ML17303A308

Forwards Proposed Corrections to 870203 Proof & Review Tech Specs & Provides Certification That Specs Reflect as-built Condition of Facility

ML17303A308
Person / Time
Site:	Palo Verde
Issue date:	02/18/1987
From:	Haynes J ARIZONA PUBLIC SERVICE CO. (FORMERLY ARIZONA NUCLEAR
To:	Knighton G Office of Nuclear Reactor Regulation
References
ANPP-40147-JGH, NUDOCS 8702260077
Download: ML17303A308 (67)

Text

REGULATORY INFORMATION DISTRIBUTION;SYST M (R IDS)

IANERSCN jNBR: 8702260077 OC. DATE: 87/02/18 NOTARI c:

YES DOCKET ¹

< FACIL:BTN-50-530 Palo Verde Nuclear Station>

Unit 3i Arizona Pub li 05000530 AUTH. NAl1E AUTHOR AFFILIATION HAYNES> J. Q.

Arizona Nuclear Power Pro Ject (formerly Api zona Public Serv RECIP. NAME RECIPIENT AFFILIATION KNIQHTON> Q. W.

PNR Progect Directorate 7

SUBJECT:

Forwards proposed corrections to 870203 proof 8< review Tech Specs 5 provides certi fication that specs reflect as-built condition of facility.

DISTRIBUTION CODE'001D COP lES RECEIVED: LTR ENCL SI ZE:

TITLE: Licensing Submittal:

PSAR/FSAR kmd+s 8c Related orrespondence NOTES: Standardized plant. M. Davis. NRR: 1Cg.

05000530 REC IP IENT ID CODE/NAME pNR-8 EB PNR-8 FOB pWR-8 PD7 PD pNR-8 PEICSB 1

COPIES LTTR ENCL 1

1 1

1 1

1 RECIPIENT ID CODE/NAME PWR-8 PEICSB PWR-8 PD7 LA LICITRA> E 04-PNR-8 RSB COPIES LTTR ENCL 2

2 1

2 2

1 1

INTERNAL: ACRS 41 ELD/HDS3 IE/DEPER/EPB 36 NRR BWR ADTS R

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1 1

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• DM/LFMB IE FILE IE/DGAVT/GAB 21 NRR PWR-8 ADTS NRR/DHFT/MTB RM/DDAMI/MIB 1

0 1

1 1

0 1

1 0

EXTERNAL: BNL(AMDTS ONLY)

LPDR 03 NSI C 05 NOTES 1

1 1

1 1

1 1

1 DMS/DSS (AMDTS)

NRC PDR 02, PNL QRUELz R 1

1 1

1 TOTAL NUMBER OF COPIES REQUIRED:

LTTR 34 ENCL 29

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Arizona Nuclear Power Project P.o. BOX 52034

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PHOENIX, ARIZONA85072-2034 February 18, 1987 NPP-40147~/JRP/98.05 Director of Nuclear Reactor Regulation Attention:

Mr. George W. Knighton, Project Director PWR Project Directorate III7 Division of Pressurized Water Reactor Licensing B

U.S. Nuclear Regulatory Commission Washington, D.C. 20555

Subject:

Palo Verde Nuclear Generating Station (PVNGS)

Unit 3 Docket No.

STN 50-530 Proof and Review-Technical Specification Certification File: 87-F-005-419.05 87-D-056-026

Reference:

(A)

ANPP letter dated November 26,

1986, from J.

G. Haynes to to G.

W. Knighton, NRC.

(B)

NRC letter dated February 5, 1987, from M. J. Davis to E. E.

Van Brunt, Jr.,

ANPP.

Dear Mr. Knighton:

This letter is submitted for the purpose of (i) transmitting proposed correc-tions to the February 3,

1987, Proof and Review Technical Specifications as received by reference (B) and (ii) provide our certification of the PVNGS Unit 3 Proof and Review Technical Specifications as amended by Attachment 1 to this letter.

In developing the PVNGS 'Unit 3 Technical Specifications, the following process was implemented to ensure that a workable set of Technical Specifications was developed.

A committee to review NUREG-0212, Revision 3 and develop the PVNGS Unit 1 Technical Specifications was established approximately four years ago.

This committee consisted of representatives from Offsite Engineering, Licensing, Onsite Engineering, H.P./Chemistry, Maintenance, Operations,

Startup, Q.A.,

STA, ISEG,

Training, Bechtel Power Corp.

and Combustion Engineering.

This group worked closely with the NRC staff to develop a set of Technical Specifi-cations that represented PVNGS.

The work of this committee resulted in Appendix A to the Operating License for Units 1

and 2.

Appendix A of the Unit 2

Operating License was used as a basis for the Proof and Review version of the Unit 3 Technical Specifications, as amended by reference (A).

8702260 g pgpp0530, p77 870218 PDR ADOC PDR, ~

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Mr. George W. Knighton

Subject:

Proof and Review Technical Specification Certification ANPP-40147 Page 2

In reviewing this draft version, the following aspects were incorporated:

(i)

Utilization of Units 1

and 2 plant specific experience to review sys-tems, their functions and parameters.

(ii)

Discussed Technical Specification problems with other utilities with operating units.

(iii)

Monitored Federal Register for Technical Specification generic issues.

(iv)

Reviewed various operating experiences (i.e.,

LER's, Special

Reports, Inspection Reports, etc.).

(v)

Compared the Technical Specifications to the PVNGS FSAR for consis-tency.

(vi)

Compared the Technical Specifications to the PVNGS SER for consis-tency.

(vii)

Compared the Technical Specifications to the CESSAR FSAR for consis-tency.

(viii)

Compared the Technical Specifications to the CE-SER for consistency.

(ix)

Ne have used our vendor's experience and support to develop the Techni-cal Specifications.

Reference (A) transmitted to the NRC marked up Unit 2 Technical Specifications as a

basis for Unit 3 Technical Specifications.

In the process of resolving

comments, meetings were conducted between

'appropriate NRC branches and ANPP representatives.

In resolving the'omments a Pr'oof and Review copy was develop-ed by the NRC and transmitted to ANPP by reference (B).

After a review by ANPP, it is apparent that there are several editorial and/or typographical errors in the Proof and Review Technical Specifications.

Attachment 1 to this letter contains changes to the Proof and Review Technical Specifications which are necessary for our certification.

Based on these

changes, the review process implemented, the certification

process, Bechtel's and Combustion Engineering's certifications, I certify that to the best of my knowledge, the Proof and Review copy of the Technical Specifi-cations for PVNGS Unit 3, as transmitted to ANPP (reference B), and as amended

/

1

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Mr. George W. Knighton

Subject:

Proof and Review Technical Specification Certification ANPP-40147 Page 3

by Attachment 1,

and as discussed

herewith, accurately reflect the as-built condition of the plant, the PVNGS Final Safety Analysis Report and the Safety Evaluation Report.

Very truly yours, J ~ G. Haynes Vice President Nuclear Production JGH/JRP/rw Attachment cc:

0.

M. De Michele E. E.

Van Brunt, Jr.

Director, Region V USNRC NRC Project Manager E.

A. Licitra (w/a)

NRC Resident Inspection R.

P.

Zimmerman NRC Tech Spec Reviewer T. Green (w/a)

STATE OF ARIZONA )

)

sate COUNTY OF MARICOPA)

I, Jerry G.

Haynes, represent that I am Vice President of Nuclear Production of Arizona Nuclear Power Project, that the foregoing document has been signed by me on behalf of Arizona Public Service Company with full authority to do so, that I have read such document and know its contents, and that to the best of my knowledge and belief, the statements made therein are true and correct.

Jerry G.

Haynes Sworn to before me this /0 day of

, 198

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( 5 ll gi ')~ "~

I

(,x, My (Cominission 'Expires:

Vy C~umiwion Irca A ril 6. 1987 Notary Pub c

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ATTACHMENT 1 Page I, Section 1.17, OFFSITE DOSE CALCULATION MANUAL.

The abbreviation should be ODCM, this is a typographical error.

Page XI, Section 3/4.3.3 MONITORING INSTRUMENTATION; change the page to B 3/4 3

2 ~

Page XIV, Section 3/4.11.4 TOTAL DOSE; change the page to B 3/4 11-5.

Page 3/4 1-4, Section 3.1.3.3, APPLICABILITX; place a period after 2~8.

Page 3/4 1-8, Section 4.1.2.2.2, the reference in this surveillance requirement should be 4.1.2.2.1.6 not 4.1.2.2.6.

1 Page 3/4 1-5, Figure 3.1-1, Allowable MTC MODES 1

AND 2; this figure replaced the previous curve which was for Unit 2 only, this curve is the same as the Unit 1 curve.

The MTC curve for Unit 2 is more conservative than for Unit 1,

because of a

condition which was discussed after the Unit

'1 Technical Specifications were issued.

The condition requiring the conservative limit was corrected in Unit 3 during construction and was also corrected in Units 1

and 2.

A request had been made to modify the Unit 1 specification, but it was withdrawn when the modifications were completed.

It is presently planned to request that the Unit 2 specification be changed as part of the reload licensing for Unit 2.

Page 3/4 1-25, Section 3.1.3.2, ACTION c; move the period to the right of the asterisk.

Page 3/4 3-48, Section 3.3.3.5, ACTION a. delete the (-) and the c; the remote shutdown monitoring channels are located on Table 3.3-9A only not A-C.

ACTION

b. after the word inoperable add the following "(Listed in Table 3.3-9 B and C)

This clarifies where the switches and circuits are located.

Page 3/4 6-12, TABLE 3.6-1, Tendon Surveillance, the changes are Unit 3

specific, the previous table was Unit 2 specific.

Page 3/4 6-13, TABLE 4.6-2, Tendon Lift-Off Force the changes are Unit 3

specific, the previous table was Unit 2 specific.

Page 3/4 6-16, Section 4.6.2.1 d.3; change (CSA) to (CSAS) "containment spray actuation test signal".

Change (SIA) to (SIAS)

"safety injection actuation signal Page 3/4 6-28, TABLE 3.6-1; Valve Number IAE-V 072 is incorrect, it should be IAE-V 073.

Page 3/4 6-32, Valve Number SIC-HV-321, "recirculation" was spelled incorrectly.

Page 3/4 7-1, Section 3.7.1.1, Action a., delete the reference to MODE 3, this was deleted in Unit 2 T/S as approved by the staff.

Add the word "setpoint" before ceiling and delete "setpoint" after ceiling.

This was also approved by the staff for Unit 2 T/S.

Action b.,

add the words "at least" between "with" and "one".'his was also approved by the staff for unit 2.

l

15.

Page 3/4 7-6, Section 3.7.1.3, Limiting Condition for Operation, The Condensate Storage Tank level is incorrect at 23 feet, the corrected calculated level is 25 feet.

Section 3.7.1.3 APPLICABILITY, move the period to the right of 4'"'t.

ACTION B.,

add the word essential before the word auxiliary.

Section 4.7.1.3.2, add the word essential before the word auxiliary.

Section 4.7.1.3.2 a,

add the word water after feed "feedwater".

These changes/

corrections were agreed to by the staff for'nit 2 T/S.

16.

Page 3/4 7-10, Section 3.7.1.6, APPLICABILITY; move the period to the right of 4%

17.

Page 3/4 7-21, Section 4.7.9.a; change the word Inspection to Snubber.

This change was agreed to by the staff for Unit 2 T/S.

18.

Page 3/4 7-22, Section 4.7.9c, in the middle of the paragraph the word susceptible is spelled incorrectly 19.

Page 3/4 4-1, Heading at the top of the

page, the 3/ is missing from the title.

20.

Page 3/4 4-7, Pressure/Temperature Limits (continued);

In the last paragraph the term specimens should be changed to

capsules, this was agreed to by the staff for Unit 2 T/S.

21.

Page 3/4 11-9, Table 4.11-2; delete the parenthesis before ARH-2537.

22.

Page B 3/4 11-2, Radioactive Effluents, Bases, add the term DOSE (continued),

to be consistent with the T/S.

23.

Page 5-1, Section 5.2.1, f; the word should be "of" Section 5.2.1,

g. the term should be 10 24.

Page 5-5, Section 5.4.2, the word should be coolant.

'I 25.

Page 5-6, Section 5.5, add a period between 5.5 and one between 5.1-1.

26.

Page 5-9, TABLE 5.7-2, Auxiliary Spray.

In column T

501-550 and 551-600 were omitted and in column NA, 225 and 150 were omit'ed.

They are both in Units 182.

27.

Page 6-4, Figure 6.2-2:

The outage management manager and the manager compliance both report to the PVNGS Plant Manager.

The line from the manager complicance should go to the top and meet the horizontial line.

I l'l

DEFINITIONS INDEX SECTION

1. 0 DEF IN IT IONS ACT 'ION

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PAGE 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9

1. 10

1. 11

1. 12

l. 13

'l. 14 AXIAL SHAPE INDEX.

AZIMUTHAL POWER TILT " T q'HANNEL CALIBRATION.......

CHANNEL CHECK.......

CHANNEL FUNCTIONAL TEST.

CONTAINMENT INTEGRITY.

CONTROLLED LEAKAGE...........

CORE ALTERATION..................

~...

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DOSE EQUIVALENT I-131............

E - AVERAGE DISINTEGRATION ENERGY ENGINEERED SAFETY FEATURES

RESPONSE

TIME FREQUENCY NOTATraN...................

GASEOUS RADWASTE SYSTEM.

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1-2 1-2 1-2 1-2 1-3 1-3 1" 3 1-3 1-3

l. 15

l. 16

1. 17

l. 18

1. 19

1. 20

1. 21

l. 22

1. 23

1. 24 IDENTIFIED LEAKAGE..

MEMBER(S) OF THE PUBLIC..............

OFFSITE DOSE CALCULATION MANUAL (OCTAD)

OPERABLE - OPERABILITY.

OPERATIONAL MODE " MODE.

PHYSICS TESTS PLANAR RADIAL PEAKING FACTOR " F PRESSURE BOUNDARY LEAKAGE.

PROCESS CONTROL PROGRAM (PCP)

PURGE " PURGING........

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1-3 1-4 1-4 1"4 1-4 1-5 1-5

l. 25

l. 26

1. 27

'.28

1. 29

1. 30 RATED THERMAL POWER.........

REACTOR TRIP SYSTEM RESPONSE REPORTABLE EVENT....

SHUTDOWN MARGIN.....

SITE BOUNDARY.

SOFTWARE

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1-5 1-5 1-5 1-6 1-6 PALO VERDE " UNIT 3 FEB 3 IN PROOF K APfIFNN<

0'

BASES INDEX SECTION PAGE 3/4.0 APPLICABILITY....,............,.........

B 3/4 0"1 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.1 BORATION CONTROL............,........

3/4. 1. 2 BORATION SYSTEMS........................................

3/4. 1 ~ 3 MOVABLE CONTROL ASSEMBLIES 3/4. 2 POWER DISTRIBUTION LIMITS 3/4.2.1 LINEAR MEAT RATE 3/4 ~ 2.2 PLANAR RADIAL PEAKING FACTORS ~.....

3/4.2.3 AZIMUTHAL POWER TILT - T....

3/4. 2.4 DNBR MARGIN.......

3/4.2.5 RCS FLOW RATE.........................

B 3/4 1-1 B 3/4 1-2 B 3/4 1-4 B 3/4 2-1 B 3/4 2-2 B 3/4 2"2 B 3/4 2-3 B 3/4 2-4 3/4.2.6 REACTOR COOLANT COLD LEG TEMPERATURE.......

B 3/4 2"4 3/4.2. 7 AXIAL SHAPE INDEX.....................

3/4.2.8 PRESSURIZER PRESSURE.

3/4.3 INSTRUMENTATION 3/4.3. 1 and 3/4.3.2 REACTOR PROTECTIVE AND ENGINEERED FEATURES ACTUATION SYSTEM INSTRUMENTATION...

3/4.3. 3 MONITORING INSTRUMENTATION.:.........

SAFETY B 3/4 2-4 B 3/4 2-4 B 3/4 3-1 B 3/4 3->Z PALO VERDE - UNIT 3 XI

)

f f

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BASES INDEX PVVF ~i P '~~>A'yp'/

SECTION 3/4. 9. 6 REFUELING MACHINE.....................

8 PAGE 3/4 9-2 3/4.9.7 CRANE TRAVEL -

SPENT FUEL STORAGE POOL BUILDING.........

8 3/4 9

2 3/4.9.8 SHUTDOWN COOLING AND COOLANT CIRCULATION.....

8 3/4 9-2 3/4.9.9 CONTAINMENT PURGE VALVE ISOLATION SYSTEM.

8 3/4 9-3 3/4.9. 10 and 3/4.9. 11 WATER LEVEL -

REACTOR VESSEL and STORAGE POOL...............

8 3/4 9-3 3/4.9.12 FUEL BUILDING ESSENTIAL VENTILATION SYSTEM..............

8 3/4 9"3 3/4. 10 SPECIAL TEST EXCEPTIONS 3/4. 10.1 SHUTDOWN HARGIN............................

8 3/4 10-1 3/4

~ 10.2 HODERATOR TEMPERATURE COEFFICIENT, GROUP HEIGHT, INSERTION, ANO POWER DISTRIBUTION LIMITS 3/4.10.3 REACTOR COOLANT LOOPS 3/4.10.4 CEA POSITION, REGULATING CEA INSERTION LIMITS AND REACTOR COOLANT COLD LEG TEMPERATURE 8 3/4 10-1 8 3/4 10-1 8 3/4 10-1 3/4.10. 5 Hl'NIMUH TEHPERATURE AND PRESSURE FOR CRITICALITY........

8 3/4 10-1 3/4.10.6 SAFETY INECTION TANKS...................

8 3/4 10"2 3/4. 10.7 SPENT FUEL POOL LEVEL.........,,.

8 3/4 10-2 3/4. 10.8 SAFETY INJECTION TANK PRESSURE.

3/4. 11 RADIOACTIVE EFFLUENTS

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3/4 10-2 3/4.11.1

'SECONDARY SYSTEM LI(UID WASTE DISCHARGES TO ONSITE EVAPORATION PONDS..

3/4. 11.2 GASEOUS EFFLUENTS 3/4.11. 3 SOLID RADIOACTIVE WASTE......

3/4. 11. 4 TOTAL DOSE..

8 3/4 11-1 8 3/4 ll"2 8 3/4 11-5 B 3/4 11-6. K 3/4. 12 RADIOLOGICAL ENVIRONMENTAL MONITORING 3/4.12.1 MONITORING PROGRAM.....,...,...,.......

8 3/4.12.2 LAND USE CENSUS.......,....,..

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8 3/4, 12.3 INTERLABORATORY COMPARISON PROGRAM......................

• 8 PALO VERDE - UNIT'3 XIV gg 3/4 12-1 3/4 12-2 3/4 12-2 FEB 3 SF

MODERATOR TEMPERATURE COEFFICIENT LIHITING CONDITION, FOR OPERATION

3. l. 1.3 The moderator temperature coefficient (MTC) shall be within the area of Acceptable Operation shown on Figure 3. 1-1.

APPLICABILITY:

MODES 1 and 2*¹.

ACTION:

With the moderator temperature coefficient outside the area of Acceptable Operation shown on Figure 3.1-1, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE RE UIREMENTS

4. 1. 1.3. 1 The HTC shall be determined to be within its limits by confirmatory measurements.

MTC measured values shall be extrapolated and/or compensated to permit direct comparison with the above limits.

4. 1. 1.3.2 The MTC shall be determined at the following frequencies and THERMAL POWER conditions during each fuel cycle:

Prior to initial operation above 5X of RATED THERMAL POWER, after each fuel loading.

b.

C.

At any THERMAL POWER', within 7 EFPD after reaching a core average exposure of 40 EFPD burnup into "the current cycle.

At any THERMAL POWER, within 7 EFPD after reaching a core average exposure equivalent to two-thirds of the expected current cycle end-of-cycle core average burnup.

"With Keff greater than or equal to 1.0.

¹See Special Test Exception

3. 10.2.

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PALO VERDE - UNIT 3 3/4 1-5

REACTIVITY CONTROL SYSTEMS FLOM PATHS - OPERATING LIMITING CONDITION FOR OPERATION FKjnF 8 REVtBV COP f 3.1.2.2 At least two of the following three boron injection flow paths shall be OPERABLE:

a.

A gravity feed flow path from either the refueling water tank or the spent fuel pool through CH-536 (RMT Gravity Feed Isolation Valve) and a charging pump to the Reactor Coolant System, b.

A gravity feed flow path from the refueling water tank through CH-327 (RMT Gravity Feed/Safety Injection System Isolation Valve) and a charging pump to the Reactor Coolant System, c.

A flow path from either the refueling water tank or the spent fuel pool through CH-164 (Boric Acid Filter Bypass Valve), utilizing.

gravity feed and a charging pump to the Reactor Coolant System.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTION:

With only one of the above required boron injection flow paths to the Reactor Coolant System OPERABLE, restore at least two boron injection flow paths to the Reactor Coolant System to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY and borated to a SHUTDOMN MARGIN equivalent to at least 6X delta k/k at 210'F within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; restore at least two flow paths to OPERABLE status within the next 7 days or be in COLD SHUTDOWN within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

SURVEILLANCE RE UIREMENTS 4.1.2.2.1 At least two of the above required flow paths shall be demonstrated OPERABLE:

a.

At least once per 31 days by verifying that each valve (manual, power-operated, or automatic) in the flow path that is not locked,

sealed, or otherwise secured in position, is in its correct position.

b.

At least once per 18 months when the Reactor Coolant System is at

. normal operating pressure by verifying that the flow path required by Specification

3. 1.2. 2 delivers at least 26 gpm for 1 charging pump and 68-gpm for two charging pumps to the Reactor Coolant System.

4. 1.2.2.2 The provisions of Specification 4.0.4 are not applicable for entry into.Mode 3 or Mode 4 to perform the surveillance testing of Specification

4. 1.2. 2! b provided the testing is performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving normal perating pressure in the reactor coolant system.

I PALO VERDE - UNIT 3 3/4 1-8

p-,wr;r g pp,~)pyV QQQg'OSITION INDICATOR CHANNELS - OPERATING LIMITING CONDITION FOR OPERATION

3. 1.3.2 At least two of the following three CEA position indicator channels shall be OPERABLE for each CEA:

a.

CEA Reed Switch Position Transmitter (RSPT 1) with the capability of determining the absolute CEA positions within 5.2 inches, b.

CEA Reed Switch Position Transmitter (RSPT 2) with the capability of determining the absolute CEA positions within 5.2 inches, and c.

The CEA pulse counting position indicator channel.

APPLICABILITY:

MODES 1 and 2.

ACTION:

With a maximum of one CEA per CEA group having only one of the above required CEA position indicator channels OPERABLE, within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> either:

a.

Restore the inoperable position indicator channel to OPERABLE

status, or b.

Be in at least HOT STANDBY, or c.

Position the CEA group(s) with the inoperable position indicator(s) at its fully withdrawn position while maintaining the requirements of Specifications

3. 1.3. 1 and 3. 1.3.6.

Operation may then continue provided the CEA group(s) with the inoperable position indicator(s) is maintained fully withdrawn, except during surveillance testing pursuant to the requirements of Specification 4. 1.3. 1.2, and each CEA in the group(s) is verified fully withdrawn at least once per 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> s thereafter by its "Full Out" limit~

SURVEILLANCE RE UIREMENTS

4. 1.3.2 Each of the above required position indicator channels shall be determined to be OPERABLE by verifying that for the same CEA, the position indicator channels agree within 5.2 inches of each other at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

• CEAs are fully withdrawn (Full Out) when withdrawn to at least 144.75 inches.

PALO VERDE - UNIT 3 3/4 1"25 PROOF E A>4 3 48 PROOFS R RBliEIJIl 00. 4

L

TABLE 4. 6-1 TENDON SURVEILLANCE - FIRST YEAR Tendon No.

Visual Inspection Monitor Forces Detension Remove Tendon Mire Test Wire V3&

i'432.6 ve3 o9 YR~ ~>

H13-4Q ohio H13-OH o~

l +~HA-039~ 4 H21-044. os H32"016 <iE H32-030~oz.y Ho

~No-x, ko-g Ho x,

No x Ho x No ~

ko x No x.

~No. x, No Ho. <

No No No No No ko. a No No No 4o <

No No No Ho No No )c.

No No Ho No x.

Ho No Ho No Ho No.w.

No Ho Notes:

2.

3.

"I" means the tendon shown shall be inspected for the stated requirements during this surveillance.

"No" means that inspection is not required for that tendon.

""" means control tendon.

PALO VERDE - UNIT 3 3/4 e-12 FEB

~

TABLE 4

~ 6-2

~

~DO a i "VI"9 ~0+~~j TENDON LIFT"OFF FORCE " FIRST YEAR U-TENDONS TENDON NUMBER V3-2 ic V4-3 2Q V62-o9 V75 +p TENDON END Sho Field Shoield Sho Field Shop Fse d

MAXIMUM (kips) 1463 ~u<a9 1510 i s~t 1436 %up~

1486 i 5zs 14 " isz.u 1486 x~~pz 1527.

1504

( ai9 MINIMUM (kips) 1943 i3 t9 1386 i+~g 3.-364 3.-364 waa

'.354 3:364 1402 1-380 ig9q HOOP TENDONS TENDON NUMBER TENDON END MAXIMUM (kips)

MINIHUH (kips)

H13-007 c io 3.428 ~-o7 1300 i e 1 d 1451 ~.u<u, 1321 15 5 i;e-1.31 1446 x u~ w ldl.7 H21-037 o~w F>eld H13-021 oSe 1-515 i.u ~p 1380 Field 1491

~.~am 13 8 H21 044co'7 Sho 148 s sg 13 F 1 e 1 d 1530

<u=.~

1403 H2.1-016 o Field 1457 i<<z H24 Sho 1473 iuu~,

19 0 F 1 el d

- 3.47-3 i wit 3:330 PROOF 8 PFVjRQ f',I',pp PALO VERDE - UNIT 3 3/4 6-13 in~~

pg&

CONTAINMENT SYSTEMS PRQQp g, pnppy ~op)

SURVEILLANCE RE UIREMENTS (Continued) 2.

Verifying that upon a recirculation actuation test signal, the containment sump isolation valves open and that a

recirculation mode flow path via an OPERABLE shutdown cooling heat exchanger is established.

3.

Verifying that each spray pump starts automatically on a safety injection actuation (SIA) and on a containment spray actuation (MA) test signal. (et~)

C~~~)

At least once per 5 years by performing an air or smoke flow test through each spray header and verifying each spray nozzle is unobstructed.

PALO VEROE - UNIT 3 3/4 e-Xe PROQF &. RBKVI COPY FEB 3 SS7

TABLE 3.6-1 (Continued)

CONTAINMENT ISOLATION VALVES YALYE NUMBER PENETRATION NUMBER FUNCTION MAXIMUM ACTUATION TIME (SECONOS)

CHE"Y M70 41

073, IAE-V 07-2, 59 SIB-Y 533 67 CHE-Y 835 72 AFE"Y 0798 75 AFE-Y 080~

76 SIA-V 523 77 D.

CHECK VALYES (Continued)

Regenerative heat exchanger to RC loop 2A Containment service air utility station Long term recirculation loop 2

RC pump seal injection water to RCP 1A, 1B, 2A, 2B Steam generator 1 auxiliary feedwater Steam generator 2 auxiliary feedwater Long term recirculation loop 1 N. A.

N. A.

N.A.

N.A.

N.A.

N.A.

N. A.

PNot Type C tested.

P~gr.~ g Pcv'lg i,QPY PALO YEROE - UNIT 3 3/4 6-28

P

Pgggj g pqi)

TABLE 3. 6-1 (Continued)

'~> 00(-7 CONTAINMENT ISOLATION VALVES VALVE NUMBER PENETRATION NUMBER FUNCTION MAXIMUM ACTUATION

'IME (SECONDS)

SID-UV 654 26 SIB-UV 656 26 SIB-HV 699 26 SIC-UV 653 27 SIA-UV 655 27 SIA-HV 691 27 HCC-HV 076¹ 32A HPA-HV 007A 35 HPB-HV 008A 36 HPA"HY 007B 38 HPB-HV 008B 39 CHA-HV 524 41 HCA-HV 074¹ 54A HCB-HV 075¹ 55A HCD-HV 077¹ 62A SIO"HV 331 67 CHB-HV 255 72 SIC-HV 321 77 SGA-UV 134¹ 2

Containment pressure monitor CB pressure monitor Long-term. recirculation l oop 2

N.A.

N. A.

N. A.

RC pump seal injection water to RCP lA, 18 2A, 28 Long-term recirculation loop 1

Main steam to auxiliary feedwater N.A.

turbine G.

REQUIRED OPEN DURING ACCIDENT CONDITIONS From shutdown cooling RC loop 2

N.A.

From shutdown cooling RC loop 2 N.A.

From shutdown cooling RC loop 2

N.A.

From shutdown cooling RC loop 1 N.A.

From shutdown cooling RC loop 1 N.A.

From shutdown cooling RC loop 1 N.A.

Containment pressure monitor N.A.

Containment to hydrogen monitor NBA.

Containment to hydrogen monitor N.A.

Hydrogen monitor to containment N.A.

Hydrogen monitor to containment N.A.

Regenerative heat exchanger to RC loop'2A N. A.

Containment pressure monitor N. A.

¹Hot Type C tested.

PALO VERDE - UNIT 3 3/4 6-32 PROF R. R~VlF<7 0~

FEB 8 587

0'

3/4.7 Pl ANT SYSTEMS 3/4.7. 1 TURBINE CYCLE

)~00) g ppff~ +PE SAFETY VALVES LIMITING CONDITION FOR OPERATION

- 3.7.1.1 All main steam safety valves shall be OPERABLE with lift settings

. as specified in Table 3.7-1.

APPLICABILITY:

MODES 1, 2, 3, and 4*.

ACTION:

a.

b.

C.

with both reactor coolant loops and associated steam generators in operation and with, one or more"~ main steam safety valves inoperable per steam generator, operation in MODES 1, 2, ~an )P may proceed.

provided that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, either all the )noperable valves are restored to OPERABLE status or the Variable Overpower trip ceiling setpoint and the Maximum Allowable Steady State Power Level are reduced per Table 3.7-2; otherwise, be in at least HOT STANDBY with-in the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOMN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

t Operation in MODES 3 and 4* may proceed with~one reactor coolant loop and associated steam generator in operation, provided that there are no more than four inoperable main steam safety valves associated with the operating steam generator; otherwise, be in COLD SHUTDOMN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

The provisions of Specification 3.0.4 are not applicable.

SURVEILLANCE RE UIREMENTS 4.7.1.1 No additional Surveillance Requirements other than those required by Specification 4.0.5.

• Until the steam generators are no longer required for heat removal.

"*The maximum number of inoperable safety valves on any operating steam generator is four (4);

PROOr

5. t',~c:;~" ~>"..

PALO VERDE - UNIT 3 3/4 7-1 FEB 3~

l

PLANT SYSTEMS CONDENSATE STORAGE TANK PROOF R RBIBV COPY LIMITING CONDITION FOR OPERATION 3.7. 1.3 The condensate storage tank (CST) shall be OPERABLE with a level of at least 23 feet (300,000 gallons).

R6 APPLICABILITY:

HODES l, 2, 3,¹ and 4~¹.

ACTION:

With the condensate storage tank inoperable, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either:

a.

Restore the CST,to OPERABLE status or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, or msgr '-'~%

b.

Demonstrate the OPERAB~I~Tof the reactor makeup water tank as a

backup supply to the>auxiliary feedwater pumps and restore the condensate storage tank to OPERABLE status within 7 days or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN with a OPERABLE shutdown cooling loop in operation within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE RE UIREMENTS 4.7. 1.3. 1 The condensate storage tank shall be demonstrated OPERABLE at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> by verifying the level (contained water volume) is within its limits when the tank is the supply source for the auxiliary feedwater pumps.

4.7. 1.3.2 The reactor makeup water tank shall be demonstrated OPERABLE at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> whenever the reactor makeup water tank is the supply source for the~auxiliary feedwater pumps by veri fying:

Sac.v,k a.

That the reactor makeup water tank supply line to the auxiliary feed ~~/~

system isolation valve is open, and

b. 'hat the reactor makeup water tank contains a water level of at least 26 feet (300,000 gallons).

"Until the steam generators are no longer required for heat removed.

Not applicable when cooldown is in progress.

FEB 3 1987 PALO VERDE " UNIT 3 3/4, 7"6 PROOF 5 RF'lBV COFY

• I

PLANT SYSTEMS ATMOSPHERE DUMP VALVES LIMITING CONDITION FOR OPERATION 3.7,1.6 The atmospheric dump valves shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4~

ACTION:

Mith less than one atmospheric dump valve per steam generator OPERABLE, restore the required atmospheric dump valve to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />; or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

SURVEILLANCE RE UIREMENTS 4.7. 1.6 Each atmospheric dump valve shall be demonstrated OPERABLE:

a.

At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by verifying that the nitrogen accumulator tank is at a pressure

> 400 psig.

b.

Prior to startup following any refueling shutdown or cold shutdown of 30 days or longer, verify that all valves will open and close fully.

"When steam generators are being used for decay heat removal.

3 1987 PALO VERDE " UNIT 3 3/4.7-10

l

Pl ANT SYSTEMS PROOF 8 REV)BY COP 3/4.7 '

SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.9 All hydraulic and mechanical snubbers shall be OPERABLE.

The only snubbers excluded from this requirement are those installed on nonsafety-related systems and then only if their failure or fai lure of the system on which they are installed, would have no adverse effect on any safety-related system.

APPLICABILITY:

MODES 1, 2, 3, and 4.

MODES 5 and 6 for snubbers located on systems requ)red OPERABLE in those MODES.

ACTION:

With one or more snubbers inoperable on any system, within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> replace or restore the inoperable snubber(s) to OPERABLE status and perform an engineering evaluation per Specification 4.7.9g; on the attached component or declare the attached system inoperable and follow the appropriate ACTION statement for that system.

SURVEILLANCE RE UIREMENTS 4.7.9 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program and the requirements of Specification 4.0.5.

T As used in this specification, type of snubber shall mean snubbers of the same design and manufacturer, irrespective of capacity.

b.

Visual Ins ections Snubbers are categorized as inaccessible or accessible during reactor operation.

Each of these groups (inaccessible and accessible) may be inspected independently according to the schedule below.

The first inservice visual inspection of each type of snubber shall be performed after 4 months but within 10 months of commencing POWER OPERATION and shall include all hydraulic and mechanical snubbers.

If all snubbers of each type are found OPERABLE during the first inservice visual inspection, the second inser vice visual inspection of that type shall be performed at the first refueling outage.

Otherwise, subsequent visual inspections of a given type shall be performed in accordance with the following schedule:

PROQF R RP/IBV COPV PALO VERDE " UNIT 3 3/4 7-21 FEB 3 19B?

I f

)f

PLANT SYSTEMS r+~OQpp g pQp) pp) gpss)pr SURVEILLANCE RE UIREMENTS (Continued)

No. of Inoperable Snubbers of Each Type er Ins ection Period 0

1 2

3,4 5,6,7 8 or more c.

Visual Ins ection Acce tance Criteria Subsequent Visual Ins ection Period*¹ 18 months

+ 25K 12 months

+ 25K 6 months

+ 25K 124 days

+ 25K 62 days

+ 25K 31 days

+ 25K Visual inspections shall verify that:

(1) there are no visible indica-tions of damage or impaired OPERABILITY and (2) attachments to the foundation or supporting structure are secure, and (3) fasteners for attachment of the snubber to the component and to the snubber anchorage are secure.

Snubbers which appear inoperable as a result of visual inspections may be determined OPERABLE for the purpose of establishing the next visual inspection interval, provided that:

(1) the cause-of the rejection is clearly established and remedied for that particular snubber and for other snubbers irrespective of type on that system that may be generically suspedtible; and (2) the affected snubber is functionally tested in the as-found condition and determined OPERABLE per Specifications 4.7.9f.

Mhen a fluid port of a hydraulic snubber is found to be uncovered, the snubber shall be declared inoperable and cannot be determined OPERABLE via functional testing unless the test is started with the piston in the as-found setting, extending the piston rod in the tension mode direction.

Snubbers which appear in-operable during an area post maintenance inspection, area walkdown, or Transient Event Inspection shall not be considered inoperable for the purpose of establishing the Subsequent Visual Inspection Period provided that the cause of the inoperability is clearly established and remedied for that particular snubber and for the other snubbers, irrespective of type, that may be generally susceptible.

d.

Transient Event Ins ection An inspection shall be performed of all hydraulic and mechanical snubbers attached to secti ons of systems that have experienced unexpected, potentially damaging transients as determined from a review of operational data.

A visual inspection of the systems shall be made within 6 months following such an event.

In addition

~The inspection interval for each type of snubber on a given system shall not be lengthened more than one step at a time unless.

a generic p'roblem has been identified and corrected; in that event the inspection interval may be lengthened one step the first time and two steps thereafter if no inoperable snubbers of that type are found on that system.

¹The provisions-of Specification 4.0.2 are not applicable.

FEB 3 39BT

-PALO VERDE - UNIT 3

)

TABLE 4. 11-2 Continued TABLE NOTATION The LLD is the smallest concentration of radioactive material in a sample that will yield a net count above background that will be detected with 95~ probat:i lity with 5~ probability of falsely concluding that a blank observation represents a "real" signal.

For a particular measurement system (which may include radiochemical separation):

4.66 sb LLD =

E

~

V

~ 2.22 x 10

~

Y. exp (-Mt)

Mhere:

LLD is the "a priori" lower limit of detection as defined above (as pCi per unit mass or volume).

Current literature defines the LLD as the detection capability for the instrumentation only and the MDC minimum detectable concentration, as the detection capability for a given instrument procedure and type of sample.

s is the standard deviation of the background counting rate or of the c5unting rate of a blank sample as appropriate (as counts per minute),

E is the counting efficiency (as counts per transformation),

V is the sample size (in units of mass or volume),

2.22 is the number of transformations per minute per picocurie, Y is the fractional radiochemical yield (when applicable),

A. is the radioactive decay constant for the particular radionuclide, and ht is the elapsed time between the midpoint of sample collection and time of counting (for plant effluents, not environmental samples).

The value of s used in the calculation of the LLD for a detection system shall b) based on the actual observed variance of the background counting rate or of the counting rate of the blank samples (as appropriate) rather than on an unverified theoretically predicted variance.

In calculating the LLD for a radionuclide determined by gamma-ray spectrometry the background should include the typical contributions of other radionuclides normally present in the samples.

Typical values of E, V, Y, and iht should be used in the calculation.

It should be recognized that the LLD is defined as an a priori (before the fact) limit representing the capability of a measurement system and not as an a posteriori (after the fact) limit for a particular measurement".

For a more complete discussion of the LLD, and other detection limits, see the following:

(1)

,HASL Procedures

Manual, HASL-300 (revised annually).

(2)

Currie, L. A., "Limits for qualitative Detection and quantitative

'etermination - Application to Radiochemistry" Anal.

Chem.

40, 586-93 (1968).

(3)

Hartwell, J. K., "Detection Limits for Radioisotopic Counting Techniques,"

Atlantic Richfield Hanford Company Report~ ARH-2537 (June 22, 1972).

~ones R,.RENHN COP'J PALO VERDE " UNIT 3 3/4 11-9

a n

~ 4.4 REACTOR COOLANT SYSTEH BASES ppgo~ a am~vA~ coPY 3/4.4. 1 REACTOR COOLANT LOOPS AND COOLANT CIRCULATION The plant is designed to operate with both reactor coolant loops and associated reactor coolant pumps in operation, and maintain DNBR above 1.231 during all normal operations and anticipated transients.

In HODES 1 and 2

with one reactor coolant loop not in operation, this specification requires that the plant be in at least HOT STANDBY within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

In HODE 3, a single reactor coolant loop provides sufficient heat removal capability for removing decay heat; however, single failure considerations require that two loops be OPERABLE.

In HODE 4, and in HODE 5 with reactor coolant loops filled, a single reactor coolant loop or shutdown cooling loop provides sufficient heat removal capability for removing decay heat; but single failure considerations require that at least two loops (either shutdown cooling or RCS) be OPERABLE.

Thus, if the reactor coolant loops are not OPERABLE, this specification requires that two shutdown cooling loops be OPERABLE.

In HODE 5 with reactor coolant loops not filled, a single shutdown cooling loop provides sufficient heat removal capability for removing decay heat; but single failure considerations, and the unavailability of the steam generators as a heat:removing component, require that at least two shutdown cooling loops be OPERABLE.

The operation of one reactor coolant pump or one shutdown cooling pump provides adequate flow to ensure mixing, prevent stratification, and produce gradual reactivity changes during boron concentration reductions in the Reactor Coolant System.

A flow rate of at least 4000 gpm will circulate one equivalent Reactor Coolant System volume of 12,097 cubic feet in approximately 23 minutes.

The reactivity change rate associated with boron reductions will, therefore, be within the capability of operator recognition and control.

The restrictions on starting a reactor coolant pump in MODES 4 and 5, with one or more RCS cold, legs less tha'n or equal to 255'F during cooldown or 295'F during heatup are provided to prevent RCS pressure transients, caused by energy additions from the secondary

system, which could exceed the limits of Appendix G

to 10 CFR Part 50.

The RCS will be protected against overpressure transients and will not exceed the limits of Appendix G by restricting starting of the RCPs to when the secondary water temperature of each steam generator is less than 100'F above each of the RCS cold leg temperatures.

3/4.4.2 SAFETY VALVES The pressurizer code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2750 psia.

Each safety valve is designed to relieve a minimum of 460,000 lb per hour of saturated steam at the'alve setpoint:

. The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown.

In the event that no safety valves are

OPERABLE, an operating shutdown cooling loop, connected to the RCS, provides overpressure relief capability and will prevent RCS overpressurization.

PALO VERDE - UNIT 3 r~<o~ a. ~z~~vv c~t s B 3/4 4-1 FEB 3 1S87

I

REACTOR COOLANT SYSTEM BASES PRGGir LQ"g($ ~~p'f!

PRESSURElTEMPERATURE LIMITS (Continued) upon the fluence and residual element content, can be predicted using Figure B 3l4.4-1 and the recommendations of Regulatory Guide 1.99, Revision 1, "Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel

., Materials."

The heatup and cooldown limit curve Figure 3.4-2 includes pre-

'icted adjustments for this shift in RTNDT at the end of the applicable service

..period, as well as adjustments for possible errors in the pressure and "temperature sensing instruments.

The actual shift in RTNDT of the vessel material will be established periodically during operation by removing and evaluating, in accordance with ASTM E185-73 and Appendix H of 10 CFR 50, reactor vessel material irradiation surveillance specimens installed near the inside wall of the reactor vessel in the core area.

Since the neutron spectra at the irradiation samples and vessel inside radius are essentially identical, the measured transition shrift for a sample can be applied with confidence to the adjacent section of the reactor vessel.

The heatup and cooldown curves must be recalculated when the delta RTNDT determined from the surveillance capsule is different from the calculated delta RT DT for the equivalent capsule radiation exposure.

The pressure-temperature limit lines shown on Figure 3.4-2 for reactor

.criticality and for inservice leak and hydrostatic testing have been provided to assure compliance with the minimum temperature requirements of Appendix G

to 10 CFR Part 50.

The reactor vessel material irradiation surveillance specimens are removed and examined to determine changes in material properties.

The results of these examinations shall be used to update Figure 3.4-2 based on the greater of the following:

(1) the actual shift in reference temperature for plate F-6411-2 and weld 101-142 as determined by impact testing, or (2) the predicted shift in reference temperature for the limiting weld and plate as determined by RG 1.99, "Effects of Residual Elements on Predicted Radiation Damage to Reactor Vessel Materials."

The maximum RT for all Reactor Coolant System pressure-retaining materials has been determined to be 40'F.

The Lowest Service Temperature limit is based upon this RTNDT since Article NB-2332 (Summer Addenda of 1972) of Sec-tion III of the ASHE Boiler and Pressure Vessel Code requires the Lowest Service Temperature to be RTNDT + 100 F for piping, pumps, and valves.

Below this tem-

perature, the system pressure must be limited to a maximum of 20K of the system's hydrostatic test pressure of 3125 psia.

However, based upon the 10 CFR Part 50 Appendix G analysis, the isothermal condition for the reactor vessel is more restrictive than the Lowest Service Temperature line.

Therefore, only the isothermal line is shown on Figure 3.4-2.

The number of reactor vessel irradiation surveillance specimens and the A,

frequencies for removing and testing these.specimens are provided in Table 4.4-5 to assure compliance with the requirements'f Appendix H to 10 CFR Part 50.

PALO VERDE - UNIT 3

e s

RADIOACTIVE EFFLUENTS BASE'S

\\ c.~ wi~'

the methodology provided in Regulatory Guide 1.109, "Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I," Revision 1, October 1977'nd Regulatory Guide 1.113, "Estimating Aquatic Dispersion of Effluents from Accidental and Routine Reactor Releases for the Purpose of Implementing Appendix I," April 1977.

This specification applies to the release of liquid effluents from each reactor at the site.

For units with shared radwaste treatment

systems, the liquid effluents from the shared system are proportioned among the units sharing that system.

3/4. 11. 1.3 LI UID HOLDUP TANKS The tanks referred to in this specification include all those outdoor radwaste tanks that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the liquid radwaste treatment system.

Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tanks'ontents, the resulting concentrations would be less than the limits of 10 CFR Part 20, Appendix B, Table II, Column 2, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.

The limit of 60 curies is based on the analyses given in Section 2.4 of the PVNGS FSAR and on the amount of soluble (not gaseous) radioactivity in the Refueling Mater Tank in Table 2.4-26.

3/4. 11.2 GASEOUS EFFLUENTS 3/4.11.2.1 DOSE RATE This specification is provided to ensure that the dose at any time at and beyond the SITE BOUNDARY from gaseous effluents from all units on the site will be within the annual dose limits of 10 CFR Part 20 to UNRESTRICTED AREAS.

The annual dose limits are the doses associated with the concentrations of, 10 CFR Part 20, Appendix 8, Table II, Column 1.

These limits provide reasonable assurance that radioactive material discharged in gaseous effluents will not result in the exposure of a MEMBER OF THE PUBLIC in an UNRESTRICTED AREA, either within or outside the SITE BOUNDARY, to annual average concentrations exceeding the limits specified in Appendix 8, Table II of 10 CFR Part 20 (10 CFR Part 20. 106(b)).

For MEMBERS OF THE PUBLIC who may at times be within the SITE BOUNDARY, the occupancy of that MEMBER OF THE PUBLIC will usually be sufficiently low to compensate for any increase in the atmospheric diffusion factor above that for the SITE BOUNDARY.

Examples of calculations for such MEMBERS OF THE PUBLIC, with the appropriate occupancy factors, shall be given in the ODCM.

The specified release rate limits restrict, at all times, the corresponding gamma and beta dose rates above background to a MEMBER OF THE PUBLIC at or beyond the SITE BOUNDARY to less than or equal to 500 mrems/year PALO VERDE - UNIT 3 B 3/4 11-2 ppQQa QR-><t-V' Ft~

3 19

~

I

5.0 DESIGN FEATURES

5. 1 SITE PRQGF 5 RB~D CGA SITE AND EXCLUSION BOUNDARIES 5.1.1 The site and exclusion boundaries shall be as shown in Figure 5.1-1.

LOW POPULATION ZONE

5. 1.2 The low population zone shall be as shown in Figure 5.1-2.

GASEOUS RELEASE POINTS

5. 1.3 The gaseous release points shall be as shown in Figure 5. 1-3.

5. 2 CONTAINMENT CONFIGURATION 5.2. 1 The reactor containment building is a steel lined, prestressed concrete building of cylindrical shape, with a dome roof and having the following design features:

a.

Nominal inside diameter

= 146 feet.

b.

Nominal inside height = 206.5 feet.

c.

Minimum thickness of concrete walls = 3 feet, 8 inches.

d.

Minimum thickness of concrete roof = 3 feet, 8 inches.

e.

Minimum thickness o

concrete floor pad = 10.5 feet.

f.

Nominal thickness; Qf steel liner = 0.25 inch.

g.

Net free volume = 2,6 x 10s cubic feet.

)o DESIGN PRESSURE AND TEMPERATURE 5.2.2 The reactor containment building is designed and shall be maintained for a maximum internal pressure of 60 psig and a temperature of 300~F.

PALO VERDE - UNIT 3 5-1

~

~

II I'

~

e ss s

s

~

IsROOF K RFI1.'."". ".1 DESIGN FEATURES 5

3 REACTOR CORE FUEL ASSEMBLIES 5.3. 1 The reactor core shall contain 241 fuel assemblies with each fuel assembly containing 236 fuel rods or burnable poison'rods clad with Zircaloy-4.

Each fuel rod shall have a nominal active fuel length of 150 inches and contain a maximum total weight of approximately 1950 grams uranium.

Each burnable poison rod shall have a nominal active poison length of 136 inches.

The initial core loading shall have a maximum enrichment of 3.35 weight percent U-235.

Reload fuel shall be similar in physical design to the initial core loading and shall have a maximum enrichment of 4 weight percent U-235.

CONTROL ELEMENT ASSEMBLIES 5.3.2 The reactor core shall contain 76 full-length and 13 part-length control element assemblies.

5 4 REACTOR COOLANT SYSTEM DESIGN PRESSURE AND TEMPERATURE 5.4.1 The Reactor Coolant System is designed and shall be maintained:

a.

In accordance with the code requirements specified in Section 5.2 of the FSAR with allowance for normal degradation pursuant ef the applicable surveillance requirements, b.

For a pressure of 2500 psia, and c.

For a temperature of 650'F, except for the pressurizer which is 700oF VOLUlllE 5.4.2 The total water and steam volume of the Reactor Co)ts ant System is 13,900

+ 300/-0 cubic feet at a nominal-T of 593'F.

avg PALO VERDE - UNIT 3 5"5

h

~

~

s

DESIGN FEATURES

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5. 5 HETEOROLOGICAL TOMER LOCATION 5.5. 1 The meteorological tower shall be located as shown on Figure 5, -1.

5.6 FUEL STORAGE

5. 6. 1 CRITICALITY 5.6. 1. 1 The spent fuel storage racks are designed and shall be maintained with:

a.

A k f equivalent to less than or equal to 0.95 when flooded with unbar/ted water, which includes a conservative allowance of 2.6X delta k/k for uncertainties as described in Section

9. 1 of the FSAR.

b.

A nominal 9.5 inch center-to-center distance between fuel assemblies placed in the storage racks in a high density configuration.

5.6. 1.2 The k for new fuel for the first core loading stored dry in the eff spent fuel storage racks shall not exceed 0.98 when aqueous foam moderation is assumed.

DRAINAGE 5.6.2 The 'spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 137 feet - 6 inches.

CAPACITY 5.6.3 The spent fuel storage pool is designed arid shall be maintained with a storage capacity limited to no more than 1329 fuel assemblies.

5 7 COHPONENT CYCLIC OR TRANSIENT LIHITS

.5.7. 1 The components identified in Table 5.7-1 are designed and shall be maintained within the cyclic or transient limits of Tables 5.7-1 and 5.7-2.

PALO VERDE - UNIT 3 5-6

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ED TABLE 5.7-2 PRESSURIZER SPRAY NOZZLE USAGE FACTOR Main Spray Auxiliary Spray 4J 201-250 251-300 301-350 351-400 401-450 451-500 501-550 7900 4500 2900 1900 1200 850 555 X H/NA =

N/HA 201-250 251-300 301-350 351-400 401-450 451;.500

~601-600--

Soi-BM NA 50000 2200 1300 850 550 375

-150-3 2,'h (SQ X N/NA Ql I

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Cumulative Usage Factor X. N/NA (Hain Spray}

X H/NA (Aux. Spray)

Total

= Cumulative Usage Factor

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PVNGS PLAttT MAtiAGER m

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OUTAGE MAWAGEMENT MANAGER 7ECNtilCAL SUPPORT MANAGER OPERATIONS MAttAGER MAIttTENANCE MANAGER PLANT SERVICES MAHAGER MANAGER COMPL IAtiCE MANAGER OPS EtiGINEFRlttG SUPERINTEHOEHT UNIT I SUPERINTENOENT IXC MAINTENANCE MANAGER OPERATIONS SECURITY 0

r~I SUPERVISOR STA SUPERIHTENOEHT UNIT 2 SUPERIHTENOENT MCC SUPERVISOR FIRE PROTECTION MANAGER RAO. PROT.

1 CIIEM.

SUPERINTEHOEHT UNIT 3 SUPERINTENOENT ELEC. MAINTEHANCE SUPERIHTEHOENT OPS COMPUTER SYSTEM SUPERVISOR OPERATIONS SUPPORT SUPERINTEtiOENT STATIOtt SERVICES 8

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n P'<t SUPERlttTEHOENT MECHANICAL MAINTENANCE FIGURE 6. 2-2 OHSITE ORGANIZATIOH

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