ML13331B103

Application for Amend to License DPR-13,revising App a Tech Specs to Incorporate Limiting Conditions for Operation & Surveillance Requirements Associated W/Mod to Incorporate Third Auxiliary Feedwater Pump Into Existing Sys

ML13331B103
Person / Time
Site:	San Onofre
Issue date:	12/08/1988
From:	Baskin K Southern California Edison Co
To:
Shared Package
ML13331B102	List: ML13331B101 ML13331B103 ML13331B104
References
NUDOCS 8812120203
Download: ML13331B103 (28)

Text

BEFORE THE UNITED STATES NUCLEAR REGULATORY COMMISSION Application of SOUTHERN CALIFORNIA EDISON

)

COMPANY and SAN DIEGO GAS & ELECTRIC COMPANY )

for a Class 104(b) License to Acquire,

)

DOCKET NO. 50-206 Possess, and Use a Utilization Facility as

)

Part of Unit No. 1 of the San Onofre Nuclear )

Amendment No. 158 Generating Station

)

SOUTHERN CALIFORNIA EDISON COMPANY and SAN DIEGO GAS & ELECTRIC COMPANY, pursuant to 10 CFR 50.90, hereby submit Amendment Application No. 158.

This amendment consists of Proposed Change No. 184 to Provisional Operating License No. DPR-13. Proposed Change No. 184 modifies the Technical Specifications incorporated in Provisional Operating License No. DPR-13 as Appendix A.

Proposed Change No. 184 is a request to revise Appendix A Technical Specifications to incorporate Limiting Conditions for Operation and Surveillance requirements associated with modifications to incorporate a third Auxiliary Feedwater Pump into the existing system.

In the event of conflict, the information in Amendment Application No. 158 supersedes the information previously submitted.

S-E12120203 C8,81208 PDR ADOCK 035Q00206 P

PDIC

-2 Based on the significant hazards analysis provided in the Description of Proposed Change and Significant Hazards Analysis of Proposed Change No. 184, it is concluded that (1) the proposed change does not involve a significant hazards consideration as defined in 10 CFR 50.92, and (2) there is reasonable assurance that the health and safety of the public will not be endangered by the proposed change.

Pursuant to 10 CFR 170.12, the fee of $150 is herewith remitted.

-3 Subscribed on this J_4_

day of

, 1988.

Respectfully submitted, SOUTHERN CALIFORNIA EDISON COMPANY By: _Z 2n Kenneth P. Baskin Vice President Subscr bed and sworn to before me this Y

day of F

I

>OFFICIAL SEAL AGNES CPABTREE

&NNotary Public-California My Comm. Exp. Sep. 14, 1990 Nota Publ ic in and for the County of Los ngeles, State of California Charles R. Kocher James A. Beoletto Attorneys for Southern California Edison Company By:

Jame Beoleto

UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of SOUTHERN

)

CALIFORNIA EDISON COMPANY

)

and SAN DIEGO GAS & ELECTRIC

)

Docket No. 50-206 COMPANY (San Onofre Nuclear

)

Generating Station Unit No. 1

)

CERTIFICATE OF SERVICE I hereby certify that a copy of Amendment Application No. 158 was served on the following by deposit in the United States Mail, postage prepaid, on the 8th day of December

, 1988.

Benjamin H. Vogler, Esq.

Staff Counsel U.S. Nuclear Regulatory Commission Washington, D.C. 20555 David R. Pigott, Esq.

Samuel B. Casey, Esq.

Orrick, Herrington & Sutcliffe 600 Montgomery Street San Francisco, California 94111 L. G. Hinkleman Bechtel Power Corporation P.O. Box 60860, Terminal Annex Los Angeles, California 90060 Michael L. Mellor, Esq.

Thelen, Marrin, Johnson & Bridges Two Embarcadero Center San Francisco, California 94111 Huey Johnson Secretary for Resources State of California 1416 Ninth Street Sacramento, California 95814 Janice E. Kerr, General Counsel California Public Utilities Commission 5066 State Building San Francisco, California 94102

-2 C. J. Craig Manager U. S. Nuclear Projects I ESSD Westinghouse Electric Corporation Post Office Box 355 Pittsburgh, Pennsylvania 15230 A. I. Gaede 23222 Cheswald Drive Laguna Niguel, California 92677 Frederick E. John, Executive Director California Public Utilities Commission 5050 State Building San Francisco, California 94102 Docketing and Service Section Office of the Secretary U.S. Nuclear Regulatory Commission Washington, D.C. 20555 eA.' Beo to '}

DESCRIPTION AND SIGNIFICANT HAZARDS CONSIDERATION ANALYSIS OF PROPOSED CHANGE NO. 184 TO THE TECHNICAL SPECIFICATIONS PROVISIONAL OPERATING LICENSE NO. DPR-13 This is a request to revise Sections 3.4.1, "TURBINE CYCLE-OPERATING STATUS;"

3.4.3, "AUXILIARY FEEDWATER SYSTEM;" 3.4.4, "AUXILIARY FEEDWATER STORAGE TANK;" 3.5.6, "ACCIDENT MONITORING INSTRUMENTATION;" 3.5.7, "AUXILIARY FEEDWATER INSTRUMENTATION;" 4.1.8, "AUXILIARY FEEDWATER INSTRUMENTATION;" and 4.1.9, "AUXILIARY FEEDWATER SYSTEM SURVEILLANCE;" of the Appendix A Technical Specifications for the San Onofre Nuclear Generating Station, Unit 1 (SONGS 1).

DESCRIPTION OF CHANGES As a result of TMI commitments, and in conjunction with the SONGS 1 Systematic Evaluation Program (SEP) review, SCE has installed a third Auxiliary Feedwater (AFW) pump. This pump will be integrated with the existing two AFW pumps during the Cycle 10 refueling outage. The basis for installation of this pump is to eliminate single failure susceptibilities in the AFW system.

Independent from the SEP and TMI commitments, SONGS 1 experienced a single failure of steam generator pressure transmitter PT-459 on July 3, 1986.

This single failure rendered one of the Reactor Protection System (RPS) trip functions (i.e., steam generator steam flow/feedwater flow mismatch reactor trip) inoperable. This single failure susceptibility prompted the NRC to request, by letter dated September 23, 1986, a single failure analysis of all of the Engineered Safety Features (ESF's) for SONGS 1. By letters dated October 16, 1987, November 6, 1987, November 20, 1987, and June 21, 1988, SCE provided to the NRC the ESF single failure analysis, methodology used to perform the analysis, results obtained, and design details for plant modifications to resolve the identified single failure concerns.

This correspondence contains SCE's detailed evaluation for the AFW system modifications corresponding to this proposed change.

In accordance with the upcoming modifications to the Auxiliary Feedwater System (AFWS) which revise the number of AFWS pumps from two to three in order to eliminate single failure susceptibilities in this system, the following Technical Specification changes are proposed:

1. Technical Specification 3.4.1 defines the conditions of the turbine cycle necessary to ensure the capability to remove decay heat from the core. Proposed Change No. 184 (PCN 184) removes specifications (B),

(C) and (D).

Specifications (B) and (C) relate to the operability of the AFWS pumps and storage tank. The Limiting Conditions for Operation for these components are specified under separate Technical Specifications 3.4.3 and 3.4.4. Since LCO's are not delineated for these components by Technical Specification 3.4.1, the references made by Specifications (B) and (C) are deleted by PCN 184.

Specification (D) establishes a requirement that system piping and valves directly associated with the components in Specifications (B) and (C) be operable. It is not necessary for this specification to be included because, by definition, the OPERABILITY of these components as specified in Technical Specifications 3.4.3 and 3.4.4 requires the piping and valves directly associated to also be OPERABLE.

g a

-2 References made in the Basis of Technical Specification 3.4.1 regarding Specifications (B), (C) and (D) are deleted as well.

Information relating to the AFWS pumps will be revised to reflect the new AFWS configuration and included in the Basis for Technical Specification 3.4.3. Information relating to the AFWS storage tank is currently included in the Basis for Technical Specification 3.4.4.

PCN 184 will incorporate an ACTION to be taken if the turbine cycle steam-relieving capability is less than the Technical Specification requirement. The ACTION corresponds to the Westinghouse Standard Technical Specification ACTION for Turbine Cycle Safety Valves.

2. Technical Specification 3.4.3 defines the components necessary to ensure the availability of auxiliary feedwater to remove decay heat from the core. PCN 184 revises these requirements to reflect the new system configuration of two separate trains of AFW. The ACTION requirements are provided to reflect the inoperability of trains versus valves.

The Basis for Technical Specification 3.4.3 is expanded to define design basis flow requirements to remove decay heat from the core.

In addition, the pumps and associated flow control valves for each AFW Train are defined.

This information is provided to clarify the system configuration and ensure appropriate limiting conditions for operation are established for inoperability of specific components.

3. Technical Specification 3.4.4 establishes the minimum volume of water for the Auxiliary Feedwater storage tank. PCN 184 will revise this volume from 150,000 gallons to 190,000 gallons of usable water. This increase is proposed in order to provide sufficient margin to account for (1) spillage that occurs during a main feedwater line break with delayed isolation of the broken line due to a single failure, and (2) loss of cooling water to the AFW pump bearings. The volume of spillage that occurs during a feedwater line break is based on the most limiting single failure for identification of the broken loop.

Assuming the single failure of the AFW flow transmitters, identification of the broken loop will be made by the RCS Loop Delta-T temperature indication. Within one hour into the event, the operators will have significant Delta-T indication from the two intact steam generators. The broken loop will provide virtually no cooling of the RCS in the affected steam generator. Thus, Delta-T indication will be evident only for the two intact steam generators allowing the operators to identify and isolate the broken loop. In addition to the above increase to account for spillage through the broken loop, the Technical Specification value has been increased to account for water lost through cooling of the AFW pump bearings.

In addition to the above change, the Technical Specification Basis has been revised to specify the requirements for the usable volume of water in the AFW tank, and to clarify the method for determining the usable volume in consideration of the location of the pump suction line and the level indication tap. With the revised minimum AFW Tank volume, at least 25,000 gallons of additional tank capacity remains available above the Technical Specification value for use during operational evolutions.

-3

4. Technical Specification 3.5.6 establishes Limiting Conditions for Operation for accident monitoring instrumentation. Currently, the requirements include a seven day ACTION for all of the accident monitoring instrumentation channels listed in Table 3.5.6-1.

PCN 184 will revise the ACTION requirement for the AFW flow transmitters to repair the inoperable flow transmitter within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

This ACTION requirement is revised to be consistent with that for AFW equipment and instrumentation as specified by the AFW Technical Specifications. The AFW flow transmitters are required to equalize flow to the three steam generators during a feedwater line break upstream of the in-containment check valve. In order to obtain the required flow from the preferred train (AFW Train B) to the intact steam generators for this feedwater line break, the control room operators must equalize flow to all three steam generators.

Verification of flow equalization is provided by the AFW flow transmitters. If the capability to equalize flow or the ability to verify equalization is not available, AFW Train A would be utilized to obtain the necessary decay heat removal.

AFW Train A will provide sufficient flow such that operator action to equalize flow is not required. An ACTION requirement will also be provided for RCS Loop Delta-T temperature indication. The Delta-T indicators will be added to Table 3.5.6-1 because they are utilized to identify the broken loop during a main feedwater line break with loss of AFW flow indication. The required ACTION will be to repair the inoperable indicator within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or begin shutdown.

In addition to the above ACTION requirements, Specification 3.5.6.E will be revised to specify that the current exemption to the provisions of Specification 3.0.4 only applies to Specifications A and D, and does not apply to the inoperability of the Auxiliary Feedwater Flow Rate Channels or RCS Loop Delta-T temperture indicators. This change is necessary because the AFW Flow Rate channels and Loop Delta-T indicators will be required for the performance of an ESF function. Thus the provisions of Specification 3.0.4 would apply.

5. Table 3.5.7-1 establishes the OPERABILITY requirements for the AFWS instrumentation channels. PCN 184 revises this table to reflect a two train configuration and includes OPERABILITY requirements for the flow switches that monitor Train B flow and provide an interlock with the Train A pumps and valves.

Two additional ACTION requirements have been included for the flow switches that monitor Train B flow to ensure the appropriate actions are taken if one or more flow switches are declared inoperable. Two sets of two flow switches (a total of four) monitor Train B flow.

These switches provide signals to initiate Train A flow if Train B does not provide flow as designed, and to stop Train A flow if Train B resumes operation. More detail regarding the operation of the Train interlocks is provided in the Significant Hazards Consideration Analysis. The two ACTION requirements included in Table 3.5.7-1 for these flow switches ensure appropriate controls are implemented in the event that one or more flow switches are declared inoperable.

The interlock design allows one flow switch from each set to be disconnected and still provides sufficient redundancy to perform the necessary safety functions assuming a single failure.

-4 ACTION 35 requires an inoperable flow switch to be returned to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or disconnected within the next one hour. This ACTION prevents the failure mode of an inoperable flow switch from affecting the operation of the interlocks. With one flow switch disconnected, the interlock logic for that set of flow switches is changed from 1-out-of-2 to 1-out-of-1 for initiating Train A, and from 2-out-of-2 to 1-out-of-1 for stopping Train A. The interlock logic for the second set of flow switches remains unaffected.

ACTION 36 is included to ensure appropriate action is taken in the event that more than one of the four flow switches become inoperable. Depending on which flow switches are inoperable (i.e., two flow switches from one set, or one flow switch from each set),

the interlock logic could be susceptible to a single failure consideration. Consequently, ACTION 36 requires the number of OPERABLE flow switches to be no less than three within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or begin shutdown. This ACTION is conservative in that no consideration is accorded to which flow switches are inoperable, two from one set or one from each set.

6. Table 3.5.7-2 establishes the setpoints for the instrumentation channels shown in Table 3.5.7-1.

PCN 184 revises this table to incorporate the additional instrumentation channels and setpoints associated with the flow switches that monitor Train B flow. Each flow switch utilizes its set and reset points for permissive signals for starting and stopping Train A. The set and reset points were determined from a reference point for starting Train A when there is decreasing flow in Train B. The reference, or set-point, establishes the lower end of the flow switch "deadband".

The reset point will stop Train A flow on increasing flow in Train B. The reset point is at the upper end of the deadband, or approximately 14 gpm greater than the set-point. Thus, Table 3.5.7-2 will verify the set and reset point for each flow switch.

The setpoints for the interlocks are based on the total flow from both Trains not exceeding the water hammer flow limit. A "safety limit" was calculated based on the water hammer flow limit (450 gpm to depressurized steam generators) minus the flow provided by Train A. Because the steam driven pump will not function during this event due to the depressurized steam generators, Train A flow is limited to the motor driven pump minus the pump mini-flow. A 15% deduction for conservatism was applied to the "safety limit" to arrive at the upper allowable value for stopping Train A of 48 gpm of Train B flow. The set and reset points were determined with consideration to factors such as repeatability, instrument span and venturi accuracy.

In addition, an administrative change will also be made to incorporate the title of Table 3.5.7-2 that was inadvertently omitted from the existing specification.

7. Table 4.1.8-1 establishes the surveillance requirements for the AFWS instrumentation channels. PCN 184 revises this table to incorporate the channel calibration and testing requirements for the flow switches that monitor Train B flow.

-5

8. Technical Specification 4.1.9 defines the surveillance requirements for the AFWS components to ensure system reliability. PCN 184 revises the wording of this specification to reflect the addition of the third AFW pump and include surveillance requirements for the third AFW pump and associated components from the two trains. An exemption to the provisions of Specification 4.0.4 is included for the Train A steam driven pump, G10, to allow entry into Mode 3 without having demonstrated the operability of the pump. This exemption is consistent with the Westinghouse STS and is necessary due to system limitations that prohibit testing of the pump with RCS pressure and temperature below those of Mode 3. For clarification, a statement is included with this exemption to require the AFW steam driven pump to be OPERABLE in all other respects. This clarification is included to ensure the steam driven pump is capable of operation while in Mode 3, but does not require testing until sufficient pressure and temperature is available to perform testing (i.e.,

within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entering Mode 3).

In addition to the normal testing requirements for the AFW pumps and valves as specified by the provisions of Specification 4.1.9, an overall AFN system test will be performed as part of the initial startup from the Cycle 10 refueling outage. The purpose of this test is to verify in-service flow characteristics in order to validate the hydraulic flow calculations performed to support the re-design of the AFW system. Train B testing will be completed in Mode 5. Because Train A utilizes both a motor driven pump (GlOS) and a turbine driven pump (GI1), its flow test must be performed with operating pressure in the steam generators.

For this reason, Train A flow tests will be performed in Mode 1 below 10% power. The Train A flow test will verify the overall system response including the ability of the flow venturi's to function as designed. In accordance with the other requirements of Specification 4.1.9, the OPERABILITY of the Train A pumps and valves will be verified as necessary prior to MODE 3 and within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entering MODE 3.

Finally, the Basis for this specification would be revised to reflect the new AFWS design basis of a three pump (two Train) system.

9. PCN 184 will provide editorial changes to Technical Specifications 3.5.7 and 4.1.8. These specifications provide the Limiting Conditions for Operation and Surveillance requirements for the AFWS instrumentation. PCN 184 will revise the APPLICABILITY and OBJECTIVE sections of these specifications to indicate these specifications relate to the operability of the auxiliary feedwater system and not only the AFW pumps. This clarification is required due to the introduction of system interlocks that impact the operability of system valves and instrumentation channels in addition to the AFW pumps.

EXISTING SPECIFICATIONS See Attachment 1 PROPOSED SPECIFICATIONS See Attachment 2

00

-6 SIGNIFICANT HAZARDS CONSIDERATION ANALYSIS As required by 10 CFR 50.91(a)(1), this analysis is provided to demonstrate that the proposed license amendment to implement technical specifications associated with installation of a third Auxiliary Feedwater pump at SONGS 1 represents a no significant hazards consideration. In accordance with the three factor test of 10 CFR 50.92(c), implementation of the proposed license amendment was analyzed using the following standards and found not to:

1) involve a significant increase in the probability or consequences for an accident previously evaluated; or 2) create the possibility of a new or different kind of accident from any accident previously evaluated; or

3) involve a significant reduction in a margin of safety.

Discussion PCN 184 is proposed to reflect modifications resulting from SCE's commitment to resolve concerns related to SONGS 1 capability to respond to certain transients and accidents assuming an arbitrary single failure. This commitment was made as part of the TMI Lessons Learned requirements. By letters dated March 10, 1982 and June 30, 1982, SCE committed to the installation of an additional redundant motor-driven AFW pump. The installation of a third AFW pump resolves the NRC concern documented in NRC letters dated October 22, 1982 and November 18, 1982 that the existing AFWS configuration does not meet the single failure criterion. During the Cycle 10 refueling outage, the third AFW pump will be integrated with the existing AFW system to enable the complete system to meet the single failure criterion.

By letter dated November 6, 1987, SCE provided to the NRC the Engineered Safety Features (ESF) Single Failure Analysis Report for San Onofre Unit 1.

This report included a module-level failure mode and effects analysis of the Auxiliary Feedwater ESF function based on the implementation of the currently proposed Cycle X modifications. In addition, because of the event-specific safety analysis requirements for, and potentially event-specific impacts on, the Auxiliary Feedwater ESF function, an event-specific single failure response evaluation was performed for this function which explicitly accounts for the location of an initiating fault, the availability or loss of off-site power, and any inter-system dependencies and common-cause effects, as applicable. This event-specific single failure response evaluation was prepared based on the module-level failure mode and effects analysis results.

The proposed modifications to the AFW system were conceptually developed based on scoping studies which included hydraulic calculations and event-specific single failure response analyses for the integrated RPS/AFW systems. The resulting design will ensure sufficient AFW flow into the intact feedwater lines for any applicable design basis event with or without concurrent loss of offsite power and a single active failure. In addition, water-hammer limits are precluded from being exceeded by design (hydraulic resistances and interlocks) rather than operator action as in the existing configuration.

By letters dated November 20, 1987 and June 21, 1988, SCE provided to the NRC the design descriptions for modifications to the auxiliary feedwater system.

Minor changes have been made to the system design as described in these previous submittals. Thus the following description supercedes the previous submittals.

-7 A. Add two new AFW flow control valves (FCVs) to the existing configuration so that two FCVs in parallel are provided on each AFW line. The parallel valves on each line will be on separate electrical trains. Train A FCVs will fail closed on loss of control power and the Train B FCVs will fail open on loss of control power.

B. The control system for the new FCVs will be identical to that for existing FCVs.

C. Install a cavitating venturi downstream of the AFW flow control valves in each of the three AFW lines.

Each venturi will be sized so as to prevent Pump GlOS run out and exceeding water hammer flow restrictions to depressurized steam generators. Two normally closed manual bypass valves, in series, will be provided for each venturi to accommodate greater flow rates should such operation be deemed desirable and safe.

D. A cavitating venturi is to be placed in the discharge of the GlOW pump so as to prevent exceeding the maximum flow limit to each steam generator under any sequence of events independent of the number of steam generators available. Two normally closed manual bypass valves, in series, will be provided for the venturi to accommodate Dedicated Safe Shutdown operation of GlOW.

E. Realign G1O controls to the same electrical train as GlOS (i.e., Train A).

F. Add GlOW to the opposite electrical train (i.e., Train B).

G. Revise the existing control room panel to include the same controls, indication and alarms for GlOW as exist for the other motor driven AFW pump. The control room panel will be revised in accordance with human factors guidelines as established by the Control Room Design Review.

This will include:

1. Suction and discharge pressure indication and low suction pressure pump trip and alarm.

2. Control switches and position indication of GlOW discharge valve, CV-3110.

3. Pump manual Start/Stop switches with running lights and ammeter.

4. Pump and valve automatic/manual control switches and status indication.

H. Remove the GlOS low discharge pressure trip, but retain the indication functions of the instrumentation. Pump run out protection will be provided by the venturi in each of the three AFW discharge lines.

I. Provide a manual transfer switch for selecting Dedicated Safe Shutdown (DSD) or normal Safety-Related power for GlOW locally. This switch will provide isolation of the normal and DSD power supplies.

3. Modify the auto-mode control circuit of each pump and respective discharge valve to operate as follows upon receipt of the steam generator low level signal (AFWS auto initiation).

-8

1. Lead Train B Pump (GlOW) will immediately start and provide flow; turbine driven Train A pump (GlO) will begin "warm-up" mode (steam bypass valves and drain valves open and turbine running at 2,000 RPM).

2. After a time delay to allow Train B to respond, lag Train A pumps (GlOS and G10) will begin to provide flow upon a no-flow signal from the GlOW pump discharge manifold.

3. Train A pumps (GlOS and G10), if operating, will stop providing flow upon a positive flow signal from the Train B pump (GlOW) discharge manifold (GlOS will trip, G10 will return to "warm-up mode" and Train A pump discharge valves will close).

4. Four flow switches will be provided on the GlOW discharge manifold for control of the Train A pumps and pump discharge valves to prevent postulated single failures from causing inadvertent operation of both trains.

K. An interlock will be provided between each AFW pump and its respective discharge valve, so that pump discharge pressure will be required in order for the discharge valve to open when the AFWS is in the automatic mode.

L. Provide instrument air and back-up nitrogen for the Train B pump (GlOW) discharge valve CV-3110.

M. Prevent loss of AFW storage tank inventory below the new Technical Specification minimum volume due to failure of the non-seismic makeup system during a seismic event. The makeup system presently connects to the AFW storage tank at approximately the 165,000 gallon level, which is below the new Technical Specification minimum level.

Loss of required AFW tank inventory due to makeup system failure will be prevented by installing a check valve to back up the manual valve in the safety related portion of the makeup line, or other suitable means.

ANALYSIS Conformance of the proposed changes to the standards for a determination of no significant hazard as defined in 10 CFR 50.92 (three factor test) is shown in the following:

1. Will operation of the facility in accordance with this proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

RESPONSE: NO The changes proposed by PCN 184 will establish surveillance requirements and limiting conditions for operation associated with plant modifications that enhance system reliability through elimination of single failure susceptibilities in the AFW system. A wide spectrum of analyses were performed to evaluate system responses for various transients. These analyses demonstrated system reliability and capability to respond to the most limiting transients. Consequently, operation of SONGS 1 in accordance with PCN 184 will not increase the probability or consequences of an accident previously evaluated.

-9

2. Will operation of the facility in accordance with this proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

RESPONSE: NO The revisions of this proposed change assure that operation of the plant is restricted to within the bounds of previously analyzed accidents. Specifically, the proposed surveillance and operability requirements ensure operation of the plant within the transient analyses described in the SONGS 1 ESF Single Failure Analysis submitted to the NRC by SCE's letters dated November 6, 1987 and November 20, 1987. The plant modifications to be implemented in the Cycle 10 refueling outage eliminate single failure susceptibilities in the AFW system. Accordingly, this proposed change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Will operation of the facility in accordance with this proposed change involve a significant reduction in a margin of safety?

RESPONSE: NO The revisions of this proposed change provide assurance that the plant is maintained within appropriate margins of safety. This conclusion is supported by the analyses provided in the above referenced Single Failure Analysis. The addition and integration of a third AFW pump with the existing AFW system, in conjunction with other system modifications, will enable the complete system to meet single failure criterion. Accordingly, it is determined that operation of the facility in accordance with this proposed change will increase the margin of safety from the current system design.

SAFETY AND SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION Based on the Safety Evaluation, it is concluded that: (1) Proposed Change No. 184 does not involve a significant hazards consideration as defined by 10 CFR 50.92; and (2) there is reasonable assurance that the health and safety of the public will not be endangered by the proposed change. - Existing Specifications -

Proposed Specifications 0936P EXISTING TECHNICAL SPECIFICATIONS

0 0

3.4 TURBINE CYCLE 38 3.4.1 OPERATING STATUS 12/20/77 APPLICABILITY:

Applies to the operating status of turbine cycle in MODES 82 1, 2 and 3.

11/7/84 OBJECTIVE:

To define conditions of the turbine cycle necessary to ensure the capability to remove decay heat from the core.

SPECIFICATION: (A) A minimum turbine cycle steam-relieving capability of 5,706,000 lb/hr (except for testing of the main steam safety valves).

(B) The auxiliary feedwater pumps OPERABLE as specified in 3.4.3.

82 11/7/84 (C) The auxiliary feedwater storage tank OPERABLE as specified in 3.4.4.

(D) System piping and valves directly associated with the 82 above components operable.

1 11/7/84 BASIS:

A reactor shutdown from power requires subsequent removal of core decay heat.

In the event of a reactor trip from high power levels, immediate decay heat removal requirements are satisfied by the steam bypass to the condensers, supplemented by release to the atmosphere.

Thereafter, core decay heat can be continuously dissipated via the steam bypass to the con denser or steam dump to atmosphere as feed water in the steam generator is converted to steam by heat absorption.

In the event of a planned shutdown, steam release to atmosphere is not required.

In either case, feedwater to the steam generators is normally supplied by operation of the turbine cycle feedwater pumps.

The power operated relief valves and the main steam safety valves have a total combined relief capability of 7,629,432 lb/hr. A capability of 5,706,000 lb/hr is required to main tain the pressure in turbine cycle components within ASME code allowable values in the event of full load rejection. There fore the limiting conditions for operation can be met with less than the full number of valves in service.

3-39 Revised:

11/7/84

Two auxiliary feedwater pumps, one steam driven and one electric driven, together with the steam system relief valves, provide core decay heat removal capability in the event of a sustained loss of off-site power. The electric driven pump is capable of being powered from the diesel.

Either auxiliary feedwater pump has the capability tl Iatisfy decay heat removal requirements from the core.

The OPERABILITY of the auxiliary feedwater storage tank with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions 82 (including cooldown) for 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> with steam discharge to the 11/7/84 atmosphere concurrent with total loss of offsite power. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.

References:

(1) Supplement No. I to the Final Engineering Report and Safety Analysis, Section 3, Question 6.

3-40 Revised:

11/7/84

3.4.3 AUXILIARY FEEDWATER SYSTEM APPLICABILITY:

Applies to the motor driven auxiliary feedwater pump and the turbine driven auxiliary feedwater pump for MODES 1, 2 and 3.

OBJECTIVE:

To ensure the availability of auxiliary feedwater to remove decay heat.

SPECIFICATION:

A.

Both steam generator auxiliary feedwater pumps and associated flow paths shall be OPERABLE as follows:

1. One-auxiliary feedwater pump capable of being powered from an emergency electrical power source, and

2.

One auxiliary feedwater pump capable of being powered 82 from an OPERABLE steam supply system.

11/7/84 B.

With one auxiliary feedwater pump inoperable, restore both auxiliary feedwater pumos (one capable of being powered from an emergency electrical power source and one capable of being powered by an OPERABLE steam supply system) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY 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 ROT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

BASIS:

The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350 F for normal operating conditions in the event of a total loss of offsite power.

Reference:

(1) NRC letter dated July 2, 1980, from D. G. Eisenhut to all pressurized water reactor licensees.

3-42 Revised:

11/7/84

3.4.4 AUXILIARY FEEDWATER STORAGE TANK APPLICABILITY: Applies to the auxiliary feedwater storage tank for MODES 1, 2 and 3.

OBJECTIVE:

To ensure the availability of auxiliary feedwater to remove decay heat.

SPECIFICATION: A.

The auxiliary feedwater storage tank (AFST) shall be OPERABLE with a contained water volume of at least 82 150,000 gallons of water.

11/7/84 B.

With the AFST inoperable, within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> restore the AFST to OPERABLE status or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

BASIS:

The OPERABILITY of the auxiliary feedwater storage tank with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions (including cooldown) for 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> with steam discharge to the atmosphere concurrent with total loss of offsite power. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.

3-43 Revised:

11/7/84

3.5.6 ACCIDENT MONITORING INSTRUMENTATION APPLICABILITY:

MODES 1, 2 and 3.

83 OBJECTIVE:

To ensure reliability of the accident monitoring 1

instrumentation.

64 42/16/81 SPECIFICATION:

The accident monitoring instrumentation channels shown in Table 3.5.6-1 shall be OPERABLE.

ACTION:

A. With the number of OPERABLE accident monitoring instrumentation channels less than the Total Number of Channels shown in Table 3.5.6-1, either restore the inoperable channel(s) to OPERABLE status within 7 days, or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

B. With the number of OPERABLE accident monitoring instrumentation channels less than the MINIMUM CHANNELS OPERABLE requirements of Table 3.5.6-1, either restore 83 the inoperable channel(s) to OPERABLE status within 48 11/2/84 hours or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

C.. The provisions of Specification 3.0.4 are not applicable.

BASIS:

The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and 64 following an accident. This capability is consistent with the 12/16/81 recommendations of Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1975 and NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations."

References:

(1) NRC letter dated July 2, 1980, from D. G. Eisenhut to all pressurized water reactor licensees.

(2) NRC letter dated November 1, 1983, from D. G. Eisenhut to all Pressurized Water Reactor Licensees, NUREG-0737 Technical Specification (Generic Lette.r No. 83-37).

3-61 Revised:

11/16/84

TABLE 3.5.6-1 ACCIDENT MONITORING INSTRUMENTATION MINIU TOTAL NO.

CHANNELS INSTRUMENT OF CHANNELS OPERABLE Pressurizer Water Level 3

2 Auxiliary Feedwater Flow Indication*

2/steam generator I/steam generator Reactor Coolant System Subcooling Margin Monitor 2

1 PORV Position Indicator (Limit. Switch) 1/valve 1/valve PORV Block Valve Position Indicator (Limit Switch) 1/valve 1/valve Safety Valve Position Indicator (Limit Switch) 1/valve 1/valve Containment Pressure (Wide Range) 2 1

Steam Generator Water Level (Narrow Range) 1/steam generator 1/steam generator Refueling Water Storage Tank Level 1

1 Containment Sump Water Level (Narrow Range)**

2 1

Containment Water Level (Wide Range) 2 1

0 4

Auxiliary feedwater flow indication for each steam generator is provided by one channel of steam generator level (Wide Range) and one channel of auxiliary feedwater flow rate.

These comprise the two channels of auxiliary feedwater flow indication for each steam generator.

Operation may continue up to 30 days with one less than the total number of channels OPERABLE.

oo a

Aotv sevRnaafrt c

i t

-w

• • Oeainmycntneu o3 as ihoels hn h oa ubrofcanl PRBE

3.5.7 AUXILIARY FEEDWATER INSTRUMENTATION APPLICABILITY:

Applies to automatic initiation of the auxiliary feedwater pumps.

OBJECTIVE:

To ensure reliability of automatic initiation of the auxiliary feedwater pumps.

SPECIFICATIONS:

A. The instrumentation channels shown in Table 3.5.7-1 shall be OPERABLE with their trip setpoints set consistent with 64 the Trip Setpoint column of Table 3.5.7-2.

12/16/81 B. With an instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.5.7-2, declare the channel inoperable and apply the applicable ACTION requirement of Table 3.5.7-1 until the channel is restored to OPERABLE status with the trip setpoint adjusted consistent with the Trip Setpoint Value.

C. With one instrumentation channel inoperable, take the action shown in Table 3.5.7-1.

82 11/7/84 BASIS The OPERABILITY of the auxiliary feedwater instrumentation ensures that 1) the associated action will be initiated when the parameter monitored by each channel or combination thereof reaches its setpoint, 2) the specified coincidence logic is maintained, 3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance, and 4) sufficient system functional capability is available from diverse 64 parameters.

12/16/81 The OPERABILITY of this instrumentation is required to provide the overall reliability, redundancy, and diversity assumed available for the protection and mitigation of accident and transient conditibns. The operation of this instrumentation is consistent with tfie assumptions used in the accident analyses.

References:

(1) NRC letter dated July 2, 1980, from D. G. Eisenhut to all pressurized water reactor licensees.

3-63 Revised:

11/7/84

TABLE 3.5.7-1 AUXILIARY FEEDWATER INSTRUMENTATION MINIMUM TOTAL NO.

CHANNELS CHANNELS APPLICABLE FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

a. Manual Actuation 2

1

.2 1, 2, 3 12

b. Automatic Actuation Logic 2

1 2

1, 2, 3 13

c. Steam Generator Water Level-Low Iu

i. Start Motor Driven Pump 3

2 2

1, 2, 3 14, 15

11.

Start Turbine-Driven Pump 3

2 2

1, 2, 3 14, 15 82 11/7/8 ACTION 12 With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

ACTION 13 -

With the number of OPERABLE Channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; however, one channel may be bypassed for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for surveillance testing per Specification 4.1.8 provided the other channel is OPERABLE.

ACTION 14 -

With the number of OPERABLE channels one less than the Total Number of Channels, operation may proceed until performance of the next required CHANNEL TEST provided the inoperable channel is placed in the tripped condition within I hour, or an operator shall assume continuous surveillance and actuate manual initiation of auxiliary feedwater, if necessary.

M ACTION 15 With more than one channel inoperable, an operator shall assume continuous surveillance and actuate manual initiation of auxiliary feedwater, if necessary. Restore the system to no more than one channel inoperable within 7 days, or be in HOT STANDBY within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

TABLE 3.5.7-2 FUNCTIONAL UNIT TRIP SETPOINT ALLOWABLE VALUES

a. Manual Actuation Not Applicable Not Applicable be Automatic Actuation Logic Not Applicable Not Applicable 82 11/7/84

c. Steam Generator Water Level-Low

> 5% of narrow range

> 0% of narrow range instrument span each instrument span each eteam generator steam generator 1

01 01 00

-r-

4.1.8 AUXILIARY FEEDWATER INSTRUMENTATION APPLICABILITY:

Applies to the instruments shown in Table 4.1.8-1.

64 12/16/81 OBJECTIVE:

To ensure reliability of automatic initiation of the auxiliary feedwater pumps.

SPECIFICATION:

A. Each instrumentation channel shall be demonstrated OPERABLE by the performance of the surveillance 82 requirements specified in Table 4.1.8-1.

11/7/84 BASIS:

The surveillance requirements specified for this instrumentation ensure that the overall system functional capability is maintained comparable to the original design standards. The periodic surveillance tests performed at the 64 minimum frequencies are sufficient to demonstrate this 12/16/81 capability.

References:

(1) NRC letter dated July 2, 1980, from D. G. Eisenhut to all pressurized water reactor licensees.

4-28 Revised:

11/7/84

TABLE 4.1.8-1 AUXILIARY FEEDWATER INSTRUMENTATION SURVEILLANCE REQUIREMENTS TRIP ACTUATING DEVICE MODES IN WHICH 82 CHANNEL CHANNEL CHANNEL OPERATIONAL SURVEILLANCE 11/7/84 FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST REQUIRED

a. Manual N/A N/A N/A R

1, 2, 3

(

b. Automatic Actuation Logic N/A N/A M

N/A 1, 2, 3

c. Steam Generator Water S

R M

N/A 1, 2, 3 Level-Low M0

-4 co

4.1.9 AUXILIARY FEEDWATER SYSTEM SURVEILLANCE 8

82 APPLICABILITY:

Applies to the motor driven auxiliary feedwater pump, the 11/7/84 turbine driven auxiliary feedwater pumD, and auxiliary feedwater valves for MODES 1, 2 and 3.

OBJECTIVE:

To ensure the reliability of the auxiliary feedwater system.

SPECIFICATION:

A. Each auxiliary feedwater pump shall be demonstrated OPERABLE by testing each pump in accordance with Section XI of the ASME Boiler and Pressure Vessel Code and applicable Addenda as required by 10 CFR 50.55a(g),

except where specific written relief has been granted by 70 the NRC pursuant to 10 CFR 50.55a(g)(6)(i).

12/1/82 B. At least once per 31 days an inspection shall be made to verify that each non-automatic valve in the emergency flow path that is not locked, sealed, or otherwise 82 secured in position is in its correct position.

11/7/84 C. Each auxiliary feedwater pump shall be demonstrated OPERABLE at least once per 18 months by:

1.

Verifying that each automatic valve in the flow path actuates to its correct position upon receipt of 70 each auxiliary feedwater actuation test signal.

12/1/82

2.

Verifying that each auxiliary feedwater pump starts as designed automatically upon receipt of each auxiliary feedwater actuation test signal. Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entering MODE 3, the steam driven 82 auxiliary feedwater pump shall be similarly tested.

11/7/84 D. When the reactor coolant system pressure remains less 70 than 500 psig for a period longer than thirty (30) days, 12/1/82 a flow test shall be performed to verify the emergency flow path from the auxiliary feedwater storage tank to each steam generator, using the motor driven auxiliary feedwater pump orior to increasing reactor coolant system pressure above 500 psig.

The flow test shall be conducted with the auxiliary feedwater system valves in their emergency alignment. Within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entering MODE 3, the steam driven auxiliary feedwater 82 pump shall be similarly tested.

11/7/84 4-30 Revised:

11/7/84

BASIS:

The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350 0F from normal operating conditions in the event of a total loss of offsite power.

The electric driven auxiliary feedwater pump and the steam 70 driven auxiliary feedwater pump are both capable of 12/1/82 delivering a total feedwater flow of 165 gpm at a pressure of 1015 psig to the entrance of the steam generators. This capacity is sufficient to ensure that adequate feedwater flow is available to remove decay heat and reduce the Reactor Coolant System temperature to less than 3500F when the residual Heat Removal System may be placed into operation.

References:

(1) NRC letter dated July 2, 1980 from D. G. Eisenhut to all pressurized water reactor licensees.

4-31 Revised:

12/1/82