ML20236N319

Proposed Tech Specs,Including Clarification of Secondary Containment Integrity Definition,Change in Name of Supporting Organization on Safety Review Committee & Mod to Environ Protection Plan for Recordkeeping Requirements

ML20236N319
Person / Time
Site:	Grand Gulf
Issue date:	08/06/1987
From:	SYSTEM ENERGY RESOURCES, INC.
To:
Shared Package
ML20236N309	List: AECM-87-0139, Application for Amend to License NPF-29,consisting of Tech Spec Changes,Clarifying Secondary Containment Integrity, Changing Name of Organization Represented on Safety Review Committee & Setpoint for Rhr/Rcic Steam Line Flow.Fee Paid ML20236N319
References
NUDOCS 8708110448
Download: ML20236N319 (39)

Text

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f C - 9 6lO4 DEFINITIONS REACTOR PROTECTION SYSTEM RESPONSE TIME 1.35 F.EACTOR PROTECTION SYSTEM RESPONSE TIME shall be the time interval from when the monitored parameter exceeds its trip setpoint at the channel sensor until de-energization of the scram pilot valve solenoids. The response time may be measured by any-series of sequential, overlapping or total steps such that the entire responce time is measured.

REPORTABLE EVENT

'1.36 A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 to 10 CFR Part 50.

' ROD' DENSITY 1.37 R00 DENSITY shall be the number of control rod notches inserted as a fraction of the total number of control rod notches. All rods fully inserted 1 is equivalent to 100% ROD DENSITY.

SECONDARY CONTAINMENT INTEGRITY

'1.38 SECONDARY CONTAINMENT INTEGRITY shall exist when:

a. All Auxiliary Building and Enclosure Building penetrations required to be closed during accident conditions are either:

1. Capable of being closed by an OPERABLE secondary containment automatic isolation system, or

2. Closed by at least one manual valve, blind flange, rupture disc or deactivated automatic valve or damper, as applicaole, secured in its closed position, except as provided in Table 3.6.6.2-1 of Specification 3.6.6.2.

b. All Auxiliary Building and Enclosure Building equipment hatches and blowout panels are closed and sealed.

In c.oyunee wth de reyMenh of lI

c. The standby gas treatment system is OPERACLE pursvant to Specification 3.6.6.3.

d. The door in each access to the Auxiliary Building and Enclosure Building is cicsed, except for normal entry and exit.

e. The sealing mechanism associated with each Auxiliary Building and Enclosure Building penetration, e.g.,-welds, bellows or 0-rings, is OPERABLE.

8708110448 870806 PDR ADOCK 05000416 P PDR i

GRAND GULF-UNIT 1 1-7  % ,n/c ,,et- M l

2. NLS 86/18 Name change of MSSI to MSV SSI of an SRC member

SUBJECT:

Technical . Specification 6.5.2.2; page 6-9 DISCUSSION: This proposed change is to provide the correct name of the organization of or.e'of the members of the Safety Review Committee which is listed in Technical Specification 6.5.2.2.

Previously the name of.the organization was Middle South Services,.Inc. ?It has now been changed to MSU System Services, Inc.

JUSTIFICATION: This proposed change is strictly administrative in nature and is being made so that the GGNS Technical Specification accurately reflects current and correct information. The company name change was made so as to more. appropriately characterize the company's role as a service organization providing support functions for all companies in the MSV System.

The designated representative from MSU System Services, Inc.

will meet the qualification requirements of SRC membership as defined in Technical Specification 6.5.2.2.

SIGNIFICANT HAZAoDS CONSIDERATIONS:

SERI has evaluated the proposed change and considers.it not to involve a significant hazards consideration for the following reasons:

(1) The ~ proposed change will not significantly increase the probability or consequences of an accident previously evaluated, because the change is strictly a name change of a supporting organization represented on the Safety Review Committee.

(2) The proposed change will not create the possibility of a new or different accident from any accident previously evaluated, because no physical modifications are being made to the plant in conjunction with this proposed change.

(3) . The proposed change will not involve a significant reduction in a margin of safety, because only the name of the company has changed. The qualification requirements L for membership on the Safety Review Committee has not been affected.

J16TSS7012602 - 1

L ADMINISTRATIVE CONTROLS-1 l; '6.5.2 SAFETY REVIEW COMMITTEE (SRC) l FUNCTION 6.5.2.1. The SRC shall function to provide independent review and audit of

. designated activities in,the areas of:

a. ' nuclear power plant operations

b. nuclear engineering

~

c. chemistry and radiochemistry

d. -metallurgy

e. instrumentation'n and control

-f. radiological safety

g. mechanical and electrical engineering

' h. ~ quality assurance practices .

COMPOSITION 6.5.2.2 The SRC shall be composed of the:

l Chairman: Vice President, Nuclear Operations Member: Vice President, Nuclear. Engineering & Support .

Member: Director, Nuclear Plant Engineering Member: Site Director, GGNS ,

Member: Director, Quality Assurance g sy, fro m Member: Designated Representative,.. _ .. ,, nth Services, Inc. l Member: GGNS General Manager Member: Director, Nuclear Licensing Member: Manager, Radiological and Environmental Services Member: j Princip:' EngE::r, Operations Analysis ,

1. 1. "*9*$ Two or more additional voting members shall be consultants to System Energy e. j Resources, Inc. consistent with the recommendations of the Advisory Committee [~

]

on Reactor Safeguards letter, Mark to Palladino dated October 20, 1981.

M The SRC members shall hold a Bachelor's degree in an engineering or physical e science field or equivalent experience and a minimum of five years of. technical t-experience of which a minimum of three years shall be in one or more of the disciplines of 6.5.2.la through h. In the aggregate, the membership of the 5 1 committee shall provide specific practical experience in the majority of the u disciplines of 6.5.2.la through h. s--

3 ALTERNATES ==

4 6.5.2.3. All alternate members shall be appointed in writing by the SRC Chairman to serve on a temporary basis;..however, no Jnore. than two alternates shall participate as voting members in SRC activities at any one time.

GRAND GULF-UNIT 1 6-9 Amendment No. _ l

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3. NPE 86/17' Makeup Water Treatment Isolation Valve Clarification

SUBJECT:

Technical Specification. Table 3.6.6.2-1; page 3/4 6-53

. DISCUSSIONS It:is proposed to change the subject Technical Specification table item " Makeup Water Treatment Sys. Aux. Bldg. Isol. Valve (P21-F024)-(A)"to"MakeupWaterTreatmentSys. Aux. Bldg.

Isol. Valve (P21-F024)-(A&B)".

JUSTIFICATION: Secondary containment isolation air operated. valve P21-F024 provides automatic isolation of a four. inch makeup water treatment supply line to the auxiliary building. The secondary containment isolation. signals that provide closure signals for P21-F024 are listed in Technical Specification Table 3.3.2-1.

The present listing of valve P21-F024 in Table 3.6.6.2-1 indicates only electrical Division I { designated (A)} as a power source for.the solenoid operated pilot valve. There are actually two solenoid 9perated pilot valves for valve.P21-F024.

Pilot valve SV-F500 is powered from ESF Division II and pilot valve SV-F501 is powered from ESF Division I. Table 3.6.6.2-1 should'be changed to reflect that both ESF Divisions I and II (A&B) supply power to operate the pilot valves associated with valve P21-F024.

This change to the technical specifications is made for  ;

clarification purposes and does not involve a design change to '

the plant.

SIGNIFICANT HAZARDS CONSIDERATIONS:

SERI has evaluated the proposed change and considers it not to involve-a significant hazards consideration for the following reasons:

(1) The proposed change will not significantly increase the probability or consequences'of an accident previously evaluated, because the change is strictly a clarification to reflect the actual design of the valve in the technical 1 specification table. No design changes to the plant are invloved and secondary containment isolation times are not  !

affected by the change. l (2) 'The~ proposed change will not create the possibility of a new or different accident from any accident previously evaluated, because no physical modifications are required to be made to the plant in conjunction with this proposed change.

(3) The proposed change will not involve a significant reduction in a margin of safety, because the change is a clarification that does not affect the design closure function of valve P21-F024.

J12 MISC 87012601 - 1

lQM - 16//7 f TABLE 3.6.6.2-1 (Continued)

, SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION DAMPERS / VALVES MAXIMUM ISOLATION TIME VALVE FUNCTION _,(Seconds)

Valves (Continued) y Cond. &' Refuel Water Transfer Aux. Bldg. Isol. Valve i- <

-(P11-F064)-(A) 4 Cond & Refuel Water Trans**r Aux. Bldg. Isol. Valve (P11-F066)-(A) 4 Cond. & Refuel Water Transfer Aux. Bldg. Isol. Valve (P11-F047)-(A) 4 Cond. & Refuel Water Transfer Aux. Bldg. Isol. Valve (P11-F063)-(B) 4

~

Cond. & Refuel Water Transfer Aux. Bldg. Isol. Valve (P11-F065)-(B) 4 Cond. & Refuel Water Transfer Aux. Bldg. Isol. Valve (P11-F067)-(B) 4 Cond. & Refuel Water l Transfer Aux. Bldg. Isol. Valve .

(P11-F061)-(B) 4 Floor and Equipment Drains System Aux. Bldg. Isol Valve (P45-F158)-(A) 9 Floor and Equipment Drains System Aux. Bldg. Isol. Valve (P45-F160)-(A) 9 Floor and Equipment Drains System Aux. Bldg. Isol. Valve (P45-F163)-(A&B) 9 ,

i Floor and Equipment Drains System Aux. Bldg. Isol. Valve (P45-F159)-(B) 9 l

i l

Floor and Equipment Drains System Aux. Bldg. Isol. Valve {

(P45-F161)-(B) 9  !

)

Makeup Water Treatment Sys. Aux. Bldg. Isol. Valve (P21-F024)-fat (A E B) , 30 g ,

l Domestic Water System Aux. Bldg. Isol. Valve (P66-F029A)-(A&B) 4 PSW Aux. Bldg. Isol. Valve (P44-F121)-(A) 100 GRAND GULF-UNIT 1 3/4 6-53 A -e n d- en #e - I i

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4.- NLS 87/01:' Manual Initiation Handswitch Calibration Requirement Correction.

SUBJECT:

. Technical Specification Table 4.3.3.1-1,' items A.I.d and B.1.d; pages 3/4 3-34 and 3/4 3-34a..

DISCUSSION: It is proposed to change the subject Technical Specification

. Table channel' calibration requirement for manual initiation (handswitch), -items A.I.d and B.1.d from Q (quarterly) to NA (Nonapplicable). This is' strictly'an administrative type' change to improve the consistency of the Technical-Specification.

~

JUSTIFICATION: The manual initiation handswitches are on-off devices which are tested by performing a channel functional test on a refueling.

frequency basis. This channel functional test checks proper performance of the handswitch th' rough the. system and component that it actuates. These manual initiation handswitches do not consist-of components that can-be calibrated and as:such a channel calibration cannot be performed. .This change is needed to make the surveillance requirements for the subject manual initiation handswitches consistent with the other manual

-initiation handswitches listed in Table 4.3.3.1-l'as well as the BWR Standard Technical Specification, l'

SIGNIFICANT HAZARDS CONSIDERATIONS:

SERI has evaluated the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:

(1) The proposed changes will not significantly increase the.

probability or consequences of an accident ;:reviously evaluated, because the changes are strictly administrative ,

in nature and are being made to improve the consistency of i Technical Specification Table 4.3.3.1-1.

(2) The proposed changes will not create the possibility of a new or different accident from any accident previously evaluated, because no physical modifications are being made to the plant in conjunction with these proposed changes.

( .,) The proposed changes will not involve a significant reduction in a margin of safety, because the appropriate and required testing of the manual initiation handswitches will continue to be performed and an inconsistency in the Technical Specification Table 4.3.3.1-1 will be corrected.

I J16TS87012601 - 1 l

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5. NLS-86/17 Delet' ion of Temporary Tech Spec Change Footnotes

SUBJECT:

Technical Specification 3.3.2, 3.6.4, 3.6.6.1, 3.6.6.2 and 3.6.6.3; pages'3/4 3-9, 3/4 3-9a, 3/4 6-28, 3/4 6-48, 3/4 6-48a, 3/4 6-49, 3/4 6-49a and 3/4 6-55.

. DISCUSSION: An emergency, temporary Technical Specification change request I was submitted October 3, 1986. This request was granted and Amendment 22 to the Facility Operating License NPF-29 was subsequently issued. 'This proposed change is being submitted in order to delete the temporary footnotes which are no longer effective.

JUSTIFICATION: This proposed change is strictly administrative in nature. The footnotes which were added by Amendment 22 are no longer effectiva; however, their inclusion with the existing footnotes  ;

could cause momentary delays or confusion for the operators who must match the footnote symbols with the appropriate footnotes which are still effective.

SIGNIFICANT HAZARDS CONSIDERATIONS:

SERI has evaluated the proposed changes and considers them not l to involve a significant hazards consideration for the following reasons.

(1) 'The proposed changes will not significantly increase the  !

probability or consequences of an accident previously evaluated, because these changes are strictly administra-tive in nature and do not involve any changes to system, i components or procedures which affect plant operation.

g (2) The proposed changes will not create the possibility of a new or different accident from any accident previously evaluated, because no physical modifications are required to be made to the plant in conjunction with these proposed changes.

(3) The proposed changes will not involve a significant reduction in a margin of safety, because the deletion of the no longer valid footnotes will not adversely effect plant operation. The deletion of the out-of-date footnotes could possibly improve the margin of safety since the operators could focus their attention on only the valid footnotes. )

'J12ATTCH87012602 - 1

ML S - 9'6//7 INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION

'3.3.2 The isolation actuation instrumentation channels shown in Table 3.3.2-1 shall be OPERABLE with their trip setpoints set consistent with the values shown 1'n the Trip Setpoint column of Table 3.3.2-2 and with ISOLATION SYSTEM RESPONSE TIME as shown in Table 3.3.2-3.

APPLICABILITY: As shown in Table 3.3.2-1 ACTION:

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

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

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

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

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

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

4.3.2.3 The ISOLATION SYSTEM RE3PONSE TIME of each isolation trip function shown in Table 3.3.2-3 shall be demonstrated to be within its limit at least once per 18 months. Each test shall include at least one channel per trip system such that all channels are tested at least once every N times 18 months, where N is the total number of redundant channels in a specific isolation trip system.

• An inoperable channel need not be placed !9 the tripped condition where this would cause the Trip Function to occur. In thu e cases, the inoperable channel shall be restored to OPERABLE status within 2 hoen er the ACTION required by Table 3.3.2-1 for that Trip Function shall be taken.

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

tripped condition without causing the Trip Function to occur, place the trip system with the most inoperable channels in the tripped condition; if both systems have the same number of inoperable channels, place either trip l

system in the tripped condition.

3/4 3-9 Amendment No.____

GRAND GULF-UNIT 1 l

( - - - _ _ - _ _ _ - _ _ _ _ - _ _ _ _ _

NLS.- FM/ 7 I j

IH57Ru G TAT;G;4 i

'1 i

i

{

i l

THIS PA GE DELETED Isolut on instrumentation is not required to be OPE control rod removal, r tion and movement ue ed core cells fo;* the period from October 3,1 c ober 10, 1986.

3/4 3-9a o.22 J"

$LS -Y4//2 i CONTAINMENT SYSTEMS 3/4.6.4 CONTAINMENT AND DRYWELL ISOLATION VALVES LIMITING CONDITION FOR OPERATION 3.6.4 The Containment and drywell isolation valves shown in Table 3.6.4-1 shall be OPERABLE with isolation times less than or equal to those shown in Table 3.6.4-1.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, and .

l ACTION:

kith one or more of the containment or drywell isolation valves shown in Table 3.6.4-1 inoperable, maintain at least one isolation valve OPERABLE in each affected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:

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

b. Isolate each affected penetration by use of at least one deactivated 1 automatic valve secured in the isolated position,* or ,

c. Isolate each affected penetration by use of at least one closed l manual valve or blind flange."

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

l 1

1

.s

• Isolation valves, except MSIVs, closed to satisfy these requirements may be  ;

reopened on an intermittent basis under administrative controls. j

1. Isolation valves shown in Table 3.6.4-1 are also required to be OPERABLE when their associated actuation instrumentation is required to be OPERABLE per Table 3.3.2-1.

1 isolation valves are not require

~ '

on during control rod remova , nt within defueled core cel ctober 3, 1986, throug CRAND GULF-UNIT 1 3/4 6-28 Amendment No. _

l

l MLS - 1Y4b7 l CONTAINMENT SYSTEMS 3/4.6.6 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY.

LIMITING CONDITION FOR OPERATION i

3.6.6.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained. l APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 nd ACTION:

Without SECONDARY CONTAINMENT INTEGRITY:

a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT SHUTOOWN within the

.next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. .In Operational Condition * , suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and operations

,with a potential for draining the reactor vessel. The provisions of i Specification 3.0.3 are not applicable. ,

. 5 SURVEILLANCE' REQUIREMENTS 4.6.6.1 SECONDARY. CONTAINMENT INTEGRITY shall be demonstrated by:

a. Verifying at least once per 31 days that:

1. All Auxiliary Building and Enclosure Building equipment hatches and blowout panels are closed and sealed.

2. The door in each access to the Auxiliary Building and Enclosure Building is closed, except for routine entry and exit. '

3. All Auxiliary Building and Enclosure Building penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers / valves and required to be closed during accident conditions are closed by valves, blind flanges, rupture discs or deactivated automatic dampers / valves secured in position. a l

b. At least once per 18 months:

1. Verifying that one standby gas treatment subsystem will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in less than or equal to 120 seconds, and Operating one standby gas treatment subsystem for one hour and l

2. l maintaining greater than or equal to 0.266 inches of vacuum water gaus2 in the secondary containment at a flow rate not exceeding i

4000 CFM.

"When irradiated fuel is being handled in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel. ,

3/4 6-48 Amendment No. _  :

GRAND GULF-UNIT 1 g 4 .

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. NLS -94/i7 W T SY:TE":

1 I

l I

THIS PAGE DELETED N, _

1. 5ECONDARY INTEGRITY is not required durin rod removal, reinstallation and moves in defueled s for the period from October 3, 1986, through October .

GRAN 1 3/4 6-48a t No. 22 j

f4LS-96!!1 CONTAINMENT SYSTEMS SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS / VALVES LIMITING CONDITION FOR OPERATION 3.6.6.2 Th'e' secondary containment ventilation system automatic isolation ,

dampers / valves shown in Table 3.6.6.2-1 shall be OPERABLE with isolation  !

times less than or equal to the times shown in Table 3.6.6.2-2.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 nd l'

ACTION:

With one or more of the secondary containment ventilation system automatic isolation dampers / valves shown in Table 3.6.6.2-1 inoperable, maintain at least one isolation damper / valve OPERABLE in each affected penetration that is oper., and within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> either:

a. Restore the inoperable damper / valve (s) to OPERABLE status, or

b. Isolate each affected penetration by use of at least one deactivated automatic damper / valve secured in the isolation position, or

c. Isolate each affected penetration by use of at least one closed manual valve or blind flange.

Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the t following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

'Otherwise, in Operational Condition * , suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and opera-tions with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not appifcable.

SURVEILLANCE REQUIREMENTS 4.6.6.2 Each secondary containment ventilation system automatic isolation damper / valve shown in Table 3.6.6.2-1 shall be demonstrated OPERABLE:

a. Prior to returning the damper / valve to service after maintenance, repair or replacement work is performed on the damper / valve or its associated actuator, control or power circuit by cycling the damper / valve through at least one complete cycle of full travel and verifying the specified isolation time.

b. During COLD SHUTDOWN or REFUELING at least once per 18 months by verifying' that on a containment isolation test signal each isolation damper / valve actuates to its isolation position.

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

"When irraciated fuel is being handled in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

GRAND GULF-UNIT 1 3/4 6-49 Amendment No.

l

NLS -eM7

: == = =

u I

i TEIS PAG E JELETE J X -

1. 5econdary con automatic isolation dampers / valves required to be OPERABLE during contW removal, reinsta and movement within defueled core cells for the per r 3,1986, through October 10, 1986. ,

GRAND fd& H MIT 1 3/4 6-49a No.22

/

- - - _ _ _ _ . _ _ _ _ _ _ - - _ - _ _ . - - - a

RLS -M,// 7 l

CONTAINMENT SYSTEMS STANDBY GAS TREATMENT SYSTEM LIMITING CONDITION FOR OPERATION l 3.6.6.3 Tw independent standby gas treatment subsystems shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and ACTION:

a. With one standby gas treatment subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 7 days, or:

1. In OPERATIONAL CONDITION 1, 2 or 3, be in at least HDT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

2. In Operational Condition *

, suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

The provisions of Specification 3.0.3 are not applicable.

b. With both sttndby gas treatment subsystems inoperable in Operational Condition *, suspend handling of irradiated fuel in the primary or secondary containment, CORE ALTERATIONS or operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3.

are not applicable. .

SURVEILLANCE REQUIREMENTS 4.6.6.3 Each standby gas usatment subsystem shall be demonstrated OPERABLE:

a. At least once per 31 days by initiating, from the control room, flow through the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 continuous hours with the heaters OPERABLE.

"When irradiated fuel is being handled in the primary or secondary containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel. ,

fstanwy v . t---+=nt systems are not required to be opraanLE :., ' ,, un1.roi rod removal, reinstallation ~ e ; ^ ': : ' - knin defueled core cells for the narW ' x Juver 3,1985, through October 10, lysis -

GRAND GULF-UNIT 1 3/4 6-55 Amendment No. f

6.A. SUBJECT

1. .OLCR-NS-87/02 Environmental Protection Plan (EPP) Recordkeeping

2. Affected Document: Environmental Protection Plan, Erosion Control Inspection, 4.2.1 -page 4-2  !

B. DISCUSSION The following change is proposed:

1. The requirement for maintenance of field logs of locations of erosion damage and measures taken to rG tify erosion problems is changed from a period of two years to a period of five years.

C. JUSTIFICATION

1. This change is purely administrative in nature and corrects an apparent inconsistency between EPP Sections 4.2.1 and 5.2. Section 4.2.1 states, " Field logs indicating locations of erosion damage and measures taken to rectify erosion problem areas and estimation of the time to achieve effective stabilization will be maintained and available for inspection for a period of two years." Section 5.2 states, "All other records, data and logs related to this EPP shall be maintained for five years or, where applicable, in accordance with the requirements of other agencies." Since the record retention requirement of Section 4.2.1 is not specified as being a requirement of "other agencies," an apparent inconsistency in the length of time these records are maintained. Changing the record retention requirements of Section 4.2.1 from two years to five years eliminates the inconsistency.

D. SIGNIFICANT HAZARDS CONSIDERATION

1. The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

This is a purely administrative change which corrects an inconsistency between the recordkeeping requirements of Section 4.2.1 and Section 5.2 of the EPP. This change involves no changes to plant systems or hardware and as such does not affect the probability or consequences of any previously evaluated accidents.

2. The proposed change does not create the possibility of a new or different kind of accident from any previously analyzed. This change is purely administrative in nature and is provided to correct an inconsistency between the recordkeeping requirements of Section 4.2.1 and Section 5.2 of the EPP. This change has no effect on any accident analysis and therefore it does not create the possibility of a new or different accident from any previously analyzed.

3. The proposed change does not involve a significant reduction in a margin of safety. The change will increase the record retention requirements of EPP Section 4.2.1 from two years to five years but does not affect any margin of safety.

J16TS87070801 - 1

by the aerial surveys, and walking patrols will be directed to the problem areas to evaluate the extent of the problem to be corrected.

• \The Erosion control Inspection 'rogram shall begin upoa coc.mencement of normal transmission line inspection proceduret Semi-annual surveys shall continue-

.until stabilization of soil and vegetation (i.e., ground cover establishment) is achieved.

A summary of the field inspection program and any procedures implemented to control abnormal erosion conditions assoicated with transmission line main s tenance activities shall be reported in the Annual Environmental Operation Report in accordance with Subsection 5.4.1. Fiele logs indicating locations of erosion damage and measures taken to rectify erosion problem areas and g , estimation of the time to achieve effective stabilization will be maintained and,availableforinspectionforaperiodof4de$ ears. Results reported shall contain information encompassing but not limited to inspection date,, ,

estimated size of erosion problem area, probable cause of erosion, type of stabilization program, and date of effective stabilization, as appropriate.

4.2.2 Coolino Tower Drift Procram Seven sampling sites will be utilized to measure cooling tower drif t-depos'ition.

At least two of the sampling sites'will have duplicate sampling devices. Six of the seven sampling sites will be located in areas where maximum salt deposition is predicted. These areas were extrapolated from the Bechtel Salt Deposition Model developed for the SERI Final Environmental Report. The seventh sampling site will be a control site located south of Raymond, Mississippi.

Fallout samples will be collected using buckets with a known volume of deionized water in each. The buckets will be located four to six feet above the ground, fitted with bird rings, and covered with fine mesh screens to exclude leaves and insects. The samples will be collected on a quarterly basis and analyzed for calcium, magnesium, sodium, iron, phosphates, nitrates, chloride, fluorides, .

sulfates, and total dissolved solids. These parameters were selected because past analyses have shown them to be prevalent in the coo _ ling tower source water.

The results of these analyses will be correlated with local rainfall data and 4-2 Amendment No. _

I t ,

4

7. NPE-86/16 - Upper: Containment' Pools and Weir Wall Gates b  :

SUBJECT:

iTechnical Specification 3.5.2 footnote', 3.5.3 footnote, and l Surveilbnce Requirement 4.6.3.4.b;pages 3/4 5-6, 3/4 5-8, and 3/4 6-27.

DISCUSSION: . The proposed technical specification change is the result of a

-design change to. increase the height of the upper containment pool' weir wall 18 inches tu oss the full. width of the pool.

This weir wall separates the reactor cavity and the moisture .

separator.-storage area. The modification which is scheduled to be performed is an ALARA radiation enhancement to provide complete submergence of the separator when in its stored i position in the pool with the reactor cavity drained. The new {

weir wall will include two removable gates that are required to be-in a stored position or otherwise removed from the upper-containment pools during Operational Conditions 1, 2, or 3 to ensure that the suppression pool makeup. capability is not affected.

Current Technical Specifications.3/4.5.2, 3/4.5.3, and 3/4.6.3.4 specify the required positions of existing upper containment pool gates and the spent fuel pool gate. With the.' addition of the.two new weir wall gates the subject technical specifications should be revised to clarify the distinctions of the new and existing gates and their proper positions. Technical 1 Specifications 3/4.5.2 and 3/4.5.3 require revision to indicate that the upper containment fuel pool gates currently referenced in the footnote are actually the reactor cavity gate and the transfer canal gate. . Technical Specification 3/4.6.3.4 will require revision to indicate that all the upper containment pool gates, including the two weir wall gates, be in their stored position or removed from the upper containment pool during Operational Conditions 1, 2, and 3 to ensure that suppression i pool make-up capability is not affected. In addition, the requirement in the footnote of Technical Specification 3/4.5.2 to have the spent fuel pool gate removed is being deleted because the spent fuel pool and upper containment pool do not need-to be in communication when declaring the ECCS inoperable.

The proposed' changes will provide consistency between Technical Specification 3/4.5.2, 3/4.5.3, and 3/4.6.3.4.

JUSTIFICATION: The upper containment pool is a rectangular stainless steel lined structure crossing the top of the drywell area. The pool which is filled with water provides shielding for the operating

. floor during normal and refueling operations. A portion of this i

J16 MISC 87032702 - 1

1 JUSTIF.ICATIONi(continued).

+ water may also be drained to.the suppression pool following'a LOCA to make up for.the' water inventory pumped:into the vessel.

and the:drywell from.the emergency core cooling systems. The

> ; upper containment pool is' divided by interior crosswalls into the following distinct areas:.

(a) steam separator storage; n b)reactorcavity; c) steam dryer-and fuel storage; and d) fuel transfer canal.

Presently, one removable stainless steel: gate is provided in the L wall between'the reactor cavity and the fuel storage' pool and a second: removable gate.is provided.in the wall between the fuel storage pool and the fuel transfer canal. These gates are l utilized.to isolate thel reactor cavity and fuel transfer canal Jfor refueling and maintenance activities in. Operational Conditions 4 and 5. The weir wall between the reactor cavity-and the separator. storage area controls the volume of water dumped.by the Suppression Pool Makeup System. 'The existing top elevation of the wall ensures that 'during refueling. operations an inadvertent dump to the suppression pool will maintain at

.-least one foot.of. water shielding over the top of active fuel

'when a fuel bundle is fully withdrawn during transfer. An additional function of the weir wall is to allow ' draining of the 1 . reactor cavity with the steam separator in a stored position.

It was discovered that the weir wall separating the reactor, cavity and the separator storage area was of insufficient height to allow for. complete water coverage o.f the moisture separator "g .

during'. refueling activities .with "the reactor cavity drained. To provide complete water coverage of the moisture separator, modifications are to be made to the upper containment pool weir E wall to increase its height 18 inches across the full width of the upper' containment pool between the reactor cavity area and moisture separator storage area.

The 18-inch extension will contain two (2) weir wall gates which will be installed in the weir wall during refueling and removed prior to.the commencement of normal plant operation. The removal of the weir wall gates during Operational Conditions 1, 2, and 3 is required to ensure that the suppression pool makeup capability is not affected.

i J16 MISC 87032702 - 2

JUSTIFICATION: (continued)

The proposed change to the footnotes of Technical Specifications 3.5.2 and 3.5.3 is required to distinguish between the different 1 upper containment pool gates and to further clarify the conditions or gate positions when the ECCS and Suppression Pool are not required to be operable during Operational Condition 5.

This change specifically identifies the reactor cavity and transfer canal gates and requires that these gates.be removed.

It also deletes the requirement for the spent fuel gate to be ,

removed because the volume of water in the spent fuel pool is l not required when the ECCS is inoperable. Furthermore 'this change allows the installation of the weir wall gates with ECCS ,

and Suppression Pool out of service _because with the water level '

at a minimum of 22 feet 8 inches, the gates will be submerged thereby maintaining adequate heat removal capabilities.

The proposed change to Technical Specification Surveillance Requirement 4.6.3.4.b is required to include the weir wall gates and the requirement that they be removed during Operational Conditions 1, 2, and 3. This change will ensure that the modifications which will be made to the upper containment pool weir wall will not affect the capability of the Suppression Pool Makeup System.

SIGNIFICANT HAZARDS CONSIDERATIONS:

SERI has evaluated the proposed changes and considers them not to involve a significant hazards consideration for the following reasons:

(1) The proposed changes do not involve a significant inacase in the probability or consequences of an accident previously evaluated because the changes will indicate the proper positions of the reactor cavity and transfer canal gates while in refueling with ECCS or Suppression Pool inoperable and of all upper containment pool gates during Operational Conditions 1, 2 and 3. The changes will provide for the needed additional water coverage of the moisture separator during storage while continuing to ensure adequate suppression pool makeup capability during normal operation. Also, the installation of the added weir wall gates during refueling with the upper containment pool water level at a minimum of 22 feet 8 inches above the reactor vessel flange will still provide adequate heat removal capability with ECCS and Suppression Pool systems out of service. The requirement for the spent fuel pool gate to be removed prior to declaring ECCS inoperable has been deleted based on a review performed by General Electric. The volume of water in the upper containment pool is not required to be in communication with the spent fuel pool when declaring ECCS inoperable. This position is consistent with the Technical Specifications of three other domestic BWR/6 MARK III plants surveyed by General Electric.

J16 MISC 87032702 - 3

, 7;,l,

. ,7 (2) The proposed changes ~do not create the possibility of a new or different kind of accident from any accident previously evaluated because the changes will provide clarification-to the ECCS operability footnote of Technical Specification 3.5.2 and the Suppression Pool operability footnote of 3.5.3 without affecting the design bases and-will identify the proper positions of all upper containment pool gates in Technical Specification Surveillance Requirement 4.6.3.4.b in order to ensure the operability of the suppression pool makeup system.

-(3) The proposed changes do not involve a significant reduction in the margin of safety because the changes will properly indicate the positions of the reactor cavity, transfer canal, and weir wall gates during refuelir.g and normal operation.

Therefore, the proposed changes involve no significant hazards considerations.

l l

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J16 MISC 8703270? - 4

Hps- 96//6 EMERGENCY CORE COOLING SYSTEMS 3/4 5.2 ECCS - SHUTDOWN LIMITING CONDITION FOR OPERATION 3.5.2 At hast two of the following shall be OPERABLE: -

a.

The low pressurc. core spray (LPCS) system with a flow path capable of taking suction from the suppression pool and transferring the water through the spray sparger to the reactor vessel.

b.

Low pressure coolant injection (LPCI) subsystem "A" of the RHR system with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to the reactor vessel.

c.

Low pressure coolant injection (LPCI) subsystem "B" of the RHR system with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to the reactor vessel, d.

Low pressure coolant inject en (LPCI) subsystem "C" of the RHR system with a flow path capable of taking suction from the suppression pool upon being manually realigned and transferring the water to the reactor vessel, e.

The high pressure core spray (HPCS) system with a flow path capable of taking suction from one of the following water sources and trans-ferring the water through the spray sparger to the reactor vessel:

1. From the suppression pool, or

2. When the suppression pool level is less than the limit or is drained, fro.'n the condensate storage tank containing at least 170,000 available gallons of water, equivalent to a level of 18 feet.

APPLICABILITY: OPERATIONAL CONDITION 4 and 5*.

ACTION:

a.

h v-With one of the above required subsystems / systems inoperable, restore

• at least two subsystems / systems to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or suspend all operations that have a potential for draining the reactor D vessei. % prov;slons of Sy~ ec.,'f;en:o s 2 A t+

e n . e g opy jic J fa., {

b.

With both of the above required subsystems / systems inoperable, suspend n CORE ALTERATIONS and all operations that have a potential for draining the reactor vessel. Restore at least one subsystem / system to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or establish SECONDARY CONTAINMENT INTEGRITY within the next 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

"The ECCS is not required to be OPERABLE provided that the reactor vessel head is removed,th; removed, the cavity is flooded, gthe upper containment 4ve4- pool .ga4e+ are

=t '=1 ;0

1 ;:te: r: rer:; S and water level is maintained within the limits of Specifications 3.9.8 and 3.9.9.

de ag efor cavhy and trans k pl yn.s la GRAND GULF-UNIT 1 3/4 5-6 Amed%4nr No. _

gy y '.- 9 4//1, EMERGENCY CORE COOLING SYSTEMS 3/4.5.3 SUPPRESSION POOL '

LIMITING CONDITION FOR OPERATION 3.5.3 ~The' suppression pool shall,be OPERABLE:

a. In OPERATIONAL CONDITION 1, 2 or 3 with a contained water volume of at

.least 135,291 ft8 , equivalent to a level of 18'4-1/12."

b. 'In OPERATIONAL CONDITION'4'or 5* with a contained water volume of at least 93,600 ft3, equivalent to-a level of 12'8",.except that the ,

suppression pool . level may be less than the limit or may be drained .

provided that:

1. No operations are performed that have a potential for draining the reactor vessel,

2. The reactor mode switch is locked in the Shutdown or Refuel position,

3. The condensate storage tank contains at least 170,000 available gallons'of water, equivalent to a level of 18', and

4. The HPCS system is OPERABLE per Specification 3.5.2 with an OPERABLE flow. path capable of taking suction from the condensate storage tank and transferring the water through the spray sparger to the reactor vessel.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4 and 5*.

ACTION;

a. In OPERATIONAL CONDITION 1, 2 or 3 with the suppression pool water level-less than.the above limit, restore the water level to within the limit within I hour or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,

b. In OPERATIONAL CONDITION 4 or 5* with the suppression pool water level less than the above limit or drained and the above required conditions not satisfied, suspend CORE ALTERATIONS and all opera-tions that have a potential for draining the reactor vessel and lock the reactor mode switch in the Shutdown position. Establish SECONDARY CONTAINMENT INTEGRITY within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

See Specification 3.6.3.1 for pressure suppression requirements.

.The suppression pool is not required to be OPERABLE provided that the reactor vessel head is removed, the cavity is flooded or being flooded from the suppression pool, he. upper containment 4*e4 pool ga4es- are removed when the cavity is flooded, nd the water level is maintained within the limits of Specification 3.9.8 nd 3.9.9.

}%e yuctor cavNy and trans[nr cen sl orTes k GRAND GULF-UNIT 1 3/4 5-8 h a sar No. _

rc

') ft 4

NPE - 9Ulb g g INMENT SYSTEMS

• SUPPRESSION p00L MAKEUP SYSTEM 4

LIMITgG CONDIT' ION FOR'0PERATION 3.6.3.4 '7he suppression pool makeup system shall be OPERABLE.

i APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3. l ACTION:

a. With one suppression pool makeup line inoperable, restore the inoperable makeup line to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT SHUT-I DOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

b. With the upper containment pool water level less than the limit, restore the water level to within the limit within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

c. With upper containment pool water temperature greater than the limit, restore the upper containment pool water temperature to within the limit within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD CHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, i

SURVEILLANCE REQUIREMENTS _

4.6.3.4 The suppression pool makeup system shall be demonstrated OPERABLE:

a. At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying the upper containment poo.

water: .

1. Level to be greater than or equal to 23'3" above the pool bottom in the dryer / separator storage area, and

2. Temperature to be less than or equal to 1?.5'F.

b. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position, and9ee cSd'n;; gates are in the stored position or are otherwise removed

. from the upper containment pool.-

c. At,least once per 18 mont.hs by performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual makeup of water to the suppression pool may be excluded from this test.

+ Q T all arp a cont 4 h M Ef n GRAND GULF-UNIT 1 3/4 6-27 A %ea M ent N0' ,

._.m.. ._.

p.

1 L

l 8.. NPE-87/03- Addition of Heat and Smoke Detectors SUBJECT Technical Specification Table 3.3.7.9-1, pages 3/4 3-81,

-3/4-3-82, 3/4 3-84', 3/4 3-85, 3/4 3-86, 3/4 3-87 i DISCUSSION: The proposed changes to the technical specifications listed above involve the addition of Function A (early warning fire detection and notification only)' smoke detectors and Function B (actuate fire suppression systems and provide early warning and notification) heat detectors in order to enhance the existing i fire detection capabilities of the fire detection system. The actual changes to the system by fire zone are as follows:

Heat Detectors Smoke Detectors-Fire Zone Description Added Added OC202 Fire Area 31 - Control 7 6 Building Division I Switchgear Area, Elevation 111' - 0".

OC215 Fire Area 38 - Control 0 3 Building Division II Switchgear Area, Elovation lil' - 0".

OC402 Fire Area 42 - Control 2 0 Building Lower Cable Spreading Room, Elevation 148' - 0".

IA101 Fire Area 1 - Auxiliary 0 1 Building Passage, Elevation 93' - 0" and 103' - 0".

1A117 Fire Area 1 - Auxiliary 0 1 Building Corridor and Miscellaneous Equipment Area, Elevation 93' - 0" and 103' - 0".

IA222 Fire Area 6 - Auxiliary 0 5 Building Motor Control Center Area, Elevation 119' - 0".

l J16TS87071501 - 1

Heat Detectors Smoke Detectors Fire Zone Description Added Added 1A301 Fire Area 11 - Auxiliary 0 1 Building Corridor, Elevation 139' - 0".

1A321 Fire Area 11 - Auxiliary 0 1 Building Motor Control Center, Elevation 139' - 0".

1A322 Fire Area 11 - Auxiliary 0 1 Building Centrifugal Chiller Area, Elevation 139' - 0".

IA401 Fire Area 19 - Auxiliary 0 1 Building Passage, Elevation 166' - 0".

1A417 Fire Area 19 - Auxiliary 0 1 Building Miscellaneous Equipment Area, Elevation 166' - 0".

1A428 Fire Area 19 - Auxiliary 0 4 Building Passage, Elevation 166' - 0".

These changes are shown on the attached mark-ups of the GGNS Tachnical Specifications.

JUSTIFICATION: The 1984 Triennial Fire Protection Audit of Grand Gulf Nuclear Station, Unit 1 identified a finding related to the location of ionization type smoke detectors and thermal heat detectors and the adherence to the requirements of NFPA 72D-1975. NFPA 72D-1975 states that automatic fire detectors shall be located in accordance with NFPA 72E.

Specifically identified was that fire detection equipment in some areas was not mounted on the ceiling and not spaced adequately in beam pockets. As a result of this finding, SERI conducted a detailed fire protection evaluation to determine the adequacy of the existing configuration and if found necessary determine where relocation and/or addition of detectors are required to meet SERI's commitment to meet the functional requirements of NFPA 72D-1975. UFSAR Table 9.5-11, Section E.1.a describes SERI's commitment to meet the functional req' rements of NFPA 720. SERI defines the functional requirements to be those requirements delineated in NFPA 72D pertaining to the performance of initiating device circuits, signaling line circuits and indicating device circuits as well as power supply sources, overcurrent protection, audible signal appliances, signal capacity of circuits and electrical supervision.

J16TS87071501 - 2

L l

I The evaluation was conducted by qualified fire protection engineers and was based on the license commitments described in the Updated Final Safety Analysis Report, the ,

requirements of NFPA 72E (1978), the manufacturer's l installation instructions, the fire hazards analysis and l the GGNS combustible heat load calculation. In all cases, the as-installed configuration, although not necessarily-in I strict'conformance with the installation requirements of '

NFPA 72E, was determined to meet the license commitments '

as required by Operating License Condition 2.C(23). l The primary function of the fire detection systems is to ,

provide early warning of a fire end/or to actuate the i appropriate suppression system such that safe shutdown of  !

the plant is not inhibited. In some cases, improvements  !

in the existing configuration were recommended in order to enhance.the early warning capability of the fire detection system. The recommended improvements were in zones which contained redundant safe shutdown equipment separated by less than 50 feet horizontally and not separated by 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> fire barriers. The detection systems located in those zones are to be enhanced as necessary to meet the strict location requirements of NFPA 72E (referenced by NFPA 72D).

The proposed enhancements will include relocation of some detectors within their respective zones but changes to the j technical specification are not required for those zones.

The proposed enhancements described above will assure that

.the detectors installed 'in those zones will be in compliance with the location requirements of NFPA 72E (1978). . Detectors installed in the remaining zones have been determined through the fire protection evaluation to be adequate to perform their required function and no changes are proposed for those zones.

The proposed modifications are to be performed prior to and during the second refueling outage currently scheduled for fourth quarter, 1987.

SIGNIFICANT HAZARDS CONSIDERATION:

SERI has evaluated the proposed changes and considers them '

not to involve a significant hazards consideration for the '

tollowing reasons:

(1) The proposed changes will not significantly increase the probability or consequences of an accident previously evaluated, because the changes are enhancements to the fire detection capability of the fire protection system described in the fire hazards analysis. The proposed changes will not increase the probability of a fire but will help to mitigate the consequences of a fire by enhancing the early warning capability of the fire detection system. Specific areas of improvement are in pockets around structural beams.

J16TS87071501 - 3

m ,

p f

.(2)'LThe proposed changes will not create the possibility-of a new or different accident'from any accident previously evaluated because the system design bases and function are not being changed.' . Fire detection systems are not the precursors for any analyzed accident and do not create the' possibility of a new n or different accident.. The proposed changes represent improvements-to the operation or design for the presently installed fire detection systems.:

(3) LThe proposed change.will.not involve a significant reduction in the margin of safety. The proposed.

changes will increase the sensitivity of the. existing

. fire detection system and as such will increase the ability to detect and/or suppress fires in the zones affected. The proposed change does not delete fire detection from any. fire zone nor will it affect any

~ other safety related. systems or equipment in the ,

plant.

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l J16TS87071501.- 4 4

pe - r7 /os TABLE 3.3.7.9-1 FIRE DETECTION INSTRUMENTATION MINIMUM INSTRUMENTS OPLRABLE*

FLAME (1) SM0KE f)

HEAT INSTRUMENT LOCATION FR) (X/Y) Wh]

a. CONTAINMENT BUILDING #

1. Return Duct Mounted Detectors 3/0 ROOM ELEV ROOM NAME

b. CONTROL BUILDING Zone 1-3 12/0 1.

OC103 93' Emergency Laundry Rm.

OC109 93' Decontamination Area 00115 93' Corridor 0C116 93' Hot Machine Shop OC117 93' Corridor OC128 93' Hot Water Heater Rm.

/0

2. Zone 1-4 OC201 111' Stairwell l OC202 111' Div. I Swgr. Rm. 0/[(CO) 2 Div. I Battery Rm. l OC207 111' (X/Y): X - is number of Function A (early warning fire detection and notification only) instruments.

Y - is number of Function B (actuation of fire suppression systems and early warning and notification) instruments.

1. The fire detection instruments located within the primary containment are not required to be OPERABLE during the performance of Type A Containment Leakage Rate Tests.

(1) Smoke and flame detectors provide only early warning capability wi'h the exception of:

(a) Zone 1-27 detectors trip closed the door between the OC208/0C208A Remote Shutdown panel rooms.

(b) Containment building return duct mounted detectors trip the containment cooler fans.

(c) Zone 1-11 and 1-13 detectors initiate the control building purge fan system.

(d) Control Room HVAC Intake Plenum Detectors trip the control room A/C units unless a control room emergency filtration system isolation mode automatic actuation signal is present.

l GRAND GULF-UNIT 1 3/4 3-81 gggy 4,

- - - - - - - _ _ _ _ _ _ _ _ . _ ]

N PE. - 7 7/O 'S TABLE 3.3.7.9-1 (Continued)

FIRE DETECTION INSTRUMENTATION

,; MINIMUM INSTRUMENTS OPERABLE" i ROOM ELEV II)

ROOM NAME HEAT FLAME SHOKE II)  !

(X/Y) (X/Y) (X/Y) l

3. Zone 1-5 3/0 i OC209 111' Div. III Bettery Rm.

OC210 111' Div. III Swgr. Rm. 0/4(CO2 )  !

4. Zone 1-6 /0 DC211 111' Div. II Battery Rm.

OC215 111' Div. II Swgr. Rm. 0/7(CO2 )

OC216 111' West Corridor

5. Zone 1-07 5/0 OC212 111' U-2 Div. I Battery Rm.

OC214 111' U-2 Div. I Swgr. Rm.

6. Zone 1-08 5/0  ;

OC203- 111' U-2 Div II Swgr. Rm. )

OC206 111' U-2 Div II Battery Rm. '

7. Zone 1-10 . 2/0 0C306 133' Electrical Chase DC307 133' Electrical Chase

8. Zone 1-11 13/0 OC302 133' HVAC Equipment Rm.

OC308 133' Corridor

9. Zone 1-12 2/0 OC304 133' Electrical Space OC305 133' Electrical Space OC412 133' Electrical Space

10. Zone 1-13 16/0 OC303 133' HVAC Equipment Rm.

11. Zone 1-14 9/0 l OC402A 148' HVAC Chase OC403 148' Computer Room 0/12(Halon) l OC410 148' Battery Room

12. Zone 1-15 15/0 OC401 148' Corridor O OC402 148' Lower Cable Spreading Room 0[(CO) 2 OC407 148' Instr. Motor Gen. Rm. 0/2(CO2 )

OC408 148' Corridor OC409 148' Electrical Chase GRAND GULF-UNIT 1 3/4 3-82 Amendment No. f ,

. . _ l

N PE-? 7 lo 1 TABLE 3.'3.7.9-1 (Continued)

FTRTbETECTION INSTRUMENTATION MINIMUM INSTRUMENTS OPERABLE

• ROOM ELEV ROOM NAME HEAT FLAME (1) SMOKE II)-

TTli) T[li1 T[Ill 19.' Zone 1 23' 21/0 OC702 189' Upper Cable Spreading Room 0/12(CO2 ) -

OC706- 189' West Corridor OC707 189' Instr. Motor Gen. Rm.

OC709 189'. Electrical Chase OC711- 189' Passage OCil2 189' HVAC Room 20.Zohe1-24 6/0 OC)03 189' Control Cabinet Area 4/0 (CO2 )

21. Z(ne 1-26 16/0 DC705 189' < U-2 Upper Cable Spreading Room OC708 189' U-2 Instr. Motor

' Gen. Rm.

22. Zone 1-27 2/0 0C208 111' Div. II Remote Shutdown Panel 0/1(CO2 )

OC208A 111' Div. I Remote Shutdown Panel 0/1(CO2 )

23. Control Room HVAC Intake 2/0 Plenum Mounted Detectors

c. AUXILIARY BUILDING  !

1. Zone 2-2 /0 1A211 119' North Corridor (Partial) 1A215 119' South Corridor (Partial) 1A222 119' West Corridor

2. Zone 2-3 5/0 1A219 119' Electrical Swgr. Rm. 0/2(CO2 )

1A220 119' Piping Penetration Room 1A221 119' Electrical Swgr. Rm. 0/2(CO2 )

3. Zone 2-4 22/0 i

1A102 93' RHR "A" Heat Ex. Rm.

1A103 93'~ RHR "A" Pump Rm. ,

IA104 93' RCIC Pump Rm.

1A105 93' RHR "B" Pump Rm.

1A106 93' RHR "B" Heat Ex. Rm.

1A128' 108' RHR "A" Heat Ex. Rm.

GRAND GULF-UNIT 1 3/4 3-84 Amendment No.

[NPE - T 7 /CG -

l p

L TABLE 3.3.7.9-1 (Continued)

FIRE DETECTION INSTRUMENTATION

!" ~ MINIMUM INSTRUMENTS OPERABLE

• ll)

ROOM ELEV ROOM NAME

• HEAT FLAME ll) SM0KE U77) (x/Y) UTC 3.- Zone 2-4 (Continued) 1A129 108' RHR "B" Heat Ex. Rm.

1A202 119' RHR "A" Heat Ex.:Rm.

1A203 119' Piping Penetration Rm.

IA204' 119' . Piping Penetration Rm.

1A205' 119' Piping Penetration Rm.

1A206 119' RHR "B" Heat Ex. Rm.

'1A207 119' Electrical Swgr. Rm. 0/3(CO2 )'

Electrical Swgr. Rm.- 0/3(C02 )

1A208 119' 1A209 115' RWCU Recirc Pump "A" Rm.

1A210 115' RWCU Recirc Pump "B" Rm.

1A223 128' Passage

'4. Zone 2-5 5/0 1A318 139' Electrical. Penetration-Room 0/2(CO2 )

~1A319 139' RPV Instr. Test Rm.

1A320 139' Electrical Penetration Room 0/2(CO2 )

27

' 5. Zone 2-6 JEWO 1A301 139' East' Corridor 1A302- 139' Southeast Corridor IA303 139' RHR "A" Heat Ex. Rm.

1A304 139' Piping Penetration Rm.

1A306 139' . Piping Penetration Rm.

1A307 139' RHR "B" Heat Ex. Rm.

1A308 139' Electrical Penetration  ;

Room 0/3(CO2 )

1A309 139' Electrical Penetration Room 0/3(CO2 )

1A314 139' South Corridor (Partial) 1A316 139' North Corridor (Partial)

6. Zone 2-7 f/0 1A417 166' North Corridor (Partial)  !

i 1A420 166' South Corridor (Partial) 1A424 166' Set Down Area (Partial) 1A428 166' West Corridor FPC & CV Pump Rm. l 1A432 166' i

~1A434 166' South Passage GRAND GULF-IAIT 1 3/4 3-85 Am d me d A . - {

i

Jppy / o 3 TABLE 3.3.7.9-1 (Continued)

' [. ) :

FIRE DETECTION INSTRUMENTATION 1

MINIMUM INSTRUMENTS OPERABLE *  !

ROOM' ELEV ROOM NAME HEAT FLAME (1) SMOKE (1)

TR77)' (X/Y) U7?]

!'.. 7.'.' Zone 2-8' P.T J//0 1A401 166' Northeast Corridor 1A402 166'. Steam Tunnel Roof 1A403 166'. Southeast Corridor 1A404 166' Unassigned Area 1A405 '166' Containment Vent..

I Equip. Room 1A406 -166' Containment Exhaust Filter Rm.

IA407; 166'- MCC. Area 0/2(C02 )'

1A410 166' MCC Area 0/2(CO2 )

1A417 166'- North Corridor (Partial) 1A420 166' South Corridor (Partial) 1A424~ 166' Set Down Area (Partial)

8. Zone 2-9 10/0 11A519 185' Storage Area 1A524 195' Platform 1A527 185' Load Center Area IA529 185' FPC & CU Rm.

IA538 185'- Platform

9. Zone 2-13 31/0 1A602 208' Storage Area 1A603 208' Passage 1A604 208' Fuel Handling Area ,

1A606 245' .HVAC Equip. Area l

10. Zone 2-14 17/0 1A114 93' Fan Coil Area (Partial) 1A115 93' Piping Penetration Rm.

.1A116 93' Piping Penetration Rm.

1A117 93' Misc. Equip. Area (Partial) 1A118 93' RHR "C" Pump Room 1A119 93' LPCS Pump Room 1A120 - 93' CCW Pump & Heat Ex. Rm.

1A122 103' South Corridor (Partial) 1A123 103' North Corridor (Partial)

11. Zone 2-15

• 1/0 1A539 185' Cable Chase

. GRAND GULF-UNIT 1 3/4 3-86 A u sd me d N"-

N PE - 77/0 3 TABLE 3.3.7.9-1 (Continued) .

FIlli DETECTION INSTRUMENTATION l 4(INIMUM INSTRUMENTS OPERA 8LE*

ROOM ELEV ROOM NAME HEAT - FLAMEll) :M0KEU3 e M) II7U 37U

12. Zone 2-17 /8 g/0 1A101 93' Passage IA109 93' HPCS Pep Rs.

IA111 93' Piping Penetration Rs.

1A114 93' Fan Coil Area (Partial) 1A117 93' Misc. Equip. Area (Partial) 4 1A121 103' East Corridor 1A122 103 Seath Corridor (Partial) 1A123 103' North Corridor (Partial)

'13. Zone 2-18 20/0 l 1A201 119' East Corridor 1A211 119' NorthCorridor(Partial) 1A215 119' South Corridor (Partial) 14 Zone 2-19 g/0 y

1A314 139' South Corridor (Partial) 1A316 139' North Corridor (Partial) 1A321 139' MCC Area 3A322 139' Centrifugal Chiller Area 1A323 139' SGTS Area IA324 139' HVAC Equip. Area 1A326 139' SGTS Area

15. Zone 2-20 2/0 1A305 139' Steam Tunnel

16. Zone 2-21 4/0 1A12 185' Stairwell 2A12 20'8' Stairwell 1A12 245' Stairve11

d. DIESEL GENERATOR BUILDING

1. Zone 2-10 9/0 2D301 133' Corridor D/3 (Deluge) 1D304 133' Day Tank Area

) 1D306 133' Div. III Diesel Gen. Room 1D4D1 158' Div. III Diesel Gen.

Room D/7 (Deluge)

2. 2-11 6/0 2D363 133' Day Tank Area 10308 133' Div. II Diesel Gen. Roos 3D4C2 158' Div. II Diesel Gen.

Room D/7 (Deluge)

GRAND GULF-UNIT 1 3/4 3-87 Amendment No.

j

1 1

9. A. SUBJECT

1. NPE-87/04 RHR/RCIC Steam Line High Flow Setpoint.

2. . Affected Technical Specifications ]

a. Isolation Actuation Instrumentation Setpoints, J Table 3.3.2-2, item 5.k - page 3/4 3-18.

B. DISCUSSION The following change is proposed:

1. The Residual Heat Removal (RHR)/ Reactor Core Isolation Cooling (RCIC) steam line high flow trip setpoint and allowable value are changed to be less than or equal to 37 inches H 20 and 43 inches H 0, respectively.

2 C. JUSTIFICATION

1. Upon review of the RHR/RCIC steam line high flow setpoint, due to a concern at another BWR/6 plant, it was determined that a correction must be made to the originally specified setpoint and allowable value. The affected instruments sense the differential pressure across two separat'e elbows in the common RHR/RCIC steam supply line that branches off of main steam line A. This RHR/RCIC line is used to supply steam to the RCIC turbine and can also supply steam to the R:iR heet exchangers when the plant is in the RHR steam condensing mode (currently prohibited by a license commitment). The instruments provide isolation signals to the RHR/RCIC steam supply and RCIC pump suction isolation valves (valve group 4) when a leak or break in the steam supply line is sensed as indicated by abnormally high steam flow.

2. The present Technical Specification setpoint is nonconservative for two reasons. The first reason is the use of the incorrect flow for the RHR system in the steam condensing mode. The second reason is the incorrect use of a formula for finding the differential pressure in an elbow tap which is empirically derived for use only in RCIC turbine steam flow applications.

The combination of these two errors results in the current trip setpoint being too high.

3. The proposed trip setpoint and allowable value are based on an analytic limit of 125% of rated (100%) f}ow to RHR loops A and B inthesteamcondengingmode(207.8x10 lb/hr) and to the RCIC turbine (38.85 x 10 lb/hr). By applying the correct RHR flow and the appropriate formula for differential pressure in an elbow tap, the new trip setpoint and allowable value are less than or equal to 37 inches H20 and 43 inches H2 0, respectively.

4. As an interim measure, administrative controls have been put into place lowering the current trip setpoint and allowable value to the corrected values until this proposed change is approved.

J16TS87070601 - 1

D. SIGNIFICANT HAZARDS CONSIDERATION

1. The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

The proposed change does not alter'the precursors of any previously evaluated accident and therefore no increase in the probability of a previously evaluated accident is involved. The consequences of previously' evaluated accidents do not increase since the proposed change is'in the conservative direction and will provide earlier steam line isolation if a break or leak were to ' occur.

2. The proposed change does not create the possibility of a new or different kind of accident from any previously analyzed. The revised setpoint enhances the mitigative measures used to isolate the RCIC/RHR steam line if, a break were to occur and lowers an already existing instrument setpoint. Lowering this setpoint will cause an isolation signal to be generated sooner if a leak'or break is detected. Therefore, there is no possibility of a new or different kind of accident from any previously analyzed.

3 . -- The proposed change does not involve a significant reduction in a margin of safety. The existing margin of safety to detect a leak is not reduced by the proposed reduction of the current instrument setpoint in the conservative direction since the system will now isolate at a lower flow. The proposed change reflects a revision in the setpoint computational model to correctly reflect the design information for the as-built plant. Based on the above, the proposed change results,in the margin of safety being increased.

i 1

i 1

J16TS87070601 - 2

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