADS Drywell Pressure Bypass 5 f.

Tiser MA CO (j G Q

MA 1, 2, 3 1, 2, 3 NA E g. ADS Itanual Inhibit Switch R NA 1, 2, 3 MA

'

• h. Manuel Initiation

_ _ _ _ _ _ _ _ _ _ _ _ . -..m_..____m.-..m__-._.__.._.__._ma_....____-.m___.____-.- - _ _ __ . . _ _ _ _ _ _ __m__u- m _2.m_ _ _'" _____m__m ' __w--_aw.emrg% Am-eu >m

_.77rytip-T-v4_-er f ami wWw-eT-e_e.w<p.eb-* - * -w'yvM-*Yrws-=y--'-'7 e *7-1r

b

, TABLE 4.3.3.1-1(Continued) 3

- EERSDICT CORE COOLING SYSTEM ACTUATION INSTRINNTATION SURVEILLANCE REQUIREMENTS ,

CHANNEL OPERATIONAL CHAINIEL FUNCTIONAL CHANNEL CONDITIONS FOR lettCH h TRIP FINICTIM . CHECK TEST CALIBRATICII SURVEILLAIICE REQUIRED C. DIVISIGII III TRIP STSTW .

Q 1. NPCS SYST M -

• • a. Reacter Wessel teater Level - p

[ aQ

. Law Low Level'2 5 Rh ',y 1. 2. 3. 4* 5*

b. Brywell Pressure-Nigh 5 I R '

1. 2. 3

c. Reacter Vessel Mater Level-High d.

Level 3 - .

Condensate Steroge Tank Level -

S hQ R(,) 1. 2. 3. 4*, 5*

R(,)

Low

e. Suppressten Peel unter

S @G 1. 2. 3. 4*. 5*

c, .

. . Level - Nigh S O R i

1. 2. 3. 4*. 5*

) f. Pump Discharge Pressure-High 5 a R 1. 2. 3. 4*, 5* ,

g. MPC5 System Flow Rate-Lew S R 't. 2, 3. 4*. 5*  !

w 1 fi. Manual Initiation MA NA 1. 2. 3. 4*, 5*

D. _ LOSS OF POWER

1. 'Dtvistens I and II

a. 4.16 kv Standby tus Under- S M Id 1, 2. 3. 4** 5** -

t voltage (sestained under-I

b. 4 6 Standby sus under- S M .R(b) 1. 2. 3. 4** 5** l 1

l voltage (segradedVoltage)

2. Divisten'III i

.h a. 4.16 kw Stan ey sus under- S

~

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

g voltage ($mstained Under-voltage) g

b. 4.16 kv.Staney Bus Under- '

voltage (Degraded voltage) .5 M R 1. 2. 3. 4,,. 5,,

1. IIot required to be OPERABLE when reactor steam dame pressure is less than or equal to 100 psig.

• When the systes is required .to be OPEftAOLE per Spectfication 3.5.2.

• • - -Required when ESF equipment is required to be Of,(RA8LE.

'(a) 'Callbrate trip untt-setpoint at-lesst once perGysays.

g <

(b)' May be extended to the completion of the first refueling outage, schedule.

- _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ = _ - _ _ _ _ _ _ _ - . _ _ _ - _ - .___. _.~._ - -.. . . - . . . . -- . . . . _ . . - . - - - . . - . .. . :

IABLE 3.3.4.1-1 5

li ATWS RECIRCUL ll0N PUMP TRIP SYSTEM INSTRUMENTATION

=

R MINIMUM OPERABLE C g LS PEN g TRIP FUNCTION TRIP SYSTEN c 1. Reactor Vessel Water Laval - 2 5n Low Low Level 2 w 2. Reactor Vessel Pressure - High 2 (o

(a) One channel may be placed in an inoperable status for up to ours for required survelliance provided the other channel is OPERABLE.

'f a

f e

6 .

.. -, . . . m . .. - . . . . . . . . _ , . . . . . . . . ...-

4 TABLE 4.3.4.1-1 ATWS RECIRCULATION PUMP 1RIN ACTUATION INSTRtMENTATION SURVEILLANCE REQUIREMENTS g CHANNEL CHANNEL FUNCTIONAL CHANNEL g TRIP FUNCTION CHECK TEST CALIBRAll0N 5

1. Reactor e ss.1 pater Level -

Low Low Level 2 s

@c @

2. Reactor Vessei Pressure - High 5

@Q b

Y t

(a) Calibrate trip unit setpoint at least once per 92 days.

s. '

e

INSTRUMENTATION END-0F-CYCLE RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION l LIMITING CONDITION FOR OPERATION f

\

3.3.4.2 The end-of-cycle recirculation pump trip (EOC-RPT) system instrumen-

{

tation channels snown in Table 3.3.4.2-1 shall be OPERABLE with their trip j setpoints set consistent with the values shown in the Trip Setpoint column i of Table 3.3.4.2-2 and with the END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM .

RESPONSE TIME as shown in Table 3.3.4.2-3. ,

\

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or i

equal to 40% of RATED THERMAL POWER. i i

ACTION:

a. With an end-of-cycle recirculation pump trip system instrumentation 4 channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.2-2, declare the channel inoperable until the channel is restored to OPERABLE status with the i channel setpoint adjusted consistent with the Trip Setpoint value.  ;

. b. With the number of OPERABLE channels one less than required by the '

Minimum OPERA 8LE Channels per Trip System requirement for one or both trip s stems, place the inoperable channel (s) in the tripped condition within __ -

c.

7tAoicD With the number of DPERABLE channels two or more less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system and:

< l. If the inoperable channels consist of one turbine control valve  ;

channel and one turbine stop valve channel, place both inoperable  !

cnannels in the tripped condition withing ; : -'

2. If the inoperable channels include two turbine control valve '

channels or two turbine stop valve channels, declare the trip system inoperable. '

d. With one trip system inoperable, restore the inoperable trip system to OPERA 8LE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or reduce THERMAL POWER to less than 405 of RATED THERMAL POWER within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

e. With both trip systems inoperable, restore at least one trip system to OPERA 8LE status within one hour or reduce THERMAL POWER to less than 40K of RATED THERMAL POWER within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

O G

RIVER BEND - UNIT 1 3/4 3-48

TABLE 3.3.4.2-1 m.

M

=

Ess-OF-CYCLE RECIR'CULATION PUMP TRIP SYSTEM -INSTRUMENTATION es h MINIMUM OPERABLECHANNEg) '

TRIP FL20CT10N PER TRIP SYSTEM g .

1. Turbine Step Valve - Closure -2(b)

2. Turbine Centrol Valve-Fest closure 2 IDI

(.o (a)A trip system may be placed in an inoperable status for up t hours for required surveillance w provided that the other trip system is OPERABLE.

) (b)This function shall be setonatically bypassed when turbine first stage pressure is less than or 1 equal to-187* psig, equivalent-te THERM 4L POWER less than 405 of RATED THERMAL POWER.

h *To allow for instrumentation accuracy, calibration and drif t, a setpoint of < 177 psig turbine first stage pressure shall be used.

b h

. . . . . ,--._._--.._..s,._,- -..... ~,--.,_. ._, . ~ , , . . . - ~ . _ s.- - ~ . . - . . . . - - - . . . . ._---.E.- . . - , . . . ,...._..._...i- ..-- .-, ,..i,,..~..-- .. ,-,

TABLE 4.3.4.2.1-1 m END-OF-CYCLE RECIRCblATION PUMP TRIP SYSTEM SURVEILLANCE REQUIREMENTS E CSIANNEL

. 5 FUNCTIONAL CHANNEL

, TRIP FUNCTION TEST CALIBRATION k

-4

1. Turbine Step Wolve-Closure Q I")

R'I*)

H 2. Turbine Control Valve-Fest Closure G I*)

R

1. I*)

• Including trip systee logic testing.

t' 97 w Calibrate the first stage pressure transmitter trip unit setpoint at least. once per days.

J, (a) The CHAleEL FUNCTIONAL TEST and CHANNEL. CALIBRATION shall include the turbine first, s age pressure

' w instruments.

e D

, _ . - , , . ..-4. ,-.~, .--..e-...-- . -- . _ . . _ , . -' . . . . - . ,- . . . . _ . . . ~ , . . ,,-.-,4 . - - . ..,v's .w.-%., , , _ . . -. , , . . , _ , -. . . . , , . . , _ , -

TABLE 3.3.5-1 REACTOR COPE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION su MINIMUN OPERABLE CHANNELS

@ FUNCTIONAL UNITS PER TRIP FUNCTION g

,) ACTION

1. Reactor Wessel Idater Level - Low Low Level 2 50

-4 e 2. Reactor Wessel idater Level - High Level 8 2 ICI 51

3. Condensate Storage Tank Idater Level - Low 2 Id) 52

4. Suppression Pool Idater Level - High 2(d) 52

5. Manual Initiation I ')

I 53 ,

R

• fo Y (a) A channel may be placed in an inoper$14 s$gtys (op up tg h u q for reqgired survpillance without-lE placing the trip function in the tripped condition provide 44 least one other OPERA 8LE channel in the same trip funct_lon is monitoring that parameter.

3 oep

.(c) 'One trfp system with two-out-of-two logic. -

(d) One trip system with one-out-of-two logic.

(e) One trip system with one channel.

O I

-_--m, - -

. . - - . - . . _ . . ~ . . . . . . . - - . . . ,. . ., - . ~ . . s, .

, . - ,v. . . . . , - - -- .1,. . _'

7 h

TASLE 3.3.5-1 (continued) 4 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION ,

i ACTION 50 - With neF r OPE '8LE ch nels 1 s tha requi ed by the Mi mum ERA 8L Chan is per rip Fu tion quir nt: i ggy . F r one rip stem, p ace th trip ystem nt tri e'd i 'l g,w ondit n wi in one ur* deel the IC stem ,

mg inop able. i go era p

~

. F bot. trip sy ens, lare RC sys in ACTION 51 - With the number of OPERABLE channels less than required by the Minimum OPERA 8LE channels per Trip Function requirement, declare I the RCIC system inoperable; g7 g ACTION 52 - W h en r OPE .L c nels ess n qui db MW int OP L Chan is per rip ncti n ufr nt, pla the]a '

1ea on i rahl e nel n t. tri ndit on w thi

['3% n o hou or la th RCI sys i r e.  ;

ACTION S3 - With the number of OPERA 8LE channels less than required by the Minimum OPERA 8tE Channels per Trip Function requirement, restors i the inoperable channel to OPERA 8LE status within hours or .;

declare the RCIC system inoperable.

l

~

l i

"The provisions of Specification 3.0.4 are not applicable.

j RIVER BEND - UNIT 1 3/4 3-56 W -

INSERT 10 ACTION 50 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that a sufficient number oflow reactor vessel water level channels remain OPERABLE or are in the tripped condition to maintain automatic RCIC system actuation capability, and place the inoperable channel (s) in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> *.

Otherwise, declare the RCIC system inoperable.

INSERT 11 ACTION 52 - With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip Function requirement, verify within one hour that the RCIC pump suction is aligned or will automatically realign to the suppression pool, and place at least one inoperable channel in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Otherwise, declare the RCIC system inoperable.

)

i j

E

i '  ;. -  :; i  ! . t .

L S

T N -

E .

N E .

R .

I .

U Q .

E  %

R .

E C

N a A

L L

I E

V N I I I ) .

R O * * *

• U LI I I I I A S ET R R R R N NA N NR .

0 AB 1 HI .

T CL a A A h i

T C .

N -

E 4

2 1

- .T t

R L

QO

' O O  :

$[

1 S LA

.N EN

[ [R 5 I NO 7  :

. NI T 7 . -

3 N ATS s .

. O HCE y 4 I CNT a T U d E A F .

L U B T .

A C A r T

N e

p E L T EK e .

S NC A c Y

S NE AH S 5 5 5 N n o

a HC .

G C t .

N s .

I a .

L - e -

O l O - l C e t l v a N e e O v L t I e . k n T L 8 n r i A

r a e o p

L ri T t O e ee e a t -

S t t v ae g W n e

I a2 Wl WL a l o s =

E r o 1 t R l e lh o o t i O

C ev se eg si t w Se P

i a n u .

sL sH L n t R e . e e o i p O

T S vwa W- t -

a 1

s I n i r .

C T rL rl sl s t A I o oe ne eh l a

E R

N U

t w ce aL t v ce aL ev de nL rg pi pH u

n t

e a

e

=

L A R e e o~ u a r ,

R C S M b N i O l I . . . . . a T a b c d e C .

C .

N ) ~

U a .

F * (

". R8, 2U e .> mE* .

L l1

w IABLE 3.3.6-1

} CONTROI ROD BLOCK IN51RlMENTATION E MINIMUN APPLICABLE im OPERABLE CHANNELS G OPERATIONAL j TRIP FUNCTION PER 1 RIP FUNCTIO CON 01110NS ACTION i 1. ROD PATIERN COIHML _$YSTEM E a. Low Power Setpoint 2 1, 2 60

-4 b. High Power Setpoint 2 1 60

2. APRN

a. Flow Blased Neutron Flux -

Upscale 6 1 61

b. Inoperative 6 1, 2, 5 61

c. Downscale 6 1 61

d. Neutron Flux - Upscale, Startop 6 2, 5 61

3. SOURCE RANGE leNITORS U

a. Detector not full inI ") 3 2 61 2** 5 62

b. Upscale (b) 3 2 61 2** 5 62

^

c. Inoperative IU) .3 2 61 2** 5 62 *

d. Downscale IC 3 2 61 2** 5 62

4. INTERMEDIATE RANGE MONITORS Detector not full in

a. 6 2, 5 61

b. Upscale 6 2, 5 61

c. Inoperative 6 2, 5 61 i

d. Downscale(d) 6 2, 5 61

5. SCRAM DISCHARGE VOLUDE '

a. ' Water Level-High 2 1, 2, 5*

45 -!

6. REACTOR COOLANT SYSTEN RECIRCULATION FLOW ,

i. Upscale .2 1 s

ee, - - - , - . .+,.is+ , * +m+ ..m. =4-. -.-n<-. -.m--m e,.- - - . - - r- . .,.v. a.- - - . . . - =i--m .. e_ m. m*__n. w w,% we -e.w- e-a u_-- --- _- 2 ._m.s.=_ u.m_m. s

i TABLE 3.3.6-1 (Continued)

CONTROL R00 BLOCK INSTRUMENTATION ACTION ACTION 60 -

Declare the RPCS inoperable and take the ACTION required by Specification 3.1.4.2.

ACTION 61 -

With the number of OPERABLE Channels:

a. One less than required by the Minimum OPERABLE Channels per Trip Function requirement, restore the inoperable channel to OPERABLE status within 7 days or place the inoperable 1 channel in the tripped condition within the next hour. l l

b. Two or more less than required by the Minimus OPERABLE Channels per Trip Function requirement, place at least one inoperable channel in the tripped condition within one hour. .

I

_ ACTION 62 With the number of OPERABLE channels less than required by the

&# Minimum OPERABLE Channels per Trip Function requirement, place

_ th d operable channel in the tripped condition within one hour.

l

[

'~ ~

w D With more than one control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

OPERABLE channels must be associcted with SRM required OPERABLE per Specification 3.9.2.

I (a) This function shall be automatically bypassed if detector count rate is

> 100 cps or the IRM channels are on range 3 or higher.

(b) This function shall be automatically bypassed when the associated IRM  ;

channels are on range 8 or higher.  !

(c) This function shall be autcoatically bypassed whsn the IRM channels are i on range 3 or higher.-

(d) This shall be automatically bypassed when the IRM channels are on rangD I.

]

(e) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the TRIP  ;

SYSTEM in the tripped condition, provided at least one other ,

OPERABLE channel in the same TRIP SYSTEM is monitoring that l parameter. _

1 RIVER BEND - UNIT 1 ,

3/4 3-61 Amendment No. 47 1

P i

INSERT 12 -

ACTION 63 - With the number of OPERABLE channels less than required _by the Minimum .j OPERABLE Channels per Trip Function requirement, verify within one hour that a -

sufficient number of channels remain OPERABLE to initiate a rod block by the associated Trip Function, and place at least one inoperable channel in the tripped conditia . within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Otherwise, initiate a rod block. -

i P

g i

I

, TABLE 4.3.6-1 2

Q CONTROLROD8LOCdINSTRUMENTATIONSURVEILLANCEREQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCT10NAL CHANNEL CONDITIONS IN WHICH TRIP FLEICTION CHECK TEST CALIBRATION (8} SURVEILLANCE REQUIRED 5 1. 200 PATTERN CONT E SYSTEM ,

H a. Low Power Setpoint S II) 5 (b)(e)-

G SA 1, 2 l

b. High Power Setpoint S III g)(*)D SA, l g 1**

2. APfm

a. Flow Biased Neutron Flux -

, Upscale NA S/U FG SA I9) 1

)- b. Inoperative NA S/U Q NA 1, 2, 5

, c. Downscale NA S/U G SA 1 4 d. Neutron Flux - Upscale, Startup NA S/U Q SA 2, 5

3. SOURCE RANGE MONITORS

a. Detector not full in'.- NA S/U NA 2, 5

b. $ scale NA S/U(b ,W SA 2, 5

c. Insperative NA S/U(b),W S/U b),W W NA 2, 5

d. Downscale NA , SA 2, 5

4. INTEWEDIATE RANGE MONITORS

a. Detector not full in NA S/UIDI,W NA 2, 5 g b. Upscale NA S/U )W ), SA 2, 5

c. Insperative NA S/U(b),W MA 2, S'

d. Downscale NA S/U ,W SA 2, 5

= 5. SCRAM DISCMARGE V0ttBE g a. Water Level-High NA' Q R 1, 2, 5*

{ 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW

a. Upscale NA S/U(b) G SA I9) 1 I

n -- _- w__ _,r - -. ,ma . w -, .~ >-.wa 6 + _ __ m- .s-, __u ~,

i

. . TABLE 4.3.6-1 (Continued) i CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS

~

NOTES:

a. Neutron detectors may be excluded from CHANNEL CALIBRATION.

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

c. [0ELETED) j

d. [0ELETED)

e. Includes reactor manual control multiplexing system input.

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

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

With any control rod withdrawn. Not applicable to control rods. removed "

per Speci fication 3.9.10.1 or 3.9.10. 2.

91

1. Calibrate trip unit setpoint once per days. j With THERMAL POWER greater than low power setpoint. l 1

~

I

)

l 4

l

' i, 1

I 1

RIVER 8END - UNIT 1 3/4 3-64 Amendment No. 3, 23 l

.. TABLE 4.3.7.1-1 j NONITORING INSTRDMENTATION SURVEILLANCE REQUIREMENTS E

CHANNEL CONDITIONS IN CHANNEL FUNCTIONAL CHANNEL WHICH SURVEILLANCE

. INSTRtNENTATION CHECK TEST Call 8 RATION REQUIRED

, 1. Main Control Raen Ventilatten Radiation Monitor

a. Local Intaka S O R 1, 2, 3, 5 and a

b. Remote Intake' S cp R 1, 2, 3, 5 and *

2. Area Montter

, s. Fuel Building Spent Fuel Storage , ,

, Pool 5 M R i

3. Main Condenser Offgas Post-Treatment System Effluent Monitoring '

System

a. Noble Gas Activity Monitor -

(Providing Alors and Auto- 1 metic Terminetten of Release) 0 R_ **

Q

4. Condenser Air Ejector Pretreatment Radioactivity Monitor Noble Gas Activity Monitor. **

a. D Q R "When irradiated fuel.is being handled _in the primer containment or the fuel Building. .

• • 0uring operation of the main condenser air ejec""

1. With fuel in the spent fuel' storage pool.

6 s

a s_.s-_ su_;___u-__mmaMwhs_-s ., we,k- w_ . .a- w .g%. w- e e4m*.'-, -

we e m. , = w e <w,--s au m e-s-m e- .,we- .--e es=3-*ee+-m +e-.~p. w. w -._ ee- w.im,c -b-e 4 g-+=, p_.yp,,g-t-a+-

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TABLE 3.3.9-1 5

PLANT SYSTEMS ACTUATION INSTRUE NTATION g

NINIMIM APPLICA8LE h OPERABLE OPERATIONAL CONDITIONS AbTION

, TRIP FLMCTION ' PERTRIPSYSTEM(("}

! 1. PRIMARY CXINTA11 GENT VENTILATION SYSTEM -

• UNIT u __8u A .__ 5

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a. Drywell Pressure-Nigh 2 1,2,3 ,

150

b. Containment-To-Annulus AP High 3 1,2,3 151

c. Reacter Wessel teater Level-Low Low Low Level 1 2 1,2,3 150

d. Timers . I 1, 2, 3 152

$ 2. FEEDWATER SYSTER/ MAIN TURBINE TRIP SYSTEM ,

a. Reacter Vessel Idater Level-Nigh Level 8 3 1 153

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(a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the TRIP SYSTEM in the tripped condition, provided at least one other OPERABLE channel in the same TRIP SYSTEM is monitoring that parameter. _

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TABLE 3.3.9-1 (Continued)-

ACTION 150 - 4. With one channel inoperable, place the inoperable' channel in the tripped condition # within @ ,or declare the (  !

associated system inoperable.

l

b. With more than one channel inoperable, declare the associated '

system inoperable.

ACTION 151 - a. With the number of OPERA 8LE channels one less than required ,

by the Minimum OPERA 8LE Channels requirement, restore the ,

inoperable channel to OPERA 8LE status within 7 days or be '

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

b. With the number of OPidA8LE channels two less than required  :

by the Minimum OPERABLE-Channels requirement, restore at .

least one of the inoperable channels to OPERA 8LE status a within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> a be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 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 />. _ i ACTION 152 - Declare the associated Containment Ventilation System -

inoperable.  ;

ACTION 153 - a. With the number of OPERA 8LE channels one less than required -

by the Minimum OPERA 8LE Channels requirement, restore the

• inoperable channel to OPERABLE status within 7 days or be  ;

in at least STARTUP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

b. With the number of OPERABLE channels two less than required  !

by the Minimum OPERA 8LE Channels requirement, restore at l least one-of the inoperable channels to OPERA 8LE status  !

- within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least STARTUP within the next -)

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. ,

r

1. Provided this does not actuate the system.

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RIVER BEND - UNIT 1 3/4 3-109 Amendment No. 47 i

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3/4 3-111 Amendment No. 9 RI.YER SE E - UNIT 1

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REACTOR C0OLANT SYSTEM i

SURVE!LLANCE REQUIREMENTS _

i 4.4.2.1.1 The acoustic monitor for each safety / relief valve shall be demonstrated OPERA 8L by performance of a:

M

a. CHANNEL FUNCTI TEST at least once per days. and I i

b. CHANNEL CALIBRATION at least once per 18 months.*

.)

4.4.2.1.2 The relief valve function pressure actuation instrumentation shall )

be demonstrated OPERA 8LE by rformance of a: l

a. -CHANNEL FUNCTION EST, including calibration of the trip unit set-l point, at least once per .

i

b. CHANNEL CALIBRATION, LOGIC SY 'EM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.

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"The provisions of Specification 4.0.4 are not applicable provided the surveil _

lance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure is adequate to 1 perform the test.

.v -

• • A channel Inay be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance. -

_- ,g

t REACTOR C0OLANT. SYSTEM  !

I SAFETY / RELIEF WALVES LOW-LOW SET FUNCTION LIMITING CON 0! TION FOR OPERATION ,.

I 3.4.2.2 The low-low set function of the following reactor coolant systen l safety / relief valves shall be OPERA 8tE with the following settings:

Low-Low Set Function i Setpoint" (psic) t 15 psi  ;

Valve No. Open Close 1821*RVF051D 1033 926 '

1821*RVF051C 1073 936 1821*RVF0518 1113 946 1821"RVF051G 1113 946  ;

1821"RVF047F 1113 946 APPLICA8ILITY: OPERATIONAL CONDITIONS 1, 2 and 3.  !

ACTION:  !

I

a. With the low-low set function of one of the above required reactor i coolant system safety / relief valves inoperable, restors the inoperable f relief valve function and the low-low set function to OPERABLE status within 14 days or be in at least HOT SHUTDO W within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> i and in COLD SHUTDOW within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. j i

b. With the low-low set function of more than one of the above required i reactor coolant system safety / relief valves inoperable, be in at least j

~

H0T SHUTDOW within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOW within the next

• 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. l

c. With either lour low set function pressure actuation trip system "A"  !

or "B" inoperable, restare the inoperable trip system to 0PERABLE  !

status within 7 days; otherwise, be in at least NOT SHUTDOW within i 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOW within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SURVE!LL m 7asingig f

4.4.2.2.1 The larlew est" function pressure actuation instrumentation shall  :

be demonstrated OPERABLE ensance of a: l

a. CHAf8EL FW CTIM AL , ins uting calibrettee of the trip unit setpoint, et least esce per days.

b. OWEEL em tensTIN, LaBIC SYSTiN ORAL TEST and staufeted auto- i setic operettee of the entire system at least enes per 18 easths. l 1

"The lif't setting pressure shall correspond to ambient conditions of the valves l

,tLaominal operating temperatures and pressures. i see lostre.T 13 j RIVER 300 - WIT 1 1/4 4-9 l

INSERT 13 A Safety / Relief Valve Low-Low Set Function instrurnent channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance provided all other Safety / Relief Valve Low-Low Set Function instrument channels are OPERABLE.

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't 3/4.3 INSTRLMENTATION BASES 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRIMENTATION The reactor protection system automatically initiates a reactor scram to:  ;

a. Preserve the integrity of the fuel cladding, f

b. Preserve the integrity of the reactor coolant system, >

c. Minimize the energy which must be adsorbed following a loss-of-coolant-accident, and j

d. Prevent inadvertent criticality.

This specification provides the Limiting Conditions for Operation necessary -

to preserve the ability of the system to perfom its intended function even l during periods when instrtament channels may be out of service because of main-tanance. When necessary, one channel any be made inoperable for brief intervals t egnduct_ reauiend 111ance.

Aeo knet.ri+

\ - i

~m system is made up of four logic channels. .The logic ,

channels A(A1) and C(A2) comprise one trip system and the logic channels 8(81) and O(B2) comprise the other trip system for detemining compliance with technical ,

specifications. Placement of either logic channel of.a trip system in the tripped condition places the trip system in the tripped condition. The trip systems as defined above are independent of each other. There are usually four instrument.  ;

channels (one in each logic channel) to monitor each parameter. The tripping- i of a logic channel in each trip system will result in a reactor scras.

The esasurement of response time at the specified frequencies provides assurance that the protective functions associated with each channel are com-plated within the time limit assumed in the safety analyses. No credit'was-taken for those channels with response times indicated as not applicable. -

Response time any be demonstrated by any series of sequential, overlapping or total channel test asseurement, provided such tests demonstrate the total channel reopense time as defined.-- Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test osasurements, or (2) utilizing replacement sensors with certified response times.

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

e ~

i Insert 14 Page 1 of 2 Action a of Technical Specification 3.3.1 ;. entered when one channel required by Table 3.3.1-1 in ,

one or more Functional Units

• are inoperable. Decause of the diversity of sensors available to provide l trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been shown to be acceptable to permit restoration of any inoperable channel to operable status.

However, this out of service time is only acceptable provided the Functional Unit which contains the inoperable channel is in one trip system and this Functional Unit still maintains RPS trip capability, refer to Action b. F 9e inoperable channel cannot be restored to OPERABLE status within the allowable out of sr e time, 'he channel or the associated trip system must be placed in the tripped  ;

condition. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure,-

and allow operation to continue. Alternately, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram),

if the inoperable channel is not restored to OPERABLE status within the required time, the ACTION  :

required by Table 3.3.1-1 for that Functional Unit shall be taken.

Action b of Technical Specification 3.3.1 is entered when two or more Channels required by Table ,

3.3.1-1 in one or more Functional Units are inoperable. When in this condition, provided at least one l channel per trip system is OPERABLE, the RPS still maintains trip capability for that Functional l Unit, but cannot accommodate a single failure in either trip system. The Actions required by b.1 and

• b.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped '

channels within one or more Functional Units results in the Functional Unit not maintaining RPS trip capability. A Functional Unit is considered to be mainmining RPS trip capability when sufficient

• channels are OPERABLE or in TRIP (or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Functional Unit on a valid signal. For the typical Functional Unit with one-out-of-two taken twice logic and the IRM and APRM Functional Units, this would require both trip systems to have one channel OPERABLE or in trip'(or the associated trip system in trip). For Functional Unit 6 (Main Steam Isolation Valve Closure), this would require both i trip systems to have each channel associated with the MSIVs in three MSLs (not necessarily the same  !

MSLs for both trip systems), OPERABLE or in trip (or the associated trip system in trip). For -l Functional Unit 10 (Turbine Stop Valve Closure), this would require both trip systems to have three channels, each OPERABLE or in trip (or the associated trip system in trip).

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Insert 14 Page 2 of 2 i

. Actions b.1 and b.2 limit the time the RPS scram logic for any Functional Unit would not' '

accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arrangement .

for a typical four channel Functional Unit). The reduced reliability of this logic arrangement was not evaluated in the USAR, Chapter 15, for the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time. The one hour Completion Time time of Action b.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The I hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels. Within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance provided in Action b.2, the associated Functional Unit will have all required channels either OPERABLE or in trip (or in any' combination) in one trip system. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low  ;

probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram. .

Completing one of these Actions restores RPS to an equivalent reliability level as that evaluated in NEDC-30851-P-A** which justified a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowable out of service time as presented in the

. condition for Action a. When both trip systems are in a degraded condition, the trip system in the -

more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels, if the two inoperable channels are in the same Functional Unit while the four inoperable channels are all in different Functional Units). .

The decision as to which trip system is in the more degraded state should be based on prudent judgment and current plant conditions (i.e., what MODE the plant is in). If this action wcidd result in a scram or recirculation pump trip, it is permissible to place the other trip system or it inoperable channels in trip.

l Functional Unit - A Functional Unit is defined as a specific condition required to cause a Trip

• Function to occur. For instance, a High Neutron Flux condition from a Intermediate Range Monitor will cause a RPS Trip Function to occur. In this case, the Functional Unit is the 1 IRM High Neutron Flux condition and the Trip Function is actuation of the_RPS. Another j example is High Drywell Pressure causes Primary Containment Isolation. The High Drywell j Pressure condition is the Functional Unit and Primary Containment Isolation is the Trip

-l Function. 1 I

NEDC-30851-P-A - " Technical Specification Improvement Analysis for BWR Reactor - .l Protection System", March 1988 i

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INSTRLMENTATION t

BASES '

3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION 1

This specification ensures the effectiveness of the instrumentation used '

to mitigate the consequences of accidents by prescribing the 00 ERA 8ILITY require-  ;

monts, trip setpoints and response times for isolation of the reactor systems.  ;

When necessary, one channel may be inoperable for brief intervals to conduct j required surveillance.

Some of the trip settings may have tolerances explicitly  !

stated where both the high and low values are critical and any have a substantial :1 effect on safety. The setpoints of other instrumentation, where only the high or low end of the setting has 'a direct bearing on safety, are established at  !

a level away from the normal operating range to prevent inadvertent actuation of_tha svs % tnvat=d ._-

f 5 U _~

_ l Aqw(Asmai d T.xcept for. the M$1Vs, the sarety analysis does not address individual sensor response times or the response times of the logic systems to which the sensors, are connected. For D.C. operated valves, a 3 second delay is assumed before the valve starts to move. For A.C.-operated valves, it is assumed that the A.C. power supply is lost and is restored by startup of the emergency diesel  :

generators. In this event, a time of 10 seconds is assumed before the valve '

starts to move. In addition to the pipe break, the failure of the D.C. oper-ated valve is assumed; thus the signal delay (sensor response) is concurrent -

with the 10 second diesel startup. The safety analysis considers an allowab'  ;

reactor coolant inventory loss in each case which in turn determines the valv.

speed in conjunction'with the 10 second delay. It follows that checking the valve speeds and the 10 second time for emergency power establishment will establish the response time for the isolation functions. However, to enhance overall system reliability and to monitor instrument channel response. time trends, the isolation actuation instrumentation response time shall be measured and recorded as part of.the ISOLATION SYSTEM RESPONSE TIME.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the differ-ence between each Trip Setpoint and the Allowable Value is equal to-or less than the drift allowance asstaned for each trip in the safety analys~es.

3/4.3.3 EDERGENCY CORE COOLING SYSTEM ACTUATION !NST**ENTATION The emergency core cooling system actuation instrumentation is provided' to initiate actions to mitigate .the consequences of accidents that are beyond the ability of the operator to control. This specification provides the OPERASILITY requirements, trip setpoints and response times that will ensure effectiveness of the. systems to provide-the design protection. Although the

'instrtments are listed by system, in some cases the same instrument may be used t actuat,jgitsinnal_ta anem than one system at the same time.

< Anol#sserIb nservative . .

uperaT1Tn with a trip 47. W.. than its Trip setpoint but within its specified Allowable Value- is acceptable on the basis that the differ-ence between each Trip setpoint and the Allowable Value is equal to or less than the drift allowance assumed for each trip in tae safety analyses.

RIVER BEND - UNIT 1 8 3/4 3-2

Insert 15 Because of the diversity of sensors available to provide isolation signals and the redundancy of the ,

isolation design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, depending on the Function,  !

has been shown to be acceptable per NEDC-31677-P-A* and NEDC-30851-P-A, Supplement 2" to permit restoration of inoperable channels to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Action c  !

Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Action b. Placing the j inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictio'ns.  ;

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the  :

inoperable channel in trip would result in an isolation), the Action required by Table 3.3.2-1 shall be i taken for that inoperable Trip Function.

Action c is intended to ensure that appropriate actions are taker' multiple, inoperable, untripped channels within the same Function results in redundant automat ix stion capability being lost for the associated flow path (s). The one hour time limitation of Ac. ar. .1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. < he one hour time limit is  !

acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

j The MSL isolation Functions are considered to be maintaining isolation capability.when sufficient channels are OPERABLE or in trip such that both trip systems will generate a trip signal from the ,

given Function on a valid signal. The other isolation Functions are considered to be maintaining f isolation capability when sufficient channels are OPERABLE or in trip such that one trip system will  :

generate a trip signal from the given Function on a valid signal. This ensures that one of the two  !

Isolation Valves in the associated flow path can receive an isolation signal from the given Function.  ;

The requirements of Action c do not apply to the Manual Initiation Functions (Functions 5n and 7), ,

since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (as allowed by Action b) is allowed. [

I NEDC-31677-P-A " Technical Specification Improvement Analysis for BWR Isolation -l Actuation Instrumentation", June,1989. i NEDC-30851-P-A (Supplement 2) "TechnicalSpecificationImprovement Analysis for BWR j isolation Instrumentation Common to RPS and ECCS Instrumentation", March,1989.  !

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insen 16 l Action b directs entry into the appropriate Action referenced in Table 3.3.3-1 when one_ or more ECCS Actuation instrumentation Channels are inoperable. The applicable Action specified in the table is dependent on the Trip Function. Each time a channel is discovered to be inoperable, Action  ;

b is entered for that channel and provides for transfer to the appropriate Action stated in Table '

3.3.3-1.

l Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> has been shown to be acceptable per +

NEDC-30936-P-A (Part 2)* to permit restoration of any inoperable channel to OPERABLE status, if the inoperable channel cannot be restored to OPERABLE status within the allowable out of service '  !

time, the subsequent action required by the individual Action Statement must be taken. Placing the l inoperable channel in trip or declaring it inoperable, as applicable, would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. These Actions are intended to ensure that appropriate actions are taken if multiple, -

inoperable, untripped channels within the same Function (or in some cases, within the same variable) result in redundant automatic initiation capability being lost for the feature (s). .;

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1 NEDC-30936-P-A (Part 2) " Technical Specification improvement Analyses for ECCS ]

Actuation Instrumentation, Part 2", December,1988. . j l

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'INSTRWENTATION '

BASES .

7 3/4.3.4 RECIRCUt.ATION PLSF TRIP ACTUATION INSTRWENTATION' f The anticipated transient without scram (ATWS system provides a means of 11afting the consequence)s of.the unlikelyrecircula occurrence of a failure to scras during an anticipated transient. The -

response study events of intheGeneral plant toElthis postulated event falls within the envelope of~

g[rch

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[ lio_ INNma narnn.9A,,,ectric Mda+=d December 1979, and Company Section 15.8 Topical Reports NE of the FSAR.-

Ine end-of Eyu. .

m:uisuon pump trip (E0C-RPT) system is a part of  !

the Reactor reactor trip.

Protection Systes and is an' essential safety supplement to the The purpose of the E0C-RPT is to recover the loss'of thermal  :;

margin which occurs at the end-of-cycle. The physical phenomenon involved is that the void reactivity feedback due to_a pressurization transient can add positive rods add reactivity negative scram to the reactivity.

reactor systes at a' faster rate _than the control. , 1 Each E0C-RPT system trips both recircu- .!

lation pumps, reducing coolant flow in order to reduce the _ void collapse in the core during two of the most limiting pressurization events. The two i events for which the EOC-RpT protective feature will. function are closure of the turbine stop valves and fast closure of the turbine control valves.

A fast-closure sensor from each of two turbine control valves provides input to the E0C-RPT systas; a fast-closure. sensor.from each of the other two. =;

turbine. control valves provides input to the second EOC-RPT system.  :

a position switch for each of two turbins stop valves provides input to one. Sta11arly, E0C-RPT system; a position _ switch from each of the other two stop valves; provides input to the other_E0C-RPT system. For each E0C-RPT system, the.  ;

I sensor relay contacts are arranged to fors _a 2-out-of-2 logic for the fast L valves. of turbine control valves and a 2-out-of-2 logic for the turbine stop cjosure The

, coperation y a . n of either logic will actuate the EOC-RPT system and lach %:Anri Dhsysue M SEE:T n 16)manually bypassed by use of a keyswitch which is administratively controlled.

bypass POce.

at less than 4 5 of RATED THEftut. POWER, are annunciated in th The EOC-WT systan' response time is the time assumed in the analysis between initiation of valve motion and complete suppression of the breaker electric arc, i.e.,-140 as. Included in this time are: the response time of-the sensor, the time allotted for breaker are suppression and the response .

time of the system logic. -

Operation with a trip set less conservative than its Trip Setpoint but within its specified Alloweble Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is equal to or less than the drift allowance' assumed for each trip in the safety analyses.

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

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i Insert 17 With one or more channels inoperable, but with ATWS-RPT capability for each Function maintained (refer to Action c Bases), the ATWS-RPT System is capable of performing the intended function. '.

However, the reliability and redundancy of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip system could result in the inability of the ATWS-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore the inoperable  :

channels to OPERABLE status. Because of the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low ,

probability of an event requiring the initiation of ATWS-RPT, 30 days is provided to restore the inoperable channel (Action b).

Action b and c are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip capability when sufficimt channels are OPERABLE or in trip such that the ATWS-RPT System will generate a trip signal fiom the given Function on a valid signal, and both recirculation pumps can be tripped. This requires two channels of the Function in the same trip system to each be OPERABLE or in trip.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is sufficient for the operator to take corrective action (e.g., restoration or tripping of channels) and takes into account the likelihood of an event requiring actuation of the

~ATWS-RPT instrumentation during this period and the fact that one Function is still maintaining ATWS-RPT trip capability.

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b Insert 18 With the number of OPERABLE channels one less than required, but with EOC-RPT trip capability maintained (refer to Action b), the EOC-RPT System is capable of performing the intended function.

However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore compliance with the LCO.

Based on GENE-770-06-1-A*, the diversity of sensors available to provide trip signals, the low' -

probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of an EOC-RPT,12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to restore the .

inoperable channels to OPERABLE status. Alternately, the inoperable channels may be placed in trip since this would conservatively compensate for the inoperability, restore capability to accommodate  ;

a single failure, and allow operation to continue.  ;

Actions c.1 and c.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining EOC-RPT trip capability. A Function is considered to be maintaining EOC-RI'T trip capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from i the given Function on a valid signal and both recirculation pumps can be tripped. This requires two ,

channels of the Function, in the same trip system, to each be OPERABLE or in trip. Based on GENE-770-06-1-A*, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time of Action c.1 and the I hour time of Action c.2 is sufficient '

for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period.

With one trip system rendered inoperable, the inoperable trip system must be restored 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 if both trip systems are inoperable, at least one trip system must be restored to operable status within one hour or THERMAL POWER must be reduced to < 40% RTP within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Alternately, the associated recirculation pump may be removed from service since this performs the intended function of the instrumentation. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 40% RTP from full power conditions in an orderly manner and without challenging plant systems.

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GENE-770-06-1-A " Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications", December 1992.- i

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q INSTRL3ENTATION ' 1 sASES q e

'I 3/4.3.5 i REACTOR CDRE ISOLATION COOLING SYSTEN ACTUATION' INSTRUMENT! ,

The reactor core isolation cooling system actuation instrumentation is-provided to initiata actions to assure adequata core cooling..in the event of j

i reactor isolation from its primary heat sink and the loss of feedwater flow to '

the renz reactor g 7 vessel,.without e

_-+ - m providing actuation of any of the emergency core ,

j Ano L MC.R.T M  !

Operai. Ton WRn a~ trip set -less conservative than its Trip Setpoint but '

within its specified Allowable Value is acceptable on the basis that the dif- >

forence between each Trip Setpoint and the A'lowable Value is equal to or i less than the drift allowance ass med for a.ch trip in the safety analyses. i 3/4.3.6 CONTROL R00 8 LOCK INSTRUMENTATION '

t The control rod block functions are provided consistent with the require- '!

monts of the specifications in Section 3/4.1.4, Rod Pattern Control System,  ;

Section 3/4.2, Power Distribution Limits and Section 3/4.3, Instrumentation.

The trip logic is arranged so that a trip fit any one of the inputs will result  !

i' n c.4Fr.E 2 % ^ (

A c o l eaf.,1a.T 10  ;

Operat on wisn e irip d conservative than its Trip Setpoint but l within its specified Allowable Value is acceptable on the basis that the I 1

difference between each Trip Setpoint and the Allowable Value is equal to or 1ess than the drift allowance assumed for each trip in the safety analyses. {

i 3/4.3.7 MONITORING INSTRt#GtTATION _

3/4.3.7.1 RADIATION MONITORING INSTRLMENTATION l The OPERABILITY of the radiation monitoring instrumentation ensures that;  ;

(1) the radiation levels are continuously measured in the areas served by the individual channels;_(2) the alare or automatic action'is initiated when the radiation level trip setpoint is exceeded; and (3) sufficient information is-available following an on accident.

selected plant parameters to monitor and assess these variables This capability is-consistant with 10 CFR Part 50, Appendix A, General Oesign criteria 13, 41,'50 51, 63 and 54.  ;

3.4.3.7.2 SEISMIC WNITORING INSTo w.NTATION t

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The OPERASILITY of the seismic monitoring instrumentation ensures that j I

sufficient capability is available to permit prompt determination of the mag- (

nitude of a seismic event and evaluation of the response of those features important to safety. This capability is-required to permit comparison of the- i measured response to that used in the design basis for the unit. This instru-mentation'is consistent with the recommendations of Regulatory Guide 1.12

" Instrumentation for Earthquakes", April 1974.  ;

RIVER 8END - UNIT 1 8 3/4 3-4 j '

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Insert 19 Action b directs entry into the appropriate Action referenced in Table 3.3.5-1. The applicable Action referenced in the Table is Function dependent. Each time a channel is discovered to be inoperable, Action b is entered for that channel and provides for transfer to the appropriate subsequent Action of '

Table 3.3.5-1.

Because of the re6undancy of sensors available to provide initiation signals and the fact that the RCIC -

System is not assumed in any accident or transient analysis, at allowable out of service time of i

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24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> has been shown to be acceptable per GENE-77042A* to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to j OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition or the RCIC system declared inoperable per the applicable Action required by Table 3.3.5-1. Placing the inoperable channel in trip, where applicable, would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

A risk based analysis, GENE-770-06-2-A*, was performed and determined that an allowable out of service time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is acceptable to permit restoration of any inoperable channel to OPERABLE status. An Action for Action 51 (similar to Action 50), limiting the allowable out of service time if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the Reactor Vessel Water Level High, Level 8 Function, whose logic is arranged such that any inoperable channel will result in a loss of automatic RCIC initiation capability. As stated above, this loss of  :

automatic RCIC initiation capability was analyzed and determined to be acceptable. The Action does i not allow placing a channel in trip since this action would not necessarily result in the safe state for the channel in all events.  ;

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GENE-770-06-2-A " Addendum to Bases for Changes to Surveillance Test Intervals and i Allowed Out-of-Service Times .for Selected Instrumentation Technical Specifications ,-  !

December 1992.

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Lasert 20 With the number of OPERABLE channels one less than required, but with Control Rod Block trip capability maintained (refer to Action 62), the Control Rod Block Instrument Trip System is capable of performing the intended function. However, the reliability and redundancy of the Control Rod Block instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the Control Rod Block System to perform the intended ftmetion. Therefore, only a limited time is allowed to restore compliance with the LCO. - Based on GENE-770-06-1-A*, the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a Control Rod Block,12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to restore the inoperable channels to OPERABLE status. Alternately, the inoperable channels may be placed in the tripped condition since -

this would conservatively compensate for the inoperability, and restore capability to accommodate a single failure.

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GENE-770-06-1-A " Bases for Changes' to ' Surveillance Test Intervals and Allowed i Out-of-Service Times for Selected Instrumentation Technical Specifications", December 1992. i l

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INSTRtBWITATION 8ASES j

MONITORING INSTRtMENTATION (Continued) 3/4.3.7.11 RADI0 ACTIVE GA5E0US EFFLUENT MONITORING INSTRLMENTATION  ;

The radioactive gaseous. effluent instrumentation is provided to monitor.  ;

and control, as applicable, the releases of radioactive meterials in gaseous affluents during actual or potential releases of gaseous effluents. The alarm /

trip setpoints for these instruments shall be calculated and adjusted in accord-ance with the methodology and parameters in the 00CM te ensure that the alare/

trip will occur prior to exceeding the limits of 10 CFR Part 20. .This instru-mentation also includes provisions for monitoring the concentrations of poten- '

tially explosive gas mixtures in the waste gas holdup system. The OPERA 81LITY and use of this instrumentation is consistent with the requirements of General t Design Criteria 60, 63 and 64 of Appendix A to 10 CFR Part 50. In addition, the radioactive release paths of the Fuel Building Ventilation Exhaust, Main

• Plant Exhaust Duct, and the Radwast Building ventilation Exhaust include  :

post-accident monitors.  ;

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3/4.3.8 TURSINE OVERSPEED PROTECTION SYSTEM This specification is provided to ensure that the turbine overspeed  !

protection system instrtseentation and the turbine speed control. valves are '

OPERABLE and will protect the turbine free excessive overspeed. Protection  ;

from turbine excessive overspeed is required since excessive overspeed of the .

turbine could generate potentially damaging missiles.

4 3/4.3.9 PLANT SYSTEMS ACTUATION INSTRLSWfTATION e

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3 The plant systems actuation instrumentation is provided to initiate action I of'the containment ventilation system and the feeduster system / main turbine l trip systan. The containment ventilation system provides emergency. containment .!

heat removal as described in Bases 3/4.6.3. The feedwater system / main turbine i trip system is initiated in the event of failure of the feedwater controller  !

urider maximum demand.

< Aop l W EE-T* M 6

6 RIVER BEND - UNIT 1 8 3/4 3-7 .

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I Lnsert 21 With the number of OPERABLE channels one less than required, but with Plant Systems Actuation ,

trip capability maintained (refer to Action 150.a), the Plant Systems Actuation Instrument Trip System '

is capable of performing the intended function. However, the reliability and redundancy of the Plant j

' Systems Actuation instrumentation is reduced such that a single failure in the remaining trip system  ;

could result in the inability of the Plant Systems Actuation System to perform the intended function.

Therefore, only a limited time is allowed to restore compliance with the LCO. Based on GENE-770-06-1-A*, the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an .i event requiring the initiation of a Plant Systems Actuation, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to restore the inoperable channels to OPERABLE status before declaring the associated trip system inoperable, i Alternately, the inoperable channels may be placed in the tripped ce lition since this would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.  :

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1 GENE-770-06-1-A " Bases for Changes to Surveillance Test Intervals and Allowed '

Out-of-Service Times for Selected Instrumentation Technical Specifications", December 1992, a i

REACTOR COOLANT SYSTEM l

3/4.4 REACTOR COOLANT $YSTEM BASES RECIRCULATION SYSTEM (Continued)

Neutron flux noise limits are also established to ensure early detection of limit cycle neutron flux escillations. SWR cores typically operate:with neutron flux noise caused by random boiling and flow noise. Typical neutron flux noise levels of 1 to 125 of rated power (peak-to peak) have been yeported for the range of low to high recirculation loop flow during both single and dual recirculation loop operation. Neutron flux noise levels which signifi-cantly bound these values are considered in the thermal GE SWR fuel and are found to be of negligible consequenc/ mechanical e (Reference 2). In design of addition, stability tests at operating OWRs have demonstrated that when stabil-

~

ity related neutron flux limit cycle oscillations occur they result in peak-to- -

peak neutron flux limit cycles of 5 to 10 times the typical values. Therefore, actions taken to reduce neutron flux noise levels exceeding three times the  ;

typical value are sufficient to ensure early detection of init cycle neutron. .

flux oscillations.

a Typically, neutron flux noise levels show a gradual increase in absolute magnitude as core flow is increased (constant control rod pattern) with two reactor recirculation loops in operation. Therefore the baseline neutron i

flux noise level obtained at a specific core flow can, be applied over a range  !

of core flows. To maintain a reasonable variation between the low flow and-high flow ends of the flow range, the range over which a specific baseline is 1

applied in operation. should not ex'ceed 205 of rated core flow with two recirculation loops Data from tests and operating plants indicate that a range of 205 of rated core flow will result in approximately a 55 increase in neutron L

flux noise level during operation with two recirculation loops. Baseline data should be taken near the maximum rod line at which the majority of operation will occur. However, baseline data taken at lower rod lines (i.e., lower power) will result in a conservative value since the neutron flux noise level ts proportional to the power level at a given core flow.

References (1) "0WR Core Thermal-Hydraulic Stability," Service Information Letter 380, Revision 1, February 1994. '

(2) G. A. Watford, "Cens11ance of the General Electric toiling Water Reactor Fuel Desi to Stability Licensing criteria," December 1982 ,

(IEDE P).

(3) g Opera on Analysis fe; River Send Station, Unit 1,"

3/4.4.2 SAFETY / RELIEF VALVES The safety valve function of the safety / relief valves ($RV) is to prevent the reactor coolant system free being pressurized above the Safety Limit of 1375 psig, in accordance with the ASE Code. A total of 9 OPERABLE safety-relief valves is required to limit reactor pressure to within ASIE III allowable values for the worst case upset transient. Any combination of 4 SRVs operating in the relief mode and 5 SRVs operating in the safety mode is acceptable.

RIVER BEND - UNIT 1 8 3/4 4-2 Amendment No. 31  !

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REACTOR C00LAllT $YSTEM 3/4.4 REACTOR C00LANT SYSTEM  ;

BASES SAFETY / RELIEF VALVES (Continued)

Demonstration of the safety-relief valve lift settings will occur only during shutdown and will be performed in accordance with the provisions of Specification 4.0.5.

The low-low set systes ensures that safety / relief valve discharges are minielzed for a second opening of these valves, following any overpressure transient. This is achieved by automatically lowering the closing setpoint of 5 valves and lowering the opening setpoint of 2 valves following the initial opening. In this way, the frequency and magnitude of the containment blowdown duty cycle is substantially reduced. Sufficient redundancy is provided for ~

the low-low set systen such that failure of any one valve to open or close at 4 M2*ad O . ... --- . - . . to the design basis.

_ A o o _I'3 SS R T 2.2.

. 3 ' REACTOR COULANT SYuuq uAKAGE 3/4.4.3.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to monitor and detect leakage free the reactor coolant pressure boundary. These detection systems are consistant with the recommendations of Regulatory Guide 1.45, " Reactor Coolant Pressure Boundary Leakage Detection Systems", May 1973. In conformance with Regulatory Guide 1.45, the atmospheric gaseous radioactivity system will have a sensitivity of 10.a pC1/cc.

The drywell and pedestal floor sump drain flow monitoring systems consist of 2 sumps with one level transmitter and two'105 pumps each. The level trans-aitters feed Main Control Room level indicators as well as various autcastic control systems. Each of the automatic systans calculate Isakage, control pumps and provide annunciation. The leak rata may be determined by the automatic sys-tem or a manual precedure through the use of the level indication and pump con-trol switches located in the an'a control room. The substitution of urab samples for the drywell particulate and gaseous monitors is to allow for cont'nued moni-toring of the function while neraal components are inoperable.

3/4.4.3 2 OPEMT!WIAL L2AME The allowable leakage rates from the reacter coolant system have been based on the predicted and experimentally sheerved behavior of cracks in pipes. The normally expected background leakage, due to equipment design and the detection capability of the instrumentation for determining syntas 1 , wee aise considered. The evidence obtained free experiments ta , for leakage somouhat greater than that specified for L5tIDOITIFIS , the probability is ses11 that the imperfection or crack associated with such leakage would grew rapidly. However, in all cases, if the leakage rates exceed the values specified or the leakage is located and known to be PRES 5URE BolseARY LEAIM E, the reactor will be shut down to allow further investigation and corrective action.

RIVER BO S - UNIT 1 5 3/4 4-3 Amendment No. 57

l' Insert 22 Because the failure of any reactor steam dome pressure instrument channels [providing relief SRV opening and LLS opening and closing pressure setpoints] in one trip system will not prevent the associated SRV from performing its relief and LLS function,7 days is allowed to restore a trip system to OPERABLE status (refer to Action c of TS 3.4.2.2). In this condition, the remaining OPERABLE trip system is adequate to perform the relief and LLS initiation function. However, the overall -

reliability is reduced because a single failure in the OPERABLE trip system could result in a loss of relief or LLS function.

The 7 day Completion Time is considered appropriate for the relief and LLS function because of the redundancy of sensors available to provide initiation signals and the redundancy of the relief and LLS design. In addition, the probability of multiple relief or LLS instrumentation channel failures, which renders the remaining trip system inoperable, occurring together with an event requiring the relief or LLS function during the 7 day Completion Time is very low.  ;

If one SRV low-low set function cannot be restored to OPERABLE status within 14 days (refer to Action a), or if more than one SRV low-low set functions are inoperable (refer to Action b), or if ,

either low-low set pressure actuation trip system is inoperable and cannot be restored to OPERABLE status within 7 days (refer to Action c), then the plant must be brought to a MODE in which the LCO  :

does not apply. To achieve this status, the plant must be brought to at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to COLD SHUTDOWN within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.  ;

The allowed 12 and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Times referenced above are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems, ,

GENE-770-06-1-A " Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications", December 1992.

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