ML20247B863

Rev 0 to Technical Requirements Manual

ML20247B863
Person / Time
Site:	Comanche Peak
Issue date:	07/21/1989
From:	TEXAS UTILITIES ELECTRIC CO. (TU ELECTRIC)
To:
Shared Package
ML20247B849	List: ML20247B843 ML20247B863
References
PROC-890721, NUDOCS 8907240228
Download: ML20247B863 (82)

Text

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1 CPSES TECHNICAL REQUIREMENTS MANUAL E

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COMANCHE PEAK - UNIT 1 July 21, 1989 8907240~228 DR ADOCK 890721 05000443 PDC

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l TECHNIChlREQUIREMENTSMANUAL-INDEX

. TECHNICAL REQUIREMENT NUMBER ~ _

SYSTEM / TITLE '. . REVISION ( ')

(Related Tech Spec .if required)

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~1.0- Administrative Controls. 0 --

1.1-(3/4.3.1) Reactor Trip. Response Time-. OL 1.2 (3/4.3.2) ESF Actuation Response Time 0 1.3 ' Moveable':Incore Detection 0 System ]j 1.4 Seismic' Instruments 'O ,

1.5 . Loose Parts Detection Sy; tem .O' 2.1 (3/4.6.3) Containment: Isolation Valves, 0: .

3.1 (3/4.7.9) 'Srubbers 0-l 3.2 Station Service Water System 0 4.1 (3/4.8.4) Containment Penetration 0 Conductor Overcurrent -

Protection DevicesL l

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l COMANCHE PEAK-STEAM ELECTRIC STATION TECHNICAL.REQUIREMENTSMANUAL(TRM)l-Description.of the Administrative' Control Process ' .;

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TECHNICAL REQUIREMENTS MANUAL (TRM)

Description of the Administrative Control Process INTRODUCTION CPSES has elected to' relocate certain.information from the Technical-Specifications-to a separate controlled dccument based on the NUMARC Technical Specification Improvement Program, the Westinghouse _ Owners Group MERITS Program, and the Commissions Interim Policy Statement for improvement of Techcical specifications for nuclear power plants (52 FR 3788 of February 6, 1987). 'This information'is now contained in a-separate document to be called the CPSES Technical Requirements Manual-(TPM). The following.is a description of the administrative program for control, distribution, updating, and amending the information contained in the TRM.

DOCUMENT ~ CONTROL The TRM is considered a licensing basis document and as such, overall control of the document will be addresseo by the c6rporate level procedures (Nuclear Engineering and Operations - NE0 procedures) for licensing document control.

(O q) , DOCUMENT DISTRIBUTION The TRM is considered a controlled document and distribution will be controlled by the Nuclear Licensing Department. Licent.ing will specify (by copy number) the proper distribution for the TRM..

Distribution is anticipated to be to at least those personnel / locations which receive the CPSES Technical Specifications as well as any other groups which need access to the information contained in the TRM.

.cfjANGES/ DELETIONS TO THE TRM Changes to the TRM will be controlled by the NEC procedure on licensing document change control. This procedure will address the administrative requirements necessary to change / amend CPSES licensing t documents (e.g., FSAR, QA Plan, etc.). For changes to the TRM, the procedure will require initiation of a Licensing Document Change Request (LDCR). The LDCR is the mechanism whereby changes.are tracked to ensure that appropriate reviews, approvals, and signatures are obtained. All TRM changes will be screened to determine if an unreviewed safety question (per 10CRF50.59(a)(2)) could be involved and if so, a Safety Evaluation will be performed. All TRM changes will require a review by SORC and the approval of the Vice President, Nt. clear Operations.

O COMANCHE PEAK - UNIT 1 0-1 July 21, 1989

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PLANT CHANGES THAT MAY EFFECT THE TRM p

(~') Many changes that will be made at CPSES have the potential to effect' (or be effected by) the TRM. These include items such as design modifications, procedure changes, SAR changes, etc. The TRM has been ioentified as a CPSES licensing basis document'.by the 10CFR50.59 Program. The 10CFR50.59 Program is currently in the developmental process and is being established based on the latest NUMARC Guidelines for 50.59. As currently outlined, this program requires that the TRM be considered in a manner similar to the FSAR when screening changes l to determine if an unreviewed safety question might be involved. The final-10CRF50.59 program description will be available later for NRC review.

DISTRIBUTION OF TRM CHANGES / DELETIONS Changes to che TRM will be issued on a replacement page basis to controlled document holders promptly following approval of the. change.

REPORT OF TRM CHANGES / DELETIONS TO THE NRC Changes to the TRM w*ll be reported to the NRC annually as part of the SAR update. related safety evaluations will be reported as part of the 50.59 annual report.

Proposed TRM changes that are determined to constitute an unreviewed safety question (as defined by 10CFR50.59(a)(2)) will either not be i

73 ' made or will be submitted to the NRC for prior review and approval.

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TECHNICAL REQUIREMENT 1.1 REACTOR TRIP RESPONSE TIME e NOTE: This Technical Requirement contains the Reactor Trip Response Time . Table. Although the CPSES Technical Specification is repeated here, in part, care must be taken net to overlook Technical Specification requirements.

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> 1 3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION-LIMITING CONDITibn FOR OPERATION- ._

1 3.3.1 As a minimum, the Reactor Trip System. instrumentation channels-and interlocks of Table 3.3-l'shall be OPERABLE. -

ti APPLICABILITY: As shown in' Table 3,3-1. -

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As shown in Table 3.3-1.  ;

i SURVEllt ANCE REQUIREMENTS j 1

. .. . . . i 4.3.1.1 Each Reactor Trip System Instrumentation channel and '1 interlock and the automatic trip logic shall be demonstrated OPERABLE i by the performance of the Reactor Trip System Instrumentation '

Surveillance Requirements specified in Table 4.3-1.

4.3.1.2 The REACTOR TRIP SYSTEM RESPONSE TIME of each Reactor trip d function shall be demonstrated to be within'its limit at least once' '

i per 18 months. Each test shall include at least one train such that '

( both trains are tested at least once per 36 months and one channel per function such that all channels are tested at'least once every N times 18 months where N is the total number of redundant channels in ~a. -1 specific Reactor trip function as shown in the " Total No. of Channels" 1

column of Table 3.3-1. 1 i

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i TECHNICAL RE0VIREMENT 1.1

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V Table 1.1.1 j

REACT 0P TRIP SYSTEM INSTRUMENTATION RESPONSE TIMES FUNCTIONAL UNIT RESPONSE TIME

1. Manual Reactor Trip N.A.

2. Power Range, Neutron Flux s 0.5 second*

3. Power Range, Neutron Flux High Negative Rate N.A.

4. Power Range, Neutron Flux High Negative Rate 1 0.5 second*

5. Intermediate Range, Neutron Flux N.A.

6. Source Range, Neutron Flux s 0.5 second*

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7. Overtemperature N-16 s 7 seconds *# l l

8. Overpower N-16 s 7 seconds *# l

9. Pressurizer Pressure-Low s 2 seconds

10. Pressurizer Pressure-High

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s 2 seconds ,

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11. Pressurizer Water Level-High N.A.

• Neutron / gamma detectors are exempt from response time testing.

Response time of the neutron / gamma flux signal portion of the channel shall be measured from detector output or input of first electronic component in a channel.

1. Response time includes the thermal well response time.

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COMANCHE PEAK - UNIT 1 1-3 July 21, 1989 !

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TECHNICAL REQUIREMENT 1.1 (continued) j

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) Tabl e .1.1.1 REACTOR TRIP SYSTEM INSTRUMENTATION RESPONSE TIMES j I

FUNCTIONAL UNIT RESPONSE TIMI j

12. Reactor Coolant Flow-Low l

a. Single Loop (Above P-8) s I second j

b. Two Loops (Above P-7 and below P-8) s 1 second

13. Steam Generator Water Level--Low-Low s 2 seconds 4 l

14. Undervoltage - Reactor Coolant Pumps s 1.5 seconds l 1

15. Underfrequency - Reactor Coolant Pumps s 0.6 second

16. Turbine Trip

a. Low Fluid Oil Pressure N.A. l

b. Turbine Stop Valve Closure N.A. j 1

17. Safety Injection Input frcm ESF N.A.

18. Reactor Trip System Interlocks N.A.

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19. Reactor Trip Breakers N.A.

20. Automatic Trip and Interlock Logic N.A.

BASES )

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1.1 REACTOR TRIP SYSTEM RESf0NSE TIMES The bases for the Reactor Trip System are contained in the CPSES j Technical Specifications. The measurement of response time at the i specified frequencies provides assurance that the Reactor trip 4' actuation associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either: (1) in place, onsite, or offsite test measurements, or (2) utilizing replacement sensors with certified response time, r~'N b

COMANCHE PEAK - UNIT 1 1-4 July 21, 1989

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'1 TECHNICAL REQUIREMENT.1.2'.ESF ACTUATION SYSTEM RESPONSE TIME-A NOTE: This Technical Requirement containsthe ESF- Actuation System - d'.q Response Time Table. Although the.CPSES Technical .. ... , - .. yR Specification.is re)eated here cin:part, care must'be taken not to overlook _ Tec1nical Specificatic: requirements.

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INSTRUMENTATION

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(v ) 3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION LIMIT @G CONDITION FOR OPERATION 3.3.2 The Engineered Safety Features Actuation System (ESFAS) l instrumentation channels and interlocks shown in Table 3.3-2 shall be OPERABLE with their Trip Setpoints set consistent with the values shown in the Trip Setpoint column of. Table 3.3-3.

APPLICABILITY: As shown in Table 3.3-2 ACTJJLy:

a. With an E3FAS Instrumentation or Interlock Trip Setpoint trip less conservative than the value shown in the Trip Setpoint column but more conservative than the value shown in the Allowable Value column of. Table 3.3-3, adjust the Setpoint consistent with the Trip Setpoint value,

b. With an ESFAS Instrumentation or Interlock Trip Setpoint less conservative than the value shown in the Allowable Value column of Table 3.3-3, either: j

1. Adjust the Setpoint consistent with the Trip Setpoint value of Table 3.3-3 and determine within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that Equation 2.2-1 was satisfied for the affected channel, or (n]

2. Declcre the channel inoperable and apply the applicable ACTION statement requirements of Table 3.3-2 until the channel is restored to OPERABLE status with its E9tpoint adjusted consistent with the Trip Setpoint value.

Equation 2.2-1 Z + R + S 1 TA Where:

Z - The value from Column Z of Tab'le 3.3-3 for the affected channel, R - The "as measured" value (in percent span) of rack error for the affected channel, j

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INSTRUMENTATION

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.( ) ACTION (Continued 1 v

S - Either the "as measured" value (in percent span) of the sensor error, or the value from Column S (Sensor Error) of.

Table 3.3-3 for the affected channel, and TA - The value from Column TA' (Total Allowance) of Table 3.3-3 for the affected channel.

c. With ESFAS instrumentation channel or interlock inoperable, take the ACTION shown in Table 3.3-2.

SURVEILLANCE RE0VIREMENTS -

4.3.2.1 Each ESFAS instrumentation channel and interlock and the automatic actuatiot logic and relays shall be demonstrated OPERABLE by performance of the ESFAS Instrumentation Surveillance Requirements specified in Table 4.3-2.

4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESFAS function shall be demonstrated to be within the limit at least once per 18 months. Each test shall include at least one train such that both trains are tested at least once per 36 months and one channel per function such that all channels are tested at least once per N times

,- 18 months where N is the total number of redundant channels in a

(,~' specific ESFAS function as shown in the " Total No. of Channels" column  !

of Table 3.3-2. {

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i TECHNICAL RE0VIREMENT 1.2 7- s  ;

TABLE 1.2.1 '

() i ENGINEERED SAFETY FEATURES RESPONSE TIMES INITIATION SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS-l

1. Manual Initiation I

a. Safety Injection (ECCS) N.A. l l

b. Containment Spray'(Phase "B" l Isolation and Containment Vent )

Isolation) N.A.

c. Phase "A" Isolation (Containment d Vent Isolation) N.A. l

d. Steam Line Isolation N.A. 1

e. Feedwater Isolation (SI) N.A. )

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f. Auxiliary Feedwater (SI) N.A. I

g. Station Service Water (SI) N.A. q 1

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h. Component Cooling Water (SI) N.A. '

i. Control Room Emergency 3 Recirculation (SI) N.A. 1

j. Reactor Trip N.A 1

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k. Emergency Diesel Generator  !

Operation N.A. i

1. Essential Ventilation Systems (SI) N.A. i

m. Turbine Trip N.A.

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r TECHNICAL RE0VIREMENT-1.2-(continued) i TABLE ~1.2.1 ENGINEERED SAFETY FEATURES RESPONSE TIMEji INITIATION SIGNAL ~AND FUNCTION . RESPONSE TINE IN SECONDS-

2. Containment Pressure--High 'l

a. Safety Injection (ECCS) 527_(1,5a)/27(4,5b) b.- Reactor Trip. , $2:

.c. Feedwater-Isolation 16,5L

d. ' Phase "A" Isolation $17(2)/27(1)

e. Containment Ventilation Isolation : N. A.

f. Auxiliary Feedwater 5 60-

g. Station Service' Water N.A.

h. Component Cooling Water N.A.

i. Essential Ventilation Systems N.A.

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j. Emergency Diesel Generator 1 12.

Operation i

k. Turbine Trip 'N.A. 1

1. Control Room Emergenay Recirculation N.A.

m. Containment Spray Pump (7) 1 17/27 s l

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I TECHNICAL RE0VIREMENT 1.2 (continued)

) TABLE 1.2.1 ENGINEERED SAFETY FEATURES RESPONSE TIMEE INITIATION SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS I

3. Pressurizer Pressure--Low

a. Safety Injection (ECCS) I 27(1,5a)/27(4,5b)

b. Reactor Trip i2

c. Feedwater Isolation s7

d. Phase "A" Isolation s 17(2)/27(l)

e. Containment Ventilation Isolation s 5(6)

f. Auxiliary Feedwater s 60

g. Station Service Water N.A.

h. Component Cooling Water N.A.

1. Essential Ventilation Systems N.A.

(~h) j. Emergency Diesel Generator Operation i 12

k. Turbine Trip N.A.

1. Control Room Emergency )

Recirculation N.A. '

m. Containment Spray Pump (7) N.A.

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COMANCHE PEAK - UNIT 1 1-10 July 21, 1989

TECHNICAL RE0VIREMENT 1.2 (continuedl TABLE 1.2.1 f3)

ENGINEERED SAFETY FEATURES RESPONSE TIMES' INITIATION _ SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS

4. Steam Line Pressure--Low

a. Safety Injection (ECCS) 537(3,5b)/27(4,5b)

b. Reactor Trip 12

c. Feedwater Isolation s 6.5

d. Phase "A" Isolation 1 17(2)/27(1)

e. Containment Ventilation Isolation N.A.

f. Auxiliary Feedwater s 60

g. Station Service Water N.A.

h. Component Cooling Water N.A.

1. Essential Ventilation Systems N.A.

O j. Emergency Diese'l Generator Operation s 12 g 1

k. Turbine Trip N.A.

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1. Control Room Emergency Recirculation N.A. l

m. Containment Spray Pump (7) N.A.

n. Steam Line Isolation s 6.5 1

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V COMANCHE PEAK - UNIT 1 1-11 July 21,1989

TECHNICAL RE0VIREMENT 1.2 (continued)

. sO - TABLE 1.2.1-

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ENGINEERED SAFETY FEATURES RESPONSE TIMES. ' ,

INITIATION SIGNAL AND FUNCTI0f( RESPONSE TIME IN SECONDS' i

5. Containment Pressure--High-3

a. Containment Spray Pump N.A. 'l i

b. Phase "B" Isolation N.A.

c. Containment Spray Pump DischargeL -

-Valve .s 119 J

6. Containment Pressure--High-2 Steam Line Isolation I 6.5-

7. Steam Line Pressure -' Negative Rate-High-Steam Line Isolation s7

8. Steam Generator Water Level - High-High e a. Turbine Trip N.A.

b. Feedwater Isolation 5 11

9. Steam Generator Water Level - Low-Low

a. Motor-Drdven Auxiliary Feedwater Pumps 1 60

b. Turbine-Driven Auxiliary Feedwater Pump s 60

10. Loss-of-Offsite Power '

i Auxiliary Feedwater. N ..A .

11. Trip of All Main Feedwater Pumps All Auxiliary Feedwater Pumps N.A. l l

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TECHNICAL REQUIREMENT 1.2 fcontinued)

( TABLE 1.2.1 ENGINEERED SAFETY FEATURES RESPONSE TIMES INITIATION SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS'

12. RWST Level - Low-Low Coincident with Safety Injection Automatic Initiation of ECCS s 30 Switchover to Containment Sump

13. Loss of Power (6.9 KV and 480V Safeguards System Undervoltage)

a. 6.9 KV Preferred Offsite Source s 2(8)

Undervoltage

b. 6.9 KV Alternate Offsite Source 1 2(8)

Undervoltage

c. 6.9 KV Bus Undervoltage 1 2(8)

d. 6.9 KV and 480V Degraded Voltage with Safety Injection 5 10(8.9)

I without Safety Injection s 63(8.9)

e. 480 V Low Grid Undervoltage s 63(8,9)

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COMANCHE PEAK - UNIT 1 1-13 July 21, 1989

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J TECHNICAL REQUIREMENT 1.2 (continued.). j

( TABLE 1.2.1' j TABLE NOTATIONS i (1) Diesel generator starting and sequence loading delays included,

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'(2) Diesel generator starting delay n21 included. Offsite power available.

i (3) Diesel generator starting delay included. Only centrifugal 1 charging pumps are included. ~l (4) Diesel generator starting and sequence loading delays not '

included. Only centrifugal charging pumps are included.

(Sa) Sequential tratisfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is 'not-included.

(5b) Sequential transfer of charging pump suction from the VCT, to the RWST (RWST valves open, then VCT valves close) is included.

(6) Includes containment pressure relief line isolation only.

(7) Response Time Limit is up through pump breaker closure only.

Both times shown include sequencer loading delays and;the larger number also includes diesel generator starting delay.

(8) Response time measured to output of undervoltage channel'only.

(9) Two additional seconds allowable for alternate offsite sourcs breaker trip functions.

BASES 1.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM RESPONSE TIMES The bases for the Engineered Safety Features Actuation System are . 3 contained in the CPSES Technical Specifications. The measurement of response time at the specified frequencies provides assurance that the i Engineered Safety Features actuation associated with each channel-is  ;

completed within the time itmit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated  !

by any- series of sequential, overlapping, or total channel test--

measurements provided that such tests demonstrate the total channel' ,

response time as defined. Sensor response time verification may be '

demonstrated by either: (1) in place, onsite, or offsite test l c measurements, or (2) utilizing replacement sensors with certified 1 response time. j i

COMANCHE PEAX - UNIT 1 1-14 July 21, 1989 l

TECHNICAL RE0VIREVENT 1.3

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f ) MOVABLE INCORE DETECTORS O ,

I OPERABILITY CRITERJA 1.3 The Movable Incore Cetection System shall be OPERABLE with:

a. At least 75% of the detector thimbles,

b. A minimum of two detector thimbles per core quadrant, and j

c. Sufficient movable detectors,. drive, and readout equipment to map these thimbles.

AMLJ{AHi1TY: When the Movable Incore Detection System is used for:

a. Recalibration of the Excore Neutron Flux Detection System, or i

b. Monitoring the QUADRANT POWER TILT RATIO, or  !

c. MeasurementofFpH,F(Z)andFxy, Q

[Qt1HN_SJTORY MEASURES: )

l j With the Movable Incore Detection System Inoperable, do not use the {

systan for the above applicable monitoring or calibration functions. j IEE M EF&llQNS A

Q TRI.3 The Movable Incere Detection system shall be demonstrated OPERABLE within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to use by irradiating each #

required detector and determining the acceptability of its voltage curva when the system is required for: j

a. Reca11bration of the Excore Neutron Flux Detection System, or I

b. Mo:11toring the Q ADRANT POWER TILT RATIO, or  ;

c. Measurement of F H, FQ(Z) and Fxy.

B.ASES 13 MOVAEE INCORE DETECTORS The OPERABILITY of the movable incore detectors with the specified minimum complement of equipment ensures that the measurements obtained l from use of this system accurately represent the spatial neutron flux I distribution of the core. The OPERABILITY of this system is l demonstrated by irradiating each detector used and determining the I acceptability of its voltage curve.

For the purpose of measuring QF (Z) or F H a full incore flux map is used. Quarter-core flux maps, as de ined in WCAP-8648, June 1976, may be used in recalibration of the Excore Neutron Flux Detection System, and full incore flux maps or symmetric incore thimbles may be rm useo for monitoring the QUADRANT POWER TILT RATIO when one Power Range d chanr el is inoperable.

COMANCHE PEAK - UNIT 1 1-15 July 21,1989 L_________.__.__

l TECHNICAL _B1241REMENT 1.4 I SEISMIC INSTRUMENTATION .

l OPERABILITY CRITERIA j 1.4 The seismic monit'oring instrumentation shown in Table;1.4.1: shall be OPERABLE.

APPLICABILITY.Y: - At ' all' times. - :j 1

COMPENSATORY MEASURES:

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a. With one or more of the'above, required seismic monitoring j '

instruments inoperable for more thar. 30 days, prepare and.- .

submit a-Special Report to the Commission persuant to CPSES

i Technical Specification 6.9.2 within-the next 10 days J outlining the cause of the malfunction and the plans for restoring the instrument (s) to OPERABLE status. ' u TESTS / INSPECTIONS j

c_ . i TRI.4.1 Each of the above required seismic monitoring instruments shall be demonstrated OPERABLE by the performance of the. H CHANNEL CHECK, CHANNEL CALISP.ATION, and ANALOG CHANNEL -1 OPERATIONAL TEST at the frequencies shown in Table 1.4.2.

TRI.4.2 Each of the above required seismic monitoring instruments which is accessible during power operations and which is actuated during a seismic event greater than or equal to 0.01g shall be restored to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> q and a CHANNEL CALIBRATION performed within 15 days ,

following the seismic event.- Data shall=be retrieved from 'I actuated instruments and analyzed to determine the magnitude of the vibratory ground motion. A Special i Report shall be prepared and submitted to the Commission-pursuant to CPSES Technical $ specification 6.9.2 within 14 "

days describing the magnitude, frequency spectrum, and l resultant effect upon facility features important to l

safety.

TRI.4.3 Each of the above seismic monitoring instruments which is actuated during a seismic event greater than or equal to 0.01g but is not accessible during power operation shall 1 be restored to OPERABLE status and a CHANNEL CALIBRATION.

performed the next time the plant enters MODE 5 or below.-

A supplemental report shall then be prepared and submittedL j to the Commission within 14 days pursuant to CPSES j Technical Specification 6.9.2 describing the-additional  :

data from these instruments. 'l

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' TECHNICAL'RE0VIREMENT 1.4 (con.tff.ugdl

! .- TABLE 1.4.1 S.El.S_MIC MONITORING INSTRUMENTATJSR l

. MINIMUM-INSTRUMENTS INSTRUMENTS AND SENSOR' LOCATIONS OPERABLE

1. Triaxial . Time-History Accelerographs

-a. Accelerometer-Fuel Building l'

b. Accelerometer-Containment 1

c. Accelerometer-Electrical Manhole 1

d. Seismic Trigger-Fuel Building I

e. Recorder Unit,.SMA-3 1 f.. P1ayback Unit, SMP-1 . I'

2. Triaxial Peak Accelerographs

a. Pressur.izer Lifting-Trunion 1 C'\

C/ b. Reactor Coolani, Piping I

c. CCW Heat Exchanger 1

3. Triaxial Seismic Switch ,

I Fuel Building 1*

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4. Triaxial Response-Spectrum Recorders I

a. Fuel Building l'

b. Reactor Bldg. Internal Structure 1

c. Safeguards Building 1

5. Response Spectrum Annunciator '1*

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TECHNICAL RE0VIREMENT 1.4 (continue')? d

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~ TABLE 1.4.2 '

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SEISMIC-MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS ANALOG *.

CHANNEL' CHANNEL CHANNEL OPERATIONAL INSTRUMENTS AND SENSOR LOCATIONS: : CHECK CALIBRATION'  : TEST ~

1. Triaxial . Time-History

-Acc'lerograph's e

a. Accelerometer-Fuel- . .

Building .M R LSA

b. Accelerometer-Contain-ment' 'M RL 'SA.

c. Accelerometer-Elec- -

trical- Manhole ML .R :cSAi.

d. Seismic Trigger-Fuel Building.L M4 R SA

e. Recorder Unit,.SMA-3. -M- .R SA

f. Playback Unit, SMP-1 M R SAL

2. Triaxial Peak Accelerographs

a. Pressurizer Lifting Trunion N.A. R N.G.

b. Reactor Coolant Piping N.A. R- N.A.

c. CCW Heat Exchanger N.A. R 'N.A.

3'. Triaxial ' Seismic: Switch Fuel Building ** M R- SA'-

r 1 ,

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- *Setpoint verification is not applicable. j

- **With control room indication. j p . COMANCHE PEAK.- UNIT 1: 'l LJuly 21,:1989 1

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TECHNICAL RE0VIREMENT I.4 (continued)

C '; TABLE 1.4.2 l()

SEISMIC MONITORING INSTRUMENTATION SURVEILLANCE RE0UIREMENTS ANALOG

• CHANNEL CHANNEL CHANNEL OPERATIONAL INSTRUMENTS AND SENSOR LOCATIONS CHECK CALIBRATION TEST

4. Triaxial Response-Spectrum Recorders

a. Fuel Building N.A. R N.A.

b. Reactor Bldg. Internal 5tructure N.A. R N.A.

c. Safeguards Building N.A. R N.A.

5. Response Spectrum Annunciator ** M R SA

[

LJ

• Setpoint verification is not applicable.

/

f.s **With control room indication.

T (J i COMANCHE PEAK - UNIT 1 1-19 July 21, 1989

BASES k--)s 1.4 SEISMIC INSTRUMENTATION The OPERABILITY'of the seismic instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event and evaluate the response of those features important to safety. This capability is required to permit comparison of the measured response to that used in the design basis for the facility to determine if plant shutdown is required pursuant to Appendix A of 10CFRIOO. The instrumentation is consistent with the recommendations-of Regulatory Guide 1.12, " Instrumentation for Earthquakes," April 1974.

i

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f COMANCHE PEAK - UNIT I 1-20 July 21, 1989

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J :;

TECHNICAL- RE0' VIREMENT ~1.5 ,

LOOSE;PART DETECTION SYSTEM

-OPERABILITY CRITERIA-1.5 The Loose-Part Detection System shall.be OPERABLE.

APPLICABILITY: 'N0 DES I and 2.-

COMPENSATORY ~ MEASURES:

a. With one or mox Loose-Part Detecti6n System channels . .

inoperable for,more than 30 days, prepare a.ndl submit a Special Reporttto the. commission pursuant to CPSES Technical Specification 6.9.2 within.the next 10! days outlining the' '

cause of the-malfunction and'the plans for: restoring the i channel (s) to OPERABLE' status.

TESTS / INSPECTIONS TRI.5

~

Each channel .of the Loose-Part' Detection Systems shall be demonstrated OPERABLE'by performance of:-

a. A CHANNEL CHECK at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,.

b. An ANALOG CHANNEL OPERATIONAL TEST *atileast once per '31 J

days, and

c. 'A CHANNEL CALIBRATION at-least once per-18 months.

• Setpoint verification is not applicable.

BASES 1.5 LOOSE PARTS DETECTION SYSTEM.

The OPERABILITY of.the Loose-Part Detection System ensures that.

sufficient capoility is avai?able to detect loose metallic parts in

~

the' Reactor System and avoid or mitigate damage to Reactor System components. .The allowable out-of-service times and surveillance' requirements are consistent with the recommendations of Regulatory Guide.l.133, " Loose-Part Detection Program for.the Primary System of Light-Water-Cooled Reactors," May 1981.

i COMANCHE PEAK - UNIT 1 1-21 July 21, 1989

': TECHNICAL REQUIREMENT 2.1 OPERATIONAL' LEAKAGE . ,.

D NOTE: This Technical Requirement ~ contains the Operational- Leakage.

Technical Specification. -'Although the;CPSES Technicali Specification:is repeated.here,.inpart, care must be takennot'-

to overlook Technical Specification Requirements j

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COMANCHE PEAK.- UNIT 1 1-22 July.21,:1989'  ;

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- _ _ _______-__:-___a

M 1 i J '

TECHNICAL. REQUIREMENTS 2.1. CONTAINMENT ISOLATION VALVES . 1 NOTE: This Technical: Requirement contains the listing of Containment '

Isolation Valves, and.their respective, testing requirements, t which are; subject to CPSES Technical Specification 3.6.3. j

.Although the Technical Specification is repeated here, careL L,

-must be taken not to overlook Tech;' cal Specification. -

requirements. '{

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. O u COMANCHE PEAK-- UNIT 1 2-1 July 21,1989' l j

i

CONTAINMENT SYSTEMS

.?

j -

3/4.6.3 CONTAINMENT ISOLATION VALVES LIMITING CO NDITION FOR OPERATION 3.6.3 The ' containment isolation valves shall be OPERABLE.#

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

• With one or more of the containment' isolation valve (s) inopcrable, maintain at-least one isolation valve OPERABLE. in each affected penetration that is op'en and:

a. Restore the inoperable' valve (s) to 0PERABLE status within' 4 i hours, or

b. Isolate each affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one deactivated automatic valve secured in the isolation '

position, or

c. Isolate sach affected penetration within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by use of at least one closm manual valve or blind flange, or

d. Be in at leart 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 COLD (A) SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

SURVEILLANCE RE0VIREMENTS 4.6.3.1 The containment isolation valves shall be demonstrated OPERABLE prior to returning the valve to service'after maintenance, repair or replacement work is performed on the valve or its associated actuator, control or power circuit by performance of a cycling test, and verification of isolation time.

1. - The requirements of specification 3.6.3 do not apply for those l valves covered by Specifications 3.7.1.1, 3.7.1.5, and.3.7.1.6.

• CAllTION: The inoperable isolation valve (s) may be part of.'a system Isolating the affected penetration (s) may affect;the l useof(s).

the system (s). . Consider the technical specification requirements on the affected system (s) and 'act accordingly.

COMANCHE PEAK - UNIT 1 2-2' July'21, 1989-

1 q

CONTAINMENT' SYSTEMS- ~;

y

. SURVEILLANCE RE0VIREMENTS fContinued)'

4.6.3.2 Each containment isolation valve.shall be demonstrated a OPERABLE during the REFUELING MODE'or_ COLD SHUTDOWN.at-least once pir j

18 months by: .j

.a

a. Verifying that .on a' Phase "A" Isolation test: signal, each l Phase "A" isolation valve actuates to'.its' isolation position;. j

'b.- Verifying that on' a Phase-_"B" Isolation' test- signal, each Phase "B" isolation valve actuates to its isolation position;.

-and' l y

l

c. Verifying that on a Containment Ventilation. Isolation test-signal, each pressure relief discharge valve. actuates.to its 1 isolation position.-

]

4.6.3.3 The isolation time of each power-operated or automatic valve- ,

shall be determined to be within its limit when tested pursuant.to )

Specification 4.0.5'.

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0 COMANCHE PEAK - UNIT 1 2-3 July 21,_.1989 l

_ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ . _ _ . _ . _ _ _ _ _ _ _ _ _ . _ . _ _ _ _ - __ _ _. _ .mm_. . _ _ _ . J

n ~

I .)]

(; !b TECHNICAL RE0VIREMENT 2.1 l

p TABLE 2.1.1

. tg CONTAINMENT J10LATION ~ VALVES-MAXIMUM-ISOLATION NOTES AND FSAR TABLE - TIME ~ LEAK TEST' VALVE NO. REFERENCE NO.* LINE OR SERVICE. (Seconds)- RE0VIREMENTS

1. Phase "A" Isolation Valves 1HV-2154 20 Feedwater Sample 5 N.A.

(FW to Stm Gen #1) 1HV-2155 22 Feedwater Sample 5 N.A.

(FW to Stm Gen #2) 1HV-2399 27 Blowdown From Steam ,5. N.A.

Generator #3 1HV-2398 28 Blowdown.From Steam 5. N.A.

' Generator #2 1HV 2397 29 Blowdown From Steam 5' N.A.

Generator #1 5

1HV-2400 30 B1owdown From Steam 5 .N.A.

Generator #4 9 1-8152' 32 Letdown Line to 10 C Letdown Heat- ,

Exchanger 1 1-8160 32 Letdown Line to 10 C.  ;

Letdown Heat Exchanger 1-8890A 35 RHR to Cold Leg 15- C Loops #1 & #2 Test Line  ;

1-8890B 36 RHR to. Cold Leg 15 C Loops #3 & #4.

Test Line -

1-8047 41 Reactor Makeup 10 C  :

Water to Pressure Relief Tank & RC' y i

Pump Stand Pipe 1-8843 42 Si to RC' System 10-  :.. A.

Cold Leg Loops #1,

1. 2, #3, #4 Test Line COMANCHE PEAK - UNIT 1 . July 21, 1989 2-4 l

p: =

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o TECHNICALREQUIREMENT2.1L(continued)

TABLE 2.1.1-(Continued).

CONTAINMENT ISOLAT[0N VALVES ~

l4 ..

MAXIMUM.

ISOLATION- . NOTES ANDL FSAR. TABLE. . TIME LEAK. TEST .

-VALVE NO. REFERENCE NO.* LINE OR SERVICE- (Secondsl 'nE0VIREMENTS

-1. Phase "A"' Isolation Valves.:(Continued) 1-8881 43 SI.to RC System. 10 C' Hot Loops #2 &

1. 3. Test Line' l-1-8824 44 SI to RC System 10- C Hot Leg Loops #1 &

1. 4 Test Line 1-8823 45 SI to no system 10' C Cold Leg Loops #1,

1. 2, #3 & #4 Test LineL 1-0100 51 Seal Water Return l'0- C and Excess Letdown -

1-8112 51 Seal Water Return 10 C and Excess. Letdown 1-7136 52 RCDT Heat Exchanger 10 C to Waste Hold Up Tank LCV-1003 52 RCDT Heat Exchanger 10 C to Waste Hold Up Tank 1HV-5365 60 Detaineralized kater . 5 C Supply 1HV-5366 60 Demineralized 5 C Water Supply llIV-5157 61 Containment Sump 5 C Pump Discharge 1HV-5158 61 Containment' 5 C Sump Pump.

1HV-3487 62 Instrument Air 5 C to Containment COMANCHE PEAK - UNIT 1 2-5 July 21,1989 i

! ,j l- i-- __ _ __

. = . .

TECHNICAL RE0VIREMENT 2.1 (continued) ,.

q-TABLE 2.1.1-(Continued)

CONTAINMENT ISOLATION VALVES-

. MAXIMUM ISOLATION NOTES AND-

. FSAR TABLE -TIME. LEAK TEST VALVE NO. REFERENCE NO.* LINE OR SERVICE (Seconds) RE0VIREMENTS.

1. Phase "A" Isolation Valves (Continued) 1-8825 63 RHR to Hot Leg Loops 1:i C

1. 2'& #3 Test Line IHV-2405 73 Sanple from Steam 5 N.A.

Generator'#1 .

1HV-4170 74 RC Sample From 5 C i Hot Legs i 1HV-4168 74 RC Sample From 5 C U Hot Leg #1

] 1 IHV-4169 74 RC Sample From 5 C Hot. Leg #4 1HV-2406 76 Sample from Steam 5 N.A. '

Generator #2 IHV-4167 77 Pressurizer Liquid 5 C I Space Sample 1HV-4166 77 Pressurizer Liquid 5 C Space Sample IHV-4176 78 Pressurizer Steam 5 C Space Sample 1HV-4165 78 Pressurizer Steam 5 C Space Sample 1HV-2407 79 Sample From Steam 5 N.A. 1 Generator #3 1HV-4175 80 Accumulators 5 C ,

1HV-4171 80' Sample From . 5 C  ;

Accumulator #1  ;

n v

COMANCHE PEAK - UNIT 1 2-6 July 21,11989

) I'

f 1.

TECHNICAL RE0VIREMENT 2.)_(continueil TfSi F 2.1.1 (conth ;&a)

CONTAINMENT ISOLATION VALVES MAX!M'JM ISOLATION NOTES AND FSAR TABLE TIME LEA'( TEST VALVE N0. (IEFERENCE NO.* LINE OR SEBylCE (Secondji). EfSp_1REMENTS

1. Phase "A" Isolation Valves (Cuntinued) 1HV-4172 80 Sample From 5 C Accumulator #2 IHV-4173 80 Sample From 5 C Accumulator #3 1HV-4174 80 Sample From 5 C Accumulator #4 1HV-7311 81 RC PASS Sample 5 C Discharge to RCDT 1HV-7312 S1 RC PASS Sample 5 C Discharge to RCDT O 1HV-2408 82 Sample from Steam Generator #4 5 N.A.

1-8871 83 Accumulator Test 10 C and Fill 1-8888 83 Accumulator Test 10 C and Fill 1-8964 83 Accumulator Test 10 C and Fill 1HV-5556 84 Containment Air 5 C PASS Return 1HV-5557 84 Containment Air 5 C PASS Return 1HV-5544 94 Radiation 5 C Monitoring Sample 1HV 5545 94 Radiation 5 C Monitoring Sample 1HV-5558 97 Containment Air 5 C PASS Inlet COMANCHE PEAK - UNIT 1 2-7 July 21, 1989 i

1-t IL(ht!JCAL RE0VIREMENT 2.1 (contingste

.. TABLE 2.1.1'(Continue Q ;

CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION. NOTES'AND FSAR TABLE . .

. TIME.. LEAK' TEST VSIVE NO. REFERENCE NO."-LINE OR SERVICE f Seconds). , RE0UIREMENTS

1. Phase "A" Isolation Valves (Continued)

IHV-5559 97 Containment' Air 5 C-

' PASS Inlet 1HV-5560 100 Containment Air 5 -C PASS Inlet 'I i

1HV-5561 100 ' Containment Air. 5 C .!

PASS Inlet ~ I IHV-5546 102 Radiation Monitor- 5 C-ing Sample Return j IHV-5547 102 Radiation Monitor-5' C ing Sample Return l 1-8880 104 N2 Supply.to' 10 C 1 Accumulators 1

1-7126 105 H2 Supply to.  : 10. C RC Drain Tank 1-7150 105 H2 Supply to 10 C RC Drain Tank.

1HV-4710 111 CCW Supply to 5- N.A.

Excess Letdown-

'& RC Drain Tank I

' Heat Exchanger I 1HV-4711 112 CCW Return From 5 N.A.

~ Excess Letdown &- ,

RC Drain Tank i Heat Exchanger 1HV-3496 113 Service Air 5 C' to Containment ,

l ..-(AJ 3

COMANCHE PEAK - UNIT 1 2-8 July 21, 19.89

_ _ '-l'._________ ___m____ ________...__.a.___1._i_l__ G

TECHNICAL REQUIREMENT 2.1-(continued)

(~}

'v ~ TABLE 2.1.1 (Continued).:

CONTAINMENT ISOLATION VALVES

MAXIMUM ISOLATION. -NOTES AND-FSA-R TADLE .

TIME .

LEAK TEST YALVE NO. REFERENCE N0.* LINE OR.EERVICE (Seconds) :BE0UIREMENTS-

1. Phase "A" Isolation Valves .(Continued).

1HV-4725. 114 Containment-CCW. S. .C-Drain Tank Pumps Discharge 1HV-4726 114 Containment CCW 5 C Drain. Tank' Pumps

' Discharge 1-8027 '116 Nitrogen Supply

~

~

10 C to PRT.

1-8026 116 Hitrogen Supply 10 ,C to PRT 1HV-6084 120 Chilled Water _ 10 C l s Supply to Contain-ment Coolers 1HV-6082 121 Chilled Water- .10 C t Return From Containment Coolers IHV-6083 121 Chilled Water 110 C Return From Containment Coolers '

IHV-4075B 124 Fire Protection 10 'C' System Isolation 1HV-4075C 124 Fire Protection 10 C System' Isol ation -

2. Phase "B" Isolation Valves i

1HV 4708 117 CCW Return From 15 C U RCP'S Motors 1 1HV-4701 117 CCW Return From c15 C RCP's Motors j)

. /3 1HV-4700 118 CCW Supply to '15 - C l

'V- RCP's Motors n COMANCHE' PEAK - UNIT 1 2-9 July 21~J, 1989

_. 9

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LTECHNICAL'RE0VIREMENT 2.1 -(continued)> j

? TABLE-2.1.1'(Continued) 1 CONTAINMENT. ISOLATION VALVES ~!

MAXIMUM

-ISOLATION NOTES AND , a FSAR TABIE .

TIME LEAK TEST.

' i 1

VALVE NO. REFERENCE NO.* 11NE OR SERVICE: (Seconds)~.. RE0VIREMENTS fi L2. Phase "B" Isolation'(continued) ,

j l

1HV-4709 119 CCW Return From ' 15' C '.

RCP's, Thermal' 1

Barrier

.c /,;

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1HV-4696 119' CCW Return From RCP's Thermal-15- . C.'

l r

Barrier. y3 4

3. Containment Ventilation Isolation' Valves m 1 0 1HV-5542- 58 Hydrogen Purge -

N.A..- C ,

7 Supply-1 q

1 IHV-5543 -58 ~ Hydrogen Purge N.A. C .,

Supply y -

1HV-5563 SS Hyd.'cgen Purge N.A. C' d.

Supply .

i, 1HV-5540 59 Hydrogen Purge, N.A. C Exhaust '

' i-n 1HV-5541 59 Hydrogen Purge Exhaust N.A. >

C l1

.5 1HV-5562 59. . Hydrogen Purge- .N.A. :C -

Exhaust '

i f I I IHV-5536 109 . Containment l' urge 5 JC:

Air Sypply' .g . '

'1HV-5537 109 Containment Purge 5. , C: L ',u , c

,gh

.a Air Supply . '

1 ";

y M . . Ji

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. -m 7.

h 1HV-5538' 110 Containment Purge- t5 ,

YCL E' M Air. Exhaust ' ~ .

'f, ,

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t 1HV-5539 110 Containment.: Purge, ~.5 C- my J - 1  ?

. Air Exhaust , .,

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> , ,. v' f  ; y 10 n.- HJuly P1, 1989j

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IECHNICALR[0DIREMENT2iffcontip_y_gdl nm

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-(J TABLE 2.I'.1 (ContinuedF -i CONTAINMENT ISOLATION VALVES- j

' i

'MNXIMUM i

' ISOLATION  : NOTES AND~ x "j

FSAR : TABLE . . TIME' . LEAL ( TEST YALVE NO. BEFERENCE NO.* LINE<OR SERVICF;, (Secondl'. REQUIREMENTS' j v

3. Containment Ventilation Isolation Valves (Continued) i 1HV-5548 1.22 Containment Pressure 3: C- -

Relief

']

1 IHV-5549 122' Containment Pressure 3 C. i Relief 1 1

'4. Manual Valves- ~

{

IMS-711# 4a. TOAFW Puep' Bypass N.A. N.A.  :

Warm-up Valve '

i a

IMS-390 Sa N2-Supply to Steam N.A. N.A. j Generator #1 1 j

D IMS-387 9a N2 ' Supply to Steam. N.A. h.A.- 1

-( Generator #2 1 1MS-384 13a N2 Supply.to Steam. .N.A. N.A. 1 Generator #3 F #

-l 1MS-712# 17a 'TDAFW Pump Bypass N.A.

N.A. .

Warmiup Valve IMS *"3 18a N2 Supply to Steam N.A. N.A.

Generator'#4- >

1

' IFW-1116 20b N2 Supply to Steam N.A. N. A.c Generator #1 o

IFW 104 22b N2 Supply tb Steam N.A. N.A.

,. Generator #2

\

L 1FW-102 7.4b 'N2 Supply to Stean' N.A. 4N.A.

lq Generator f3 - '

[L

~

1FW-108. 26b N2 Supply; to Steam N.A. N.A.

Generator #4' 1-7135 85 52- RCDTNeatExchenger N.A. C to Kaste Holdup Tank y,

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cCOMANCHE PEAK -! UNIT'l'-

t 2-11 .daly21,'1989' l

[) a f/

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^

TECHNICAL RE0QIREMENT 2.1 (continued)

,b)a.,

TABLE 2.1.1-(Continued 1 CONTAINMENT ISOLATION VALVES MAXIMUM -c l

ISOLATION NOTES AND FSAR TABLE- TIME- . LEAK = TEST yJMVE NO.- REFERENCE NO.* LINE OR' SERVICE (Seconds) RE0VIREMENTS l'

4. Manual Valves (Continued)

ISF-011 56 Refueli_ng Water N.A. C Purification to Refueling Cavity ISF-012' 56 Refueling Water N.A. C Purification to -

Refueling Cavity ISF-021 67 Refueling Cavity N.A. C to Refueling Water l Purification Pump.

ISF-022 67 Refueling Cavity N.A. C to' Refueling Water Purification Pump

% ISF-053 71 - Refueling Cavity -N.A. C-Skimmer Pump.

Discharge ISF-054 71 Refueling Cavity. N. A. - C Skimmer Pump-Discharge IHV-2333B# 2 MSIV: Bypass from N.A. Note 1 Steam Generator #1 1HV-23348# 7 MSIV Bypass from- N.A. Note 1 Steam Generator #2 "

1HV-2335B# 11 MSIV Bypass from- N.A. -Note 1 Steam Generntor #3 IHV-2336B# 15 MSIV Bypass.from 'N.A. > Note 1 Steam Generator #4 l

l-

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COMANCHE ~ PEAK - UNIT 1 2-12 July 21,1989

f. l

J TECHNICALi RE0VIREMENT 2,1 (continued) g TABLE 2.1.1 (Continued).

CONTAINMENT ISOLATION VALVES

, . MAXIMUM- t ISOLATION NOTES AND d ^

FSAR TABLE . TIME- ' LEAK. TEST VALVE-NO. REFERENCE NO.* LINE OR SERT' ICE (Seconds) RE0VIREMENTS

5. Power-0perated Isolation Valves 1HV-2452-1 '4 Main Steam to' Aux. N.A. N.A.

FPT From Steam Line #1 1PV-2325 5 Atmospheric Relief N.A. N.A.

Steam Generator

1. 1 1PV-2326 9 Atmospheric Relief.. N.A. N.A.

Steam Generator #2:

IPV-2327 13 Atmospheric Relief N.A. N.A.

Steam Generator #3 1HV-2452-2 9 17 Main Steam to Aux..

FPT From Steam Line #4 N.A. N.A.

]

IPV-2328 18 Atmospheric Relief Steam Generator #4 N.A. N.A. l

.{

1HV-2491A 20a Auxiliary'Feedwater N.A. -N.A.  :

16 Steam Generttor #1 '

1HV-24918 20a Auxiliary . Fe-edwater N.A. N.A. I to Steam Generator #1 IHV.2492A 22a Auxiliary Feedwater N.A. N.A.

to Steam Generator #2 IHV-24928 22a Auxiliary Feedwater N.A. . N . A .'

to Steam Generator #2 1HV-2493A 24a Auxiliary Feedwater N.A. N.A.

to Steam Generator #3 ,

1HV-2493B 24a Auxiliary Feedwater N.A. .N.A.

l to Steam Generator #3 O

CCMANCHE PEAK - UNIT 1 2-13. July 21,1989 i

l

't 1

TECHNICAL RE0VIREMENT 2'1 (continued)

TAOLE 2.1.1-(Continued)

CONTAINMENT ISOLATION VALVES 'I MAXIMUM . i ISOLATION NOTES AND 1

~FSAR TABLE . . TIME . > LEAK TEST l y_AjiERQ.

A REFERENCE N0;* 11NE OR SERVICE (Second11 RE0VIREMENTS

5. Power-0perated Isolation Valves (Continued) 1HV-2494A 26a Auxiliary Feedwater N.A. N.A. l to Steam Generator

1. 4 1HV-2494B 26a Auxiliary:Feedwater 'N.A. N . A .'-

to' Steam Generator

1. 4 1-8701B 33 RHR From Hot _. Leg N.A. C-Loop #4 1-8701A 34 RHR From Hot Leg N.A. C-Loop #1 1-8809A 35 RHR to Cold' Leg N.A.

0 1-8809B 36 Loops #1 and #2 C

RHR to Cold Leg- N.A. C Loops #3 and #4' l

1-8601A 42 Safety Injection N.A. N.A.

to Cold Leg Loops

1. 1, #2, #3,.~and #4 1-8801B 42 Safety Injection N.A. N.A.

to Cold Leg Loops . ,

1. 1, #2, #3, and #4 1

1-8802A 43 SI' Injection to N.A. N.A.

RCS Hot Leg Loops

1. 2 and #3 1-8802B 44 SI Injection to. N.A. N.A. "

RCS Hot Leg Loops

1. 1 and #4' 1-8835 45 SI Injection to N'. A. N.A. i RCS Cold Leg' Loops ')

1. 1, #2, #3, and_#4 )

i l

'(u~N COMANCHE PEAK - UNIT 1 2-14, July 21,1989:

TECHNICAL REQUIREMENT 2.1 (continued)

TABLE 2.1.1 (Continued)

CONTAINMENT' ISOLATION VALVES MAXIMUM . .

ISOLATION NOTES AND.

FSAR TABLE . TIME-  : LEAK TEST VALVE NO.. REFERENCE N0.* LINE OR SERVICE- (Seconds) ftE0VIREMENTS

5. Power-Operated Isolation Valves-(Continued) 1-8351A 47 Seal Injection to N.A. N.A.

RC Pump (Loop #1) 1-8351B 48 Seal Injection to N.A. N.A.

RC Pump (Loop #2)'

1-8351C 49 Seal Injection to N . A'. 'N.A.

RC Pump (Loop #3) 1-8351D 50 Seal Injection to N.A. N.A.

RC Pump (Loop #4).

1HV-4777 54 Containment-Spray N.A. C to Spray Header

,- (Train B)

IHV-4776 55 Containment Spray N.A. C to Spray Header l (Train A) 1-8840 63 GHR to Hot Leo N.A. C-Loops #2 and #3 1-8811A 125 Containment N.A. N. A. .

Recire. Sump i

to RHR Pumps 1 (Train A)'

1-8811B 126 Containment N.A. N.A. -i Recire. Sump l to RHR Pumps (Train B) <

1HV-4782 127 Containment N.A. N.A. )

l Recirc. to Spray '

Pumps (Train A) i 1HV 4783, 128 Containment N.A. N.A.

Recire. to Spray Pumps (Train B) i o)

(~ i COMANCHE PEAK - UNIT 1 2-15 July 21,1989

}-

.4 TECHNICAL RE0VIREMENT 2;l (continued)'

/' . . . 'l

( TABLE 2'.1.1 (Continued)

CONTAINMENT' ISOLATION VALVES .

9 MAXIMUM . l ISOLATION NOTES AND-FSAR TABLE TIME LEAK TEST-VALVE NO. REFERENCE NO.* LINE OR SERVICE LSf_C.QDdi). REQUIREMENTS I

6. Check Valves

\

1-8818A 35- RHR to Cold Leg N.A.. N.A.

Loop #1 1-8818B 35 RHR to Cold Leg N.A. N.A.

Loop #2 1-8818C 36 RHR to Cold Leg- N.A. N . A'.

Loop #3 1-8818D 36 RHR to Cold Leg N.A. N.A. l Loop #4 1-8046 41 Reactor Makeup _N.A. C l Water to Pressu-

' .rizer Relief Tank.

and RC Pump Stand Pipe

)

1-8815 42 -High Head Safety N . A .- N.A.

Injection to Cold

{

Leg Loops #1, #2,

1. 3, and #4 .]

1S1-8905B 43 SI to RC System N A._ N.A.

Hot Leg Loop #2 j l

1SI-8905C 43 SI to RC System N.A. N.A. J Hot' Leg Loop #3 ISI-8905A 44 SI to RC System N.A. N.A. j Hot Leg Loop #1'  ;

1SI-8905D  !

44 SI to RC: System. N.A. N.A. ;j Hot Leg Loop ~#4- ~

a ISI-8819A

.i 45 SI to RC System N.A. N.A.' l Cold Leg Loop #1 1

,I

) '

(J i LGANCHE PEAK -. UNIT 1 2-16 July 21,.1989 i

s 4 .

TECHNICAL REQUIREMENT 2.1 (continued)

/' TABLE 2.1.1 (Continued)

CONTAINMENT ISOLATION VALVES '

MAXIMUM-ISOLATION NOTES AND l i FSAR TABLE TIME LEAK TEST l VALVE NQ. REFERENCE N0.* LINE OR SERVICF,- (Seconds) RE0!)IREMENTS -l

6. Check Valves (Continued) 4 ISI-8819B 45 SI to RC System N.A. N.A.

Cold Leg Loop #2 ,

i ISI-8819C 45 SI to RC System N.A. N.A. {'

Cold Leg Loop #3 1SI-98190 45 SI to RC System N.A. N.A. 4 Cold Leg loop #4 'i 1-8381 46 Charging Line to N.A. C l Regenerative Heat  !

Exchanger ICS-8368A 47 Seal Injection to N.A. N.A.

RC Pump (Loop #1)

I L ICS-8368B 48 Seal Injection to N.A.

N.A. i RC Pump (Loop #2) j ICS-8368C 49 Seal Injection to N.A. N.A.  !

RC Pump (Loop #3) 4 1CS-83680 50 Seal Injection to N.A. N.A.

RC Pump (Loop #4)

^

ICS-8180 51 Seal Water Return N.A. C and Excess Letdown ICT-145 54 Containment Spray N.A. C to Spray Header (Tr. B) ,

l COMANCHE PEAK - UNIT 1 2-17 July 21, 1989

TECHNICAL RE0VIREMENT 2.1 (continued)

TABLE 2.1.'1 (Continued)

CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST VALVE NO.- REFERENCE NO.* LINE OR SERVICE (Seconds) REQUIREMENTS

6. Check Valves (Continued)

ICT-142 55 Cor.tainment Spray N . A.- C to Spray Header.

(Tr. A)-

1C1-030 62 Instrument Air N.A. C to Containment 1-8841A 63 RHR to Hot Leg N.A. N. A. ,

~ Loop #2 1-8841B 63 RHR to Hot Leg N.A. N.A.

Loop #3 1S1-8968 104 N2 Supply to N.A.. C Accumulators 1CA-016 113 Service Air to .N.A. C.

Containment 10C-629 117 CC Return From N.A. C RCP's Motcrs 10C-713 118 CC Supply to RCP's N.A. C Motors-100 831 119 CC Return From N.A. C RCP's Thermal .

Barrier-ICH-024 120 Chilled Water N.A. C-Supply to Contain-ment Coolers O 1 COMANCHE PEAK - UNIT 1 2-18 July 21,'1989 .

' . , .* L i-

.d_b1___________-___.____-__-_ - _-------:- - - -

\

TECHNICAL RE0VIREMENT 2.1 (continued)

. TABLE 2.1.1 (Continued)

!. CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST VALVE N0. REFERENCLN_Q.* LINE OR SERVICE (Seconds) RE0VIREMENTS

7. Steam Line Isolation Signal 1HV-2333A 1 Main Steam From 5 Note 2.& 3 Steam Generator #1 1HV-2409 3 Drain From Main 5 N.A.

Steam Line #1 1HV-2334A 6 Main Steam From 5 Note 2 & 3 Steam Generator #2 1HV-2410 8 Drain From Main 5 N.A.

Steam Line #2 i

{

1HV-2335A 10 Main Steam From 5 Note 2 & 3 Steam Generator #3 j 1HV-2411 12 Drain From Main 5 N.A. f Steam Line #3 1

)

IHV-2336A 14 Main Steam From 5 Note 2 & 3 Steam Generator #4 IHV-2412 16 Drain From Main 5 N.A.

Steam Line #4 1

i COMANCHE PEAK - UNIT 1 2-19 July 21,1989

TECHNICAL REQUIREMENT 2.1 (continued)

TABLE 2.1.1 (Continued)

CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST VALVE NO. REFERENCE N0.* LINE OR SERVICE . Seconds) RE0VIREMENTS

8. Feedwater Line Isolation Signal IHV-2134 19 Feedwater to 5 Note 3 Steam Generator #1 IFV-2193 20c Feedwater Preheat 5 Note 3 Bypass Line S.G. #1 IHV-2185 20d Feedwater Bypass 5 Note 3 Line S.G. #1 IHV-2135 21 Feedwater to 5 Note 3 Steam Generator #2 IFV-2194 22c Feedwater Preheat 5 Note 3 Bypass Line S.G. #2 O IHV-2186 22d Feedwater Bypass Line S.G. #2 5 Note 3 IHV-2136 23 Feedwater to 5 Note 3 Steam Gene'.'ator #3 IFV-2195 24c Feedwater Preheat 5 Note 3 Bypass Line S.G. #3 IHV-2187 24d Feedwater Bypass 5 Note 3 Line S.G. #3 IHV-2137 25 Feedwater to 5 Note 3 Steam Generator #4 IFV-2196 26c Feedwater Preheat 5 Note 3 Bypass Line S.G. #4 IHV-2188 26d Feedwater Bypass 5 Note 3 Line S.G. #4 O

COMANCHE PEAK - UNIT 1 2-20 July 21, 1989

TECHNICAL RE0VIREMENT 2.1 (continued)

TABLE 2.1.1 (Continued)

CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION NOTES AND FSAR TABLE TIME LEAK TEST-VALVE NO. REFERENCE NO.* LINE OR SERVICE 1 ;onds) RE0V!REMENTS

9. Safety Injection Actuation Isolation 1-8105 46 Charging Line 10 C to Regenerative Heat Exchanger

10. Relief Valve:;

1-8708B 33 RHR From Hot N.A. C Leg Loop #4 1-8708A 34 RHR From Hot N.A. C Leg Loop #1 IMS-021 Sb Main Steam Safety N.A. Note 3 Valve S.G. #1 IMS-022 5b Main Steam Safety N.A. Note 3 Valve S.G. #1 IMS-023 Sb Main Steam Safety N.A. Note 3 Valve S.G. #1 IMS-024 5b Main Steam Safety N.A. Note'3 Valve S.G. #1 IMS-025 Sb Main Steam Safety N.A. Note 3 Valve S.G. #1 ,

IMS-058 9b Main Steam Safety N.A. Note 3 Valve S.G. #2 IMS-059 9b Main Steam Safety N.A. Note 3 l Valve S.G. #2 '

IMS 160 9b Main Steam Safety N.A. Note 3 l Valve S.G. #2 {

l 9

COMANCHE PEAK - UNIT 1 2-21 July 21, 1989 1

TECHNICAL RE0VIREMENT 2.'1 (continued)

TABLE 2.1.1-(Continued)'

CONTAINMENT ISOLATION VLVES l MAXIMUM l- ISOLATION ' NOTES AND FSAR TABLE TIME LEAK-TEST VALVE NO. REFERENCE NO.* LINE OR SERVICE- (Seconds) RE0VIREMENTSl l

10. Relief Valves (Continued) 1MS-061 9b Main Steam Safety N.A. Note 3 Valve S.G. #2 IMS-062 9b Main Steam Safety N.A. Note 3 Valve S.G. #2 IMS-093 13b Main Steam Safety- N.A. Note.3 Valve S.G. #3 IMS-094 13b Main Steam Safety N.A. Note 3.

Valve S.G. #3 IMS-095 13b Main Steam Safety. N.A. Note =3 Valve S.G. #3 O IMS-096 13b Main Steam rafety Valve S.G. #3 N.A. Note ~3 IMS-097 13b Main Steam Safety N.A. Note i Valve S.G. #3 IMS-129 18b Main Steam Safety N.A. Note 3 Valve S.G. #4 IMS-130 18b Main Steam Safety N.A. Note 3 Valve S.G. #4 IMS-131 18b Main Steam Safety N.A. Note 3 Valve S.G. #4 IMS-132 18b Main Peam Safety N.A. Note 3 Valve s.G. #4 IMS-133 18b Main Steam Safety N.A. Note 3 Valve S.G. #4 O

COMANCHE PEAK - UNIT 1 July 21, 1989 22

TECHNICAL REQUIREMENT 2.1 (continued)

TABLE 2.1.1 (Continued)

CONTAINMENT ISOLATION VALVES MAXIMUM ISD'

• TION NOTES AND FSAR TABLE .fME LEAK TEST VALVE NO. REFERENCE NO.* LINE OR SERVICE (Secondsl REQUIREMENTS

10. Relief Valves (Continued) 1RC-036 41a Penetration Ther- N.A. C mal Relief IWP-7176 52a Penetration Ther- N.A. C mal Relief 10D-430 60a Pen 7tration Ther- N.A. C mal Relief IVD-907 61a Penetration Thor- N.A. C mal Relief IPS-503 74a Penetration Ther- N.A. C mal Relief G IPS-501 77a Penetration Ther-mal Relief N.A. C IPS-502 78a Penetration Ther- N.A. C mal Relief IPS-500 80a Penetration Ther- N.A. C mal ReDef IWP-7177 Bla Penetration Ther- N.A. C mal Relief ISI-8972 83a Penetration Ther- N.A. C mal Relief 100-1067 114a Penetration Ther- N.A. C  ;

mal Relief l ICH-271 120a Penetration Ther- N.A. C mal Relief ICH-272 121a Penetration Ther- N.A. C mal Relief 1

O COMANCHE PEAK - UNIT 1 2-23 July 21, 1989

l TECHNICAL RE0VIREMENT 2.1 (continued)  !

r\ A

(

) TABLE 2.1.1 (Continuedl TABLE NOTATIONS

• Identification code for containment penetration and associated j isolation valves in FSAR Tables 6.2.4-1, 6.2.4-2, and 6.2.4-3. j

1. May be opened on an intermittent basis under administrative control. 1 i

The table does not list local vent, drain and test connections as they {

are a special class of containment isolation valves and are locked  !

closed and capped to meet containment isolation criteria when located )

within the penetration boundary.  !

1 Note 1: All four MSIV bypass valves are locked closed in Modo 1. i During Mode 2, 3, and 4 one MSIV bypass valve may be j opened provided the other three MSIV bypass valves 6re locked closed and their associated MSIVs are closed.

Note 2: ihese valves require steam to be tested and are thus not required to be tested until the plant is in MODE 3.

Note 3: These valves are included for table completeness, the requirements of Specification 3.6.3 do not apply.  !

p Instead, the requirements of Specification 3.7.1.1, y 3.7.1.5 and 3.7.1.6 apply for main steam safety valves, mainsteam isolation valves, and feedwater isolation l

valves, respectively.

BASES l

2.1 CONTAINMENT ISOLATION VALVES i

The OPERABILITY of the containment isolation valves ensures that the I containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment and is consistent with the requirements of General Design Criteria 54 through 57 of 10CFR50, Appendix A. Containment isolation within the time limits specified for those isolation valves designed to close automatically ensures I

that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA. 1 COMANCHE PEAK - UNIT 1 July 21,1989 1 2-24

TECHNICAL REQUIREMENT 3.1 SNUBBER-INSERVICE INSPECTION PROGRAM G NOTE: This Technical Requirement contains the augmented inservice inspection program for snubbers. Although the CPSES Technical Specification is repeated here, care must be taken not to overlook Technical Specification requirements.

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O COMANCHE PEAK - UNIT 1 3-1 July 21, 1989

PLANT SYSTEMS 3/4.7.9 SNUBBERS LIMITING CONDITION FOR OPERATION 3.7.9 All snubbers shall be OPERABLE. The'only snubbers excluded from the requirements are those installed on nonsafety-related systems, and then only if their failure or failure 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 required 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 snubbers (s) to OPERABLE status and perform an engineering evaluation in accordance with'the approved augmented inservice inspection program on the attached component or declare the attached system inoperable and follow the appropriate:

ACTION statement for that system.

SURVEILLANCE REQUIREMENTS j t 4.7.9 Each snubber shall be demonstrated OPERABLE by performance of the requirements of the approved augmented inservice inspection program.

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COMANCHE PEAK - UNIT 1 3-2 July 21, 1989

TECHNICAL RE0VIREMENT 3.1 t SNUBBERS

\,_

TESTS / INSPECTIONS TR3.1 Each snubber shall be demonstrated OPERABLE by performance of the following augmented inservice inspection program in lieu of the requirements of Technical Specification 4.0.5.

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

b. Visual Inspections Snubbers are categorized as inaccessible or accessible during reactor operation. Each of these groups (inaccessible and i accessible) may be inspected independently according to the sche'ule below. The first inservice visual inspection of each typc of snubber shall be performed after 4 months but within 10 months of commencing POWER OPERATION and shall include all snubbers. If all snubbers of each type on any system are found i OPERABLE during the first inservice visual inspection, the second  ;

inservice visual inspection on that type shall be performed at the '

first refueling outage. Otherwise, subsequent visual inspections

(' of a given system shall be performed in accordance with the s following schedule:

No. of Inoperable Snubbers of Each Type on any system per Subsequent Visual i Inspection Period Inspection Period * #

0

{

18 months 25% j 1 12 months 25%  !

2 6 months 25% 1 3,4 124 days t 25%

5,6,7 1 62 days 1 25% (

8 or more 31 days 25% j l

Mhe inspection Tnterval for each type of snubber shall not be lengthened more than one step at a time unless a generic problem has I

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 any system.

1. The provisions of Technical Specification 4.0.2 are not applicable.

COMANCHE PEAK - UNIT 1 3-3 July 21, 1989  ;

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TECHNICAL RE0VIREMENT 3.1 (continued)

(9 SNUBBERS 1 LJ TESTS / INSPECTIONS (Continued)

c. Visual Inspection Acceptance Criteria i

Visual inspections shall verify that: (1) there are no visible l indications of damage or impaired OPERABILITY, (2) attachments to j the foundation or supporting structure are secure, and (3) fasteners for attachment of the snubber to the component ano 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 that may be generically susceptible; or (2) the affected snubber is functionally tested in the as-found condition and determined j OPERABLE per Test / Inspection TR3.lf. All snLbbers connected to an inoperable common hydraulic fluid reservoir shall be counted as inoperable snubbers.

d. Transient Event Insoection 7 An inspection shall be performed of all snubbers attached ta sections of systems that have experienced unexpected, potentially damaging transients as determined from a review of operational data. A visual inspection of those systems shall be performed within 6 months following such an event. In addition to ,

satisfying the visual inspection acceptance criteria, freedom-of-motion of mechanical snubbers shall be verified using at least one {

1 of the following: (1) manually induced snubber movement; or (2) }

evaluation of in-place snubber piston setting; or (3) stroking the {

mechanical snubber through its full range of travel. '

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O L.) l l COMANCHE PEAK - UNIT 1 3-4 July 21, 1989

TECHNICAL RE0VIREMENT 3.1 (continued) 9

[O SNVBBERS TESTS / INSPECTIONS (Continued)

e. Functional Tests During the first refueling shutdown and at least once per 18 months thereafter during shutdown, a representative sample of snubbers of each type shall be tested using one of the following sample plans. The sample plan for each type shall be selected prior to the test period and cannot be changed during the test period. The NRC Regional Administrator shall be notified in writing of the sample plan selected for each snubber type prior to the test period or the sample plan used'in the prior test period shall be implemented:

1) At least 10% of the total of each type of snubber shall be functionally tested either in-place or in a bench test. For each snubber of a type that does not meet the functional test acceptance criteria of Test / Inspection TR3.lf, an additional 10% of that type of snubber shall be functionally tested until no more failures are found or until all snubbers of that type have been functionally tested; or p 2) A representative sample of each type of snubber shall be k}

( functionally tested in accordance with Figure 3.1-1. "C" is the total number of snubbers of a type found not meeting the i acceptance requirements of Test / Inspection TR4.lf. The  !

cumulative number of snubbers of a type tested is denoted by j "N". At the end of each day's testing, the new values of "N" l and "C" (previous day's total plus current day's increments)  !

shall be plotted on Figure 3.1-1. If at any time the point i plotted falls in the " Reject" region, all snubbers of that type shall be functionally tested. If at any time the point plotted falls in the " Accept" region, testing of snubbers of that type may be terminated. When the point. plotted lies in the " Continue Testing" region, additional snubbers of that l type shall be tested until the point falls in the " Accept" region or the " Reject" region, or all the snubbers of that type have been tested; or COMANCHE PEAK - UNIT 1 3-5 July 21,1989

i TECHNICAL RE0UIREMENT 3.1 (continued)

TESTS / INSPECTIONS (Continued)

e. fynctional Testi i

3) An initial representative sample of 55 snubbers shall be {

functionally tested. For each snubber type which does not j meet the functional test acceptance criteria, another sample '

of at least one-half the size of the initial sample shall be tested until the total number tested is equal to the initial sample size multiplied by the factor,1 + C/2, where "C" is the number of snubbers found which do not meet the functional test acceptance criterie. The results from this sample plan  ;

shall be plotted using an " Accept" line which follows the equation N - 55(1 + C/2). Each snubber point should be plotted as soon as the snubber is tested. If the point plotted falls on or below the " Accept" line, testing of that type of snubber may be terminated. If the point plotted falls above the " Accept" line, testing must continue until the point falls in the " Accept" region or all the snubbers of that type have been tested. Testing equipment failure during functional testing may invalidate that day's testing and allow that day's testing to resume anew at a later time provided all snubbers tested with the failed equipment during the day of equipment failure are retested. The representative sample selected for the functional test sample plans shall be randomly selected 3 from the snubbers of each type and reviewed before beginning (V the testing. The review shall ensure, as far as praticable, that they are representative of the various configurations, operating environments, range of size, and capacity of snubbers of each type. Snubbers placed in the same location '

as snuLbers which failed the previous functional test shall be retested at the time of the next functional test but shall not be included in the sample plan. If during the functional testing, additional sampling is required due to failure of only one type of snubber, the functional test results shall be reviewed at that time to determine if additional samples should be limited to the type of snubber which has failed the functional testing. j i

O N.

COMANCHE PEAK - UNIT 1 3-6 July 21, 1989 4

L._m.__ _ _ _ _ _ _ _ . _ _ _

TECHNICAL'RE0VIREMENT 3.1 (continued)

SNUBBERS TESTS / INSPECTIONS (Continued)

f. Functional Test Acceptance Criteria The snubber functional test shall verify:that:

1) Activation (restraining action) is achieved'with'in the specified range in both tension and compression;

2) Snubber bleed, or release rate where required, is present in both tension.and compression, within the.specified range;

3) For mechanical snubbers, the force required to initiate or maintain motion of the snubber is within the specified range in both directions of travel; and

4) For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement.

Testing methods may be used to measure parameters indirectly or parameters other than those specified if those results can be correlated to the specified parareters through established methods,

g. Functional Test Failure Analysis An engineering evaluation shall be made of each failure to meet the functional test acceptance criteria to determine the cause of the failure. The results of this evaluation shall be used, if applicable, in' selecting snubbers to.be tested. in an effort to .;

determine the OPERABILITY of other snubbers irrespective of type which may be subject to the same failure mode.

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COMANCHE PEAK - UNIT 1 3-7 July 21,1989

TECHNICAL RE0VIREMENT 3.1 (continued)

SNVBBERS TESTS / INSPECTIONS (Continued)

g. Functional Test Failure Analysis (Cont'inued)

For the snubbers found inoperable, an engineering evaluation shall be performed on the components to which the inoperable snubbers are attached. The purpose of this engineering evaluation shall be-to determine if the components to which the inoperable snubbers ',

are attached were adversely affected by the inoperability of the snubbers in order to ensure that the component remains capable of i meeting the designed service.

If any snubber selected for functional testing either fails to lock up or fails to move, i.e., frozen in-place, the cause will be evaluated and, if caused by manufacturer or design deficiency, all snubbers of the same type subject to the same defect shall be functionally tested. This testing requirement shall be independent of the requirements stated in Test / Inspection TR3.le i for snubbers not meeting the functional test acceptance criteria.

h. Functional Testina of Repaired and Replaced Snubbers es Snubbers which fail the visual inspection or the functional test '

acceptance criteria shall be repaired or replaced. Replacement  ;

snubbers and snubbers which have repairs which might affect the i

functional test results shall be tested to meet the functional  ;

test criteria before installation in the unit. Mechanical I snubbers shall have met the acceptance criteria subsequent to their most recent service, and the freedom-of-motion test must have been performed within 12 months before being installed in the unit.

4

i. Snubber Service Life Proaram The service life of hydraulic and mechanical snubbers shall be monitored to ensure that the service life is not exceeded between surveillance inspections. The maximum expected service life for various seals, springs, and other critical parts shall be determined and established based on engineering information and shall he extended or shortened based on monitored test results and failure history. Critical parts shall be replaced so that the maximum service life will not be exceeded during a period when the snubber is required to be OPERABLE. The parts replacements shall be documented and the documentation shall be retained in accordance with Technical Specification 6.10.2.

A COMANCHE PEAK - UNIT 1 3-8 July 21, 1989

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TECHNICAL REQUIREMENT 3.1 (continued)

]

O 10 1

9 l

l' 8

- )

/

6 REJECT r

/

C 3 41) r 4 09 O 4 9vy s

/

, CONTINIE TEliTING 1 l 2 ,

l

, ACC EPT

2 1

rv 0 #

10 20 30 40 50 60 70 80 90 100 N

Figure 3.1-1 Sample Plan 2) for Snubber Functional Test COMANCHE PEAK - UNIT 1 3-9 July 21, 1989 4

C._-________.__ ___

TECHNICAL REQUIREMENT 3.2 STATION SERVICE WATER SYSTEM OPERABILITY CRITERIA

~

3.2- A Unit 2 Service Water Pump shall be available to support Unit-1 operation.

APPLICABILITY: Modes 1, 2, 3 and 4.-

COMPENSATORY MEASURES:

a. If neither Unit.2. Service. Water Pump is available, either restore a Unit 2 Service Water Pump to available status within 7 days,.or, place Unit 1 in 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 COLD SHUTDOWN within the following,30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />..

b. If only one Unit 1 Service Water Pump is OPERABLE and neither Unit 2 Service Water Pump is available, immediately initiate action to-restore either a Unit 2 Service Water Pump to available status or the inoperable Unit 1 Service Water Pump to an OPERABLE status.

TEST / INSPECTIONS The Unit 2 Service Water Pump (s) shall be cotisidered available if'it' is capable of being manually started and cross-connected to tho Unit 1 Service Water System. This availability shall be demonstrated by: i TR3.2.1 At least once per day, verifying that Bus 2EAl is energized if the 2A Service Water Pump is the available pump,-or Bus 2EA2 is energized if the 28 Service Water Pump. is the.available.

pum,1; snd TR3.2.2 At least once por day, verifying that the cross connect valve (s) betwet the Unit 1 Service Water System and the ,

available Unit 2 Service Water Pump are open or capable of  !

being' opened.

j TR3.2.3 At least once quarterly stroking cross-connect valves XSW-0006, XSW-0007, XSW-0008, XSW-0028, XSW-0029 through their fu'l range of motion.

TR3.2,f At least once per 31 days, the available pump will be operated

l. for at least 15 minutes.

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O COMANCHE PEAK - UNIT 1 3-10 July 21, 1989 1

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TECHNICAL RE0VIREMENT 3.2 (continued) b)

q BASES ,

3.2 STATION SERVICE WATER SYSTEM The inclusion of this requirement for Unit 2 Station Service Water .

Pump availability while Unit 1 is operating in MODES 1 through 4, the attendant Test / Inspections to demonstrate availability, and the compansetory measures to be taken in the event a Unit 2 Service Water Pump is not available, provide the necessary level of administrative controls to assure acceptable results from the Probabilistic Risk Assessment (PRA) for loss of Unit 1 Station Serv'ce Water. These [

requirements are in addition to the requirements for Unit 1 Station Service Water contained in the Technical Specifications.  !

The Test / Inspection requirements for the Unit 2 Station Service Water pump availability are adequate to ensure that power is available to the pump and the pump is capable of pumping upon demand. The cross-connect discharge path valves are tested at least once per quarter by i stroking these valves through their full range of motion. These- I cross-connect valves are also verified to be capable of being opened I or already open by an administrative check by examining logs or other I information to determine if these valves are out-of-service for j maintenance or other reasons. l

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COMANCHE PEAK - UNIT 1 3-11 July 21, 1989 l

TECHNICAL RE0VIREMENT 4.1 CONTAINMENT PENETRA110N CONDUCTOR OVERCURRENT PROTECTION DEVICES NOTE: This Technical Requiremtat contains the listing of overcurrent protection devices subject to the requirements of Technical Specification 3.8.4. Although the Specification is repeated here, care must be taken not to overlook Technical Specification Requirements.

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COMANCHE PEAK - UNIT 1 4-1 July 21, 1989 i

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3/4.8.4 ELECTRICAL E0VIPMENT PROTECTIVE DEVICES ')

(v CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION  !

3.8.4 All containment penetration conductor overcurrent protective devices shall be OPERABLE. l APPLICABILITY: MODES 1, 2, 3, and 4.

ACTION:

1 With one or more of the containment penetration conductor overcurrent i protective device (s) inoperable: )

a. Restore the protective device to OPERABLE' status or:

1. Deenergize the circuit (s) by racking out, locking open, or )

removing the inoperable protective device ap_d tripping / removing the associated protective device within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, declare the affected system or component inoperable,  :

and verify the inoperable protective device racked out, locked open, or removed at least.once per 31 days-thereafter; the provisions of Specification 3.0.4 are not applicable to i overcurrent protective devices in circuits which have their I p associated protective device tripped / removed and their I inoperable protective. device racked out, locked open, or -

removed; or )I

2. Deenergize the circuit (s) by tripping / removing the associated protective device pr racking out, locking open, or remov bg the inoperable protective device within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, declare the affected system or component inoperable, and verify the 2 associated protective device to be tripped / removed or the l inoperable protective device racked out, locked open, or removed at least once per 7 days thereafter; the provisions of Specification 3.0.4 are not applicable to overcurrent devices t in circuits which have their associated protective device <

trippad/ removed or their inoperable protective device racked '

out, locked open, or removed; or

b. Be in at least HOT ;TANOBY 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 COLD SHUTD0WN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

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COMANCHE PEAK - UNIT 1 4-2 July 21, 1989

i ELECTRICAL E0VIPMENT PROTECTIVE DEVICES SURVEILLANCE RE0VIREMENTS 4.8.4- Tne containment penetration conductor overcJrrent protective devices shall be demonstrated OPERABLE:

a. At least once per 18 months:

1

1. By verifying;that the medium voltage 6.9 kV and low voltage 480V switchgear circuit breakers are OPERABLE by selecting, on a rotating basis, at least 10% of the circuit breakers of each current rating and performing the following:

a) A CHANNEL CALIBRATION of the associated protective relays, b) An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and control circuits function as designed, and c) For eaci .ircuit breaker found' inoperable during these functions tests, one or an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures )

are found or all circuit breakers of that type have been functionally tested; )

2) By selecting and functionally testing a representative sample of at least 10% of each type of 480V molded case circuit breakers and-lower voltage circuit breakers. Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these circuit breakers shall consist of injecting a current with a value equal to 300% of the pickup of the long-time delay trip element and 150% of the .

pickup of the short-time de' lay trip element, and verifying  !

that the circuit breaker operates within the time delay band .

width for that current specified by the manufacturer. The  !

instantaneous element shall be tested by injecting a current '

equal to 20% of the pickup value of the element and verifying that the circuit breaker trips instantaneously with no intentional time delay. Molded case circuit breaker testing shall also follow this procedure except that generally no more i than two trip elements, time delay and instantaneous, will be involved.

4-3 COMANCHE PEAK - UNIT 1 July 21, 1989 u

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.j ELECTRICAL EOUIPMENT PROTECTIVE DEV_lf1S SURVEILLANCE RE0UIREMENTS' The instantaneous element for molded ~ case circuit breakers shall be tested by injecting a current.for'a frame size of 250 amps or less with tolerances of +40%, -25% and a frame size of, 400 amps or greater of 25% and verifying that the circuit.

breaker trips instantaneously with no apparent time delay. 4 Circuit breakers found inoperable during_ functional testing '

shall be restored to OPERABLE status prior to resuming .

operation. For each circuit breaker found . inoperable during these functional tests, an additional representative sample of a least 10% of all the circuit breakers of the inoperable type.  :

shall also be functionally tested until' no more failures are found or all circuit breakers of that type have been functionally tested; and 1

b. At least once per 60 months by subjecting each circuit breaker to an inspection and preventive maintenance'in accordance with procedures prepared'in conjunction with its manufacturer's recommendations.

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COMANCHE PEAK - UNIT 1 4-4 July 21, 1989 l 1

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ J

i TECHNICAL REQUIREMENT 4.1 TABLE 4.1.1 CONTAINMENT PENETRATION CONDUCTOR l OVERCURRENT PROTECTIVE DEVICES i

DEVICE NUMBER SYSTEM .f AND LOCATION POWERED' i

1. 6.9 KVAC from Switchgears

a. Switchgear Bus IAI RCP #11 i

1) Primary Breaker IPCPX1 a) Relay 50M1 b) Relay 26-  !

c) Relay 86M i d) Relay 51M2 e) Relay 50N

2) Backup Breakers IAl-1 or IAl-2 a) Relay 51M3 )

b) Relay 51 for IAl-1 c) Relay 51 for IAl-2 d) Relay 86/1A1 ,

O- b. Switchgear Bus IA2 RCP #12 q

'1) Primary Breaker IPCPX2 a) Relay 50M1-51 b) Re1ay 26 c) Relay 86M d) Relay 51M2 ,

e) Relay 50N i

2) Backup Breakers IA2-1 or IA2-2  !

a) Relay 51M3 b) Relay 51 for IA2-1 <

c) Relay 51 for'1A2-2 l d) Relay 86/1A2 s

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O COMANCHE PEAK - UNIT 1 4-5 . July 21, 1989' l

TECHNICAL REQUIREMENT 4.1 icontinued)

- [3 TABLE 4.1.1 (Continuedl V

CONTAINMENT PENETRATION CONDUCTOR fI I

OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER SYSTEM )

AND LOCATION POWERED i l

1. 6.9 KVAC from Switchgears (Continued.) l

c. Switchgear Bus IA3 RCP #13

1) Primary Breaker IPCPX3 a) Relay 50M1-51 l b) Relay 26 j c) Relay 86M j d) Relay 51M2  ;

e) Relay SON j 1

2) Backup Breakers 1A3-1 or 1A3-2 l

a) Relay 51M3 b) Relay 51 for IA3-1 c) Relay 51 for 1A3-2

, . d) Relay 86/1A3

d. Switchgear Bus IA4 RCP #14

1) Primary Breaker IPCPX4 i i

a) Relay 50M1-51 b) Relay 26 c) Relay 86M ,

d) Relay 51M2 e) Relay 50N 2 Backup Breaker IA4-1 or IA4-2  !

a) Relay 51M3  !

b) Relay 51 for 1A4-1 c) Relay 51 for 1A4-2 d) Relay 86/1A4

2. 480 VAC from Switchgears 2.1 Device Location - Containment 480V Switchgears IEB1, IEB2, Recirc. Fans IEB3 and IEB4 and CRDM Vent Fans e a. Primary Breakers - IFNAV1,

(') IFNAV2, IFNAV3, IFNAV4, IFNCBI and IfNCB2 COMANCHE PEAK - UNIT 1 4-6 July 21, 1989 l

TECHNICAL RE0VIREMENT 4.'1 (continsed).

( TABLE 4.1.1-(Continued)

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER . SYSTEM AND LOCATION POWERED

2. 480 VAC from Switchgears.(Continued) b .~ Backup Breakers - IEB1-1, IEB2-1, IEB3-1 and IEB4-1, BT-1EB13 and BT-1EB24

1) Long' Time & Instantaneous Re1ays*

1Q/11 (IEB1-1) 50/51 (IEB2-1)

IFNAV1 IFNAV2 10/51 (IEB3-1) 10/11 . (IEB4-1)

IFNAV3 IFNAV4' 10251 (IEB3-1) 10/51 (IEB4-1)

IFNCBI IFNCB2

2) Time Delav Relavs*

12-1 (IEB1-2 #2-11 (IFNAVI)

IFNAVI and IFNAVI BT-1EB13) 52-1 (IEB2-1 12-1X (IFNAV2)

IFNAV2 and IFNAV2 BT-lEB24) f2_-1 (IEB3-1 52-1X (IFNAV3)

IFNAV3 and IFNAV3 BT-1EB13) 5.1-1 (IEB4-1 52-1X .(IFNAV4)

IFNAV4 and IFNAV4 BT-1EB24) 62_-1 (IEB3-1 52-11 (IFNCB1)

IFNCBI and IFNCBI BT-1EB13) 52 _1 (IEB4+1 s2-1X .(IFNCB2)

IFNCB2 and IFNCB2 BT-1EB24)

{

Associated circuit breaker shown in parentheses; e.g. .lEB1-1, is backup breaker for IFNAV1.

COMANCHE PEAK - UNIT 1 4-7 July 21,1989

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TECHNICAL RE0VIREMENT 4.1 (continued) I

(] TABLE 4.1.1 (Continued)

Ns j CONTAINMENT PENETRATION CONDUCTOR 1 OVERCURRENT PROTECTIVE DEVICES i DEVICE NUMBER SYSTEM I AND LOCATION POWERED 1 l

2.2 Device Location - 480V Containment i Switchgear IEB4 Polar Crane  !

a. Primary Breaker - ISCCPI

b. Backup Breaker IEB4-1 and BT-1EB24 f

1) Lono Time Delav Relav*

51 (IEB4-1 and - 62X (ISCCPI)

ISCCPI BT-1EB24) ISCCPI

2) Time Delav Relays 62 q ISCCPI

( 3. 480VAC from Motor Control Centers 3.1 Device Location - MCC IEB1-2 Containment Numbers listed below.

Primary and Backup - Both primary and backup breakers I Breakers have identical trip ratings and l are in the same MCC Compt. These breakers are General Electric type THED or THFK with thermal-magnetic trip elements. ,

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Associated circuit breaker (s) shown in parentheses; e.g. IEB4-1 and BT-lEB24 are backup breakers for ISCCPl.

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COMANCHE PEAK - UNIT 1 4-8 July 21, 1989 t

TECHNICAL RE0VIREMENT 4.1 (continued)

( TABLE 4.1.1 (Continued)

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION

3. 480 from Motor Control Centers (Continued)

MCC IEB1-2 G.E.

COMPT. ND. ER. TYPE SYSTEM POWERED 4G THED Motor Operated Valve 1-TV-4691 4M THED Motor Operated Valve 1-TV-4693 3F THED Containment Drain Tank Pump-03 9H THED Reactor Cavity Sump Pump-01 9M THED Reactor Cavity Sump Pump-02 7H THED Containment Sump #1 Pump-01 7M THED Containment Sump #1 Pump-02 6H THED RCP #11 Motor Space Heater-01 6M THED RCP #13 Motor Space Heater-03 8B THED Incore Detector Drive "A" 8D THED Incore Detector Drive "B" 78 THED Incore Detector Drive "F" 3B THED Stud Tensioner Holst Outlet-01 6

7D THED Hydraulic Deck Lift-01 4B THED Reactor Coolant Pump Motor Hoist Receptacle-42 BH THED RC Pipe Penetration Cooling Unit-01 8M THED RC Pipe Penetration Cooling Unit-02 5H tiled RCP #11 011 Lift Pump-01 SM ThED RCP #13 011 Lift Pump-03 10B 1HED Preaccess Filter Train Package Receptacle-17 5B THED Containment Ltg. XFMR-14 (PNL C3) 10F THED S.G. Wet Layup Cire. Pump 01 (CPI-CFAPRP-01) 12M THED S.G. Wet Layup Cire. Pump 03 (CPI-CFAPRP-03) 12H THFK Containment Ltg. XFMR-28 (PNL Cll &

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COMANCHE PEAK - UNIT 1 4-9 July 21,1989

TECHNICAL RE0VIREMENT 4.1-(continued)-

TABLE 4.1.1 fContinued)

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION

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3. 480VAC from Motor Control Centers (Continued)

MCC IEB1-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 6D THED Refueling Machine-(Manipulator Crane-01) 2M THED RC Drain Tank Pump No. I 2F THED Containment Ltg. XFMR-16 (PNL.C7 & 09)

IM THED Containment Ltg. XFMR-12 (PNL Cl & C5) 3M THED Preaccess Fan No. 11 50 THED Fuel Transfer System Reactor S'de Cont. Pnl. for TBX-FHSTTS-0 1 3.2 Device Location - MCC IEB2-2 Containment Numbers' listed below.

Primary and Backup - Both primary and backup breakers have O Breakers identical trip ratings and are located in the same MCC compt. These breakers-are i Gent ral Electric type THED and THFK with  !

thermal-magnetic trip elements. i MCC IEB2-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 4G THED Motor Operated-Valve 1-TV-4692 4M THED Motor Operated Valve 1-TV-4694 3F THED Containment Drain Tank Pump-04 i 7H THED Containment Sump No. 2 Pump-03  !

7M THED Containment Sump No. 2 Pump-04  !

6H THED RCP No. 12 Motor Space Heater-02 1 6M THED RCP No. 14 Motor Space Heater-04 5B THED Incore Detector Drive "C" , ;

2B THED Incore Detector Drive "D" s 78 THED Incore Detector Drive "E"  !

SD THED Containment fuel Storage Cran?-01 1 3B THED Stud Tensioner Hoist Outlet-02  !

4B THED Containment Solid Rad Waste j Compactor-01 )

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COMANCHE PEAK - UNIT 1 4-10 July 21,1989 l l

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y TECHNICAL RE0VIREMENT 4.1 (continued)

-l TABLE 4.1.1 (Continued)

CONTAINMENT PENETRATION CONDUCTOR  !

OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION

3. 480VAC from Motor Control Centers (Continued). ,

MCC IEB2-2 G.E.

COMPT. NO. DKR TYPE SYSTEM POWERED 10B THED RCC Change Fixture Hoist Drive-01 10F fHED Refueling Cavity Skimmer Pump-Ol' 12B THED Power Receptacles (Cor.t. El. 841')

IM THED S.G.. Wet Layup Cire. Pump 02 (CPI-CFAPRP-02)-

12M THED 'S.G. Wet Layup Cire. Pump 04  !

(CPI CFAPRP-04) 8H THED RC Pipe Penetration Fan-03 ,

BM THED RC Pipe Penetration Fan-04 1 SH THED RCP #12 011-Lift Pump-02 SM THED RCP #14 011 Lift Pump-04 12H THED Preaccess Filter Train Package a Receptacles - 18 5O 6D 2F THED THED Containment Auxiliary Upper Crane-01 Containment Ltg. XFMR-13 (PNL C2) )

70 Containment Elevator-01 THED 2D THED Containment Access Rotating Platform-01 2M THED Reactor Coolant Drain Tank Pump-02 9F THED ContainmentLtg.XFMR-17(PNLC8&C10) 9M THED Containment Ltg.XFMR-15 (PNL C4 & C6) 3M THED Preaccess Fan-12 IG THFK Containment Welding Machine Power Supply Unit I

3.3 Device Location - MCC IEB3-2 Containment numbers s listed below.

Primary and Backup - Unless noted otherwise, both primary j and backup breakers have. identical. '

trip ratings' and are located in the same MCC compt. These breakers are General Electric type THED or THFK with thermal-magnetic trip elements.

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O COMANCHE PEAK - UNIT 1 4-11 July 21, 1989 1

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TECHNICAL RE0VIREMENT 4.1 (continued) ]

[ TABLE 4.1.1 (1ontinued) s._ / (

CONTAINMENT PENETRATION CONDUCTOR  !

OVERCURRENT PROTECTIVE DEVICES DEVICE NUhlER l; AND LOCATION

3. 480VAC from Motor Control Centers (Continued)

MCC 1EB3-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED BRF THED J8-IS-1005, Altern. Feed to Motor Operated Valve 1-8702A IG THED Motor Operated Valve 1-8112 9G THED Motor Operated Valve 1-8701A 9M THED Notor Operated Valve 1-8701B i

I SM THED Motor Operated Valve 1-8000A 5G THED Motor Operated Valve 1-HV-6074 4G THED Motor Operated Valve 1-HV-6076 4M THED* Motor Operated Valv; 1-HV-6078 2G THED Motor Operated Valve 1-HV-4696 2M THED Motor Operated Valve 1-HV-4701 3G THED* Motor Operated Valve 1-HV-5541 l

(q 3M IM THED*

THED Motor Operated Valve 1-HV-5543 Motoc Operated Valve 1-HV-6083 6F THED Motor Operated Valve 1-HV-8808A 6M THED Motor Operated Valve 1-HV-8808C 7M THED Containment Ltg. XFMR-18 (PNL SC1&SC3) 8M THED Neutron Detector Well Fan-09 7F THFK Electric H2 Recombiner Power Supply PNL-01 8RM THED Motor Operated Valve 1-HV-4075C 9F THED Motor Operated Valve 1-HV-4782 9RM THED Motor Operated Valve 1-8811A l

Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

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COMANCHE PEAK - UNIT 1 4-12 July 21,1989

TECHNICAL RE0VIREMENT 4.1 (continued) t O) TABLE 4.1.1 (Continued)

CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER AND LOCATION l l

3. 480VAC From Motor Control Centers (Continued) i 3.4 Device Location - MCC 1EB4-2 Containment numbers listed below.

Primary and Backup - Unless noted otherwise, both primary and backup breakers have identical tr'p ratings and are located in the same MCC compt. These breakers are General Electric type THED or THFK with thermal-magnetic trip elements.

MCC 1EB4-2 G.E. I COMPT NO. BKR. TYPE SYSTEM POWERED j IM THED JB-IS-1230G, Altern. ft.ed to Motor Operrted Valve 1-8701B 8G THED Motor Operated Valve 1-8702A

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8M 4M THED THED Motor Operated Vaive 1-8702B Motor Operated Valve 1-8000B 1 4G THED Motor Operated Valve 1-HV-6075 i 3G THED Motor Operated Valve 1-HV-6077  !

3M THED* Motor Operated Valve 1-HV-6079 1 2G THED Motor Operated Valve 1-HV-5562 2M THED* Motor Operated Valve 1-HV-5563 l 5F THED Motor Operated Valve 1-8808B SM THED Motor Operated Valve 1-8808D 6M THED Containment Ltg. XFMR-19 (PNL SC2&SC4) i Neutron Detector Well Fan-10 7M THED 6F THFK Elect. H2 Recombiner Power Supply PNL-02 BRF THED Motor Operated Valve 1-HV-4783 8RM THED Motor Operated Valve 1-8811B

• Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

COMANCHE PEAK - UNIT 1 b 13 July 21, 1989

TECHNICAL RE0UIREMENT 4.1 (continued)

TABLE 4.1.1'(Continued)

CONTAINMENT PENETRAT"4N CONDUCTQB OVERCURRENT PROTECT.v" DEVICES DEVICE NUMBER SYSTEM-LND LOCATION POWERED

4. 480VAC From Panelboards For Pressurizer Pressurizer Heaters Heaters (1) groups A,B, & D

a. Primary Breakers - General Electric Type TJJ Thermal Magnetic.

breakers.

Breaker No. & Location - Ckt. Nos. 2 thru 4 of Pane 1 boards 1EB2-2, IEB3-2, IEB4-1,-1EB4-2 and C?ct. Nos. 2 thru 5 of Pane 1 boards IEi,2-1 and 1EB3-1.

b. Backup Breakers - General Electric Type THJS with longtime and insts. solid state trip devices with 400 Amp. sensor.

Breaker No. & Location - Ckt. No. 1 of Pane 1 boards 1EB2-1, O IEB2-2, IEB3-1, IEB3-2, IEB4-1 and IF34-2.

These breakers should be tested at the following settings:

- 1EB2-2, IEB3-2, IEB4-1, and IEB4-2 at 200 & 280 Amps.

- IEB2-1, and IEB3-1 at 200, 280, and 360 Amps.

(2) group C

a. Primary Breakers - General Electric. Type THED breakers.

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Breaker No. and Location - For both IEB1-l'& 1EB1-2 are

. located at Ckt. Nos. 2 thru 4.

b. Backup Breakers - General Electric Type. TJJ Thermal Magnetic breakers.

Breaker No. and Location - Ckt No. 1 of Switch .

boards IEB1-1 & IEB1-2.

5. 120V Space Heater Circuits Containment Recire.

from 480V Switchgears Fan _a-d CRDM Vent, Fan hator Space Heaters O

COMANCHE PEAK - UNIT 1 4-14 July 21, 1989 j

TECHNICAL RE0VIREMENT 4.1'(continued)

, . TABLE 4.1'.1 (Continued)-

CONTAINMENT PENETRATION CONDUCTOR 0VERCURRENT PROTECTIVE DEVICES

5. 120V Space Heater Circuits from 480V Switchgears (Continued)

a. Primary Breakers BKR. LOCATION WESTINGHOUSE

& NUMBER BKR. TYPE-Swgr. IEB1, .EB1010 Cubicle 3B CPI-VAFNAV-02 Space Heater Bkr.

Swgr. IEB2, EB1010' Cubicle 3B CVPI-VAFNAV-02 Space Heater Ckr.

Swgr. IEB3, EB1010 Cubicle 9B CPI-VAFNAV-03 Space Heater Bkr.

Swgr. IEB4, EB1010 Cubicle 9B CP1-VAFNAV-04 Space Heater Bkr.

Swgr. IEB3, EB1010 Cubicle 88, CPI-VAFNCB-01 Space Heater Bkr.

Swgr. IEB4, EB1010 Cubicle BB, CPI-VAFNCB-01 Space Heater Bkr.

i COMANCHE PEAK - UNIT 1 4-15 July 21, 1989

TECHNICAL RE0VIREMENT 4'1 (continued) l; TABLE 4.1.1 (Continued)

CONTAINMENT PENETRATION CONDUC(OR OVERCURRENT PROTECTIVE DEVICES

5. 120V Space Heater Circuits from 480/ Switchgears-(Continued)L

b. Backup Breakers

'BKR. LOCATION GENERAL ELECTRIC.

& NUMBER BKR. TYPE-Panel IEC3-2 TED Ckt. No. 3' Panel IEC3-2 TED Ckt. No. 4 Panel IEC4-2 TED Ckt. No. 3 Panel IEC4-2 'TED Ckt. No. 4 O

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TECHNICAL REOUIREMEl4T 4.1-(continued)

TABLE 4.1.1 (Continue'd)

,r0NTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER SYSTEM AND LOCATION POWERED

6. 125V DC Control Power Various

a. Primar.y Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT. NO. BREAKER TYPE XED1-1 1,6 TED XE02-1 1,3,6 TED XD2-3 8,17 TED 1ED2-1 14,17 TED-IED1-1 14,17 :TED 102-3 7,10 TED ID2-2 9 TED 1ED2-2 12 TED 1ED3-1 O

5 TED 1EDI-2 7,8 TED ,

7. 118V AC Instrument Distribution Panel Board 103-3

a. Primary Devices - N/A (Fuse)

b. Backup Breaker - GE Type TED located in Instrument' Distribution Panel Board IC3-3-CK#11

8. 120V AC Power for Personnel and Emergency Airlocks

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC EANELB0ARD NO. CKT. NO. BREAKER TYPE XEC2 34 TED XEC1-2 2 TED O 4-17 COMANCHE PEAK - UNIT 1 July 21, 1989

IfE NICAL RE0VIREMENT 4.1 (continued)

[ TABLE 4.1'.1 (Continued)'

-[QMTAINMENT PENETRATION CONDUCTOR UVERCURRENT PROTECTIVE DEVICES DEVICE NUMBER-AND LOCATION

9. 118V AC Control Power

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL. ELECTRIC - .

PANELBOARD NO. .CKT.~NO. BREAKER TYPE 1 102 22 TED 1C3 14 TED IPC1 10,13 TED IPC4 6,10 TED j IEC1 4,7 TED 1EC2 4,7 TED 1EC5 8 TED 1EC6 3,8 TED ,

IPC2-1 4 TED

10. Emergency Evacuation System Warning. Lights Power

a. Primary Devices - N/A (Fuse) i

b. Backup Breakers j SQUARE D PANELBOARD NO. CKT. NO. BREAKER TYPE XEC3 3 FAL-12020 XEC4 3 FAL-12020

11. DRPI Data Cabinet Power Supplies

a. Primary Devices - N/A (Fuse)

b. Backup Breakers

^

SQUARE D PANELBOARD NO. CKT. NO. BREAKER TYPE 1014 1,2 FA-14050A I i

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COMANCHE PEAK - UNIT 1 4-18 July 21,_1989 l

1 BASES

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4.'1 CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT PROTECTION DEVICES The bases for OPERABILITY and surveillance of these devices are contained'in .the CPSES Technical Specifications. .,

All Class IE motor-operated valves' motor starters 'are provided with thermal. overload protection which is permanently bypassed.and provides.-

an alarm function only at Comanche Peak Steam Electric Station.

Therefore, there are no OPERABILITY or Surveillance Requirements for these devices, since they will not prevent safety-related -valves from performing their function (refer to Regulatory Guide 1.106, " Thermal Overload Protection for Electric Motors-on Motor Operated Valves,"

Revision 1, March 1977).

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