Text

Technical Specifications Pages for Amendment Nos. 335, 335 and 336, Respectively
	ML032731475
Person / Time
Site:	Oconee
Issue date:	09/29/2003
From:	Olshan L; NRC/NRR/DLPM/LPD2
To:	Rosalyn Jones; Duke Energy Corp
References
	TAC MB8083, TAC MB8084, TAC MB8085
	Download: ML032731475 (39)
	v • d • e

RCS PIV Leakage 3.4.14 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage LCO 3.4.14 Leakage from the following RCS PIV shall be within limits:

a. CF-12,

b. CF-14,

c. LP-47,

d. LP-48,

e. LP-176, and

f. LP-177

ES----------------------------

1. Prior to completion of the LPI passive cross connect modification on each Unit, the limits for LP-1 76 and LP-1 77 are not applicable.

2. After completion of the LPI passive cross connect modification on each Unit, the limits for LP-47 and LP-48 are not applicable except as stated in Note 3 below.

3. After completion of the LPI passive cross connect modification on each Unit, the limits of both LP-47 and LP-48 may be met in lieu of either LP-176 and LP-177 limits.

APPLICABILITY: MODES 1,2, and 3, MODE 4 except valves in the decay heat removal (DHR) flow path when in, or during the transition to or from, the DHR mode of operation.

ACTiONS art &.n re

1. Separate Condition entry is allowed for each flow path.

2. Enter applicable Conditions and Required Actions for systems made inoperable by an inoperable PIV.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more flow ------------ NOTE---------------

paths with leakage Each valve used to satisfy from one or more Required Action A.1 and required RCS PIVs Required Action A.2 must have not within limit. been verified to meet SR 3.4.14.1 and be on the RCS pressure boundary or the high pressure portion of the system.

----- (continued)

OCONEE UNITS 1 2 3 3.4.14-1 Amendment Nos. 335, 335, & 336 l

LPI 3.5.3 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.3 Low Pressure Injection (LPI)

LCO 3.5.3 Two LPI trains shall be OPERABLE.

--- -------------------------- NE------------------------

1. Only one LPI train is required to be OPERABLE in MODE 4.

2. In MODE 4, an LPI train may be considered OPERABLE during alignment, when aligned or when operating for decay heat removal (DHR) if capable of being manually realigned to the LPI mode of operation.

3. In MODES 1, 2, and 3, the LPI discharge header crossover valves outside containment shall be manually OPERABLE to open on each Unit until after completion of the passive LPI cross connect modification on the respective unit.

4. In MODES 1, 2, and 3, the LPI discharge header crossover valves inside containment shall be open on each Unit after completion of the passive LPI cross connect modification on the respective unit.

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One LPI train A.1 Restore LPI train to 7 days inoperable in MODE 1, OPERABLE status.

2, or 3.

B. One or more required B.1 Restore LPI discharge 7 days LPI discharge header header crossover crossover valve(s) valve(s) outside outside containment containment to manually Inoperable to OPERABLE status.

open in MODE 1, 2, or 3.

(continued)

OCONEE UNITS 1, 2, & 3 3.5.3-1 Amendment Nos. 335, 335, & 336 1

LPI 3.5.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more required C.1 Open LPI discharge 7 days LPI discharge header header crossover crossover valve(s) valve(s) inside inside containment not containment.

open in MODE 1, 2, or3.

D. Required Action and D.1 Be in MODE 3. 12 hours0.5 days 0.0714 weeks 0.0164 months associated Completion Time of Condition A, B, AND or C not met.

D.2 Be in MODE 4. 60 hours2.5 days 0.357 weeks 0.0822 months E. One required LPI train E.1 Initiate action to restore Immediately inoperable in MODE 4. required LPI train to OPERABLE status.

AND E.2 -NOTE---------

Only required if DHR loop is OPERABLE.

Be in MODE 5. 24 hours1 days 0.143 weeks 0.0329 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify each LPI manual and non-automatic 31 days power operated valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

(continued)

OCONEE UNITS 1, 2, & 3 3.5.3-2 Amendment Nos. 335, 335, 336 l

LPI 3.5.3 ACTIONS (continued)

SURVEILLANCE FREQUENCY SR 3.5.3.2 --------------- NOTE -------------

Not applicable to operating LPI pump(s).

Vent each LPI pump casing. 31 days SR 3.5.3.3 Verify each LPI pump's developed head at the In accordance with the test flow point is greater than or equal to the Inservice Testing required developed head. Program SR 3.5.3.4 Verify each LPI automatic valve in the flow 18 months path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.5.3.5 Verify each LPI pump starts automatically on 18 months an actual or simulated actuation signal.

SR 3.5.3.6 Verify, by visual inspection, each LPI train 18 months reactor building sump suction inlet is not restricted by debris and suction inlet trash racks and screens show no evidence of structural distress or abnormal corrosion.

SR 3.5.3.7 --------- NOTE---------------

Not applicable after completion of the passive LPI cross connect modification on each Unit.

Cycle each LPI discharge header crossover 18 months valve outside containment, LPI cooler outlet throttle valve, and LPI header isolation valve open manually.

O C O NEE U NITS 1,2,& 3 3.5.3-3 Amendment Nos. 335, 335, & 336 l

PAM Instrumentation B 3.3.8 B 3.3 INSTRUMENTATION B 3.3.8 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the PAM instrumentation is to display unit variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Events.

The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected unit parameters to monitor and to assess unit status and behavior following an accident.

The availability of accident monitoring instrumentation Is important so that responses to corrective actions can be observed, and so that the need for and magnitude of further actions can be determined. These essential instruments are identified by the ONS specific Regulatory Guide 1.97 analysis (Ref. 1), UFSAR, Section 7.5 (Ref. 2), and the NRC's Safety Evaluation Report for the ONS Regulatory Guide 1.97 analysis (Ref. 3) which address the recommendations of Regulatory Guide 1.97 (Ref. 4),

as required by Supplement 1 to NUREG-0737 (Ref. 5).

The instrument channels required to be OPERABLE by this LCO equate to two classes of parameters dentified during unit specific implementation of Regulatory Guide 1.97 as Type A and Category 1 variables.

Type A variables are specified because they provide the primary information that permits the control room operator to take specific manually controlled actions that are required when no automatic control Is provided and that are required for safety systems to accomplish their safety functions for accidents.

Category 1 variables are the key variables deemed risk significant because they are needed to:

Determine whether systems important to safety are performing their intended functions; OCONEE UNITS 1, 2, & 3 B 3.3.8-1 Amendment Nos. 335, 335, & 3361

PAM Instrumentation B 3.3.8 BASES BACKGROUND (continued)

Provide information to the operators that will enable them to determine the potential for causing a gross breach of the barriers to radioactivity release; and

Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protect the public and to estimate the magnitude of any impending threat.

These key variables are identified by the ONS specific Regulatory Guide 1.97 analysis (Ref. 1). This analysis identifies the unit specific Type A and Category I variables and provides justification for deviating from the NRC proposed list of Category 1 variables.

The specific instrument Functions listed in Table 3.3.8-1 are discussed in the LCO Bases Section.

APPLICABLE The PAM instrumentation ensures the availability of information so SAFETY ANALYSES that the control room operating staff can:

Perform the diagnosis specified in the emergency operating procedures. These variables are restricted to preplanned actions for the primary success path of accidents (e.g., loss of coolant accident (LOCA));

Take the specified, preplanned, manually controlled actions, for which no automatic control is provided, which are required for safety systems to accomplish their safety functions;

Determine whether systems Important to safety are performing their Intended functions;

Determine the potential for causing a gross breach of the barriers to radioactivity release;

Determine if a gross breach of a barrier has occurred; and

Initiate action necessary to protect the public and estimate the magnitude of any impending threat.

OCONEE UNITS 1, 2, & 3 B 3.3.8-2 Amendment Nos. 335, 335, & 3361

PAM Instrumentation B 3.3.8 BASES APPLICABLE The ONS specific Regulatory Guide 1.97 analysis (Ref. 1) documents SAFETY ANALYSES the process that identifies Type A and Category I non-Type A (continued) variables.

PAM instrumentation that meets the definition of Type A in Regulatory Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6). Category 1, non-type A, instrumentation must be retained in Technical Specifications because it is Intended to assist operators in minimizing the consequences of accidents. Category 1, non-Type A variables are important for reducing public risk, and therefore, satisfy Criterion 4 of 10 CFR 50.36 (Ref. 6).

LCO LCO 3.3.8 requires two OPERABLE channels for all but one Function to ensure no single failure prevents the operators from being presented with the information necessary to determine the status of the unit and to bring the unit to, and maintain it in, a safe condition following that accident.

Furthermore, provision of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

Where a channel includes more than one control room Indication, such as both an indicator and a recorder, the channel Is OPERABLE when at least one Indication is OPERABLE.

The exception to the two channel requirement Is containment Isolation valve position. In this case, the important information is the status of the containment penetrations. The LCO requires one position Indicator for each electrically controlled containment Isolation valve. This is sufficient to redundantly verify the isolation status of each isolable penetration either via Indicated status of the electrically controlled valve and prior knowledge of the passive valve or via system boundary status. If a normally active containment isolation valve Is known to be closed and deactivated, position indication Is not needed to determine status.

Therefore, the position indication for valves in this state is not required to be OPERABLE.

Each of the specified instrument Functions listed in Table 3.3.8-1 are discussed below:

OCONEE UNITS 1, 2, & 3 B 3.3.8-3 Amendment Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES LCO 1. Wide Range Neutron Flux (continued)

Wide Range Neutron Flux indication is a Type B, Category 1 variable provided to verify reactor shutdown. The Wide Range Neutron Flux channels consist of two channels of fission chamber based instrumentation with readout on one recorder. (Note: four channels are available only two are required). The channels provide indication over a range of 1E-8% to 200% RTP.

2. Reactor Coolant System (RCS) Hot Lea Temperature RCS Hot Leg Temperature instrumentation is a Type B, Category 1 variable provided for verification of core cooling and long term surveillance. The two channels provide readout on two indicators. Control room display Is through the inadequate core cooling monitoring system. The channels provide indication over a range of 5 0 °Fto 700 0F.

3,5. Reactor Vessel Head Level and RCS Hot Leg Level Reactor Vessel Water Level instrumentation is a Type B, Category I variable provided for verification and long term surveillance of core cooling. The reactor vessel level monitoring system provides an indication of the liquid level from the top of the Hot Leg on each steam generator to the bottom of the Hot Leg as it exits the vessel and from the top of the reactor vessel head to the bottom of the Hot Leg as it exits the vessel.

Compensation is provided for impulse line temperature variations.

The Reactor Vessel Water Level channels consist of two Reactor Vessel Head Level channels that provide readout on two indicators (RC-LT0125 and RC-LT0126) with one channel recorded In the control room and two RCS Hot Leg Level channels that provide readout on two indicators (RC-LT0123 and RC-LT01 24) with one channel recorded In the control room.

4. RCS Pressure (Wide Range)

RCS Pressure (Wide Range) instrumentation is a Type A, Category 1 variable provided for verification of core cooling and RCS integrity long term surveillance.

OCONEE UNITS 1, 2, & 3 B3.3.8-4 Amendment Nos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES LCO 4. RCS Pressure (Wide Ranae) (continued)

Wide range RCS loop pressure is measured by pressure transmitters with a span of 0 psig to 3000 psig. The pressure transmitters are located outside the RB. Redundant monitoring capability is provided by two trains of Instrumentation. Control room indications are provided through the inadequate core cooling plasma display. The inadequate core cooling plasma display is the primary indication used by the operator during an accident. Therefore, the accident monitoring specification deals specifically with this portion of the Instrument string.

RCS Pressure is a Type A, Category 1 variable because the operator uses this indication to monitor the cooldown of the RCS following a steam generator (SG) tube rupture or small break LOCA. Operator actions to maintain a controlled cooldown, such as adjusting SG pressure or level, would use this indication. In addition, high pressure njection (HPI) flow Is throttled based on RCS Pressure and subcooled margin. For some small break LOCAs, low pressure injection (LPI) may actuate with RCS pressure stabilizing above the shutoff head of the LPI pumps. If this condition exists, the operator is instructed to verify HPI flow and then terminate LPI flow prior to exceeding 30 minutes of LPI pump operation against a deadhead pressure. RCS Pressure, In conjunction with LPI flow, is also used to determine if a core flood line break has occurred.

6. Containment Sump Water Level (Wide Range)

Containment Sump Water Level (Wide Range) instrumentation is a Type B, Category 1 variable provided for verification and long term surveillance of RCS integrity. The Containment Sump Water Level instrumentation consists of two channels with readout on two indicators (LT-90 and LT-91) and one recorder. The indicated range Is 0 to 15 feet.

OCONEE UNITS 1, 2, & 3 B 3.3.8-5 Amendment Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES LCO 7. Containment Pressure (Wide Ran-e)

(continued)

Containment Pressure (Wide Range) instrumentation is a Type B, Category 1 variable provided for verification of RCS and containment OPERABILITY. Containment Pressure instrumentation consists of two channels with readout on two indicators (PT-230 and PT-231) and one channel recorded. The indicated range is -5.0 psig to 175 psig.

8. Containment Isolation Valve Position Containment solation valve (CIV) position is a Type B, Category 1 variable provided for verification of electrically controlled containment Isolation valve position. In the case of CIV position, the Important information Is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each electrically controlled CIV in a containment penetration flow path, i.e., two total channels of CIV position Indication for a penetration flow path with two electrically controlled valves. For containment penetrations with only one electrically controlled CIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the solation status of each isolable penetration via indicated status of the electrically controlled valve, as applicable, and prior knowledge of passive valve or system boundary status. As indicated by Note (a)to the Required Channels, Ka penetration flow path is Isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured, position ndication for the CIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position Indication for valves In an Isolated penetration flow path is not required to be OPERABLE. Note (c) to the Required Channels indicates that position Indication requirements apply only to CIVs that are electrically controlled. The CIV position PAM instrumentation consists of limit switches that operate both Closed-Not Closed and Open-Not Open control switch indication via indicating lights In the control room.

OCONEE UNITS 1, 2, & 3 B 3.3.8-6 Amendment Nos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES LCO 9. Containment Area Radiation (High Range)

(continued)

Containment Area Radiation (High Range) instrumentation is a Type C, Category 1 variable provided to monitor the potential for significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. The Containment Area Radiation instrumentation consists of two channels (RIA 57 and 58) with readout on two indicators and one channel recorded. The indicated range is 1 to 10 Rhr.

10. Containment Hydrogen Concentration Containment Hydrogen Concentration instrumentation is a Type A, Category I variable provided to detect high hydrogen concentration conditions that represent a potential for containment breach. This variable Is also Important in verifying the adequacy of mitigating actions. The Containment Hydrogen Concentration instrumentation consists of two channels (MT 80 and 81) with readout on two indicators and one channel recorded. The Indicated range is 0 to 10% hydrogen concentration.

11. Pressurizer Level Pressurizer Level instrumentation is a Type A, Category 1 variable used in combination with other system parameters to determine whether to terminate safety Injection (SI), if still in progress, or to reinitiate SI if it has been stopped. Knowledge of pressurizer water level is also used to verify the unit conditions necessary to establish natural circulation In the RCS and to verify that the unit Is maintained In a safe shutdown condition. The Pressurizer Level Instrumentation consists of three channels (two for Train A and one for Train B) with two channels indicated and one channel recorded.

(Note: three channels are available only two are required). The indicated range is 0 to 400 inches (1 % to 84% level as a percentage of volume).

OCONEE UNITS 1, 2, & 3 B 3.3.8-7 Amendment Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES LCO 12. Steam Generator Water Level (continued)

Steam Generator Water Level instrumentation is a Type A, Category 1 variable provided to monitor operation of decay heat removal via the SG. The indication of SG level is the extended startup range level Instrumentation, covering a span of 0 inches to 388 inches above the lower tubesheet.

The operator relies upon SG level information following an accident (e.g., main steam line break, steam generator tube rupture) to isolate the affected SG to confirm adequate heat sinks for transients and accidents.

The extended startup range Steam Generator Level Instrumentation consists of four transmitters (two per SG) that feed four gauges.

.13. Steam Generator Pressure Steam Generator Pressure instrumentation is a Type A, Category I variable provided to support operator diagnosis of a main steam line break or SG tube rupture accident to identify and Isolate the affected SG. In addition, SG pressure Is a key parameter used by the operator to evaluate primary-to-secondary heat transfer.

Steam generator pressure measurement is provided by two pressure transmitters per SG. Each instrument channel inputs to the ICCM cabinet that provide safety inputs to two indicators located on the main control board in the control room. One channel per SG also provides input to a recorder located in the control room.

14. Borated Water Storage Tank (BWST) Level BWST Level instrumentation Is a Type A, Category I variable provided to support action for long term cooling requirements, i.e.,

to determine when to initiate the switch over of the core cooling pump suction from the BWST to sump recirculation. BWST level measurement is provided by three channels with readout on two indicators and one recorder. (Note: three channels are available only two are required). Two of the three channels provide inputs OCONEE UNITS 1, 2, & 3 B 3.3.8 Amendment Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES LCO 14. Borated Water Storacie Tank (BWST) Level (continued) to the ICCM cabinet which provides inputs to qualified indicators on the Control Board. The third channel provides a safety input to a dedicated recorder. The channels provide level indication over a range of 0 to 50 feet (13% to 100% of volume).

15. Upper Surge Tank (UST) Level Upper Surge Tank Level instrumentation is a Type A, Category 1 variable provided to ensure a water supply for EFW. EFW draws condensate grade suction from the USTs and the Condenser Hotwell.

Two Category 1 instrumentation channels are provided for monitoring UST level. These instrument channels are Inputs to corresponding train A and B Inadequate Core Cooling Monitoring (ICCM) system cabinets. The ICCM Train A cabinet provides UST level input to a dedicated qualified recorder and to a qualified indicator, both located in the Control Room. The ICCM Train B cabinet also provides an input to a qualified indicator located in the Control Room. The range of UST level indication is 0 to 12 feet.

UST Level is the primary indication used by the operator to identify loss of UST volume. The operator can then decide to replenish the UST or align suction to the EFW pumps from the hotwell.

16. Core Exit Temperature Core Exit Temperature Is a Type A, Category 1 variable provided for verification and long term surveillance of core cooling.

The operator relies on this information following a LOCA to secure HPI and throttle LPI, following a SBLOCA to throttle HPI and begin forced HPI cooling if needed, and following a MSLB and SG Tube Rupture to throttle HPI and isolate the affected SG.

OCONEE UNITS 1, 2, & 3 B 3.3.8-9 Amendment Nos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES LCO 16. Core Exit Temperature (continued)

There are a total of 52 Core Exit Thermocouples (CETs) per Oconee Unit. Twenty-four (12 per train) meet seismic and environmental qualification requirements (Category 1). The unit computer Is the primary display for 47 CETs. Five CETs are displayed on the corresponding SSF Unit console. The CETs are distributed to provide monitoring of four or more in each quadrant for each train. The ICCM plasma displays (1 per train) located in the Control Room serve as safety related backup displays for the twenty-four Category 1 CETs. The range of the readouts is 500 F to 23000F.

The ICCM CET function uses inputs from twelve incore thermocouples per train to calculate and display temperatures of the reactor coolant as it exits the core and to provide indication of thermal conditions across the core at the core exit. Each of the twelve qualified thermocouples per train is displayed on a spatially oriented core map on the plasma display. Trending of CET temperature Is available continuously on the plasma display. The average of the five hottest CETs is trendable for the past forty minutes.

An evaluation was made of the minimum number of valid core exit thermocouples (CETs) necessary for inadequate core cooling detection. The evaluation determined the reduced complement of CETs necessary to detect initial core recovery and to trend the ensuing core heatup. The evaluations account for core nonuniformities and cold leg injection. Based on these evaluations, adequate or inadequate core cooling detection is ensured with two sets of five valid CETs.

Table 3.3.8-1 Note (d) indicates that the subcooling margin monitor takes the average of the five highest CETs for each of the ICCM trains. Two channels ensure that a single failure will not disable the ability to determine the representative core exit temperature.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 0 Amendnent Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES LCO 17. Subcoolinq Monitor (continued)

The Subcooling Monitor is a Type A, Category 1 variable provided for verification and long term surveillance of core cooling. This variable is a computer calculated value using various inputs from the Primary System.

Two channels of indication are provided. An operable Subcooling Monitor shall consist of: 1) One direct indication from one channel for RCS Loop Saturation margin and one direct indication from the other channel for Core Saturation margin, or 2) One direct indication from each of the two channels for RCS Loop Saturation margin. The indication readouts are located in the control room.

This variable also inputs to the unit computer through isolation buffers and Is available for trend recording upon operator demand. The range of the readouts Is 200OF subcooled to 500F superheat. The control room display is through the ICCM plasma display unit.

A backup method for determining subcooling margin ensures the capability to accurately monitor RCS subcooling margin (Refer to Specification 5.5.17).

18. HPI System Flow HPI System Flow instrumentation is a Type A, Category 1 variable provided to support action for short term cooling requirements, to prevent HPI pump runout and inadequate NPSH, and to indicate the need for flow cross connect. HPI flow is throttled based on RCS pressure, subcooled margin, and pressurizer level. Flow measurement Is provided by one channel per train with readout on an indicator and recorder. There are two HPI trains. The channels provide flow Indication over a range of 0 to 750 gpm.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 1 Amendment Nos. 335, 335, & 3361

PAM Instrumentation B 3.3.8 BASES LCO 19. LPI System Row (continued)

LPI System Flow instrumentation is a Type A, Category 1 variable provided to support action for long term cooling requirements.

The flow instrumentation is provided to prevent LPI and Reactor Building Spray pump runout as well as providing flow Indication for HPI termination. The indication is also used to identify an LPI pump operating at system pressures above its shutoff head. Flow measurement is provided by one channel per train with readout on an indicator and recorder. There are two LPI trains. Prior to completion of the LPI cross connect modification, the LPI channels provide flow indication over a range of 0 to 6000 gpm.

After completion of the LPI cross connect modification, the LPI channels provide flow indication over a range of 0 to 4000 gpm.

20. Reactor Building Sprav Flow Reactor Building Spray Flow instrumentation is a Type A, Category 1 variable provided to support action for long term cooling requirements and iodine removal and to prevent Reactor Building Spray and LPI pump runout. Flow measurement is provided by one channel per train with readout on an indicator and recorder. There are two RBS trains. The channels provide flow indication over a range from 0 to 2000 gpm.

21. Emeraencv Feedwater Flow EFW Flow instrumentation is a Type D, Category 1 variable provided to monitor operation of RCS heat removal via the SGs.

Two channels provide Indication of EFW Flow to each SG over a range of approximately 100 gpm to 1200 gpm. Redundant monitoring capability is provided by the two independent channels of instrumentation for each SG. Each flow transmitter provides an input to a control room indicator. One channel also provides input to a recorder.

EFW Flow is the primary indication used by the operator to verify that the EFW System is delivering the correct flow to each SG.

However, the primary indication used by the operator to ensure an adequate inventory is SG level.

OCONEE UNITS 1 2 3 B 3.3.8-12 Amendment Nos. 335, 335, & 3361

PAM Instrumentation B 3.3.8 BASES LCO 22. Low Pressure Service Water (LPSW) flow to LPI Coolers (continued)

LPSW flow to LPI Coolers is a Type A, Category 1 variable which is provided to prevent LPSW pump runout and Inadequate NPSH.

LPSW flow to LPI Coolers is throttled to maintain proper flow balance in the LPSW System.

Flow measurement is provided by one channel per train with readout on an indicator and the plant computer via a qualified signal isolator. The channels provide flow indication over a range from 0-8000 gpm.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3.

These variables are related to the diagnosis and preplanned actions required to mitigate accidents and transients. The applicable accidents and transients are assumed to occur In MODES 1, 2, and 3. In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event occurring that would require PAM instrumentation Is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.

ACTIONS The ACTIONS are modified by two Notes. Note 1 Is added to the ACTIONS to exclude the MODE change restriction of LCO 3.0.4. This exception allows entry into an applicable MODE while relying on the ACTIONS even though the ACTIONS may eventually require a unit shutdown. This exception Is acceptable due to the passive function of the instruments, the operator's ability to respond to an accident utilizing alternate instruments and methods, and the low probability of an event requiring these instruments.

Note 2 is added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered Independently for each Function listed In Table 3.3.8-1. When the Required Channels for a function In Table 3.3.8-1 are specified on a per" basis (e.g., per loop, per SG, per penetration flow path), then the Condition may be entered separately for each loop, SG, penetration flow path, etc., as appropriate. The Completion Time(s) of the inoperable channels of a Function are tracked separately for each Function starting from the time the Condition Is entered for that Function.

OCONEE UNITS 1, 2, & 3 B 3.3.8-13 Amendment Nos. 335, 335, & 3361

PAM Instrumentation B 3.3.8 BASES ACTIONS A.1 (continued)

When one or more Functions have one required channel inoperable, the inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion lime is based on operating experience.

This takes into account the remaining OPERABLE channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.

Condition A is modified by a Note indicating this Condition is not applicable to PAM Functions 14, 18, 19, 20, and 22.

B.1 Required Action B.1 specifies initiation of action described In Specification 5.6.6 that requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability and Identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability and given the likelihood of unit conditions that would require Information provided by this instrumentation. The Completion Time of mmediately for Required Action B.1 ensures the requirements of Specification 5.6.6 are initiated.

C.1 When one or more Functions have two required channels inoperable (i.e.,

two channels inoperable in the same Function), one channel in the Function should be restored to OPERABLE status within 7 days. This Condition does not apply to the hydrogen monitor channels. The Completion Time of 7 days Is based on the relatively low probability of an event requiring PAM instrumentation action operation and the availability of aiternative means to obtain the required Information. Continuous operation with two required channels inoperable In a Function Is not acceptable because the altemate Indications may not fully meet all performance of qualification requirements applied to the PAM Instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 4 Amendment Nos. 335, 335, & 3361

PAM nstrumentation B 3.3.8 BASES ACTIONS C.1 (continued)

Condition C Is modified by a Note indicating this Condition is not applicable to PAM Functions 10, 14, 18, 19, 20, and 22.

D.1 When two required hydrogen monitor channels are inoperable, Required Action D.1 requires one channel to be restored to OPERABLE status.

This action restores the monitoring capability of the hydrogen monitor.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time Is based on the relatively low probability of an event requiring hydrogen monitoring. Continuous operation with two required channels inoperable is not acceptable because alternate indications are not available.

Condition D is modified by a Note indicating this Condition is only applicable to PAM Function 10.

E.1 When one required BWST water level channel is inoperable, Required Action E.1 requires the channel to be restored to OPERABLE status.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is based on the relatively low probability of an event requiring BWST water and the availability of the remaining BWST water level channel. Continuous operation with one of the two required channels inoperable is not acceptable because alternate indications are not available. This indication is crucial in determining when the water source for ECCS should be swapped from the BWST to the reactor building sump.

Condition E Is modified by a Note indicating this Condition Is only applicable to PAM Function 14.

F.1 When a flow instrument channel is inoperable, Required Action F.1 requires the affected HPI, LPI, or RBS train to be declared noperable and the requirements of LCO 3.5.2, LCO 3.5.3, or LCO 3.6.5 apply. For Function 22, LPSW flow to LPI coolers, the affected train is the O C O NEE U NITS 1,2,& 3 B 3.3.8^15 Amendment Nos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES ACTIONS F.1 (continued) associated LPI train. For Function 18, HPI flow, an inoperable flow instrument channel causes the affected HPI train's automatic function to be inoperable. The HPI train continues to be manually OPERABLE provided the HPI discharge crossover valves and associated flow instruments are OPERABLE. Therefore, HPI is In a condition where one HPI train is incapable of being automatically actuated but capable of being manually actuated. The required Completion Time for declaring the train(s) Inoperable Is immediately. Therefore, LCO 3.5.2, LCO 3.5.3, or LCO 3.6.5 is entered Immediately, and the Required Actions in the LCOs apply without delay. This action is necessary since there is no alternate flow indication available and these flow indications are key In ensuring each train Is capable of performing ts function following an accident. HPI, LPI, and RBS train OPERABILITY assumes that the associated PAM flow Instrument is OPERABLE because this Indication is used to throttle flow during an accident and assure runout limits are not exceeded or to ensure the associated pumps do not exceed NPSH requirements.

Condition F is modified by a Note indicating this Condition is only applicable to PAM Functions 18, 19, 20, and 22.

G.1 Required Action G.1 directs entry into the appropriate Condition referenced in Table 3.3.8-1. The applicable Condition referenced In the Table is Function dependent. Each time an Inoperable channel has not met the Required Action and associated Completion Time of Condition C, D, or E, as applicable, Condition G is entered for that channel and provides for transfer to the appropriate subsequent Condition.

H.1 and H.2 If the Required Action and associated Completion Time of Conditions C, D or E are not met and Table 3.3.8-1 directs entry into Condition H, the unit must be brought to a MODE in which the requirements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and MODE 4 within 18 hours0.75 days 0.107 weeks 0.0247 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 6 Amendment Nos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES ACTIONS 1.1 (continued)

If the Required Action and associated Completion Time of Condition C, D or E are not met and Table 3.3.8-1 directs entry into Condition I, alternate means of monitoring the parameter should be applied and the Required Action is not to shut down the unit, but rather to follow the directions of Specification 5.6.6 in the Administrative Controls section of the Technical Specifications. These alternative means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allowed time. The report provided to the NRC should discuss the alternative means used, describe the degree to which the alternative means are equivalent to the installed PAM channels, justify the areas In which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

Both the RCS Hot Leg Level and the Reactor Vessel Level are methods of monitoring for inadequate core cooling capability. The subcooled margin monitors (SMM), and core-exit thermocouples (CET) provide an alternate means of monitoring for this purpose. The function of the ICC instrumentation is to Increase the ability of the unit operators to diagnose the approach to and recovery from ICC. Additionally, they aid in tracking reactor coolant inventory.

The alternate means of monitoring the Reactor Building Area Radiation (High Range) consist of a combination of installed area radiation monitors and portable instrumentation.

SURVEILLANCE As noted at the beginning of the SRs, the SRs apply to each PAM REQUIREMENTS instrumentation Function In Table 3.3.8-1 except where Indicated.

SR 3.3.8.1 %

Performance of the CHANNEL CHECK once every 31 days for each required Instrumentation channel that is normally energized ensures that a gross failure of nstrumentation has not occurred. A CHANNEL CHECK Is normally a comparison of the parameter Indicated on one channel with a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two OCONEE UNITS 1, 2, & 3 B 3.3.8-17 Amendment Flos. 335, 335, & 336 1

PAM Instrumentation B 3.3.8 BASES SURVEILLANCE SR 3.3.8.1 (continued)

REQUIREMENTS instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. CHANNEL CHECK will detect gross channel failure; therefore, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared with similar unit instruments located throughout the unit. If the radiation monitor uses keep alive sources or check sources OPERABLE from the control room, the CHANNEL CHECK should also note the detectors response to these sources.

Agreement criteria are based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it Is an Indication that the channels are OPERABLE. If the channels are normally off scale during times when surveillance Is required, the CHANNEL CHECK will only verify that they are off scale In the same direction. Offscale low current loop channels are, where practical, verified to be reading at the bottom of the range and not failed downscale.

The Frequency Is based on operating experience that demonstrates channel failure Is rare. The CHANNEL CHECK supplements less formal but more frequent checks of channels during normal operational use of the displays associated with this LCO's required channels.

SR 3.3.8.2 and SR 3.3.8.3 A CHANNEL CALIBRATION Is a complete check of the instrument channel, Including the sensor. This test verifies the channel responds to measured parameters within the necessary range and accuracy.

Note 1 to SR 3.3.8.3 clarifies that the neutron detectors are not required to be tested as part of the CHANNEL CALIBRATION. There is no adjustment that can be made to the detectors. Furthermore, adjustment of the detectors is unnecessary because they are passive devices, with minimal drift. Slow changes in detector sensitivity are compensated for by performing the daily calorimetric calibration and the monthly axial channel calibration.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 8 Amendment Nos. 335, 335, & 336

PAM Instrumentation B 3.3.8 BASES SURVEILLANCE SR 3.3.8.2 and SR 3.3.8.3 (continued)

REQUIREMENTS For the Containment Area Radiation instrumentation, a CHANNEL CALIBRATION may consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr, and a one point calibration check of the detector below 10 R/hr with a gamma source.

Whenever a sensing element is replaced, the next required CHANNEL CALIBRATION of the resistance temperature detectors (RTD)sensors or Core Exit thermocouple sensors Is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.

SR 3.3.8.2 is modified by a Note indicating that it Is applicable only to Functions 7, 10 and 22. SR 3.3.8.3 is modified by Note 2 Indicating that it Is not applicable to Functions 7, 10 and 22. The Frequency of each SR is based on operating experience and is Justified by the assumption of the specified calibration Interval in the determination of the magnitude of equipment drift.

REFERENCES 1. Duke Power Company letter from Hal B. Tucker to Harold M.

Denton (NRC) dated September 28, 1984.

2. UFSAR, Section 7.5.

3. NRC Letter from Helen N. Pastis to H. B. Tucker, Emergency Response Capability - Conformance to Regulatory Guide 1.97,'

dated March 15, 1988.

4. Regulatory Guide 1.97, Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 3, May 1983.

5. NUREG-0737, Clarification of TMI Action Plan Requirements,"

1980.

6. 10 CFR 50.36.

OCONEE UNITS 1, 2, & 3 B 3.3.8-1 9 Amendment Nos. 335, 335, & 3361

RCS PIV Leakage B 3.4.14 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage BASES BACKGROUND 10 CFR 50.2 (Ref. 1), 10 CFR 50.55a(c) (Ref. 2), and Ref. 3 define RCS PIVs as any two normally closed valves in series within the RCS pressure boundary that separate the high pressure RCS from an attached low pressure system. During their lives, these valves can produce varying amounts of reactor coolant leakage through either normal operational wear or mechanical deterioration. The RCS PIV Leakage LCO allows RCS high pressure operation when leakage through these valves exists in amounts that do not compromise safety.

The PIV leakage limit applies to each individual valve. Leakage through both series PIVs in a line must be included as part of the identified LEAKAGE, governed by LCO 3.4.13, RCS Operational LEAKAGE.' This is true during operation only when the loss of RCS mass through two series valves is determined by a water inventory balance (SR 3.4.13.1). A known component of the identified LEAKAGE before operation begins is the least of the two individual leakage rates determined for leaking series PiVs during the required surveillance testing; leakage measured through one PIV in a line is not RCS operational LEAKAGE if the other is leaktight.

Although this specification provides a limit on allowable PIV leakage rate, its main purpose is to prevent overpressure failure of the low pressure portions of connecting systems. The leakage limit is an indication that the PlVs between the RCS and the connecting systems are degraded or degrading. PIV leakage could lead to overpressure of the low pressure piping or components. Failure consequences could be a loss of coolant accident (LOCA) outside of containment, an unanalyzed accident that could degrade the ability for low pressure Injection.

The basis for this LCO is the 1975 NRC Reactor Safety Study" (Ref. 4) that identified potential intersystem LOCAs as a significant contributor to the risk of core melt.

A subsequent study (Ref. 5) evaluated various PIV configurations to determine the probability of intersystem LOCAs.

PIVs are provided to isolate the RCS from the Low Pressure Injection (LPI)

System.

OCONEE UNITS 1, 2, & 3 B 3.4.14-1 Amendment Nos. 335, 335, & 336 1

RCS PIV Leakage B 3.4.14 BASES BACKGROUND Violation of this LCO could result in continued degradation of a PIV, which (continued) could lead to overpressurization of a low pressure system and the loss of the integrity of a fission product barrier.

APPLICABLE Reference 4 identified potential intersystem LOCAs as a significant SAFETY ANALYSES contributor to the risk of core melt. The dominant accident sequence in the intersystem LOCA category is the failure of the low pressure portion of the LPI System outside of containment. The accident is the result of a postulated failure of the PIVs, which are part of the reactor coolant pressure boundary (RCPB), and the subsequent pressurization of the LPI System downstream of the PIVs from the RCS. Because the low pressure portion of the LPI System is designed for pressures significantly less than RCS pressure, overpressurization failure of the LPI low pressure line would result in a LOCA outside containment and subsequent risk of core melt.

Reference 5 evaluated various PIV configurations, leakage testing of the valves, and operational changes to determine the effect on the probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce the probability of an intersystem LOCA.

RCS PIV leakage satisfies Criterion 2 of 10 CFR 50.36 (Ref. 6).

LCO RCS PIV leakage is identified LEAKAGE into closed low pressure systems connected to the RCS. PIV leakage is usually on the order of drops per minute. Leakage that increases significantly suggests that something is operationally wrong and corrective action must be taken.

The PIV leakage limit for specified valves is 0.5 gpm per nominal inch of valve size with a maximum limit of 5 gpm. A study concluded a leakage rate limit based on valve size was superior to a single allowable value.

Reference 7 permits leakage testing at a lower pressure differential than between the specified maximum RCS pressure and the normal pressure of the connected system during RCS operation (the maximum pressure differential) in those types of valves in which the higher service pressure will tend to diminish the overall leakage channel opening. In such cases, the observed rate may be adjusted to the maximum pressure differential by assuming leakage is directly proportional to the pressure differential to the one half power.

The LCO is modified by three Notes. These Notes exclude RCS PIVs that are required to meet the LCO requirement based on the status of the OCONEE UNITS 1, 2, & 3 B 3.4.14-2 Amendment Nos. 335, 335, & 336 1

RCS PIV Leakage B 3.4.14 BASES LCO passive LPI cross connect modification for each Unit. Note 1 indicates that (continued) prior to completion of the passive LPI cross connect modification, the limits for LP-176 and LP-177 are not applicable. Note 2 indicates that after completion of the passive LPI cross connect modification, the limits for LP-47 and LP-48 are not applicable except as stated in Note 3. Note 3 indicates that after completion of the LPI passive cross connect modification on each Unit, the limits of both LP-47 and LP-48 may be met in lieu of either LP-1 76 and LP-1 77 limits. If either LP-1 76 or LP-1 77 limits are not met both LP-47 and LP-48 limits must be met.

APPLICABILITY In MODES 1, 2, 3, and 4, this LCO applies because the PIV leakage potential is greatest when the RCS is pressurized. In MODE 4, valves in the DHR flow path are not required to meet the requirements of this LCO when in, or during the transition to or from, the DHR mode of operation.

In MODES 5 and 6, leakage limits are not provided because the lower reactor coolant pressure results in a reduced potential for leakage and for a LOCA outside the containment.

ACTIONS The ACTIONS are modified by two Notes. Note 1 is added to provide clarification that each flow path allows separate entry into a Condition. This is allowed based upon the functional Independence of the flow path.

Note 2 requires an evaluation of affected systems if a PIV is inoperable.

The leakage may have affected system OPERABILITY, or isolation of a leaking flow path with an alternate valve may have degraded the ability of the interconnected system to perform its safety function.

A.1 and A.2 The flow path with leakage must be isolated by two valves. Required Actions A.1 and A.2 are modified by a Note that the valves used for isolation must meet the same leakage requirements as the PlVs and must be on the RCS pressure boundary or the high pressure portion of the system.

Required Action A.1 requires that the isolation with one valve must be performed within 4 hours0.167 days 0.0238 weeks 0.00548 months . Four hours provides time to reduce leakage in excess of the allowable limit and to isolate the affected system if leakage cannot be reduced. The 4 hours0.167 days 0.0238 weeks 0.00548 months allows the actions and restricts the operation with leaking isolation valves.

OCONEE UNITS 1, 2, & 3 B 3.4.14-3 Amendment Nos. 335, 335, & 336 l

RCS PIV Leakage B 3.4.14 BASES ACTIONS A.1 and A.2 (continued)

Required Action A.2 specifies that the double isolation barrier of two valves be restored by closing some other valve qualified for isolation. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months time after exceeding the limit considers the time required to complete the Action and the low probability of a second valve failing during this time period.

B.1 and B.2 If Required Actions and associated Completion Times are not met, the unit must be brought to a MODE in which the requirement does not apply. To achieve this status, the unit must be brought to MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and to MODE 5 within 36 hours1.5 days 0.214 weeks 0.0493 months . This Required Action may reduce the leakage and also reduces the potential for a LOCA outside the containment. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.4.14.1 REQUIREMENTS Performance of leakage testing on each required RCS PIV or isolation valve used to satisfy Required Action A.1 or A.2 is required to verify that leakage is below the specified limit and to identify each leaking valve. The leakage limit of 0.5 gpm per inch of nominal valve diameter up to 5 gpm maximum applies to each valve. Leakage testing requires a stable pressure condition.

For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves. If the PIVs are not individually leakage tested, one valve may have failed completely and not detected if the other valve in series meets the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

Testing is to be performed every 18 months, a typical refueling cycle, if the unit does not go into MODE 5 for at least 7 days. The 18 month Frequency is consistent with 10 CFR 50.55a(g) (Ref. 8) as contained in the Inservice Testing Program, is within frequency allowed by the American Society of Mechanical Engineers (ASME) Code, Section Xl (Ref. 7), and is based on the need to perform such surveillances under conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the unit at power.

OCONEE UNITS 1,2, &3 B 3.4.14-4 Amendment Nos. 335, 335, & 336 l

RCS PIV Leakage B 3.4.14 BASES SURVEILLANCE SR 3.4.14.1 (continued)

REQUIREMENTS The leakage limit is to be met at the RCS pressure associated with MODES 1 and 2. This permits leakage testing at high differential pressures with stable conditions not possible in the MODES with lower pressures.

To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable conditions to allow for performance of this Surveillance. The Note that allows this provision Is complimentary to the Frequency of prior to entry into MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months. In addition, this Surveillance is not required to be performed on the LPI System when the LPI System is aligned to the RCS in the decay heat removal mode of operation. PVs contained in the DHR flow path must be leakage rate tested after DHR is secured and stable unit conditions and the necessary differential pressures are established. For the purposes of meeting this SR, test activities including contingencies may be performed prior to declaring a PIV inoperable. A PIV will be considered "in testing" until the test procedure is complete, or the test coordinator determines that further test contingencies would not be expected to produce an acceptable result.

REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3 NRC letter to DPC, Order for Modification of Ucense Conceming Primary Coolant System Pressure Isolation Valves,* dated April 20, 1981.

4. NUREG-75/014, Appendix V, October 1975.

5. NUREG-0677, NRC, May 1980.

6. 10 CFR 50.36.

OCONEE UNITS 1, 2, & 3 B 3.4.14-5 Amendment Nos. 335, 335, & 336 l

RCS PIV Leakage B 3.4.14 BASES REFERENCES 7. ASME, Boiler and Pressure Vessel Code, Section Xl.

(continued)

8. 10 CFR 50.55a(g).

OCONEE UNITS 1, 2, & 3 B 3.4.14-6 Amendment Nos. 339, 335, & 336 l

LPI B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.3 Low Pressure Injection (LPI)

BASES BACKGROUND The function of the ECCS is to provide core cooling to ensure that the reactor core is protected after any of the following accidents:

a. Loss of coolant accident (LOCA);

b. Rod ejection accident (REA);

c. Steam generator tube rupture (SGTR); and

d. Main steam line break (MSLB).

There are two phases of ECCS operation: injection and recirculation. In the injection phase, all injection is initially added to the Reactor Coolant System (RCS) via the cold legs or Core Flood Tank (CFT) lines to the reactor vessel.

After the borated water storage tank (BWST) has been depleted, the recirculation phase is entered as the suction is transferred to the reactor building sump.

Two redundant low pressure injection (LPI) trains are provided. The LPI trains consist of piping, valves, instruments, controls, heat exchangers, and pumps, such that water from the borated water storage tank (BWST) can be injected into the Reactor Coolant System (RCS). In MODES 1, 2 and 3, both trains of LPI must be OPERABLE. This ensures that 100% of the core cooling requirements can be provided even in the event of a single active failure. For Unit(s) in which the passive LPI cross connect modification has been completed, the LPI discharge header manual crossover valves inside containment must be maintained administratively open in MODE 1, 2, and 3 to assure abundant, long term cooling. For Unit(s) in which the passive LPI cross connect modification has not been completed, the LPI discharge header crossover valves outside containment must be manually (locally and remotely) OPERABLE in MODE 1, 2, and 3 to assure abundant, long term core cooling. Only one LPI train is required for MODE 4.

A suction header supplies water from the BWST or the reactor building sump to the LPI pumps. LPI discharges into each of the two core flood nozzles on the reactor vessel that discharge into the vessel downcomer area.

The LPI pumps are capable of discharging to the RCS at an RCS pressure of approximately 200 psia. When the BWST has been nearly emptied, the OCONEE UNITS 1, 2, & 3 B 3.5.3-1 Amendment Nos. 335, 335, & 336 1

LPI B 3.5.3 BASES BACKGROUND suction for the LPI pumps is manually transferred to the reactor building (continued) sump. In the long term cooling period, flow paths in the LPI System are established to preclude the possibility of boric acid in the core region reaching an unacceptably high concentration. Two gravity flow paths are available by means of a drain line from the hot leg to the Reactor Building sump which draws coolant from the top of the core, thereby inducing core circulation. The system is designed with redundant drain lines.

During a large break LOCA, RCS pressure will rapidly decrease. The LPI System is actuated upon receipt of an ESPS signal. If offsite power is available, the safeguard loads start immediately. If offsite power is not available, the Engineered Safeguards (ES) buses are connected to the Keowee Hydro Units. The time delay (38 seconds) associated with Keowee Hydro Unit startup and pump starting determines the time required before pumped flow is available to the core following a LOCA. Full LPI flow is not available until the LPI valve strokes full open.

The LPI and HPI (LCO 3.5.2, High Pressure Injection (HPI)"), along with the passive CFTs and the BWST covered in LCO 3.5.1, Core Flood Tanks (CFTs)," and LCO 3.5.4, Borated Water Storage Tank (BWST),N provide the cooling water necessary to meet 10 CFR 50.46 (Ref. 1).

APPLICABLE The LCO helps to ensure that the following acceptance criteria for the SAFETY ANALYSES ECCS, established by 10 CFR 50.46 (Ref. 1), will be met following a LOCA:

a. Maximum fuel element cladding temperature is 5 22000 F;

b. Maximum cladding oxidation is 5 0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium water reaction is

0.01 times the hypothetical amount generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react;

d. Core is maintained in a coolable geometry; and

e. Adequate long term core cooling capability is maintained.

The LCO also helps ensure that reactor building temperature limits are met.

OCONEE UNITS 1, 2, & 3 B 3.5.3-2 Amendment Nos. 335, 335, & 336 1

LPl B 3.5.3 BASES APPLICABLE The LPI System is assumed to provide injection in the large break LOCA SAFETY ANALYSES analysis at full power (Ref. 2). This analysis establishes a minimum (continued) required flow for the LPI pumps, as well as the minimum required response time for their actuation.

The large break LOCA event assumes a loss of offsite power and a single failure (loss of the CT-4 transformer). For analysis purposes, the loss of offsite power assumption may be conservatively inconsistent with the assumed operation of some equipment, such as reactor coolant pumps (Ref.

3). During the blowdown stage of a LOCA, the RCS depressurizes as primary coolant is ejected through the break into the reactor building. The nuclear reaction is terminated by moderator voiding during large breaks. Following depressurization, emergency cooling water is injected into the reactor vessel core flood nozzles, then flows into the downcomer, fills the lower plenum, and refloods the core.

In the event of a Core Flood line break which results in a LOCA, with a concurrent single failure on the unaffected LPI train opposite the Core Flood line break, for Unit(s) in which the passive LPI cross connect modification is complete, the system is fitted with flow restricting devices in each injection leg and an upstream cross-connect pipe. These serve to limit the ECCS spillage through the faulted header and ensure that flow is diverted from the faulted header to the intact header at lower pressures. These flow restricting devices also provide LPI pump run-out protection during LBLOCAs. For Unit(s) in which the passive LPI cross connect modification is not complete, the LPI discharge header crossover valves (LP-9 and LP-1 0) outside containment must be capable of being manually (locally and remotely) opened and the LPI cooler outlet throttle valves and LPI header isolation valves must be capable of being manually opened to provide assurance that flow can be established in a timely manner even If the capability to operate them from the control room is lost. For Unit(s) in which the passive LPI cross connect modification is not complete, these manual actions will allow cross-connection of the LPI pump discharge to the intact LPI/Core Flood tank header to provide abundant emergency core cooling.

The safety analyses show that an LPI train will deliver sufficient water to match decay heat boiloff rates for a large break LOCA.

In the large break LOCA analyses, full LPI is not credited until 53 seconds after actuation of the ESPS signal. This is based on a loss of offsite power and the associated time delays In Keowee Hydro Unit startup, valve opening and pump start. Further, LPI flow is not credited until RCS pressure drops below the pump's shutoff head. For a large break LOCA, HPI is not credited at all.

The LPI trains satisfy Criterion 3 of 10 CFR 50.36 (Ref. 4).

OCONEE UNITS 1 2 3 B 3.5.3-3 Amendment Nos. 335, 335, 336 1

LPI B 3.5.3 BASES (continued)

LCO In MODES 1, 2, and 3, two independent (and redundant) LPI trains are required to ensure that at least one LPI train is available, assuming a single failure in the other train. Additionally, individual components within the LPI trains may be called upon to mitigate the consequences of other transients and accidents. Each LPI train includes the piping, instruments, pumps, valves, heat exchangers and controls to ensure an OPERABLE flow path capable of taking suction from the BWST upon an ES signal and the capability to manually (remotely) transfer suction to the reactor building sump. The safety grade flow indicator of an LPI train Is required to support OPERABILITY of the LPI and RBS trains to preclude NPSH or runout pro-blems. In addition, during an event, RBS train flow must be monitored and controlled to support the LPI pumps to ensure that the NPSH requirements for the LPI pumps are not exceeded. If the flow instrumentation or the capability to control the flow in a RBS train is unavailable then the associated IPI train's OPERABILITY is affected until such time as the RBS train is restored or the associated RBS pump is placed in a secured state to prevent actuation during an event. The safety grade flow indicator associated with LPSW flow to an LPI cooler is required to be OPERABLE to support LPI train OPERABILITY.

In MODE 4, one of the two LPI trains is required to ensure sufficient LPI flow Is available to the core.

During an event requiring LPI injection, a flow path is required to provide an abundant supply of water from the BWST to the RCS, via the LPI pumps and their respective supply headers, to the reactor vessel. In the long term, this flow path may be switched to take its supply from the reactor building sump.

This LCO is modified by four Notes. Note 1 changes the LCO requirement when in MODE 4 for the number of OPERABLE trains from two to one.

Note 2 allows an LPI train to be considered OPERABLE during alignment, when aligned or when operating for decay heat removal if capable of being manually (remotely) realigned to the IPI mode of operation. This provision Is necessary because of the dual requirements of the components that comprise the LPI and decay heat removal modes of the LPI System. Note 3 requires the LPI discharge header crossover valves (LP-9 and LP-10) outside containment to be OPERABLE in MODES 1, 2, and 3 until after completion of the passive IPI cross connect modification on the respective Unit. Note 4 requires the LPI discharge header crossover valves inside containment to be open in MODES 1, 2, and 3 after completion of the passive LPI cross connect modification modification on the respective Unit. If one of these valves is closed, then the system will be unable to sustain a single failure.

OCONEE UNITS 1 2 3 B 3.5.3-4 Amendment Nos. 335, 335, & 336 1

LPI B 3.5.3 BASES LCO The flow path for each train must maintain its designed independence (continued) outside containment to ensure that no single failure can disable both IPI trains. If train separation is not maintained outside containment then only one LPI train is considered OPERABLE.

APPLICABILITY In MODES 1, 2 and 3, the LPI train OPERABILITY requirements for the Design Basis Accident, a large break LOCA, are based on full power operation. Prior to completion of the passive LPI cross connect modification, the LPI discharge crossover valve OPERABILITY requirements for CFT line break are based on full power operation. After the completion of the passive LPI cross connect modification, the position requirements of the LPI discharge crossover valves inside containment for the CFT line break are based on full power operation. Although reduced power would not require the same level of performnance, the accident analysis does not provide for reduced cooling requirements in the lower MODES.

In MODE 4, one OPERABLE LPI train is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the limited core cooling requirements.

In MODES 5 and 6, unit conditions are such that the probability of an event requiring LPI injection is extremely low. Core cooling requirements in MODE 5 are addressed by LO 3.4.7, RCS Loops-MODE 5, Loops Filled," and LCO 3.4.8, RCS Loops-MODE 5, Loops Not Filled." MODE 6 core cooling requirements are addressed by LCO 3.9.4, DHR and Coolant Circulation-High Water Level," and LCO 3.9.5, DHR and Coolant Circulation-Low Water Level."

ACTIONS A.1 With one LPI train inoperable in MODES 1, 2 or 3, the inoperable train must be returned to OPERABLE status within 7 days. The 7 day Completion Time is based on the findings of the deterministic and probabilistic analysis in Reference 7. Reference 7 concluded that extending the Completion Time to 7 days for an Inoperable LPI train improves plant operational flexibility while simultaneously reducing overall plant risk. Specifically, the risk incurred by having the LPI train unavailable for a longer time at power will be substantially offset by the benefits associated with avoiding unnecessary plant transitions and by reducing risk during shutdown operations.

OCONEE UNITS 1, 2, & 3 B 3.5.3-5 Amendment Nos. 335, 335, & 336

LPI B 3.5.3 BASES ACTIONS B.1 (continued)

With one or more required LPI discharge crossover valves outside containment inoperable, the inoperable valve(s) must be returned to OPERABLE status within 7 days. The 7 day Completion Time is based on the findings of the deterministic and probabilistic analysis in Reference 7.

C.1 With one or more required LPI discharge header manual crossover valves inside containment closed, the closed valve(s) must be opened within 7 days. The 7 day Completion Time is based on the findings of the deterministic and probabilistic analysis in Reference 7.

D.1 If the Required Action and associated Completion Time of Condition A, B, or C are not met, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours0.5 days 0.0714 weeks 0.0164 months and MODE 4 within 60 hours2.5 days 0.357 weeks 0.0822 months . The allowed Completion Times are reasonable, based on operating experience, reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

E.1 With one required LPI train inoperable in MODE 4, the unit is not prepared to respond to an event requiring low pressure injection and may not be prepared to continue cooldown using the LPI pumps and LPI heat exchangers. The Completion Time of immediately, which would initiate action to restore at least one LPI train to OPERABLE status, ensures that prompt action is taken to restore the required LPI capacity. Normally, in MODE 4, reactor decay heat must be removed by a decay heat removal (DHR) loop operating with suction from the RCS. If no LPI train is OPERABLE for this function, reactor decay heat must be removed by some alternate method, such as use of the steam generator(s).

The alternate means of heat removal must continue until one of the inoperable LPI trains can be restored to operation so that continuation of decay heat removal (DHR) is provided.

OCONEE UNITS 1, 2, & 3 B 3.5.3-6 Amendment Nos. 335. 335, & 336

LPI B 3.5.3 BASES ACTIONS E.1 (continued)

With the LPI pumps (including the non ES pump) and LPI heat exchangers inoperable, it would be unwise to require the unit to go to MODE 5, where the only available heat removal system is the LPI trains operating in the DHR mode. Therefore, the appropriate action is to initiate measures to restore one LPI train and to continue the actions until the subsystem is restored to OPERABLE status.

E.2 Required Action E.2 requires that the unit be placed in MODE 5 within 24 hours1 days 0.143 weeks 0.0329 months . This Required Action is modified by a Note that states that the Required Action is only required to be performed if a DHR loop is OPERABLE. This Required Action provides for those circumstances where the LPI trains may be inoperable but otherwise capable of providing the necessary decay heat removal. Under this circumstance, the prudent action is to remove the unit from the Applicability of the LCO and place the unit in a stable condition in MODE 5. The Completion Time of 24 hours1 days 0.143 weeks 0.0329 months is reasonable, based on operating experience, to reach MODE 5 in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.5.3.1 REQUIREMENTS Verifying the correct alignment for manual and non-automatic power operated valves in the LPI flow paths provides assurance that the proper flow paths will exist for LPI operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. Similarly, this SR does not apply to automatic valves since automatic valves actuate to their required position upon an accident signal.

This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. The 31 day Frequency is appropriate because the valves are operated under administrative control, and an inoperable valve position would only affect a single train. This Frequency has been shown to be acceptable through operating experience.

When in MODE 4 an LPI train may be considered OPERABLE during alignment, when aligned or when operating for decay heat removal if capable of being manually realigned to the LPI mode of operation.

Therefore, for this condition, the SR verifies that LPI is capable of being manually realigned to the LPI mode of operation.

OCONEE UNITS 1, 2, & 3 B 3.5.3-7 Amendment.Nos. 335, 335, & 336 l

LPI B 3.5.3 BASES SURVEILLANCE SR 3.5.3.2 REQUIREMENTS (continued) With the exception of systems in operation, the LPI pumps are normally in a standby, non-operating mode. As such, the flow path piping has the potential to develop voids and pockets of entrained gases. Venting the LPI pump casings periodically reduces the potential that such voids and pockets of entrained gases can adversely affect operation of the LPI System. This will also minimize the potential for water hammer, pump cavitation, and pumping of noncondensible gas (e.g., air, nitrogen, or hydrogen) into the reactor vessel following an ESPS signal or during shutdown cooling. This Surveillance is modified by a Note that indicates it is not applicable to operating LPI pump(s). The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the LPI piping and the existence of procedural controls governing system operation.

SR 3.5.3.3 Periodic surveillance testing of LPI pumps to detect gross degradation caused by impeller structural damage or other hydraulic component problems is required by Section Xl of the ASME Code (Ref. 6). SRs are specified in the Inservice Testing Program, which encompasses Section Xl of the ASME Code.

SR 3.5.3.4 and SR 3.5.3.5 These SRs demonstrate that each automatic LPI valve actuates to the required position on an actual or simulated ESPS signal and that each LPI pump starts on receipt of an actual or simulated ESPS signal. This SR is not required for valves that are locked, sealed, or otherwise secured in position under administrative controls. The test will be considered satisfactory if control board indication verifies that all components have responded to the ESPS actuation signal properly (all appropriate ESPS actuated pump breakers have opened or closed and all ESPS actuated valves have completed their travel). The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment. The actuation logic is tested as part of the ESPS testing, and equipment performance is monitored as part of the Inservice Testing Program.

O C O NEE U NIT S 1,2,& 3 B 3.5.3-8 Amendment Nos. 335, 335, & 336 1

LPI B 3.5.3 BASES SURVEILLANCE SR 3.5.3.6 REQUIREMENTS (continued) Periodic inspections of the reactor building sump suction inlet ensure that it is unrestricted and stays in proper operating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage, on the need to preserve access to the location, and on the potential for an unplanned transient if the Surveillance were performed with the reactor at power. This Frequency has been found to be sufficient to detect abnormal degradation and has been confirmed by operating experience.

SR 3.5.3.7 The function of the required LPI discharge header crossover valves (LP-9, LP-1 0) outside containment is to open and allow a cross-connection between LPI trains. The LPI cooler outlet throttle valves (LP-12, LP-14)

I and LPI header isolation valves (LP-1 7, LP-1 8) must be capable of being manually opened to provide assurance that flow can be established in a timely manner even the capability to operate them from the control room is lost. Manually cycling each valve open demonstrates the ability to fulfill this function. This test is performed on an 18 month Frequency. Operating experience has shown that these components usually pass the Surveillance when performed at this Frequency. Therefore, the Frequency is acceptable from a reliability standpoint. The Surveillance is modified by a note ndicating that it is not applicable after completion of the passive LPI cross connect modification on each Unit.

REFERENCES 1. 10 CFR 50.46.

2. UFSAR, Section 15.14.3.3.6.

3. UFSAR, Section 15.14.3.3.5.

4. 10 CFR 50.36.

5. NRC Memorandum to V. Stello, Jr., from R.L. Baer, Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975.

6. ASME, Boiler and Pressure Vessel Code, Section Xl, Inservice Inspection, Article IWV-3400.

OCONEE UNITS 1, 2, & 3 B 3.5.3-9 Amendment Nos. 335, 335, & 336 1

LPI B 3.5.3 BASES REFERENCES 7. NRC Safety Evaluation of Babcok & Wilcox Owners Group (continued) (B&WOG) Topical Report BAW-2295, Revision 1, Justification for the Extension of Allowed Outage Time for Low Pressure Injection and Reactor Building Spray systems,' (TAC No. MA3807) dated June 30, 1999.

OCONEE UNITS 1, 2, & 3 B 3.5.3-1 0 Amendment Nos. 335, 335, & 336 1

v t e Letter Sequence Acceptance Review
TAC:MB8083, (Approved, Closed) TAC:MB8084, (Approved, Closed) TAC:MB8085, (Approved, Closed)
Initiation Acceptance Administration Meeting Questions Answers Results Approval Other:
MONTHYEAR2003-05-01 [Table View]

ML032731475

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