Text

Proposed Tech Specs Including Changes to Surveillance Procedure Review - Package 1,Items 1-32
	ML20069H283
Person / Time
Site:	Grand Gulf
Issue date:	03/24/1983
From:	; MISSISSIPPI POWER & LIGHT CO.
To:	;
Shared Package
ML20069H272	List: AECM-83-0180, Proposed Amend PCOL-83/03 to License NPF-13,consisting of Changes to Surveillance Procedure Review - Package 1, Items 1-32 & Miscellaneous Tech Spec Changes; ML20069H283;
References
	PCOL-83-03, PCOL-83-3, NUDOCS 8303280316
	Download: ML20069H283 (74)
	v • d • e

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U Attachm:nt to AECM-83/0180 PROPOSED CHANGE TO THE OPERATING LICENSE NPF-13 PCOL-83/03 Missiscippi Power & Light (MP&L) requests that the operating license for Grand Gulf Nuclear Station (GGNS)(NPF-13) be amended as detailed below. These proposed changes, as discussed below, are provided for Nuclear Regulatc,ry Commission (NRC) review and approval per 10 CFR 50.90.

A. SURVEILLANCE PROCEDURE REVIEW - PACKAGE NO. 1 (ITEMS 1 THROUGH 32).

1. (GGNS-204)

SUBJECT:

Technical Specification 3.6.4, Table 3.6.4-1, Page 3/4 6-44 DISCUSSION:

Page 3/4 6-44 of table 3.6.4-1, Containment and Drywell Isolation Valves is subheaded "Drywell (continued)." This is incorrect. The correct subheading should be " Containment (continued)."

JUSTIFICATION:

Page 3/4 6-44 is a continuation of Table 3.6.4-1, Eection 4.a.

Containment Test Connections which begins on page 3/4 6-42. Penetrations 67-92 covered on this page are containnent penetrations as verified by Table 6.2-44 of the FSAR.

2. (GGNS-238)

SUBJECT:

Technical Specification 3.6.4, Table 3.6.4-1, page 3/4 6-30.

DISCUSSION:

Technical Specification Table 3.6.4-1, page 3/4 6-30, Containment and Drywell Isolation Valves lists the number for the RHR "C" Test Line to Suppression Pool as E12-F021B-B. This is incorrect. The correct number Should be E12-F021-B.

JUSTIFICATION:

FSAR Table 6.2-44 lists the RHR "C" Pump Test Line to Suppression Pool as E12-F021-B. This can also be confirmed on FSAR Figure 5.4-16.

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3. (GCNS-234)

SUBJECT:

Technical Specification Bases 3.0.3, page B 3/4 0-1.

DISCUSSION:

Bases Section 3.0.3 cites as example "... Specification 3.6.6.1 requires two primary containment hydrogen recombiner systems to be OPERABLE...".

This reference is incorrect. The correct reference should be

" Specification 3.6.7.1."

JUSTIFICATION:

Technical Specification section 3.6.7.1 pertains to the Containment and Drywell Hydrogen Recombiner Systems and contains the requirements ,

referenced in Bases Section 3.0.3.

4. (GGNS-235)

SUBJECT:

Technical Specification Bases Figure B 3/4 3-1, page B 3/4 3-7.

DISCUSSION:

Bases Figure B 3/4 3-1 indicates MSIV closure at low, low level 2(-41.6 inches) and also at low, low, low level'1(-150.3 inches). The level 2 trip is incorrect and reference to MSIV closure should be deleted from the figure for level 2.

JUSTIFICATION:

Technical Specification Table 3.3.2-2, Fage 3/4 3-15 and FSAR Table 6.2-44 list MSIV trip setpoint' to be . low, low, low level 1(-150.3 inches) as the correct trip setpoint.

5.- (GGNS-51)

SUBJECT:

Technical Specification 3/4.3.3, Table 3.3.3-2, page 3/4 3-28.

DISCUSSION:

Table 3.3.3-2, ECCS Actuation Instrumentation Setpoints, Section C.1.a.

' lists, the reactor water level-low, low level 2 trip setpoint for the HPCS system as greater than or equal to -41.6 inches and the allowable value as less than or equal to -43.8 inches. The allowable value is incorrect. The allowable value should read greater than or equal to

-43.8 inches.-

D3

0 JUSTIFICATION:

The entire traversing in-core probe system mechanism is within the Mark III Containment Building, and the only containment penetrations are electrical. These isolation valves are therefore not required and are, in fact, not part of the GGNS design.

8. (GGNS-79)

SUBJECT:

Technical Specification Bases 3/4.7.2, page B 3/4 7-1 DISCUSSION:

Section 3/4.7.2 Control Room Emergency Filtration System, first paragraph, gives the bases for the operability requirement of Technical Specification 3/4.7.2. The second paragraph deals with surveillance requirements for the RCIC system. The second paragraph should be deleted.

JUSTIFICATION:

The second paragraph is identical to the last paragraph on page B 3/4 7-1 and does not apply to the control room emergency filtration system.

9. (GCNS-236, 300)

SUBJECT:

Technical Specification Table 3.6.4-1, Section 1.a. page 3/4 6-29, Section 3.a. page 3/4 6-37 and Section 4.a page 3/4 6-42.

DISCUSSION:

Technical Specification Table 3.6.4-1, Section 1.a incorrectly lists valve number E12-F023B as a "RCIC and RHR to Head Spray" valve. The words "RCIC and" should be deleted from the phrase to reflect the GGNS design.

Technical Specification Table 3.6.4-1, Section 3.a also incorrectly lists valves E51-F066 and E51-F344 as "RCIC and RHR to Head Spray" valves.

Also, the system designator E51 of valve number E51-F344 is incorrect.

This is an E12 (RHR) valve and should be designated as E12-F344.

Technical Specification Table 3.6.4-1, Section 4.a contains incorrect numbers for the RHR to Head Spray Test connection isolation valves.

These are listed as E51-F061 and E51-F342. Their correct numbers should be E12-F061 and E12-F342.

JUSTIFICATION:

GGNS "as built" design drawings and documents along with FSAR Figure 5.4-16 have been reviewed to verify the changes listed above.

D5

s JUSTIFICATION:

Basis 3/4.3.3 states that " Operation with a trip setpoint less conservative than its Trip Setpoint but within its specified allowable 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 analysis." An allowable value of less than or equal to -43.8 inches would allow the trip setpoint to be below the -43.8 level which is non conservative. The correct allowable value is greator than or equal to -43.8 inches which would be the lower bound of the drift allowance.

6. (GGNS-319)

SUBJECT:

Technical Specification 3/4.3.2 Table 3.3.2-1, Section 3.c and 3.d, page 3/4 3-11, 14.

DISCUSSION:

Table 3.3.2-1, Items 3.c and 3.d incorrectly lists the isolation which occurs on high radiation in the Auxiliary Building Fuel Handling Area and Fuel Pool Sweep Exhaust. A high radiation condition in these areas causes the isolation of the Auxiliary Building ventilation isolation dampers, starts the Standby Gas Treatment System and starts the D/P recorder in fast speed. In Table 3.3.2-1, these signals are incorrectly recorded as causing group 6 isolation valve closures. References to group six closure should be deleted.

JUSTIFICATION:

FSAR sections 9.4.2.2., 9.4.2.3 and 9.4.2.5 discuss the requirements to prevent an uncontrolled release of radioactivity from this radiation -

l High High Signal. Group 6 isolation valve closures are not part of the

! requirements. In fact, no specified isolation valve group is closed by l this signal. Only the Auxiliary Building ventilation isolation dampers

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are closed by this signal which is specified in the proposed new note.

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! 7. (GCNS-50, 94)

SUBJECT:

Technical Specification 4.6.4.4, page 3/4 6-28 DISCUSSION:

Surveillance Requirement 4.6.4.4 requires that each traversing in-core probe system explosive isolation valve be demonstrated operable. These explosive isolation valves are not used in GGNS-1; therefore, the section should be daleted, i D4

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10. (GGNS-271) 4

SUBJECT:

Technical Specification 3.1.3.2, Section b, Page 3/4 1-7.

DISCUSSION:

Section b of Technical Specification 3.1.3.2, Control Rod Maximum Scram Insertion Times, refers to action statement a.1.a. This reference is incorrect. The correct reference should be a.1.

JUSTIFICATION:

Action Statement a.1.a as referenced in section b does not exist.

Section b should reference action statement a.1.

11. (CGNS-274)

SUBJECT:

Technical Specification 3.3.7.11, Table 4.3.7.11-1, page 3/4 3-85 DISCUSSION:

Table 4.3.7.11-1 lists the Radioactive Liquid Effluent Monitoring Instrumentation Surveillance Requirements. The second item, flow rate measurement devices, is incorrectly numbered with a.three (3) instead of a two (2). The three (3) should be deleted and replaced with a two (2).

JUSTIFICATION:

The second item was inadvertently numbered three (3) instead of two (2).

12. (GGNS-74)

SUBJECT:

l Technical Specification 4.8.3.1.1 and 4.8.3.2,1, pages 3/4 8-16, 18.

DISCUSSION:

The subject surveillance requirements currently require at least the power distribution system divisions as indicated in Technical Specification 3.8.3.1 and 3.8.3.2 to be determined energized by veri"ying correct breaker alignment and voltage on the Busses /MCCs/ panels.

Technical Specification 4.8.3.1.1 and 4.8.3.1.2 should be revised to read

"... correct breaker alignment on the Busses /LCs/MCCs/ panels and voltage on the Busses /LCs".

D6

s JUSTIFICATION:

The above mentioned changes reflect the types of motor control centers and panels employed in the Grand Gulf design. There is no instrumentation on MCCs or panels for voltage readings. The LCs which feed the MCs have installed instrumentation for voltage readings as do the busses which feed the LCs.

13. (GGNS-324)

SUBJECT:

Technical Specification 4.1.4.2, Section a.2, page 3/4 1-17. Technical j

Specification 3.3.6, Table 3.3.6-2, Section 1.a. page 3/4 3-52.

I DISCUSSION:

Technical Specification Table 3.3.6-2, Control Rod Block Instrumentation Setpoints and Surveillance Requirements 4.1.4.2.a.2 incorrectly state the Rod Pattern Control System (RPCS) low power set point as less than or equal to 20% of Rated Thermal Power. According to the appropriate General Electric design specification, the low power setpoint and allowable value should be 20% + 15%,-0% of Rated Thermal Power.

JUSTIFICATION:

Bases 3/4.1.4 states that when Thermal Power greater than 20% of Rated Thermal Power, there is no possible rod worth which, if dropped at the design rate of the velocity limiter, could result in a peak enthalpy of 280 cal /gm. Therefore, the RPCS is required to be operable when Thermal Power is less than or equal to 20% of Rated Thermal Power. In order to assure this, the low power setpoint must be at least 20% of Rated Thermal Power.

14. (GGNS-257)

SUBJECT:

Technical Specification 3.8.4, Table 3.8.4.1-1, page 3/4 8-21 DISCUSSION:

The proposed change involves revising the Trip Setpoint for the 6.9 KV circuit breakers which protect the Reactor Recirculation Pump Motors.

Since the instantaneous overcurrent protection devices trip the Reactor Recirculation Pump Motor breakers when switching from low to high speed but do not trip during a direct high speed start, the trip setpoint specified in the Technical Specifications should be revised slightly to reflect the locked rotor current rise due to the residual voltage.

Breaker Number 252-1003-C is misnumbered. The correct number is 252-1103-C.

D7

s JUSTIFICATION:

An engineering evaluation was performed to insure that the higher current values are appropriate and that these devices continue to function as designed. In order to provide better protection for an inside containment fault, the overcurrent unit time dial setting will be decreased from 9 to 8 seconds. FSAR Figure 040.5-1 shows that an increase from 6400/40A to 7200/45A will not adversely affect the penetration or cable.

15. (GGNS-297, 320)

SUBJECT:

Technical Specification 4.8.2.1, Section a.1, page 3/4 8-11 and Table 4.8.2.1-1, page 3/4 8-13.

DISCUSSION:

Table 4.8.2.1-1 gives the limits for specific gravity for the Division 1, Division 2, and Division 3, 125 volt batteries. These limits, however, do not reflect the manufacturer's recommended value for specific gravity.

Table 4.8.2.1-1 should be amended to reflect manufacturer's specifications.

JUSTIFICATION:

According to vendor specifications, the manufacturer's full charge specific gravity for the 125 volt batteries installed at GGNS is 1.210.

Therefore, the Battery Surveillance Requirements given in Table 4.8.2.1-1 should be changed to reflect this value. The changes indicated on the markup page 3/4 8-13 conform to the normal limits specified in Bases Section 3/4.8.2.

16. (GGNS-302)

SUBJECT:

i Technical Specification 3.3.2, Table 3.3.2-3, page 3/4 3-18 .

l DISCUSSION:

i l Table 3.3.2-3, Section 1.c, Response Time for Containment and Drywell Ventilation Exhaust Radiation - High, gives a response time for MSIV l closure. These instruments do not cause isolation of the MSIVs. This l response time requirement should be deleted from this table.

JUSTIFICATION:

FSAR Section 7.3.1.1.2.4.1.7 discusses the Containment and Drywell Ventilation Exhaust Radiation Monitoring Instremantation and Controls.

l Section 7.3.1.1.2.4.1.7.4 states that a trip causes isolation of all containment and drywell ventilation penetrations. FSAR figure 7.6-1 confirms the fact that no MSIV isolations occur.

D8

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17. (CGNS-352, 356)

SUBJECT:

Technical Specifications 3/4.3.7.11, Table 4.3.7.11-1, page 3/4 3-85; 3/4.11.1. Table 4.11.1.1.1-1, page 3/4 11-2; ard Definitions Table 1.1, page 1-9.

DISCUSSION:

Table 4.3.7.11-1, Radiological Liquid Ef fluent Monitoring Instrumentation Surveillance Requirements and Table 4.11.1.1.1-1, Radioactive Liquid Waste Sampling and Analysis Program, use "P" as a surve Alance frequency notation. The letter "P," as used in these tables, is intended to designate " Completed prior to each release". This definition, however, is not given in these tables nor in Table 1.1, page 1-9 with the other surveillance frequency notations.

The following should be added to Table 1.1, page 1-9:

Notation Frequency P Completed prior to each release JUSTIFICATION:

The letter "P" is used in such a manner in the Standard Radiological Environmental Technical Specification and is also defined as such in the Grand Gulf Nuclear Station Operations Manual Administrative Procedure 01-S-06-12 Rev. 5, Attachment 1.

18. (GGNS-362)

SUBJECT:

Technical Specification 3/4.6.6, Table 3.6.6.2-1, page 3/4 6-48.

DISCUSSION:

Technical Specification Table 3.6.6.2-1, Secondary Containment Ventilation System Automatic Isolation Dampers / Valves, incorrectly gives the number of the Fuel Handling Area Ventilation Supply Dampers as (Q1T42 F0011) and (Q1T42 F0012). These dampers should be correctly listed as (Q1T42 F011) and (Q1T42 F012) respectively.

JUSTIFICATION:

FSAR section 9.4.2 describes the Fuel Handling Area Ventilation System Figure 9.4-2 in the FSAR shows the dampers in question and gives their correct numbers.

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19. (GGNS-102, 384)

SUBJECT:

Technical Specification 3/4.3.2.12, Tables 3.3.7.12-1 and 4.3.7.12-1 on pages 3/4 3-88, 3/4 3-90, 3/4 3-91 and 3/4 3-92.

DISCUSSION:

Items 3.a in Table 3.3.7.12-1 and Item 3.a in Table 4.3.7.12-1 are designated as: " Noble Gas Activity Monitor Providing Alarm and Automatic Termination of Release." This designation should be changed to eliminate the reference to automatic termination of release. The action statement for item 3.a in Table 3.3.7.12-1 should be changed to action 121. Action statement 125 should be deleted from page 3-91 and statement 126 should accordingly be renumbered 125. Finally, the action statement for Item 6.a in Table 3.3.7.12-1 should be revised to 125.

JUSTIFICATION:

Automatic termination of radioactive effluent releases is provided by the containment and drywell ventilation exhaust radiation monitors which are listed as item 7 in Technical Specification Table 3.3.7.1-1. These monitors automatically isolate the containment on high radiation. The noble gas monitors, identified as item 3.a in Tables 3.3.7.12-1 and 4.3.7.12-1, do not provide any automatic ; solation function. Therefore reference to automatic termination of release should be deleted from their designation. Since the automatic isolation function is provided by separate monitors, the requirements of action statement 125, i.e.,

suspension of release of radioactive effluent from the containment ventilation system, are not warranted. The same actions should be required as a result of inoperability of these monitors as the actions required due to inoperability of other building ventilation noble gas activity monitors. The action statement for item 3.a in Table 3.3.7.12-1 should be changed to 121. Since item 3.a is the only item which references action statement 125, action statement 125 should be deleted on page 3/4 3-91 and action statement 126 should accordingly be renumbered Action 125. This necessitates changing the action statement for item 6.a in Table 3.3.7.12-1 from 126 to 125.

20. (CGNS-173, 237)

SUBJECT:

Technical Specification Table 3.3.2-2, page 3/4 3-15.

DISCUSSION:

The main steam line isolation trip setpoint and allowable value for main steam line radiation are currently specified as less than or equal to 1.5 times full power background and 3.0 times full power background respectively in Table 3.3.2-2, Item 2.b. These setpoint and allowable values are inconsistent with the correct setpoints which are identified D10

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elsewhere in the technical specification. The correct trip setpoint fot item 2.b in table 3.3.2-2 should be less than or equal to 3.0 times full power background and the allowable value for item 2.b should be less than or equal to 3.6 times full power background.

JUSTIFICATION:

Subsection 7.3.1.1.2.4.1.2.3 of the FSAR states that the main steam line radiation monitors provide dual functions in actuating the reactor protection system and closing the main steam isolation valves at the same setpoint. Technical Specification Table 2.2.1-1 item 7 requires that the main steam line radiation monitors should trip the reactor protection system at less than or equal to 3.0 times full power background with an allowable value of less than or equal to 3.6 times full power background.

This is the correct trip setpoint and allowable value based upon NSSS vendor documentation.

21. (GGNS-256)

SUBJECT:

Technical Specification 3.3.7, Table 3.3./.1-1, page 3/4 3-56.

DISCUSSION:

The range for items 1, 2 and 4 of Technicgl Specification Table 3.3.7.1-1 is incorrectly listed as 1 to 10 counts per minute. The correct gange for these instruments should be listed in this table as 10 to 10 counts per minute.

JUSTIFICATION:

The correct range for these instruments, (the Component Cooling Water radiation monitor, the Standby Service Water System radiation monitor, andtheOffgasPostTreatmentradiationmonitor),gsprovidedinTable 11.5-1 of the FSAR. The correct range is 10 to 10 counts per minute.

22. (GGNS-354)

SUBJECT:

Technical Specification 4.8.1.1.2.d.16, page 3/4 8-7.

DISCUSSION:

In Item f of Surveillance Requirement 4.8.1.1.2.d.16, the word

" generator" should be replaced with the word " engine" such that Item f reads " engine bearing temperature high (11 and 12 only). In Item j , the parenthetical expression "(13 only)" should be appended to the trip listing such that Item j reads " low lube oil pressure (13 only)".

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,n Bearing Temperature Monitoring

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- A review of the:1astalled electrical drawings shows that the lockout i features listed in section d.16 are reversed. H!gh engine bearing temperature for diesel 11 and 12 prevents these diesel generators

. , from starting or trips the generators during operation if the LOCA pv and LOP signals are absent.- A high generator hearing temperature i . ; signal vil,1 produce an alarm on the local panel for diesel 11 and

, , , , 12.fyhis'designprovidessuperiorprotectionforthediesel

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, engines. Engine bearing temperature is more critical with respect

> to maintaining the ability of the diesel generators to fulfill their

/< . - specified safety function. The diesel generators 11 and 12 should 4

s a be tripped, during tests, on high engk e bearing temperature, Y Low Lube Oil Pressure Monitoring Surveillance requirement 4.8.1.1.2.d.16 requires verification of diesel generator lockout features which prevent the diesel generator

/ from starting and which trip the diesel generator when it is operating without the presence of the LOCA or LOP signals.

Surveillance requirement 4.8.1.1.2.d.8 requires verification of trips which prevent the diesel generators from starting and which trip the diesel generators when they are operating even with the presence of the LOCA or LOP signals. FSAR subsection 8.3.1.1.4.1.f states that a low lube oil pressure will prevent starting or trip operation of diesel generators 11 and 12 even if the LOCA and LOP signals are present. Therefore, the low lube oil pressure lcckout feature in Item j of surveillance requirement 4.8.1.1.2.d.16 applies only to diesel generator 13.

23. (GGNS-158, 292, 17)

SUBJECT:

Technical Specification Table 3.8.4.2-1, pages 3/4 8-40 through 3/4 8-45.

DISCUSSION:

Technical Specification Tabic 3.8.4.2-1 lists the safety related motor operated valves which are furnished with thernal overload protection.

This table requires revision to include ~ additional valves and certain changes to accurately reflect the plant design.

JUSTIFICATION:

Regulatory Guide 1.106 specifies requirements for design of safety related motor operated valve thermal overload protection devices. This regulatory guide controls application of continuous bypasses, bypasses under accident conditions and identifies when bypasses are not iequired for thermal overload protection devices. MP&L committed to implement D12

s this regulatory guide in Appendix 3A of the FSAR. The changes noted on the attached pages reflect additional valves which fulfill a safety function and should be added to the table or changes which are necessary.

to reflect the correct regulatory requirements and accordingly, the as-installed arrangement.

24. (GGNS-501)

SUBJECT:

Technical Specification Table 3.3.7.5-1, page 3/4 3-71.

DISCUSSION:-

A portion of the text for Action 80,.part b, has'been inadvertently omitted from the technical specifications. Action 80, part b, should be revised to read as follows:

"b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE. requirements of Table 3.3.7.5-1, restore the inoperable channel (s).to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ."

JUSTIFICATION:

The text currently in the technical specifications for Action 80, part b is unclear. The revised text is taken from the corresponding section of NUREG 0123, Standard Technical Specifications for General Electric Boiling Water Reactors.

25. (GGNS-452)

SUBJECT:

Technical Specification 4.9.12, page 3/4 9-18 DISCUSSION:

Technical Specification 4.9.12 specifies that the surveillance requirements for the Horizontal Fuel Transfer System (HFTS) should be completed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to operation of HFTS and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. This requirement should be changed to specify that the surveillance requirements should be completed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to operation of HFTS and at least once per 7 days thereafter.

JUSTIFICATION: '

The surveillance requirements for the HFTS presently included in the technical specifications are appropriate for an Inclined Fuel Transfer System (IFTS). An IFTS includes interlocks to prevent draining of the upper containment fuel pool and to prevent overexposure of personnel due to inadvertent opening of certain critical doors. The HFTS installed at D13

.=- . - - - ,- . . - - , - . .

Grand Gulf Nuclear Station does not include these interlocks since the system cannot result in draining the upper containment pools and personnel access to high radiation areas is blocked with concrete shield walls. The surveillance requirements for the HFTS should be made consistent with the surveillance requirements for the refueling interlocks specified in surveillance requirements 4.9.1.2. These requirements specify that the refueling system interlocks should be verified to be operable within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to commencing core alterations and at least once per 7 days thereafter.

26. (GGNS-416, 417, 433)

SUBJECT:

+ Technical Specification 3.9.1.b, page 3/4 9-1.

DISCUSSION:

The wording for item 3.9.1.b.3 should be revised to read as follow:

"3. Refuel platform main hoist fuel-loaded" Items 3.9.1.b.4 and 3.9.1.b.5 should be deleted.

JUST1FICATION:

The four interlock conditions monitored by the Refueling Interlock System are: refueling platform positioned near or over the core, refueling platform dain hoist fuel-loaded, reactor mode switch position, and control rod position.

The fuel grapple not full up interlock has been deleted from the GGNS design. This interlock was a backup interlock to assure that no single failure could permit the refueling platform to be positioned over the core, a fuel. assembly lifted, and a control rod to be inadvertently withdrawn. The need for this interlock was eliminated when redundant circuits were installed to sense the positioning of the refueling platform over the core and when the refueling platform main hoist is loaded with fuel. Since the fue? grapple position interlock has been deleted in the GGNS Design, Technical Specification 3.9.1.b.4 should be deleted.

The other two hoists on the refueling platform are furnished with load sensors which specifically prohibit these hoists from lifting fuel. The only hoist which needs to have a hoist fuel-loaded interlock is the main hoist. Therefore Technical Specification 3.9.1.b.3 should be revised to reflect applicability of the fuel loaded interlock to only the main hoist.

No interlocks are provided between the source range monitor count-rates and the refueling equipment. Technical Specification 3.9.2 controls operability requirements for the source range monitors when the plant is D14

' JUSTIFICATION:

The trip functions for items C.1.d and C.I.e in Technical Specification

~ Table 3.3.3.1-1 are only required to be operable for operational conditions 4 and 5 when the HPCS is aligned to take suction from the

-condensate storage tank and the suppression pool is operable. The

~ existing asterisk note in Table 3.3.3-1 adequately states that these Echannels need not be operable in operational condition 4 and 5 unless the specified conditions are satisfied. Equally, surveillance requirements for. items C.t.d and C.1.e need not be imposed in operational conditions 4 and.5 by Technical Specification Table 4.3.3.1-1 unless the same conditions are satisfied.'

lThe asterisk (*) note for Technical Specification Table 4.3.3.1-1 is unclear and is inconsistent with the asterisk note for Table 3.3.3.1-1.

The surveillance requirements for items C.1.a. C.1.c, C.1.d, C.1.e, and C.I.f in operational conditions 4 and 5 should ie performed whenever the HPCS system is required to be operable by specificatians 3.5.2 or 3.5.3.

The modifications to the asterisk note clarify the requirements for performing surveillance of the HPCS actuation instrumentation and make these surveillance requirements consistent with the operability requirements specified in Table 3.3.3.1-1.

29. (GGNS-99)

SUBJECT:

Technical Specification Table 3.3.2-1, page 3/4-3-14.

DISCUSSION:

Note i in Technical Specification Table 3.3.2-1 indicates that the Standby Liquid Control System actuation logic closes only the Reactor Water Cleanup (RWCU) system inlet outboard valve G33-F004. This signal also isolates RWCU valves G33-F001 and G33-F251 and note 'i should b3 revised to reflect that these valves are also isolated.

JUSTIFICATION:

Table 6.2-44 in the FSAR shows that for penetration number 87, signal Y, which corresponds to the Standby Liquid Control System actuation isolation signal, isolates valves G33-F004, G33-F001 and G33-F251.

Therefore, note i in Technical Specification Table 3.3.2-1 should be revised to include these additional valves.

30. (GGNS-470)

SUBJECT:

Technical Specification Table 3.3.7.3-1, page 3/4 3-64 and Table 4.3.7.3-1, page 3/4/3-65.

.D16

in operational condition 5. Technical Specification item 3.9.1.b.5 should, therefore, be deleted. Therefore, Techsical Specification 3.4.1.b should be revised as discussed above to reflect the interlocks which are present in the installed casign.

27. (GGNS-303)

SUBJECT:

Technical Specification Tables 3.3.2-1, page 3/4 3-10, 3.3.2-2, page 3/4 3-15, 3.3.2-3, page 3/4 3-18, and 4.3.2.1-1, page 3/4 3-20.

DISCUSSION:

Iton 1.c in each of the subject technical specification tables is labeled as Containment and Drywell Ventilation Exhaust Radiation - High. The correct designation for this primary containment isolation function should be Containment and Drywell Ventilation Exhaust Radiation -

High-High.

JUSTIFICATION:

Each channel for the containment and drywell ventilation exhaust radiation monitors has three trips. The downscale trip indicates instrument trouble. The middle trip function initiates an alarm in the control room. The upscale trip produces an alarm and is capable of isolating the drywell and containment vcuci1ation penetrations. As stated in FSAR Subsection 7.3.1.1.2.4.1.7.2 through 7.3.1.1.2.4.1.7.4, four channels are provided aith two channels being powered from each RPS bus. Two upscale or high-high trips, two downscale or instrument inoperative trips, or one high-high and one instrument inoperative trips on either set of two channels will provide a trip signal for isolation of all containment and drywell ventilation penetrations.

28. (GGNS-249)

SUBJECT:

Technical Specification Table 4.3.3.1-1 page 3/4 3-33.

DISCUSSION:

The asterisk (*) notes for modes 4 and 5 under Applicable Operational Conditions for item C in Technical Specification Tables 3.3.3-1 and 4.3.3.1-1 are not consistent. The asterisk note in Table 4.3.3.1-1 should be revised to read as follows:

"* Applicable when the system is required to be operable per specification 3.S.2 or 3.5.3."

D15

_ .- . . . _. . . , . ~ . _ _ _ _ _ -

DISCUSSION:

Technical Specification Tables 3.3.7.3-1 and 4.3.7.3-1, define _

requirements for the meteorological monitoring instrumentation. Both tables define requirements for the air temperature instruments at elevation 162 feet. Item c in tables 3.3.7.3-1 and 4.3.7.3-1 should be revised to delete reference to the temperature instruments at elevation 162 feet.

JUSTIFICATION:

Item d in Technical Specification Tables 3.3.7.3-1 and 4.3.7.3-1 defines requirements for the instruments which measure air temperature difference between elevations 33 feet and 162 feet. The temperature sensor at elevation 162 feet only provides input to this instrument. No separate indication is provided for the temperature sensor at elevation 162 as opposed to the separate indication which is provided for the temperature sensor at elevation 33 feet. The operability requirements and surveillance requirements specified for item d in tables 3.3.7.3-1 and 4.3.7.3-1 provide for operability and surveillance for the temperature eensor at elevation 162 feet. Data available in the control room from the meteorological instruments are discussed in FSAR subsection 2.3.3.2.2.2.

31. (GGNS-457)

SUBJECT:

Technical Specification Tables 4.3.6-1, items 2.a and 2.c, page 3/4 3-53.

DISCUSSION:

The channel calibrations for the control rod block instrumentation Average Power Range Monitors (APRMs) should be revised as follows:

2 APRM Channel Calibration

a. Flow Biased Neutron W( )(8) , SA Flux Upscale

c. Downscale W( , SA The following notes should be added to Technical Specification Table 4.3.6-1.

a

f. This calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when Thermal Power is greater than or equal to 25% of RATED THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2%

of RATED THERMAL POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be included in determining the absolute difference.

D17

g. This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a calibrated flow signal.

h. This calibration shall consist of verifying the trip setpoint only.

JUSTIFICATION:

The channel calibration requirements currently specified in Technical Specification Table 4.3.6-1, item 2.a. for the APRM initiated control rod blocks, do not agree with the channel calibration requirements currently specified in Technical Specification Table 4.3.1.1-1, item 2.b, for the APRM reactor protection system function. Table 4.3.6-1 presently

~

. requires quarterly calibration of the APRM initiated control rod block for flow biased neutron flux upscale. Table 4.3.1.1-1 requires semi-annual calibration of the APRM reactor protection system function with weekly verification that the adjustment of the APRM channels are valid. The APRM functions associated with the reactor protection system are more significant with respect to plant safety than the APRM initiated control rod blocks. Therefore, the channel calibration frequency requirements for APRM initiated control rod blocks as specified in item 2a of Table 4.3.6-1 should be revised to conform with the requirements in Table 4.3.1.1-1 for item 2.b. which defines requirements for channel calibration frequency.of the APRM reactor protection system function.

The frequency of channel calibration of the APRM initiated control rod blocks should not be greater than the frequency of channel calibration for the APRM reactor protection system functions.

The downscale rod block identified as item 2.c in Table 4.3.6-1 has no corresponding reactor protection system surveillance requirement in Table 4.3.1.1-1. In order to be consistent with the upscale rod block listed as item a in Table 4.3.6-1, the channel calibration frequency should be l

revised to semi-annually with a requirement that this channel calibration is limited to verifying trip setpoint only.

This change is also necessa:P to support MP&L's ALARA program. Since r full calibration would include entry into the containment, quarterly calibration of APRM initiated rod blocks would enthil unnecessary l

exposure to operating personnel given that semi-annual calibration is acceptable for the APRM reactor protection system functions. Therefore, the channel calibration frequency for the APRM initiated rod blocks should be revised as shown above.

32. (GGNS-427) t

SUBJECT:

l Technical Specification Tables 3.3.7.2-1, page 3/4 3-61 and 4.3.7.2-1, page 3/4 3-62.

D18

DISCUSSION:

Item 4 in Technical Specification Tablas 3.3.7.2-1 and 4.3.7.2-1 should read:

"4. Vertical-Seismic Trigger" This instrument is not a recorder.

JUSTIFICATION:

The vertical seismic trigger identified as item 4 in Technical Specification Tables 3.3.7.2-1 and 4.3.7.2-1 is similar in function to the horizontal seismic trigger identified in item 5 of these tables. The word " recorder" should be deleted from item 4 in Tables 3.3.7.2-1 cad 4.3.7.2-1.

B. MISCELLANEOUS TECHNICAL SPECIFICATION CHANGES, (ITEMS 33 THROUGH 36).

33. -

SUBJECT:

Technical Specification 6.5.2, page 6-9.

DISCUSSION:

Remove the asterisk and delete the footnote from Technical Specification

6.5.2. JUSTIFICATION

The advitor to the Assistant Vice-President, Nuclear Operations is presently limited in effectiveness by the provisions of Technical Specification 6.5.2, which make him a non-voting member of the Safety Review Committee (SRC). To make more effective use of the experience of the Advisor, remove the asterisk and reference footnote and allow the Advisor to be a voting member of the SRC. ,

34.

SUBJECT:

Technical Specification 3.11.1.3. page 3/4 11-6.

DISCUSSION:

Technical Specification 3.11.1.3 refers to ODCM Figure 5.1.4.1 which is an error. The correct Figure is 5.1.3-1.

JUSTIFICATION:

Remove Figure number 5.1.4.'1 since it does not exist and insert the correct ODCM Figure 5.1.3-1.

D19

. . - - -~ . - _ . _ _ . _ _ _ _

35.

SUBJECT:

Technical Specification 6.5.2.10, page 6-12.-

DISCUSSION:

Technical Specification 6.5.2.10 should be revised to modify the documentation procedure for,SRC review activities.

JUSTIFICATION:

Technical Specification 6.5.2.10 should be revised to more accurately reflect required audit practices - that is, the Cperational Quality Assuranae manual requires the Manager of Quality Assurance to conduct audits of SRC written reports. This Technical Specification 6.5.2.10 should be revised to remove the redundent requirement of separate audit repcrts by the SRC and to more accurately reflect current administrative procedures consistent with this philosphy.

h e

k r

o f

I D20

. _ ~ _ . - .

1. '(ssss -sc4-) . -

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES

~

SYSTEM AND PENETRATION VALVE NUMBER NUMBER

m:: (Continued) l l

hMR"B"TestLine E12-F350 67(0)(c) !

T/C l RHR "B" Test Line E12-F312 67(0)(C)

T/C RHR "B" Test Line E12-F305 67(0)(C)

T/C Refueling Water P11-F425 69(0)(c)

Transf. Pump Suction T/C Refueling Water P11-F132 69(0)(C)

Transf. Pump Suction T/C Inst. Air to ADS P53-F043 70(0)

T/C Cont. Leak Rate M61-F010 82(I)

T/C RWCU To Feedwater G33-F055 83(0)

T/C Suppr. Pool P60-F011 85(0)

Cleanup T/C Suppr. PcS1 P60-F034 85(0)

Cleanup T/C RWCU Pump Suction G33-F002 87(0)

T/C RWCU Pump G33-F061 88(0)

Discharge T/C P41-F163A SSW T/C SSW T/C P41-F163B 89(0)((c) 92(0) c)

b. Drywell LPCI "A" T/C E12-F056A 313(0)

LPCI "B" T/C E12-F056B 314(0)

Intrument Air T/C P53-F493 327(0)

SLCS T/C C41-F026 328(0)

Service Air T/C PS2-F476 363(0)

Reactor Sample B33-F021 465(0)

T/C GRAND GULF-UNIT 1 3/4 6-44 l _ _ _ _ . . _ , . _ . _ _ _._

. l 2.(66 MS-f.38)'

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES

- MAXIMUM SYSTEM AND PENETRATION g ISOLATION TIME

-NUMBER VALVE GROUP ,) -

(Seconds)

VALVE NUMBER Containment (Continued)

RHR Heat Exchanger E12-F028A-A 20(I)(c) 5 78 "A" to LPCI .

RHR Heat Exchanger E12-F037A-A 20(I)(C) 3 63 "A" to LPCI .

22 l RHR Heat Exchanger E12-F0428-B 21(I)(C) 5 "B" to LPCI - ,

RHR Heat Exchanger E12-F028B-B 21(I)(C) 5 78 l "B" to LPCI RHR Heat Exchanger E12-F0378-B 21(I)(C) 3 63 "B" to LPCI RHR "A" Test Line E12-F024A-A 23(0)(d) 5 93 ,

to Supp. Pool RHR "A" Test Line E12-F011A-A 23(0)Id) 5 27 to Supp. Pool RHR "A" Test Line E12-F290A-A 23(0)(d) 6 8 to Supp. Pool E 12 - Fo z l-S RHR "C" Test Line M ^210 4 24(0)(d) 5 101 to Supp. Pool HPCS Test Lite E22-F023-C 27(0) 6 60 RCIC Pump Suction E51-F031-A 28(0) 4 38 RCIC Turbine E51-F077-A 29(0)(C) 9 18 Exhaust .

LPCS Test Line E21-F012-A 32(0) 5 131 Cont. Purge and 34(0) 7 4

( M41-F011 Vent Air Supply Cont. Purge and M41-F012 34(I) 7 4 Vent Air Supply Cont. Purge and M41-F034 35(I) 7 4 and Vent Air Exh.

Cont. Purge and M41-F035 35(0) 7 4 and Vent Air Exh.

Plant Service P44-F070-B 36(1) 6 24

! Water Return 36(0) 6 24 i Plant Service P44-F069-A *

! Water Return .

Plant Service P44-F055-A 37(0) 6 24 l ..

WateriSupply l

Chilled Water P71-F150 38(0) 6 30 Supply Chilled Water P71-F248 39(0) 6 30 l Return GRAND GULF-UNIT'1 3/4 6-30 Amendment No. 3

3. (GGNs - 2.54-) l

\

3/4.0 APPLICABILITY 8ASES ,

The specifications of this section provide the general reauirements I applicable to each of the Limiting Conditions for Operation and Surveillance l Requirements within Section 3/4.

3$0.1 This specification states the applicability of each specification ,

in terms of defined OPERATIONAL CONDITION or other specified applicability l condition and is provided to delineate specifically when each specification is applicable.

3.0.2 This specification defines those conditions necessary to constitute compliance with the terms of an individual Limiting Condition for Operation and associated ACTION requirement.

3.0.3 This specification delineates the measures to be taken for those circumstances not directly provided for in the ACTION statements and whose For example, occurrence would violate the intent of the specification.

Specification 3.7.2 requires two control room emergency filtration subsystems 8 b7*

to be OPERABLE and provides explicit ACTION requirements if one subsyttem is

. inoperable. Under the requirements of Specification 3.0.3, if both of the required subsystems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , in at least 1TDOWN HOT within the e SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least CO iHK3@ requires wo j subsequent 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . As a further example, Specificati ABLE and provides primary containment hydrogen recombiner Systems to be OP Under explicit ACTION requirements if one recombiner system is inoperable.

the requirements of Specification 3.0.3, if both of the required systems are inoperable, within one hour measures must be initiated to place the unit in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least MOT SHUTDOWN following 6 hears.

3.0.4 This specification provides that entry into on OPERATIONAL CONDITION must be made with (a) the full complement of required systems, equipment or components OPERABLE and (b) all other parameters as specified the Limiting Conditions for Operation being met without regard for allowable deviations and out of service provisions contained in the ACTION statements.

The intent of this provision is to ensure that unit operation is not initiated with either required equipment or systems inoperable or other limits being exceeded.

Exceptions to this provision have b:en provided for a limited number of specifications when startup with inoperable equipment would not affect plant safety. These exceptions are stated in the ACTION statements of the appropriate specifications.

GRAND GULF-UNIT 1 B 3/4 0-1

l l

WATER LEVEL NOMENCLATURE 4., (64MS- 235) COTE: SCAtE iN iNCNES ABOVE VESSEL ZERO HEIGHT ABOVE VESSEL ZERO READING LEVEL NO. tinches) (inches) 20= -

ts) 886.5 53 $

D) 573 7 40 7

44) M .7 32.7 (3) 644 4 11.4 350- -- 12) 401.4 -41.6 (1) E2.7 150.3 gg

( FLANGE

,o0- -

7648 - MAINLINE STEAM f

b -

1

.00- -

- - .. ) . . 0. _

,,, l E -573.7 D) E ~40 7 D) -Hi ALARM

' ~

BOTTOM OF STE M ,, g' _

SEPARATOR g3' INSTRUMENT S AIRT S17.5 533 0-0 0 0-

, ZERO - 3 300 -

' 48 "**II'8 III W R CORE h - - 81 5 I23

-479.3 SPRAY INITI ATE RCIC. AND i MPCS. TRIP RECIRC 450 - -

PUMPS.N 416.3 400

-- B2.7 (1) - - 150 3 (11 g - 150- - lNITIATE bdR. LPCS AND g um 366.3 START DIESEL.

JL CONTRIBUTE TO A.D.S. AND CLOSE MStV'S xo_ -

ACTIVE FUEL aso- -

U E - 216.3 216.3 RECIRC y

-173.3 = DISCH ARGE RECIRC NOZZLE SUCTION 172.3 NOZZLE 150 - -

100- -

so- -

i e- ._

l Bases Figure B 3/4 3-1 REACTOR VESSEL WATER LEVEL !

GRAND GULF-UNIT 1 B 3/4 3~7

f TABLE 3.3.3-2 .

"' EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS

ALLOWABLE 5 "

n TRIP SETPOINT VALUE O O

c)

E

[

TRIP FUNCTION A. DIVISION 1 TRIP SYSTEM

1. RHR-A (LPCI MODE) AND LPCS SYSTEM (Y

a. Reactor Vessel W,tter Level - Low Low Low, Level 1 1 -150.3 inches

1 -152.5 inches h b. Drywell Pressure - High 5 1.89 psig $ 1.94 psig Q 5 5 seconds F

c. LPCI Pump A Start Time Delay Relay 5 5 seconds v NA NA

d. Manual Initiation

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYST P "A"

a. Reactor Vessel Water Level - Low Low Lo!, Level 1 > -150.3 inches

3 -152.5 inches

$ 1.94 psig

b. Drywell Pressure - High 5 1.89 psig

< 115 seconds < 117 seconds

c. ADS Timer 5 11.4 inches

i 10.8 inches

d. Reactor Vessel Water Level-Low, Level 3 LPCS Pump Discharge Pressure-High [145psig, increasing [140psig, increasing I

e. > 125 psig, increasing > 122 psig, increasing

f. LPCI Pump A Discharge Pressure-High NA NA

g. Manual Initiation B. DIVISION 2 TRIP SYSTEM y 1. RHR B AND C (LPH MODE)

a. Reactor Vessel Water Level - Low Low Low, Level 1 3 -150.3 inches

1 -152.5 inches

[ 5 1.89 psig $ 1.94 psig

b. Drywell Pressure - High a

m c. LPCI Pump B Start Time Delay Relay 5 5 seconds ** $ 5 seconds NA NA

d. Manual Initiation

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B" > -152.5 inches

a. Reactor Vessel Water Level - Low Low Low, Level 1 > -150.3 inches

Drywell Pressure - High 31.89psig' 31.94psig

b. < 115 seconds < 117 seconds

c. ADS Timer 5 11.4 inches

F 10.8 inches

d. Reactor Vessel Water Level-Low, Level 3 [ 122 psig', increasing

e. LPCI Pump B and C Discharge Pressure-High E125psig, increasing NA NA

f. Manual Initiation C. DIVISION 3 TRIP SYSTEM y

3

1. HPCS SYSTEM l

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

>-41.6 inches

Y-43.8 inches 5 1.89 psig '_< 1.94 psig.

b. Drywell Pressure - High

c. Reactor Vessel Water Level - High, Level 8 5 53.5 inches * $ 55'.7 inches 3 0 inches > -3 inches

d. Condensate Storage Tank Level - Low

e. Suppression Pool Water Level - High $ 5.9 inches 5 6.5 inches NA NA

f. Mc.ual Initiation I

- m _

l l

' TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION z

VALVE GROUPS MINIMUM APPLICABLE E OPERATED BY OPERABLE CHANNELS OPERATIONAL

4 SIGNAL (a) PER TRIP SYSTEM (b) CONDITION _ ACTION j TRIP FUNCTION l

l C 3. SECONDARY CONTAINMENT ISOLATION

" d I a. Reactor Vessel Water Level-Low Low, Level 2 6 ICIId)Ih) 2 1, 2, 3, and # 25 g l

i b. Drywell Pressure - High 6(c)(d)(h) 2 1,2,3 25 p Fuel Handling Area rJ N. A.W 2 1, 2, 3, and

25

! c.

i Ventilation Exhaust Radiation - High High

d. Fuel Handling Area l

l Pool Sweep Exhaust _f uugM C 2 1, 2, 3, and

25 R Radiation - High High -6' '

t 26 6 1/ group 1,2,3 l e. Manual Initiation 1/ group

25 6

j y l 4. REACTOR WATER CLEANUP SYSTEM ISOLATION 1 1,2,3 27

a. & Flow - High 8 '

1 1,2,3 27

b. A Flow Timer 8 1 1,2,3 27

c. Equipment area Temperature - 8 High l d. Equipment Area a Temp. - 1,2,3 27 8 1

' High l e. Reactor Vessel Water 2 1,2,3 27 Level - Low Low, Level 2 8 l 1 1,2,3 27

! f. Main Steam Line Tunnel 8 Ambient Temperature - High l

j g. Main Steam Line Tunnel a 1 1,2,3 27 Temp. - High 8 q

1,2,3 27

h. SLCS Initiation 8( ) NA l 1/ group 1,2,3 26

1. Manual Initiation 8 l

t

1. _ ____ ___ __ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ __ ___ _ ________ _ _

6 CG6#5 - 311) p g .

INSTRUMENTATION TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION ACTION ACTION 20 -

Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21 - Close the affected system isolation valve (s) within one hour or:

a. In OPERATIONAL CONDITION 1, 2, or 3, be in at least NOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in C01.0 SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. In Operational Condition *, suspend CORE ALTERATIONS, handling of irradiated fuel in the containment and operations with a potential for draining the reactor vessel.

ACTION 22 -

Restore the manual initiation function to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT SHUTDOWN wit 11n the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 23 -

Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 24 -

Be in at least STARTbP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 25 - Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas treatment system operating within one hour.

ACTION 26 -

Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or close the affected system isolation valves within the next hour and declare the affected system inoperable.

ACTION 27 - Close the affected system isolation valves within one hour l

and declare the affected system inoperable.

ACTION 28 - Lock the affected system isolation valves closed within one hour and declare the affected system inoperable.

NOTES

When handling irradiated fuel in the containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

During CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

(a) See Specification 3.6.4, Table 3.6.4-1 for valves in each valve group.

(b) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for required surveillance without placing the trip system in the tripped con-dition provided at letst one other OPERABLE channel in the same trip system i

is monitoring that parameter.

(c) Also actuates Also actuates the standby gas treatment system.

the control room emergency filtration system in the isolation (d) mode.of operation.

(e) One upscale and/or two downscale actuate the trip system.

l (f) Also trips and isolates the mechanical vacuum pumps.

l (g) A channel is OPERABLE if 2 of 4 instruments in that channel are OPERABLE.

l (h) Also actuates secondary containment ventilation isolation dampers and i

valves per Table 3.6.6.2-1.

(i) Closes only RWCU system inlet outboard valve G33-F004 ke s b abyGasTre.:6edp++"ew a.=J hel Sees Acharg y)AMe5+W GRANDG$LI~Uh! 3 3-Y4

~

")

f

7. (Gaps-so, %)

j CONTAINMENT SYSTEMS, SURVEILLANCE REQUIREMENTS l

4.6.4.1 Each isolation valve shown in Table 3.6.4-1 shall be demonstrated OPERABLE prior to returning the valve to service after maintenance, repair or l replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time.

4.6.4.2 Each automatic isolation valve shown in Table 3.6.4-1 shall be demonstrated OPERABLE during COLD SHUTDOWN or REFUELING at least once per 18 months by verifying that on an isolation test signal each automatic isolation valve actuates to its isolation position.

4.6.4.3 The isolation time of each power operated or automatic valve shown in Table 3.6.4-1 shall be determined to be within its limit when tested pursuant to Specification 4.0.5.

4.4 Each traversing in-core probe system explosive isolation valve s be de trated OPERABLE:

a. At lea nce per 31 days by verifying the cont

y of the explosive charge.

b. At least once per 18 hs by ving st least one explosive squib from each explosive valve that each explosive squib in each explosive valve will ested a ast once per 36 months, and initiating the osive squibs. The lacement charge for the exploded s

~

s shall be from the same man tured batch as the one fire from another batch which has been cert

d by having at st one of that batch successfully fired. No squi all remain life, in use beyond the expiration of its shelf-life and operati as applicable.

GRAND GULF-UNIT 1 3/4 6-28

8. (GUS- 71) 3/t..7 PLANT SYSTEMS BASES 3/4.7.1 SERVICE WATER SYSTEMS The OPERABILITY of the service water systems ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions. The redundant cooling capacity of these systems, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits.

3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM The OPERABILITY of the control room emergency filtration system ensures that the control room will remain habitable for operations personnel during and following all design basis accident conditions. Cumulative operation of the system for 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters OPERABLE over a 31 day period is sufficient to reduce the buildup of moisture on the adsorbers and HEPA filters. The OPERABILITY of this system in conjunction with control room

design provisions is based cn limiting the radiation exposure to personnel occupying the control room to 5 rem or less whole body, or its equivalent.

This limitation is consistent with the requirements of General Design Critaria 19 of Appendix "A", 10 CFR Part 50. _

~

The nce requirements provide adequate nce that RCICS will lthough all be OPERABLE when requ omponents are testable and full flow can be demonstrated ation durirg reactor operation, a complete functional tes res reactor shuTdU n. um discharge piping

~

is maintained prevent water hammer damage and to star the l

j earli ssible moment.

3/4._7.3 REACTOR CORE ISOLATION COOLING SYSTEM The reactor core isolation cooling (RCIC) system is provided to assure adequate core cooling in the event of reactor isolation from its primary heat sink and the loss of feedwater flow to the reactor vessel without requiring actuation of any of the Emergency Core Cooling System equipment. The RCIC system is conservatively required to be OPERABLE whenever reactor pressure exceeds 135 psig even though the LPCI mode of the residual heat removal (RHR) system provides adequate core cooling up to 225 psig.

l The RCIC system specifications are applicable during OPERATIONAL CONDITIONS l 1, 2 and 3 when reactor vessel pressure exceeds 135 psig because RCIC is the primary non-ECCS source of emergency core cooling when the reactor is pressurized.

With the RCIC system inoperable, adequate core cooling is assured by the OPERABILITY of the HPCS system and justifies the specified 14 day out-of-service period.

The surveillance requirements provide adequate assurance that RCICS will be OPERABLE when required. Although all active components are testable and full flow can be demonstrated by recirculation during reactor operation, a complete functional test requires reactor shutdown. The pump discharge piping is maintained full to prevent water hammer damage and to start cooling at the earliest possible moment.

GRAND GULF-UNIT 1 B 3/4 7-1

T , (GGNS - 2.36,300) P1.

TABLE 3.6.4-1 CONTAINMENT AND DRYWELL ISOLATION VALVES .

MAXIMUM PENETRATION ISOLATION TIME

" SYSTEM AND- .

VALVE NUMBER NUMBER VALVE GROUP (a) (Seconds)

1. Automatic Isolation valves

a. Containment B21-F028A 5(0) 1 5 Main Steam Lines 5 Main Steam Lines B21-F022A 5(1) 1 1 6 Main Steam Lines B21-F067A-A 5(0) 821-F028B 6(0) 1 5 Main Steam Lines 5 Main Steam Lines B21-F022B 6(1) 1 B21-F067B- A 6(0) 1 6 Main Steam Lines B21-F028C 7(0) 1 5 Main Steam Lines Main Steam Lines B21-F022C 7(I) 1 5 B21-F067C- A 7(0) 1 6 Main Steam Lines B21-F0280 8(0) 1 5 Main Steam Lines 5 Main Steam Lines B21-F0220 8(I) 1 6

Main Steam Lines B21-F0670-A 8(0) 1 .

E12-F008-A 14(0)(C) 1 40 RHR Reactor Shutdown Cooling Suction 40 RHR Reactor E12-F009-B 14(I)(c) 3 Shutdown Cooling Suction E51-F063-B 17(I) 4 20 Steam Supply to RHR and RCIC Turbine .

17(0) 4 20 Steam Supply to E51-F064-A RHR and RCIC Turbine E51-F076-B 17(I) 4 20 Steam Supply to RHR and RCIC Turbine 18(0)(C) 3 90 h RHR to E12-F023-B Head Spray.

B21-F019- A 19(0) 1 15 Main Steam Line Drains 19(I) 1 15 Main Steam Line B21-F016-B Drains -

5 <22 RHR Heat Exchanger E12-F042A-A 20(I)(C)

"A" to LPCI (a) See Specification 3.3.2, Table 3.3.2-1, for isolation signal (s) that operates each valve group.

(b) Hydrostatically tested to ASME Section XI criteria.

11.5 psig.

(c) 1:ydrostatic:11y tested with water at P,s,ystem to 1.10 12.65 P,, psig.

(d) Hydrostatically tested by pressurizing (e) Hydrostatically tested during system functional testt.

(f) Hydrostatically sealed by feedwater leakage control system. Type C test not required.

--- - ' ~ ' ' ' '

3/a 6-29

% (ccus-z%,3=') et, TABLE 3.6.4-1 (Continued)

CONTAI MENT AND DRYWELL ISOLATION VALVES i~

SYSTEM AND PENETRATION VALVE NUMBER NUMBER ,

b. Drywell Cont. Cooling P42-F114-B 329(0)

Water Inlet Cont. Cooling P42-F116-A 330(I)

Water Outlet Cont. Cooling P42-F117-B 330(0)

- Water Outlet Plant Serv. Water P44-F076-A 331(I)

Return

Plant Serv. Water P44-F077-B 331(0)

Return Plant Serv. Water P44-F074-B 332(0)

Supply Condensate Flush B33-F204 333(I)

Connection Condensate Flush B33-F205 333(0)

Connection

3. Other Isciation Valves

a. Containment Fuel Transfer F11-E015 4(I)

Tube Cont. Leak Rate NA 40(I)(0) (

Sys.

Feedwater Inlet B21-F010A 9(I)((I)

Feedwater Inlet B21-F032A 9(0) I)

Feedwater Inlet B21-F010B 10(I)((I)

I)

Feedwater Inlet B21-F0328 10(0)(d)

RHP. "A" Suction E12-F017A E12-F017B 11(0)(d)

RHR "B" Suction RHR "C" Suction RHR Shutdown E12-F017C E12-F308 12(0)fcf 13(0) d 14(I)

Cooling Suction EC3C S RHR Head E51-F066 18(I)(c)

Spray E 12.

3C32 2 RHR Head 222-F344 18(I)(c)

Spray RHR Heat Ex. "A" E12-F044A 20(I)(c) to LPCI RHR Heat Ex. "A" E12-F025A 20(I)(c) to LPCI RHR Heat Ex. "A" E12-F107A 20(I)(c) to LPCI l RHR Heat Ex. "B" E12-F025B 21(I)(c) to LPCI RHR Heat Ex. "B" E12-F044B 21(I)(c)

- to LPCI

' RHR Heat Ex. "B" E12-F107B 21(I)(C) to LPCI GRAND GULF-UNIT 1 3/4 6-37

9 [64NS- 235) 3d P3.

TABLE 3.6.4-1 (Continu:d)

CONTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM M.D PEEETRATION VALVE NUMBER NUMBER

4. Test Connections

a. Containment Main Steam T/C B21-F025A 5(0)

Main Steam T/C B21-F025B 6(0)

Main Steam T/C B21-F025C 7(0)

Main Steam T/C B21-F0250 Feedwater T/C B21-F030A 8(0)(f)

Feedwater T/C B21-F063A 9(0)(#)

Feedwater T/C B21-F0638 9(0) (I)

Feedwater T/C B21-F030B 10(0)(I)

RHR Shutdown Cool. E12-F002 10(0)(c) 14(0)

Suction T/C RCIC Steam Line E51-F072 17(0)

T/C E12 RHR to Head 291-F342 18(0)(c)

Spray T/C El2 RHR to Head 881-F061 18(0)(c)

Spray T/C LPCI "C" T/C E12-F056C RHR " A" Pump E12-F322 22(0)((c) 23(0) c)

Test Line T/C (

RHR "A" Pump E12-F336 23(0)(c)

Test Line T/C RHR "A" Pump E12-F349 23(0)(c)

Test Line T/C RHR "A" Pump E12-F303 23(0)(c)

Test Line T/C RHR "A" Pump E12-F310 23(0)(c)

Test Line T/C RHR "A" Pump E12-F348 23(0)(C)

Test Line T/C RHR"C" Pump E12-F311 24(0)(c)

Test Line T/C RHR"C" Pump E12-F304 24(0)(c)

Test Line T/C HPCS Discharge T/C E22-F021 26(0)

HPCS Test Line T/C E22-F303 27(0)(c) 4 HPCS Test Line T/C E22-F304 27(0)(c)

RCIC Turbine E51-F258 24(0)

Exhaust T/C RCIC Turbine E51-F257 27(0)(c)

Exhaust T/C E21-F013 LPCS Te/C LPCS Test Line E21-F222 31(0)((c) 32(0) c)

T/C

, LPCS Test Line E21-F221 32(0)(c)

T/C GRAND GULF-UNIT 1 3/4 6-42

~

$0e (GGNS-2 71h ?b-*

REACTIVITY CONTROL SYSTEMS NB OM&665 I CONTROL ROD MAXIMUM SCRAM INSERTION TIMES LIMITING CONDITION FOR OPERATION 3.1.3.2 The maximum scram insertion time of each control rod from the fully withdrawn pos_ition, based on de-energization of the scram pilot valve solenoids as time zero, shall not exceed the following limits:

Maximum Insertion Times to Notch Position ~(Seconds)

Reactor Vessel Dome Pressure (psic)* 43 29 13 950 0.31 0.81 1.44 e 1050 0.32 0.86 1.57 APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

a. With the maximum scram insertion time of one or more control rods

, exceeding the maximum scram insertion time limits of Specification 3.1.3.2 as determined by Surveillance Requirement 4.1.3.2.a or b, operation may continue provided that:

1. For all " slow" control rods, i.e., those which exceed the limits of Specification 3.1.3.2, the individual scram insertion times do not exceed the following limits:

Maximum Insertion Times to Notch Position (Seconds)

Reactor Vessel Dome Pressure (psig)* 43 29 13 950 G IH 2.09 1050 0.39 1.14 2.22

2. For " fast" control rods, i.e., those which satisfy the limits of Specification 3.1.3.2, the average scram insertion times do not exceed the following limits:

Maximum Average Insertion Times to Notch Position (Seconds)

Reactor Vessel Dome Pressure (psig)* 43 29 13 950 0.30 G 1.40 1050 0.31 0.84 1.53

3. The sum of " fast" control rods with individual scram insertion times in excess of the limits of ACTION a.2 and of " slow" control rods does not exceed 7.

4. No " slow" control rod, " fast" control rod with individual scram insertion time in excess of the limits of ACTION a.2, or other-wise inoperable control rod occupy adjacent locations in any direction, including the diagonal, to another such control rod.

Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

For intermediate reactor vessel dome pressure, the scram time criteria is determined by linear interpolation at each notch position.

GRAND GULF-UNIT 1 3/4 1-6

10. (sgys- 271.) P2.

REACTIVITY CONTROL SYSTEMS I LIMITING CONDITION FOR OPERATION (Continued) f ACTION: (Continued) Lj b., With a " slow" control rod (s) not satisfying ACTION W, above:

'1.' Declare the " slow" control rod (s) inoperable, and

)

2. Perform the Surveillance Requirements of Specification 4.1.3.2.c at least once per 60 days when operation is continued with three or !

more " slow" control rods declared inoperable.

Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . ,

c. With the maximum scram insertion time of one or more control rods exceeding J the maximum scram ir.sertion time limits of Specification 3.1.3.2 as deter-mined by Specification 4.1.3.2.c, operation may continue provided that:

1. " Slow" control rods, i.e., those which exceed the limits of (

Specification 3.1.3.2, de not make up more than 20% of the 10% sample i of control rods tested.

2. Ear.h of these "s% w" control rods satisfies the limits of ACTION a.1.

3. The eight adjacent control rods surrounding each " slow" control rod are:

a) Demonstrated through measurement within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to satisfy the

' maximum scram insertion time limits of Specification 3.1.3.2, and b) OPERABLE.

4. The total number of " slow" control rods, as determined by Specification L.1.3.2.c, when added to the sum of ACTION a.3, as determined by Specification 4.1.3.2.a and b, does not exceed 7.

Otherwise, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.2 The maximum insertion time of the control rods shall be demonstrated through measurement with reactor coolant pressure greater than or equal to 950 psig and, during single control rod scram time tests, the control rod drive pumps isolated from the accumulators:

a. For all control rods prior to THERMAL POWER exceeding 40% of RATED THERMAL POWER following CORE ALTERATIONS

or after a reactor shutdown that is greater than 120 days,

b. For specifically affected individual control rods following t maintenance on or modification to the control rod or control rod drive system which could affect the scram insertion time of those specific control rods, and

c. For at least 10% of the control rods, on a rotating basis, at least once per 120 days of POWER OPERATION.

'Except movement of SRM, IRM, or special removable detectors or normal control rod movement. ,

GRAND GULF-UNIT 1 3/4 1-7

TABLE 4.3.7.11-1 RADI0 ACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION SURVEILLA m a

CHANNEL SOURCE CHANNEL FUNCTIONAL y CHANNEL TEST CALIBRATION _g 4 CHECK CHECK _

-4 g INSTRUMENT V

A

1. GROSS RADIDACTIVITY MONITORS PROVIDING ALARM AND AUTOMATIC TERNINATION OF RELEASE D P R(2) Q(1)

a. Liquid Radwaste Effluent Line 2.

[ FLOW RATE MEASUREMENT DEVICES (4)

a. Liquid Radwaste Effluent Line D(3) N.A. R Q N.A. R Q Discharge Canal D(3)

$ b.

Y S

I .

12 . (Gaps -74) H.

ELECTRICAL POWER SYSTEMS LIMITING CONDITIONS FOR OPERATION (Continued)

ACTION:

~a. For A.C. power distribution:

1. With either Division 1 or Division 2 of the above required A.C.

distribution system not energized, re-energize the division within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2. With Division 3 of the above required A.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.1.

3. With one of the above required load shedding and sequencing panels inoperable, restore the inoperable panel to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b.- For D.C. power distribution:

1. With either Division 1 or Division 2 of the above required D.C.

distribution system not energized, re-energize the division within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2. With Division 3 of the above required D.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.1.

SURVEILLANCE REQUIREMENTS 4.8.3.1.1 Each of tile above required power distribution system divisions shall be determined energized at least once per 7 days by verifying correct breaker alignment _;-f .;1t; :: th: L;. /:2^ /,_

pa-uds a.e d Voh;;:.ge_ ou 4.Le. bu sses[,, L%. C sou. ne. busses /LCs/MC(s/

4.8.3.1.2 Each of the above required load shedding and sequencing panels shall be demonstrated OPERABLE:

a. At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months by determining that the auto-test - 1 system is operating and is not indicating a faulted condition. l J

b. At least once per 31 days by performance of a manual test and verifying response within th.e design criteria to the following test j inputs:

l a) LOCA.

b) Bus undervoltage, c) Bus undervoltage followed by LOCA.

d) LOCA followed by bus undervoltage.

GRAND GULF-UNIT 1 3/4 8-16

a , CGGNS- 74) P2 -

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION:

a. For A.C. power distribution: ,

1. With not'1 Division 1 and Division 2 of the above required A.C.

distribution system not energized and/or with the load shedding and sequencing panel associated with the division (s) required to be energized inoperable, suspend CORE ALTERATIONS, handling of irradiated fuel in the Auxiliary Building and Enclosure <

Building and operations with a potential for draining the reactor vessel.

2. With Division 3 of the cove required A.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.

b. For D.C. power distribution:

1. With both Division 1 and Division 2 of the above required D.C.

distribution system not energized, suspend CORE ALTERATIONS, handling of irradiated fuel in the Auxiliary Building and Enclosure Building and operations with a potential for draining

, the reactor vessel.

2. With Division 3 of the above required D.C. distribution system not energized, declare the HPCS system inoperable and take the ACTION required by Specification 3.5.2 and 3.5.3.

c. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.3.2.1 At least the above required power distribution system divisions shall be determined energized at least once per 7 days by verifying correct breaker alignment --' "7 --":

LC s /MCC.s/ panels, "a~d voMme. ou tke. busses [LC s .h::::.'"'0;,'p.;' . on t k e. b 4.8.3.2.2 The above required load shedding and sequencing panes (s) shall be demonstrated OPERABLE:

a. At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months by determining that the auto-test system is operating and is not indicating a faulted condition.

b. At least once per 31 days by performance of a manual test and verifying response within the design criteria to the following test inputs:

a) LOCA.

b) Bus undervoltage.

c) Bus undervoltage followed by LOCA.

d) LOCA followed by bus undervoltage.

GRAND GULF-UNIT 1 3/4 8-18

13.(GGvs - 3E4 ) Pi .

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.4.2 The RPCS shall be demonstrated OPERABLE by verifying the'0PERABILITY of.the:

a. Rod pattern controller when THERMAL POWER is less than the low power setpoint by selecting and attempting to move an inhibited control rod:

1. After withdrawal of the first insequence control rod for each reactor startup.

2. As soon as the rod inhibit mode is automatically initiated at P9 R:

the RPCS during powerlow power setpoint.

reduction. 2W.+4 1 20 c' 4-07. of Rd.4h*4 P.e

3. The first time only that a banked position, N1, N2, or N3, is reached during startup or during power reduction below the RPCS low power setpoint.

b. Rod withdrawal limiter when THERMAL POWER is greater than or equal to the low power setpoint by selecting and attempting to move a restricted control rod in excess of the allowable distance:

1. As each power range above the RPCS low power setpoint is entered during a power increase or decrease.

2. At least once per 31 days while operation continues within a given power range above the RPCS low power setpoint.

1 l

GRAND GULF-UNIT 1 3/4 1-17

TABLE 3.3.6-2 y CONTROL R00 BLOCK INSTRUMENTATION SETPOINTS W x ALLOWA8LE VALUE W

TRIP FUNCTION TRIP SETPOINT

c)

{ 1. ROD PATTERN CONTROL SYSTEM yop;.+fs%,-O% 20% +/5%,-0%

of RATED THERMAL POWER gp

a. Low Power Setpoint @ of RATED THERMAL POWER E-Intermediate Rod Withdrawal < 70% of RATED THERMAL POWER @%ofRATEDTHERMALPOWER

< 70 t 5 b. -

~

Limiter Setpoint

] M i 2. APRM tu

a. Flow Biased Neutron Flux-Upscale 5 0.66 W + 42%* $ 0.FS W + 45%* 8 NA

b. Inoperative NA

> 3% of RATED THERMAL POWER -0

c. Downscale > 5% of RATED THERMAL POWER

~

N

d. Neutron Flux - Upscale ~

Startup 5 12% of RATED THERMAL POWER 1 14% of RATED THERMAL POWER

3. SOURCE RANGE MONITORS NA

a. Detector not full in NA 5 5

< 1.5 x 10 cp, l

b. Upscale < 1 x 10 cps NA NA

. R c. Inoperative > 2 cps

d. Dowr. scale > 3 cps l 4. INTERMEDIATE RANGE MONITORS NA j a. Detector not full in NA 5 110/125 of full scale

b. Upscale 5 108/125 of full scale NA .

c. Inoperative NA

> 3/125 of full scale

d. Downscale > 5/125 of full scale l S. SCRAM DISCHARGE VOLUME

a. Water Level-High 5 32 inches 5 33.5 inches

}

! 6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW i a. Upscale 5 108% of rated flow $ 111% of rated flow 1

The Average Power Range Monitor rod block function is varied as a function of recirculation loop flow l

(W). The trip setting of this function must be maintained in accordance with Specification 3.2.2.

14,(66#5-257) TABLE 3.s.4.1-1 I

PRIMARY CONTAINMENT PENETRATION CONOUCTOR OVERCURRENT PROTECTIVE DEVICES TRIP RESPONSE SYSTEM /

DEVICE NUMBER SETPOINT TIME COMPONENT AND LOCATION (Amperes) (Cycles) AFFECTED

a. 6.9 kV Circuit Breakers 1103 -B 60 Reactor Recir. Pump 252- 74o0/9515'00/'0/1 1 % 60 Pump B33C001A 52 C 7200/45-d 5'00/'0/ 1 Reactor Recir. Pump 252-1205-B 72 eo/4sd 5'00/'0/1 1 60 60 Pump B33C001B 252-1205-C 72oc/Vd 5'00/'0/ 1

b. 480 VAC Molded Case Circuit Breakers

1. Stored Energy Type SS3G3 TRIP RESPONSE BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes) (Seconds) AFFECTED 52-12202 1200 0.05 CONTAINMENT COOLING FILTER TRAIN HEATERS (N1M41D002B-N) 52-12209 2000 0.05 CNTMT POLAR CRANE (Q1F13E001-N) 1200 0.05 CNTMT CLG. FILTER 51-11502 TRAIN HEATER (N1M410002A-N) 52-15105 2000 0.05 DRYWELL PURGE COMPRESS.

(Q1E61C001A-A) 52-16204 2000 0.05 DRYWELL PURGE COMPRESS.

(Q1E61C001B-B) i

! 52-16404 1200 0.05 HYDROGEN RECOMBINER (Q1E61C003B-B)

Primary current /setpoint.

f GRAND GULF-UNIT 1 3/4 8-21

L5.(GGNS- M 7, 320) 1 TABLE 4.8.2.1-1 BATTERY SURVEILLANCE REQUIREMENTS CATEGORY A II) CATEGORY B(2)

Parameter Limits for each Limits far each A110wable I3) designated pilot connected cell value for each cell connected cell Electrolyte > Minimum level > Minimum level Above top of Level indication mark, indication mark, plates, and < k" above and < %" above and not maxiium level maxiium level overflowing indication mark indication mark Float Voltage > 2.13 volts > 2.13 volts (b) > 2.07 volts Not more than

.020 below the

/./D average of all

> 4.105 -

connected cells

/, / W Specifig ,) > 4-eG4k Gravity Average of all Average of all connected cells connected cells

> L205 /.2oo ) 4-1%- /, / 90 (a) Corrected for electrolyte temperature and level.

(b) May be corrected for average electrolyte temperature.

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

(2) For any Category B parameter (s) outside the' limit (s) shown, the battery may be considered OPERABLE provided that the Category B parameters are

,within their allowable values and provided the Category B parameter (s) are restored to within limits within 7 days.

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

GRAND GULF-UNIT 1 3/4 8-13

M.(csa.s -so2) TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME RESPONSE TIME (Seconds)#

TRIP FUNCTION

1. PRIMARY CONTAINMENT ISOLATION _

Reactor Vessel Water Level - Low Low, Level 2

< 13(*)

a. 313(*)

b. Drywell Pressure - High

c. Containment and g ell Ventilation Exhaust I *)**

Radiation - High 4 1.0*fi 13 NA

d. Manual Initiation

2. MAIN STEAM LINE ISOLATION

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

< 1.0*/< 13 ,a))*.*.

Level 1 ID)

b. Main Steam Line Radiation - High 7 1.0*/71313(I")**

I 1.0*/7

c. Main Steam Line Pressure - Low 7 0.5*/7 13 I ")**

d. Main Steam Line Flow - High HA

e. Condenser Vacuum - Low NA f.

Main S%am Line Tunnel Temperature - High NA

g. Main Steam Line Tunnel a Temp. - High NA

h. Manual Initiation

3. SECONDARY CONTAINMENT ISOLATION *)

Reactor Vessel Water Level - Low Low, Level 2 < 13(I a.

b. Drywell Pressure - High 313")

c. Fuel Handling Area Ventilation Exhaust 1 13(,) '

Radiation - High High(b)

d. Fuel Handling Area Pool Sweep Exhaust i 13(,)

Radiation - High High(b) NA

e. Manual Initiation

4. REACTOR WATER CLEANUP SYSTEM ISOLATION ##

NA

a. A Flow - High NA

b. A Flow Timer NA

c. Equipment Area Temperature - High NA

d. Equipment Area a Temp. - High < 13(,)

e. Reactor Vessel Water Level - Low Low, Level 2 ~

f. Main Steam Line Tunnel Ambient NA Temperature - High NA

g. Main Steam Line Tunnel a Temp. - High NA

h. SLCS Initiation NA

1. Manual Initiation l

3/4 3-18 GRAND GULF-UNIT 1

17 .(CGNS- 35E,35G)

TABLE 1.1 SURVEILLANCE FREQUENCY NOTATION NOTATION FREQUENCY S At least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

D At least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

W At least once per 7 days.

M At least once per 31 days. c Q

At least once per 92 days.

SA At least once per 184 days.

A At least once per 366 days.

R At least once per 18 months (550 days). ,

S/U Prior to each reactor startup.

N.A. Not applicable.

p CS d d pe:o r -t o eA re_te se.

ete GRAND GULF-UNIT 1 1-9

18,(c;4ys- 3G2.h TABLE 3.6.6.2-1 SECONDARY CONTAINMENT VENTILATION SYSTEM AUTOMATIC ISOLATION DAMPERS / 1 MAXIMUM ISOLATION TIME DAMPER / VALVE FUNCTION (Number) (Seconds)

a. Dampers Auxiliary Building Ventilation Supply Damper 5

(Q1T41F006)

Auxiliary Building Ventilation Supply Damper 5

(Q1T41F007)

Fuel Handling Area Ventilation Exhaust Damper 5

(Q1T42F003)

Fuel Handling Area Ventilation Exhaust Damper 5

(Q1T42F004)

Fuel Handling Area Ventilation Supply Damper 5

-(Q1'42r00"_)

(QiT h FOl b -

Fuel Handling Area Ventilation Supply Damper 5

(01'12f0012)

(Q1T4t.F oll) Ventilation Supply Damper Fuel Pool Sweep 5

(Q1T42F019)

Fuel Pool Sweep Ventilation Supply Damper 5

(Q1T42F020) l l

GRAND GULF-UNIT 1 3/4 6-48 1

i -

TA8LE 3.3.7.12-1 o p.

5 RADI0 ACTIVE GASE0US EFFLUENT MONITORING INSTRUMENTATION -o 5

m MINIMUM CHANNELS n

E OPERABLE APFLICABILITY ACTION O

? INSTRUMENT. A E D Z 1. RADWASTE BUILDING VENTILATION "

w MONITORING SYSTEM I i P

a. Noble Gas Activity Monitor -

121 O Providing Alarm 1 to D

1

122

b. Iodine Sampler bl

c. Particulate Sampler 1

122

%s

d. Effluent System Flow Rate

123 p-Measuring Device 1

{

123 Sampler Flow Rate Measuring Device 1 Y e.

8

2. MAIM CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING SYSTEM

- 124 Hydrogen Monitor 1 a.

3. CONTAINMENT VENTILATION MONITORING SYSTEM

a. Noble Gas Activity Monitor Providing /2-/

Alare r d ^?* -**r T:. !i.;;f:--

125 I Na 1

122 Iodine Sampler 1 b.

122

c. Particulate Sampler 1

123 Effluent System Flow Rate Monitor 1 d.

123 Sampler Flow Rate Monitor 1 e.

~O

@ TABLE 3.3.7.12-1 (Continued) .

R RADI0 ACTIVE GASEOUS EFFLUENT MONIl0 RING INSTRUMENTATION $

E E

t;; te a MINIMUM CHANNELS ACTION 5 INSTRUMENT OPERABLE APPLICABILITY p

O w N

6. OFFGAS PRE-TREATMENT MONITOR g g

a. Noble Gas Activity Monitor 1 '?'

l

7. 0FFGAS POST-TREATMENT MONITOR m

a. Nobid Gas Activity Monitor w Providing Alarm and Automatic

- 121 1 Termination of Release 1 Y

8

)

^

3 [g@S-102,380 M- TABLE 3.3.7.12-1 (Centinued)

RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION l

TABLE NOTATION

.At all times.

- During main condenser offgas treatment system operation.

- - During operation of the main condenser air ejector.

ACTION 121 - With the number of channels OPERABLE less than required by the Minnum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided grab samples are taken at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and these samples are analyzed for gross activity within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 122 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent releases via this pathway may continue for up to 30 days provided samples are continuously collected with auxiliary sampling equipment as required by Table 4.11.2.1.2-1.

ACTION 123 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, effluent release via this pathway may continue for up to 30 days provided the flow rate is estimated at least once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

ACTION 124 - With the number of channels OPERABLE less than required by the Minimum Channels OPERABLE requirement, operation of main condenser offgas treatment system may continue for up to 30 days provided grab samples are collected at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and analyzed within the following 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

ACTION 125 ~ M tha number of channels OPERABLE less +* wirca ny the Minimum Channels udr^"'l =y orement, suspend release of 2 1 . aive effluents via this pathway.

ACTION M6-- With the number of channels OPERABLE less than required by the jg Minimum Channels OPERABLE requirement, the SJAE effluent may be released to the environment for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. The offgas system is not bypassed, except for filtration system bypass during plant startups, and

b. The offgas delay system noble gas activity effluent downstream monitor is OPERABLE; Otherwise, be in at least HOT STANDBY within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

GRAND GULF-UNIT 1 3/4 3-91

TA8tc 4.3.7.12-1 .

h RADI0 ACTIVE _GASE0US EFFLUENT MDNITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS 5

E CNANNEL MODES IN WNICH q CNANNEL SOURCE CNANNEL FUNCTIONAL SURVEILLANCE CALIBRATION TEST g INSTRUMENT CHECK. CHECK REQUIRED

1. RAWASTE BUILDING VENTILATION MONITORING SYSTEM

a. Noble Gas Activity Monitor -

Providing Alarm D M R(3) Q(2) h p

sn

b. Iodine Sampler W N.A. N.A. M.A. i e

c. Particulate Sampler W N.A. N.A. N.A.

u

(A w d. Flow Rate Monitor D N.A. R Q y @

l w e. Sampler Flow Rate Monitor D N.A. R N.A. *

[

E 2. MAIN CONDENSER OFFGAS TREATMENT SYSTEM EXPLOSIVE GAS MONITORING 7 SYSTEN

a. Hydrogen Monitor D N.A. Q(4) M

3. CONTAINMENT VENTILATION MONITORING SYSTEN

a. Noble Gas Activity Monitor-Providing Alarm :d ^. t ztk

T:-- S; tis. ;f S: eeee- D M R(3) -Q(2)

b. Iodine Sampler W N.A. N.A. N.A.

c. Particulate Sampler W' N.A. N.A. N.A..

d. Effluent System Flow Rate

Monttor D N.A. R Q

e. Sampler Flow Rate Monitor D N.A. R N.A.

TABLE 3.3.2-2 g

ISOLATION 4CTUAT10N INSTRUMENTATION SETPOINTS o g ALLOWABLE O

TRIP SETPOINT VALUE _ ba

@ TRIP FUNCTION t M

h e

1. PRIMARY CONTAINMENT ISOLATION yq 5 a. Reactor Vessel Water Level - 1 -43.8 inches Low Low, Level 2 1 -41.6 inches * (A

] $ 1.93 psig u

b. Drywell Pressure - High i 1.73 psig

c. Containment and Drywell Ventilation 1 4.0 mr/hr** 4 Exhaust Radiation - High 1 2.0 mr/hr**

NA NA

d. Manual Initiation

2. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - 1 -152.5 inches Low Low Low, Level 1 1 -150.3 inches

l b. Main Steam Line Radiation - High 63. O p xbackground fuii power "z y, g p background x fuii power l 1 849 psig 1 837 psig

$ c. Main Steam Line Pressure - Low 5 169 psid 5 176.5 psid

d. Main Steam Line Flow - High

{ 1 9 inches Hg. Vacuum 1 8.7 inches Hg. Vacuum

e. Condenser Vacuum - Low 1 180*F** $ 186*F**

f. Main Steam Line Tunnel Temperature - High i 80*Fa* $ 83*F**

g. Main Steam Line Tunnel a Temp. - High NA NA

h. Manual Initiation

3. SECONDARY CONTAINNENT ISOLATION

a. Reactor Vessel Water Level - 1 -43.8 inches Low Low, Level 2 1 -41.6 inches

5 1.73 psig 5 1.93 psig

b. Drywell Pressure - High

c. Fuel Handling Area Ventilation $ 4.0 mR/hr**

l Exhaust Radition - High High 5 2.0 mR/hr**

d. Fuel Handling Area Pool Sweep 1 35 mR/hr**

Exhaust Radiation - High High 5 18 mR/hr**

NA NA

e. Manual Initiation n _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

2 TABLE 3.3.7.1-1 ,

i c3 RADIATION MONITDAING INSTRUMENTATION 5

2 '

MINIMUM CHANNELS APPLICABLE ALARM / TRIP MEASUREMENT

OPERA 8LE CONDITIONS SETPOINT RANGE ACTION h INSTRUMENTATION ,

1. Component Cooling /g

[

z Water Radiation Z Monitor 1 At all times 5

il x 10 cpe/NA to 10 cpm 70~ h

2. Standby Service Water d System Radiation 5 6 M i Monitor 1/ heat exchanger 1, 2, 3, anda il x 10 cpe/NA [to10 cpm 70 V

b train J. Offgas Pre-treatment Radiation Monitor 1 1, 2 3

15.x 10 mR/hr/NA 1 to 100mR/hr 70

4. Offgas Post-treatment 5

/C 6 l

Radiation Monitor 2I ") 1, 2 11 x 10 cpu (Hi), /to10 c,, 77 6

11.0 x 10 cpm (H1 H1)

R 5. Carbon Bed Vault Radiation Monitor 1 1, 2 < 2 x full power 1 to 10 mR/hr 72 background /NA

[

6. Control Room Ventila- -2 to 102mR/hr 73 tion Radiation Monitor 2 1,2,3,5 and** 14 mR/hr/ 10 15 mR/hr#

7. Containment and Drywell Ventilation Exhaust ~2 l

I Radiation Monitor 3I *) At all times <2.0 mR/hr/ 10 to 102mR/hr 74 14 mR/hr(U)*

Fuel Handling Area 8~

Ventilation Exhaust 3(*} 1,2,3,5 and** $ 2mR/hr/ 10"2 to 102mR/hr 75 Radiation Monitor I 14 mR/hr

9. Fuel Handling Area Pool Sweep Exhaust Radiation -2 to 102mR/hr 10 75 Monitor 3(a) (c) $ 18 mR/hr/

135 mR/hr(d)#

. zz . (s o s .a u )

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued

. 14. Verifying that the fuel transfer pump transfers fuel .from each fuel storage tank to the day tank of each diesel via.the installed lines.

15. Verifying that the automatic load sequence timer is OPERABLE with the interval between each load block within i 10% of its' design interval for diesel generators 11 and 12.

16. Verifying that the following diesel generator lockout features prevent diesel generator starting and/or trip the diesel generator only when required:

a) Generator loss of excitation.

b) Generator reverse power.

c) Highjacketwatertemperature.

d) Generator overcurrent with voltage restraint.

1. )p Bus underfrequency (11 and 12 only). a e) f) Q earing temperature high (11 and 12 only). l g) Low turbo charger oil pressure (11 and 12 only).

h) High vibration (11 and 12 only).

1) High lube oil temperat re (11 and 1 only).

j) Low lube oil pressure 1 3. o u ( ,

l k) High crankcase pressure.

e. At least once per 10 years or after any modifications which could affect diesel generator interdependence by starting all three diesel generators simultaneously, during shutdown, and verifying that the three diesel generators accelerate to at least 441 rpm for diesel generators 11 and 12 and 882 rpm for diesel generator 13 in less than or equal to 13 seconds.

f. At least once per 10 years by:

1

1. Draining each fuel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite or equivalent solution, and

[

2. Performing a pressure test of those portions of the diesel fuel l

' oil system designed to Section III, subsection ND of the ASME Code in accordance with ASME Code Section 11, Article IWD-5000.

4.8.111.3 Reports - All diesel generator failures, valid or non-valid, shall be reported to the Commission pursuant to Specification 6.9.1. Reports of diesel generator failures shall include the information recommended in Regu-If latory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977.

the number of failures in the last 100 valid tests, on a per nuclear unit basis, is greater than or equal to 7, the report shall be supplemented to

include the additional information recommended in Regulatory Position C.3.b of Regulatory Guide 1.108, Revision 1, August 1977.

l GRAND GU!.F-UNIT 1 3/4 8-7 l

l l

23 . (G GN.s - 1% 1% L7) H -

TABLE 3.8.4.2-1 MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON- l TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER CONDITIONS) (NO) AFFECTED Q1E51F010-A Continuous RCIC System Q1E51F013-A Continuous RCIC System Q1E51F019-A Continuous RCIC System Q1E51F022-A Continuous RCIC System Q1E51F031-A Continuous RCIC System Q1E51F045-A Continuous RCIC System Q1E51F046-A Continuous RCIC System Q1E51F059-A Continuous RCIC System Q1E51F068-A Continuous RCIC System Valve on Turbine Q1E51C002 c A,,3, RCIC System Q1821F065A-A No Reactor Coolant System Q1821F0658-A No Reactor Coolant System Q1821F098A-N B No Reactor Coolant System Q1821F0988-k 6 No Reactor Coolant System Q1821F098C-)r 8 No Reactor Coolant System Q1821F0980-h 6 No Reactor Coolant System Q1B21F019 Continuous Reactor Coolant System Q1821F067A Continuous Reactor Coolant System Q1821F067B Continuous Reactor Coolant System Q1821F067C Continuous Reactor Coolant System Q1B21F0670 Continuous Reactor Coolant System Q1821F01 41821Fl4 Continuou .

g cg r,g,o g S gte g

~ *

Q1833F019 Continuous NirNu~1ItYSysYe Q1833F020 Continuous Recirculation System Q1B33F125 Continuous Recirculation System Q1833F126 Continuous Recirculation System Q1B33F127 Continuous Recirculation System Q1B33F128 Continuous Recirculation System Q1023F5918

Drywell Monitoring System Q1D23F592A

Drywell Monitoring System Q1023F593B

Drywell Monitoring System Q1023F594A

Drywell Monitoring Systen Continuous RHR System Q1E12F040 '

Continuous RHR System Q1E12F023 Continuous RHR System Q1E12F006A Continuous RHR System Q1E12F052'A Continuous RHR System Q1E12F008 Continuous RHR System Q1E12F074A RHR System Q1E12F026A ContJ*nuous QtE12 fos 1 A ,<ng sysice QIE t ZFo826

8 ,

Kult 5y sien GRAND GULF-UNIT 1 3/4 8-40

P2

. 23.((4NS-ISB.,292,17) TABLE 3.8.4.2-1 (Continued)

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER CONDITIONS) (NO) AFFECTED Continuous RHR System Q1E12F290A Continuous RHR System Q1E12F047A Continuous RHR System Q1E12F027A Continuous RHR System Q1E12F073A Continuous RHR System Q1E12F346 Continuous RHR System Q1E12F024A Continuous RHR System Q1E12F087A Continuous RHR System Q1E12F048A Continuous RHR System Q1E12F042A Continuous RHR System Q1E12F004A Continuous RHR System Q1E12F003A Continuous RHR System Q1E12F011A Continuous RHR System Q1E12F053A Continuous RHR System Q1E12F037A Continuous RHR System Q1E12F028A Continuous RHR System Q1E12F064A Continuous RHR System Q1E12F290B Continuous RHR System Q1E12F004C Continuous RHR System Q1E12F021 Continuous RHR System Q1E12F064C Continuous RHR System Q1E12F042C Continuous RHR System 01E12F048B Continuous RHR System Q1E12F049 Continuous RHR System Q1E12F037B Continuous RHR System Q1E12F053B Continuous RHR System Q1E12F074B Continuous RHR System Q1E12F042B Continuous RHR System Q1E12F064B Continuous RHR System Q1E12F096 Continuous RHR System Q1E12F094 Continuous RHR System Q1E12F006B Continuous RHR System Q1E12F011B Continuous RHR System Q1E12F052B Continuous RHR System Q1E12F047B Continuous RHR System Q1E12F027B Continuous RHR System Q1E12F004B Continuous RHR System Q1E12F087B Continuous RHR System Q1E12F003B Continuous RHR System Q1E12F026B Continuous RHR System Q1E12F024B Continuous RHR System Q1E12F028B Continuous RHR System Q1E12F009 Continuous RHR System Q1E12F073B No CRD Hydraulic System Q1011F083 CRD Hydraulic System Q1C11F322 Continuous QlC4IF001 A co~ b ooos M- 4h Lg.:d C 4rol QlC,4lF0016 Coul;*uo*5 h abyLij.;d Costr.\

GRAND GULF-UNIT 1 3/4 8-41

23,(G6gs- 158,3 242,17) P3.

TABLE 3.8.4.2-1 (Continued)

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER CONDITIONS) (NO) AFFECTED Continuous LPCS System Q1E21F001 Continuous LPCS System Q1E21F011 Continuous LPCS System Q1E21F012 Continuous LPCS System Q1E21F005 Continuous Suppression Pool Makeup System Q1E30F002A

Suppression Pool Makeup System Q1E30F591A

Suppression Pool Makeup System Q1E30F592A

Suppression Pool Makeup System Q1E30F593A

Suppression Pool Makeup System Q1E30F594A Continuous Suppression Pool Makeup System Q1E30F001A Continuous Suppression Pool Makeup System Q1E30F001B Continuous Suppression Pool Makeup System Q1E30F002B

Suppression Pool Makeup System Q1E30F591B

Suppression Pool Makeup System Q1E30F592B

Suppression Pool Makeup System Q1E30F5938 Q1E30F594B 4IE3IF100A c d. .o3 {upp g sig

_ pgg{ M,akeupJ,ystem p

"" y "

Q1E32F001 $uo"u! N*N~b Continuous MSIV - LCS Q1E32F001E Continuous MSIV - LCS Q1E32F003A Continuous MSIV - LCS Q1E32F003E Continuous MSIV - LCS Q1E32F003J Continuous MSIV - LCS Q1E32F003N Q1E32F001J Continuous MSIV - LCS Continuous MSIV - LCS Q1E32F001N Continuous MSIV - LCS Q1E32F002A Q1E32F002E Continuous MSIV - LCS l Continuous MSIV - LCS Q1E32F002J Continuous MSIV - LCS Q1E32F002N Q1E32F006 Continuous MSIV - LCS Q1E32F007. Continuous MSIV - LCS Q1E32F008 Continuous MSIV - LCS Continuous MSIV - LCS Q1E32F009 Continuous Feedwater LCS Q1E38F001A Continuous Feedwater LCS Q1E38F001B Continuous RCIC System Q1E51F064 Continuous RCIC System Q1E51F063 Continuous RCIC System Q1E51F076 Continuous RCIC System Q1E51F077 Continuous RCIC Syster.

Q1E51F078 gec , sy34r g Q tE 2 Z Foot C ou4: ou 3 0tE2.LFod c. 4:,.u.o s gecs sysic4 QIEItFolo co 4 s.wou > Arcs 5 54e M

c.oboov s w,%

oiEZ1Fott gets QlE11F081 e om,4:.a w o u 5 g pc 5 g sie m O t EltFO f f C o-4 t aw ** S 'g 9%

4I En f o13 C a ~4 5 8"" *

5 g u GRAND GULF-UNIT 1 3/4 8-42

g3,[ggNS - 158,292,17) P4 TABLE 3.8.4.2-1 (Continued)

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-SYSTEM (S) l TINUOUS) (ACCIDENT VALVE NUMBER CONDITIONS) (NO) AFFECTED J

Combustible Gas Control System Q1E61F595A

Combustible Gas. Control System Q1E61F596A

Combustible Gas' Control System Q1E61F597A

Combustible Gas Control System Q1E61F598A

Combustible Gas Control System Q1E61F595C l

Combustible Gas Control System ,

Q1E61F596C

Combustible Gas Control System Q1E61F597C

Combustible Gas Control System Q1E61F598C

Combustible Gas Control System Q1E61F595B 1

Combustible Gas Control System Q1E61F5968

Combustible Gas Control System Q1E61F5978

Combustible Gas Control System Q1E61F5988

Combustible Gas Control System Q1E61F595D

Combustible Gas Control System Q1E61F596D

Combustible Gas Control System Q1E61F597D

Combustible Gas Control System Q1E61F598D Combustible Gas Control System Q1E61F003A Continuous Continuous Combustible Gas Control System Q1E61F005A Combustible Gas Control System Q1E61F003B Continuous Q1E61F005BjQtG33FL51 g jnu,0,us, gomgs,f,c4.stibjeGasControlSys mos eweg

\ ciG33F Z S3 co s;inuous Cont RWCU System Q1G33F004 RWCU System Q1G33F039 Continuous Continuous RWCU System Q1G33F034 RWCU System Q1G33F054 Continuous Continuous RWCU System Q1G33F028 RWCU System Q1G33F053 Continuous Continuous RWCU System Q1G33F040 Q1G33F001 q,g33pzgo ggiggs, RWyS u g g g QlG 33r z r2. cwt:uo od s kwtu s te % l Continuous Spent F el Pool Cooling and Q1G41F028 Cleanup System Continuous Spent Fuel Pool Cooling and Q1G41F029 Cleanup System Continuous Spent Fuel Pool Cooling and Q1G41F044 QLG4t FM3 A'o sg.Aw..kpCleanupSystem l

(

No 't,y&,'"g Spent Fuel Pool Cooling and I

! Q1G41F021 Cleanup System l

RL mirs95' s* c w/,;p m l/pey,et( I4C, l Containment /Drywell I&C Q1M71F591A

Containment /Drywell I&C Q1M71F593A

$N h h"$ N

"*" Continuous k[f[lp kHN Ta~L7r"iMaOneN Q1P21F017 Makeup Water Treatment System Q1P21F018 Continuous i

GRAND GULF-UNIT 1 3/4 8-43

g3,(66N TAB .8.4.2-1 (Ccntinu;d)

MOTOR OPERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER CONDITIONS) (NO) AFFECTED Continuous SSW System Q1P41F237* SSW System Q1P41F018 Continuous Continuous SSW System Q1P41F241 SSW System Q1P41F238 Continuous Continuous SSW System l QSpqipestA Q17417001A SSW System l ASP 9lF0M AQ17417004A Continuous Continuous SSW System Q1P41F068A Continuous SSW System Q1P41F014A Continuous SSW System Q1P41F159A Continuous SSW System Q1P41F160A Continuous SSW System Q1P41F113 Continuous SSW System Q1P41F168A SSW System Q1P41F001A . Continuous Continuous SSW System Q1P41F016A SSW System Q1P41F015A Continuous Continuous SSW System Q1P41F006A SSW System Q1P41F005A Continuous Continuous SSW System Q1P41F007A SSW System 4594tFD7% Q1741r074A Continuous Continuous SSW System QSPi\FOMA, Q1E41I000A Continuous SSW System aspytFid Q1P41T125 SSW System Q1P41F018B Continuous Continuous SSW System Q1P41F160B SSW System Q1P41F159B Continuous Continuous SSW System Q1P41F168B SSW System G5P4t F154 Q1P01F15i Accident Conditions Accident Conditions SSW System GSP4tFis5 A Q1P41T155". SSW System Q1P41F068B Continuous Accident Conditions SSW System l QSPM F t 5'5 B Q1741rl;;0 Continuous SSW System Q1P41F014B SSW System CSP 91 Fo64E Q1r41r0040 Continuous Continuous SSW System osp4L Fott B Q1741T0010 Continuous SSW System Q1P41F006B SSW System Q1P41F007B Continuous Continuous SSW System Q1P41F001B SSW System Q1P41F0168 Continuous Continuous SSW System Q1P41F005B SSW System Q1P41F0158 Continuous Continuous SSW System Q SP41 FOWBQ1P41T0000 SSW System Continuous osP4t FOMSQ1P41i0740 Continuous SSW System QSp4 t F 1129 Q1741Il00 SSW System Q1P41F011 Continuous No SSW System i Q1P41F119A SSW System No Q1P41F)19B SSW System No Q1P41F121A SSW System No Q1P41F121B . SSW System No Q1P41F122A SSW System No Q1P41F122B GRAND GULF-UNIT 1 3/4 8-44

_. G]5E.5L Foo7 - - _.. . Conrmvous .._-_CenisoL Boon HVM

~ - . . . Cenimucus CaninD L Room YYAC.

_-QsE51.Foob QSE JL F31+ . . . _ _ . . . _ _ _ . CowTsNusur#__.._..cowTast. Roos Hv4c..

R QSE 51 FOLG . . . . .CoH.TINuovS . CoNTRDL Room HVAC.

23 .(GGNS-158;M2pl7)fs ABLE 3.8.4.2-1 (Continued)

.;)i.f MOTOR 0 ERATED VALVES THERMAL OVERLOAD PROTECTION BYPASS DEVICE (CON-TINUOUS) (ACCIDENT SYSTEM (S)

VALVE NUMBER - CONDITIONS) (NO) AFFECTED 1P42F067 Continuous CCW System Q1P42F116 Continuous CCW System Q1P42F028A Continuous CCW System Q1P42F032A Continuous CCW System ,

Q1P42F201A Continuous CCW System Q1P42F204 Continuous CCW System Q1P42F205 Continuous CCW System Q1P42F105 Continuous CCW System Q1P42F200A Continuous CCW System Q1P42F203 Continuous CCW System Q1P42F117 Continuous CCW System Q1P42F114 Continuous CCW System Q1P42F068 Continuous CCW System Q1P42F200B Continuous CCW System Q1P42F028B Continuous CCW System

. Q1P42F201B Continuous CCW System Q1P42F0328 Continuous CCW System Q1P42F066 Continuous CCW System

, Q1P44F053 Continuous Plant SW System s Q1P44F069 Continuous Plant SW System Q1P44F076 Continuous Plant SW System Q1P44F070 Continuous Plant SW System Q1P44F074 Continuous Plant SW System Q1P44F077 Continuous Plant SW Sy: tem Q1P44F042 Continuous Plant SW System Q1P44F054 Continuous Plant SW System Q1P44F067 Continuous Plant SW System

~

Q1P45F096 Continuous Floor & Eqpt. Drain System Q1P45F097 Continuous Floor & Eqpt. Drain System Service Air System Q1P52F195 Continuous Q1P53F003 Continuous Instrument Air System Q1P53F007 Continuous Instrument Air System Q1T48F005 Continuous SGTS Q1T48F006 Continuous SGTS Q1T48F024 Continuous SGTS l Q1T48F026 Continuous SGTS Q1T48F023 Continuous SGTS Q1T48F025 Continuous SGTS Q1P45F273 Continuous Floor & Eqmt. Drain System

.. Q1P45F274 Continuous Floor & Eqmt. Drain. System j

" Manual bypass of thermal overload protection of manually controlled valve.

GRAND GULF-UNIT 1 3/4 8-45

2.4.h@.5 dh TABLE 3.3.7.5-1 (Continued)

ACCIDENT MONITORING INSTRUMENTATION ACTION STATEMENTS ACTION 80 - .

.a. With the number of OPERABLE accident monitoring inst'rumentation

- channels less than the Required Number of Channels shown in Table 3.3.7.5-1, restore the inoperable channel (s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum Channels OPERABLE requirements of Table 3.3.7.5-1, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , cc- ders % ' go pe,..W d=mkQ h OPE Ri\B t.E 1 LM w.W = % have s . .

ACTION 81 -

With the number of OPERABLE accident monitoring instrumentation channels less than required by the Minimum Channels OPERABLE requirement, either restore the inoperable channel (s) to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , or:

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

b. Prepare and submit a Special Report to the Commission pursuant

( to Specification 6.9.2 within 14 days following the event outlining the action taken, the cause of the incperability and the plans and schedule for restoring the system to OPERABLE status.

e a

k

\

GRAND GULF-UNIT 1 3/4 3-71

2s.ccansasz) i REFUELING OPERATIONS 1

3/4.9.12 HORIZONTAL FUEL TRANSFER SYSTEM l LIMITING CONDITION FOR OPERATION 3.9.12 The horizontal fuel transfer system (HFTS) may be in operation provided that:

l

a. The room through which the transfer system penetrates is sealed.

b. All interlocks with the refueling and fuel handling platforms are OPERABLE.

c. All HFTS primary carriage position indicato'rs are OPERABLE.

APPLICABILITY: OPERATIONAL CONDITION 4* and 5*.'

ACTION:

With the requirements of the above specification not satisfied, suspend HFTS operation with the HFTS at either the Spent Fuel Building pool or the Reactor Containment Building pool terminal point.

SURVEILLANCE REQUIREHENTS zy 4.9.12 Within g hours prior to the operation of HFTS and at least once per l 42 7.ews thereafter, verify that: I 74.fsa. All interlocks with the refueling and fuel handling platforms are

, OPERABLE.

l i b. All HFTS primary carriage position indicators are OPERABLE.

When the reactor mode switch is in the Refuel position.

l l

l GRAND GULF-UNIT 1 3/4 9-18 6

26.(64HS- 44G 3 417 3 433) 3/4.9 REFUELING OPERATIONS 3/4.9.1 REACTOR MDDE SWITCH LIMITING CONDITION FOR OPERATION 3.9.1 The reactor mode switch shall be OPERABLE and locked in the Shutdown or Refuel position. When the reactor mode switch is locked in the Refuel position:

a. A control rod shall not be withdrawn unless the Refuel position one-rod-out interlock is OPERABLE.

b. CORE ALTERATIONS shall not be performed using equipment associated with a Refuel position interlock unless at least the following associ-ated Refuel position interlocks are OPERABLE for such equipment.

1. All rods in. .

2. Refuel platform position s M*'"

3. Refuelplatfore(:ioist\ fuel-loaded.

m emoi .....,- --- . -,

~

e. .~ .T. _. ._. ." ~ .' 'n v' Y " ' 1. :. .:. . ~_. _. . . . . _. . ._.. . ____

APPLICABILITY: OPERATIONAL CONDITION 5* 8.

ACTION:

a. With the reactor mode switch not locked in the Shutdown or Refuel position as specified, suspend CORE ALTERATIONS and lock the reactor mode switch in the Shutdown or Refuel position.

b. With the one-rod-out interlock inoperable, lock the reactor mode switch in the Shutdown position.

c. With any of the above required Refuel position equipment interlocks inoperable, suspend CORE ALTERATIONS with equipment associated with the inoperable Refuel position equipment interlock.

l

" See Special Test Exceptions 3.10.1 and 3.10.3.8#

I f The reactor shall be maintained in OPERATIONAL CONDITION 5 whenever fuel is l

in the reactor vessel with the vessel head closure bolts less than fully

! tensioned or with the head removed.

The reactor mode switch may be placed in the Run or Startup/ Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or l other technically qualified member of the unit technical staff.

1 l

l l

GRAND GULF-UNIT 1 3/4 9-1 l

~

=

TABLE 3.3.2-1 N n

l E o

ISOLATION ACTUATION INSTRUMENTATION n ss

@ VALVE GROUPS MINIMUM APPLICABLE D q OPERATED BY OPERA 8LE CHANNELS OPERATIONAL h a TRIP FUNCTION SIGNAL (a) PER TRIP SYSTEM (b) CONDITION ACTION h 1. PRIMARY CONTAINNENT ISOLATION

" a. Reactor Vessel Water Level- W I Low Low, Level 2 6,7,8,10(c)(d) 2 1,2,3 W f M V m

-l b. Drywell Pressure - High 5,6,7,9(c)(d) 2 1,2,3 20

c. Containment and Drywell 7 2I 'I 1, 2, 3 and

21 Ventilation Exhaust Radiation - High }.\

lv w d. Manual Initiation 5, 6, 7, 8, 9, 10 2/ group 1, 2, 3 and *# 22 1

w 2. MAIN STEAM LINE ISOLATION

.'. a. Reactor Vessel Water Level-Low Low Low, Level 1 1, 5 2 1,2,3 20

b. Main Steam Line .

Radiation - High 1,10(f) 1/line 1,2,3 23

c. Main Steam Line ~

Pressure - Low 1 1/11ne 1 24

d. Main Steam Line Flow - High 1 2/11ne I9I 1, 2, 3 23

e. Condenser Vacuum - Low 1 2 1,2,3 23

f. Main Steam Line Tunnel Temperature - High 1 2 1,2,3 23

g. Main Steam Line Tunnel A Temp.- High 1 2 1,2,3 23

h. Manual Initiation 1, 5, 10 2/ group 1, 2, 3 22 J1 _ _ _ _ _

TABLE 3.3.2-2 N I

,, ISOLATION 4CTUATION INSTRUMENTATION SETPOINTS y 5 O I E ALLOWABLE @

g TRIP FUNCTION TRIP SETPOINT VALUE h 1. PRIMARY CONTAINMENT ISOLATION g l

$ a. Reactor Vessel Water Level - @

Low Low, Level 2 1 -41.6 inches

1 -43.8 inches 08

] v

b. Drywell Pressure - High i 1.73 psig i 1.93 psig g

c. Containment and Drywell Ventilation j f*

Exhaust Radiation - High Mig h 1 2.0 mr/hr** 1 4.0 mr/hr** I

d. Manual Initiation NA NA

2. MAIN STEAM LINE ISOLATION t

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1 -150.3 inches

1 -152.5 inches

b. Main Steam Line Radiation - High 1 1.5 x full power i 3.0 x full power background background

, u 1 c .- Main Steam Line Pressure - Low 1 849 psig 1 837 psig W d. Main Steam Line Flow - High 1 169 psid i 176.5 psid 5 e. Condenser Vacuum - Low 1 9 inches Hg. Vacuum 3 8.7 inches Hg. Vacuum

f. Main Steam Line Tunnel Temperature - High 1 180*Fa* 1 186*F**

g. Main Steam Line Tunnel a Temp. - High $ 80*F** i 83*F**

h. Manual Initiation NA NA

3. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

Low Low, Level 2 3 -41.6 inches

3 -43.8 laches

! b. Drywell Pressure - High 1 1.73 psig i 1.93'psig i c. Fuel Handling Area Ventilation Exhaust Radition - High High 1 2.0 mR/hr** i 4.0 mR/hr**

d. Fuel Handling Area Pool Sweep Exhaust Radiation - High High i 18*mR/hr** $ 35 mR/hr**t

e. Manual Initiation NA NA

N.(66 NS-303) P 3 TABLE 3.3.2-3 ISOLATION SYSTEM INSTRUMENTATION RESPONSE TIME RESPONSE TIME (Seconds)#

TRIP FUNCTION

1. PRIMARY CONTAINMENT ISOLATION Reactor Vessel Water Level - Low Low, Level 2 < 13(*)

a.

b. Drywell Pressure - High 313(*)

c. entilation Exhaust Containment and g ell {N Radiation - High H1 h i 1.0*/1 13(a),,

NA

d. Manual Initiation

2. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level - Low Low Low, < 1.0*/< 13(a) ,

Level 1

b. Main Steam Line Radiation - High(b) I 1.0*8 13((**)**

c. Main Steam Line Pressure - Low II 0.5*/7 1.0*8 13 13(*))**

d. Main Steam Line Flow - High ~

NA

e. Condenser Vacuum - Low NA

f. Main Steam Line Tunnel Temperature - High NA

g. Main Steam Line Tunnel a Temp. - High NA

h. Manual Initiation

3. SECONDARY CONTAINMENT ISOLATION Reactor Vessel Water Level - Low Low, Level 2 < 13(a) a.

b. Drywell Pressure - High 513(*)

c. Fuel Handling Area Ventilation Exhaust 1 13(,)

Radiation - High High(b)

d. Feal Handling Area Pool Sweep Exhaust 1 13(,)

Radiation - High High(b)

NA

e. Manual Initiation

4. REACTOR WATER CLEANUP SYSTEM ISOLATION ##

NA

a. A Flow - High NA

b. A Flow Timer NA

c. Equipment Area Temperature - High NA

d. Equipment Area a Temp. - High. 1 13(,)

e. Reactor Vessel Water Level - Low Low, Level 2

f. Main Steam Line Tunnel Ambient NA Temperature - High NA

g. Main Steam Line Tunnel a Temp. - High NA

h. SLCS Initiation NA

i. Manual Initiation GRAND GULF-UNIT 1 3/4 3-18

, TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS N y

E CHANNEL OPERAT10dAL G CHANNEL FUNCTIONAL CHANNEL CONDITIONS IN WHICH 9 j TRIP FUNCTION CHECK TEST CALIBRATION SURVEILLANCE REQUIRED p sn

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level - %

Low Low, Level 2 5 ;4 R 1, 2, 3 and # u v

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

c. Containment and Orywell .+

Ventilation Exhaust Radiation - High M;7 k S M R 1, 2,,3 and *

d. Manual Initiation NA MI ") NA 1, 2, 3 and *#

M.

i., 2. MAIN STEAM LINE ISOLATION

$ a. Reactor Vessel Water Level -

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

b. Main Steam Line Radiatien -

High S M R 1,2,3

c. Main Steam Line Pressure - .

Low S M R 1

d. Main Steam Line Flow - High S ,M R 1,2,3

e. Condenser Vacuum - Low S M R 1, 2**, 3**

f. Main Steam Line Tunnel Temperature - High S M R 1,2,3

g. Main Steam Line Tunnel

& Temp. - High S M R 1, 2, 3

h. Manual Initiation NA MI *) NA 1,2,3

I l

28,(GGNS-241)

TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTATION

Not required to be OPERABLE when reactor steam done pressure is less than or equal to 135 psig.

f aWhen the system is required to be OPERABLE e't-- be h; := x113 Apehc.blel ~="; .:d, ;; eppikeh, per Specification 3.5.2. o r 3.S. 3.

- Required when ESF equipment is required to be OPERABLE.

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

(b) Manual initiation switches shall be tested at least once per 18 months during shutdown. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 31 days as a part of circuitry required to be tested for automatic system actuation.

(c) Manual initiation test shall include verification of the OPERABILITY of the LPCS and LPCI injection valve interlocks.

(d) This calibration shall consist of the CHANNEL CALIBRATION of the LPCS and LFCI injection valve interlocks with the interlock setpoint verified to be 5 150 psig.

l l

(

l l

I GRAND GULF-UNIT 1 3/4 3-33

D e(GGNS-49)

INSTRUMENTATION TA8LE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION !

ACTION ACTIDN 20 Be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUT within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 21

- Close the affected system isolation valve (s) within one hour er:

a. In OPERATIONAL CONDITION 1, 2, or 3, he in at least NOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ,

b. In Operational Condition *, suspend CORE ALTERATIONS, handling of irradiated fuel in the containment and operations with a potential for draining the reactor 1

vessel.

ACTION 22 Restore the manual initiation function to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least NOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

' and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 23 Be in at least STARTUP with the associated isolation valves closed within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

ACTION 24 Be in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

- Establish SECONDARY CONTAINMENT INTEGRITY with the standby gas ACTION 25 treatment system operating within one hour.

ACTION 26 Restore the manual initiation function to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or close the affected system isolation valves ,

within the next hour and declare the affected system inoperable.

ACTION 27

- Close the affected system isolation valves within one hour and declare the affected system inoperable.

ACTION 28 - Lock the affected system isolation valves closed within one hour and declare the affected system inoperable.

NOTES

When handling irradiated fuel in the containment and during CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

During CORE ALTERATIONS and operations with a potential for draining the reactor vessel.

(a) See A Specification 3.6.4, Table 3.6.4-1 for valves in each valve group.

channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for (b) required surveillance without placing the trip system in the tripped con-dition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.

(c) Also actuates Also actuates the standby gas treatment system.

the control room emergency filtration system in the isolation (d) ~

mode.of operation.

(e) One upscale and/or two downscale actuate the trip system.

(f)

Also trips and isolates the mechanical vacuum pumps.

(g) A channel is OPERABLE if 2 of 4 instruments in that channel are OP (h) Also actuates secondary containment ventilation isolation dampers and '

4 ya - ;^ 633-F00L G33-f 00Dcg

},va;lve CO:

(i) valves per Table 3.6.6.2-1. Closes only RWCU system Pht cuttE

. f G 33- F 2 51.

GRAND GULF-UNIT 1 3/4 3-14

so.. C. caus- 47o) PL INSTRUMENTATION

! TABLE 3.3.7.3-1 l METEOROLOGICAL MONITORING INSTRUMENTATION .

MINIMUM

- INSTRUMENTS OPERABLE INSTRUMENT .

a. Wind Speed

1. Elev. 33 ft and 162 ft 1 each

b. Wind Direction

1. Elev. 33 ft and 162 ft 1 each

c. Air Temperature

1. Elev. 33 ft c..d 10: n 1 each

d. Air Temperature Difference 1

1. Elev. 33/162 ft a

l GRAND GULF-UNIT 1 3/4 3-64

, 3F. (46#5- 470) P2.

INSTRUMENTATION

! TABLE 4.3.7.3-1 METEOROLOGICALMONITORINGINSTRUMENTATIONSURVEILLANCERE6UIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION

a. Wind Speed

1. Elev. 33 ft and 162 ft D SA

b. Wind Direction

1. Elev. 33 ft and 162 ft D SA i

c. Air Temperature

1. Elev. 33 ft e D SA

d. Air Temperature Difference

1. Elev. 33/162 ft D SA l

l 1

GRAND GULF-UNIT 1 3/4 3-65

-- ~

TABLE 4.3.6-1 - Os E "

E ,

CONTROL R00 BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS e o O

@ CHANNEL FUNCTIONAL CHANNEL OPERAT'IONAL CONDITIONS FOR WHICH k G;

ch TRIP FUNCTION CHANNEL CHECK TEST CALIBRATION (a) SURVEILLANCE REQUIRED g 5 1. ROD PATTERN CONTROL SYSTEM

a. Low Power Setpoint NA S{g

') , D(c)(e) , Q 1, 2 g b)(e) , D(c)(e) 1, 2

b. Intemediate Rod Withdrawal NA S M{g()I') . Q Limiter Setpoint [

2. APRM

a. Flow Biased Neutron Flux- U Upscale NA S/U ,M %W)(3)SA) 1 1,2,5 Inoperative NA S/U ,M NA b.

w c. Downscale NA S/U ,M gWN,SA 1

,M 2, 5

) d. Neutron Flux - Upscale, Startup NA S/U Q Y 3. SOURCE RANGE MONITORS NA 2, 5

a. Detector not full in NA S/U((b) b), W 2, 5

b. Upscale NA S/UI ),W Q NA NA 2, 5

c. Inoperative S/U(b),W 2, 5 NA S/U ,W Q

d. Downscale

4. INTERMEDIATE RANGE MONITORS S/UI)W NA 2, 5

a. Detector not full in NA S/UI ),W 2, 5

b. Upscale NA Q Inoperative NA S/UI ),W NA 2, 5

c. S/UI ),W 2, 5

d. Downscale NA , Q

5. SCRAM DISCHARGE VOLUME M R 1, 2, 5*

a. Water Level-High NA

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW S/U(b) g q y

a. Upscale -

NA ,

l

n .cacsis- +sr) e.2.

INSTRUMENTATION TABLE 4.3.6-1 (Continued)

CONTROL ROD BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTES:

a. Neutron detectors may be excluded from CHANNEL CALIBRATION.

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

c. Within one hour prior to control rod movement, unless performed within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and as each power range above the RPCS low power setpoint is entered for the first time during any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period during power increase or decrease,

d. At least once per 31 days while operation continues within a given power range above the RPCS low power setpoint.

e. Includes reactor manual control multiplexing system input.

With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

"* * ^

f' 7k's c d ke A'oc Sld C**M 5Y *E N' "*b5 c( .e \ % cou. Corm -b %.e. p..ve r Ma s cd cMed by a Ked 6 buce. ebr.u$ OPERATio4At Conom ou i wheo 4Le<md ro**.e 15 h 2 5 */o of %TEb W E RMM. h> ER. , AApst 4Le APRK Cho.u we \ . 4. 4ke ab solv 4'e c\'d{e eue.e.

r '.s S reder kl a 2 */.

d R ATED Twr.ta r AL PDW E" R. A.uy APR M R.Luw e \ S oc. c Jjus4 %euf %%de ;u comph u t e w .h. S gec G e .At o.o 3, 2. 2.

s L M u .4 b e : u t.l o d e J i a d etc, m , -: y) .R, mg 3,g,+ g . q,,,c ,

.). 7ba cd.ke._% s.La\ coa 5M og 4te, d.gma ,g 4q APm O.m W 3 1 e_(muye,\4,e,y.p,,,9, ,c y g,3 flos >9ud, A. TL,s cd b edt.e sL M c.on s.s-f = { Ver: f y:q +k e 4 r.y 6 c.4 p,. t ut ou h .

GRAND GULF-UNIT 1 3/4 3-54 l

32. (GGNS - 4 27) PL.

INSTRUMENTATION TABLE 3.3.7.2-1 SEISMIC MONITORING INSTRUMENTATION MINIMUM MEASUREMENT INSTRUMENTS INSTRUMENTS AND SENSOR LOCATIONS RANGE OPERABLE

1. T,riaxial Strong Motion Accelerometer

a. Containment foundation 0.001 to 1.0g 1

b. Drywell 0.001 to 1.0g 1

c. SGTS Filter Train 0.001 to 1.0g 1

d. SSW Pump House A 0.001 to 1.0g 1

e. Free Field 0.001 to 1.0g 1

2. Triaxial Peak Recording Accelerograph

a. Containment Dome 0.01 to 2g I

b. Auxiliary Building Foundation 0.01 to 2g I

c. Diesel Generator 11 0.01 to 2g 1

d. Control Building Foundation 0.01 to 2g 1

e. Control Room 0.01 to 2g I

f. Reactor Vessel Support 0.01 to 2g 1

g. Reactor Recire. Piping 0.01 to 2g I

h. Main Steam Piping 0.01 to 2g 1

1. LPCS Spray Line 0.01 to 2g 1

j. HPCS Spray Line 0.01 to 2g 1

k. SSW Pump House B 0.01 to 2g 1

3. Triaxial Seismic Switches

a. Containment Foundation (SSE) 0.025 to 0.25g 1*

b. Containment Foundation (OBE) 0.025 to 0.25g 1*

c. Orywell (SSE) 0.025 to 0.25g 1*

d. Orywell (OBE) 0.025 to 0.25g 1*

4. Vertical Seismic Trigger.4eeeedoes

a. Containment Foundation 0.005 to 0.05g 1*

5. Horizontal Seismic Trigger

a. Drywell 0.005 to 0.05g 1*

"With control room annunciation.

5 GRAND GULF-UNIT 1 3/4 3-61

32. C4avs -427) rz.

INSTRUMENTATION TABLE 4.3.7.2-1 SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL Cr.ANNEL FUNCTIONAL CHANNEL CHECK TEST CALIBRATION INSTRUMENTS AND SENSOR LOCATIONS

1. Triaxial Strong Motion Accelerometer M SA R

a. Containment Foundation SA R

b. Drywell M M SA R

c. SGTS Filter Train R SSW Pump House A M SA d.

M SA R

e. Free Field

2. , Triaxial Peak Recording Accelerograph NA NA R

a. Containment Dome Auxiliary Building Foundation NA NA R b.

NA NA R

c. Diesel Generator 11

d. Control Building Foundation NA NA R NA NA R

e. Control Room Reactor Vessel Support NA NA R f.

g. Reactor Recirc. Piping NA NA R NA R

h. Main Steam Piping NA NA R

1. LPCS Spray Line NA

j. HPCS Spray Line NA NA NA R

R

k. SSW Pump House 8 NA

3. Triaxial Seismic Switches M SA R

a. Containment Foundation (SSE)

M SA R

b. Containment Foundation (OBE) R M SA

c. Drywell (SSE)

M SA R

d. Drywell (OBE)

4. Vertical Seismic Trigger.aeeemdeas M SA R

a. Containment Foundation l S. Horizontal Seismic Trigger M SA R

a. Drywell GRAND GULF-UNIT 1 3/4 3-62

33 . B I ADMINISTRATIVE CONTROLS 6.5.2 SAFETY REVIEW COMMITTEE (SRC) h0NCTION h.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 a

d. metallurgy

e. instrumentation 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:

Chairman: Assistant Vice President for Nuclear Production Member: Manager of Nuclear Plant Engineering Member: Manager of Quality Assurance Member: Manager of System Nuclear Operations, Middle South Services, Inc.

Member: Nuclear Plant Manager Member: Manager of Nuclear Services Member: Corporate Health Physicist Member: Principal Engineer, Operations Analysis aus Member Advisor to the Assistant Vice-President, Nuclear Operations Two additional voting members shall be consultants to Mississippi Power l

and Light Company consistent with the recommendations of the Advisory Committee on Reactor Safeguards letter, Mark to Palladino dated October 20, 1981.

The SRC members shall hold a Bachelor's degree in an engineering or physical science field or equivalent experience and a minimum of five years of technical 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 committee shall provide specific practical experience in the majority of the disciplines of 6.5.2.la through h.

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

r GRAND GULF-UNIT 1 6-9

.' 3+, 8 RADI0 ACTIVE EFFLUENTS LIQUID WASTE TREATMENT l

LIMITING CONDITION FOR OPERATION = _

'3.11.1.3 The liquid radwaste system components as specified in the ODCM shall be OPERABLE. The appropriate portions of the system shall be used to reduce the radioactive materials in liquid wastes prior to their discharge when the cumulativ p iected dose due to the liquid effluent from the site (see Eiaure6.1.0-1) n a 31 day period would exceed 0.06 arem to the total body l or 0.2 are o any organ.

f./.3-l APPLICABILITY: At all times.

ACTION:

a. With the liquid radwaste treatment system inoperable for more than 31 days or with radioactive liquid waste being discharged without j

treatment and in excess of the above limits, in lieu of any other l

report required by Specification 6.9.1, prepare and submit to the Commission within 30 days pursuant to Specification 6.9.2 a Special Report which includes the following information:

1. Identification of the inoperable equipment or subsystems and ,

+he reason for inoperability,

2. Action (s) taken to restore the inoperable equipment to OPERABLE status, and

3. Summary description of action (s) taken to prevent a recurrence.

b. The provisions of Specifications 3.0.3, 3.0.4 and 6.9.1.11 are not applicable, j

SURVEILLANCE REQUIREMENTS 4.11.1.3.1 Doses due to liquid releases to unrestricted areas shall be projected at least once per 31 days, in accordance with the ODCM.

4.11.1.3.2 The liquid radwaste system components specified in the ODCM shall i

be demonstrated OPERABLE by operating the liquid radwaste treatment system equipment for at least 30 minutes at least once per 92 days unless the liquid radwaste system has been utilized to process radioactive liquids during the previous 92 days.

GRAND GULF-UNIT l' 3/4 11-6

i .O ADMINISTRATIVE CONTROLS

[

AUTHORITY .

l 6.5.2.9 The SRC shall report to and advise the Senior Vice President - Nuclear l on those areas of responsibility specified in Sections 6.5.2.7 and 6.5.2.8.

RECORDS 6.5.2.10 Records of SRC activities shall be prepared, approved and distributed as indicated below:

a. Minutes of each SRC meeting shall be prepared, approved and forwarded to the Senior Vice President - Nuclear within 14 days following each meeting. 4,3 g.s.z.6

b. Reports of reviews encompassed by Section 6.5.2.7 bove, shall be prep: red, :ppre :d :nd f: .;;rd:d t th: hri:r "k: Pr;;id:nt -

u.._,___ .a.u. u um, ,_,,..:._ ____3.. __ .,.u _ _ . .

oficJrilihsE W hid AIA57cs if M c. W s'rMTi i h 4 o' "

. %dit repert: erc- par :d by Sectf er 5. 5. 2.9 e:: , th: 5: vgggg, forwarded to the Senior Vice President - Nuclear $;n: :: th;

-e;c ent petitier r:: pen:ib h f:r th: :r::: = dited "ith'- 20 d y:

a#t r cc p'etkr Of th: =dit h th; _diting rg:ri :th:

6.5.3 TECHNICAL REVIEW AND CONTROL ACTIVITIES 6.5.3.1 Activities which affect nuclear safety shall be conducted as follows:

a. Procedures required by Technical Specification 6.8 and other procedures which affect plant nuclear safety, and changes thereto, shall be prepared, reviewed and approved. Each such procedure or procedure change shall be reviewed by an individual / group other than the individual / group which prepared the procedure or procedure change, but who may be from the same organization as the individual / group which prepared the procedure or procedure change. Procedures other than Administrative Procedures shall be approved as delineated in writing by the Plant Manager. The Plant

> Manager shall approve administrative procedures, security implementing procedures and emergency plant implementing procedures. Temporary approval to procedures which clearly do not change the intent of the 1 approved procedures may be made by two members of the plant management staff, at least one of whom holds a Senior Reactor Operator's License.

For changes to procedures which may involve a change in intent of the approved procedures, the person authorized above to approve the proce-dure shall approve the change.

b. Proposed changes or modifications to plant nuclear safety-related structures, systems and components shall be reviewed as designated i by the Plant Manager. Each such modification shall be reviewed by I an individual / group other than the individual / group which designed the modification, but who may be from the same organization as the individual / group which designed the modifications. Implementation of proposed modifications to plant nuclear safety-related structures, systems and components shall be approved by the Plant Manager.

GRAND GULF-UNIT 1 6-12

. .- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

ML20069H283

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6.5.2. JUSTIFICATION

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