ML063470137

Technical Specification Bases (Tsb) Change

ML063470137
Person / Time
Site:	Oconee
Issue date:	12/06/2006
From:	Brandi Hamilton Duke Energy Carolinas, Duke Energy Corp, Duke Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML063470137 (71)

Text

hDue BRUCE H HAMILTON Vice President 6 oEnergy Oconee Nuclear Station Duke Energy Corporation ON01 VP / 7800 Rochester Highway Seneca, SC 29672 864 885 3487 December 6, 2006 864 885 4208 fax bhhamilton@duke-energy.

corn U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Attention:

Document Control Desk

Subject:

Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC Oconee Nuclear Station'Docket Numbers 50-269, 270, and 287 Technical Specification Bases (TSB) Change Please see attached a revision to TSB 3.3.8, Post Accident Monitoring Instrumentation:

Chart Recorder Replacement.

TSB Change 2006-04 revises TS Bases 3.3.8 LCO as follows: a) LCO 14 (BWST Level) to indicate that the "third channel provides a safety input to dedicated recorder" to read "third channel provides an input to a recorder." b) LCO 15 (UST level) statement concerning a "dedicated qualified recorder" to delete the words "dedicated qualified." c) LCO 21 (Emergency Feedwater Flow) to indicate that one channel provides input to a recorder on Units 2 and 3 while for Unit 1, one channel provides input to a recorder on Units 2 and 3 while for Unit 1, one channel provides input to separate recorders.

Attachment 1 contains the new TSB pages, Attachment 2 contains the marked up version of the TSB pages.If any additional information is needed, please contact Reene Gambrell at 864-885-3364.

Very truly yours, B. H. Hamilton, Vice President Oconee Nuclear Site www -i ke-energy.

cor in C U. S. Nuclear Regulatory Commission December 6, 2006 Page 2 cc: Mr. L. N. Olshan Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Mr. W. D. Travers, Regional Administrator U. S. Nuclear Regulatory Commission

-Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, Georgia 30303 Dan Rich Senior Resident Inspector Oconee Nuclear Station Mr. Henry Porter, Director Division of Radioactive Waste Management Bureau of Land and Waste Management Department of Health & Environmental Control 2600 Bull Street Columbia, SC 29201 bcc: w/o attachments L. F. Vaughn C. J. Thomas -MNS R. D. Hart -CNS R. L. Gill -NRI&IA w/attachments Document Management ELL NSRB MR Coordinator (Ron Harris)Licensing Working Group Attachment

1. 1 Proposed Bases revision Remove Page B 3.3.8-1 thru 19 Insert Page B 3.3.8-1 thru 19 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 identified 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 BASES REVISION DATED 11/21/06 I 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 1 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 BASES REVISION DATED 11/21/06 1 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 1 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 BASES REVISION DATED 11/21/06 I 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 1 E-8% to 200% RTP.2. Reactor Coolant System (RCS) Hot Leg 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 50EF to 700EF.3, 5. Reactor Vessel Head Level and RCS Hot Leg Level Reactor Vessel Water Level instrumentation is a Type B, Category 1 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-LT01 26) 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 B 3.3.8-4 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES LCO 4. RCS Pressure (Wide Ranqe) (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 injection (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 Ranqe)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 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES LCO 7. Containment Pressure (Wide Range)(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 isolation 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 isolation 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, if a 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 indication 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 BASES REVISION DATED 11/21/06 I 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 7 R/hr.10. Not Used 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 two channels (Train A channel consisting of two indications and Train B channel consisting of one indication) with two channels indicated and one channel recorded.(Note: two indications are available in Train A, but only one is required).

The indicated range is 0 to 400 inches (11% to 84%level as a percentage of volume).OCONEE UNITS 1, 2, & 3 B 3.3.8-7 BASES REVISION DATED 11/21/06 I 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 1 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 1 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 3.3.8-8 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES LCO 14. Borated Water Storage Tank (BWST) Level (continued) to the ICCM cabinet which provides inputs to qualified indicators on the Control Board. The third channel provides an input to a 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 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 BASES REVISION DATED 11/21/06 I 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 50°F to 2300 0 F.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 3.3.8-10 BASES REVISION DATED 11/21/06 I 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 200°F subcooled to 50°F 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 3.3.8-11 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES LCO 19. LPI System Flow (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. Not used 21. Emerqency 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 on Units 2 and 3. On Unit 1, one channel provides input to separate recorders for EFW flow to each SG.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.22. Low Pressure Service Water (LPSW) flow to LPI Coolers 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.OCONEE UNITS 1, 2, & 3 B 3.3.8-12 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES (continued)

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.A.1 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 Time 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, and 22.OCONEE UNITS 1, 2, & 3 B 3.3.8-13 BASES REVISION DATED 11/21/06 1 PAM Instrumentation B 3.3.8 BASES ACTIONS B.1 (continued)

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 "Immediately" 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 alternative means to obtain the required information.

Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate 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. Condition C is modified by a Note indicating this Condition is not applicable to PAM Functions 14, 18, 19, and 22.D.1 Not Used.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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 OCONEE UNITS 1, 2, & 3 B 3.3.8-14 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES ACTIONS E.1 (continued) 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 or LPI train to be declared inoperable and the requirements of LCO 3.5.2 or LCO 3.5.3 apply. For Function 22, LPSW flow to LPI coolers, the affected train is the 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 or LCO 3.5.3 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 its function following an accident.

HPI and LPI 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, 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 OCONEE UNITS 1, 2, & 3 B 3.3.8-15 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES ACTIONS G.1 (continued) 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 within 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. 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.1.1 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.

OCONEE UNITS 1, 2, & 3 B 3.3.8-16 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES (continued)

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 instrumentation 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 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 detector's 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.OCONEE UNITS 1, 2, & 3 B 3.3.8-17 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES SURVEILLANCE SR 3.3.8.2 and SR 3.3.8.3 (continued)

REQUIREMENTS 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.

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 and 22. SR 3.3.8.3 is modified by Note 2 indicating that it is not applicable to Functions 7 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.OCONEE UNITS 1, 2, & 3 B 3.3.8-18 BASES REVISION DATED 11/21/06 I PAM Instrumentation B 3.3.8 BASES REFERENCES

5. NUREG-0737, "Clarification of TMI Action Plan Requirements," (continued) 1980.6. 10 CFR 50.36.OCONEE UNITS 1, 2, & 3 B 3.3.8-19 BASES REVISION DATED 11/21/06 I Attachment

1. 2 Markup of current Bases PAM Instrumentation B 3.3.8 BASES LCO an 14. Borated Water Storage Tank (BWST) Level (continued) to the ICCM cabinet which provides inputs to qualified indicators on the Control Board. The third channel provides input to a dic ed 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 de ted lified 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.BASES REVISION DAT I I xx/xxo6 IJ PAM Instrumentation B 3.3.8 BASES LCO 19. LPI System Flow (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. Not used 21. Emergency 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 on Units 2 and 3. On Unit of instrumentation for each SG. Each flow transmitter provides an 1, one channel provides input to a control room indicator.

One channel also provides input input to separate recorders to a recordero for EFW flow to each SG.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.22. Low Pressure Service Water (LPSW) flow to LPI Coolers 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.OCONEE UNITS 1, 2, & 3 B 3.3.8-12 [AmyF'dment NosA50, 352, y9351 I BASES REVISION DATED xx/xx/06 1/

Attachment

1. 3 1OCFR50.59 Evaluation 2TA(;A04 C-k P4g& zooc.-oq 14r-dnj, See Attachment I

SUMMARY

OF EVALUATION:

See Attachment I Does the proposed activity require a modification, deletion, or addition to the Technical Specifications?

[ YES NO If "YES," then Identify Technical Specification sections that require change.For each question, check the correct response and provide Justification.

If the answer to any question is "YES," then the proposed activity may not be implemented until approval Is obtained from the NRC.-Iu I---o pa7LCp 16, 17 2-a4 C,)-r. R c 4 zy-ýf~~qA 1-P,- I't&/-7 4, 4-e-I C- , C-1'< -.':)'ý2-oa6- 10 )

EFFECT ON ACCIDENTS AND MALFUNCTIONS EVALUATED IN THE LICENSING BASIS DOCUMENTS 1. Does the proposed activity result In more than a minimal Increase In the frequency of occurrence or an accident previously evaluated in the UFSAR?JUSTIFICATION:

See Attachment 1 2. Does the proposed activity result in more than a minimal Increase in the likelihood of occurrence of a malfunction of an SSC Important to safety previously evaluated in the UFSAR?JUSTIFICATION:

See Attachment I 3. Does the proposed activity result Inmore than a minimal Increase In the consequences of an accident previously evaluated In the UFSAR?JUSTIFICATION:

See Attachment I 4. Does the proposed activity result In more than a minimal Increase in the consequences of a malfunction of an SSC Important to safety previously evaluated in the UFSAR?JUSTIFICATION:

See Attachment 1 POTENTIAL FOR CREATION OF A NEW TYPE OF UNANALYZED EVENT 5. Does the proposed activity create a possibility for an accident of a different type than previously evaluated in the UFSAR?JUSTIFICATION:

See Attachment I 6. Does the proposed activity create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated In the UFSAR?JUSTIFICATION:

See Attachment I IMPACT ON FISSION PRODUCT BARRIERS 7. Does the proposed activity result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or mitered?JUSTIFICATION:

See Attachment I O ES ONO[3 YES ONO[I YES ONO 0]YES 1 NO 0]YES ONO 0 YES ONO D YES 0 NO IMPACT ON EVALUATION CONSERVATISM

8. Does the proposed activity result In a departure from a method of evaluation described In the UFSAR 0 YES 0 NO used In establishing the design bases or in the safety analyses?JUSTIFICATION:

See Attachment I List consulted references.

At a minimum, the UFSAR and Technical Specification should be Identified with applicable revisions and amendment numbers. For other referenced items, Include sufficient Identifylng detail to facilitate independent review and retrieval.

See Attachment I

ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: I of 41 SCOPE DESCRIPTION The purpose of this design change OD100076 Unit 1 activity is two fold. Part ELI will install a Foundation fieldbus host system and replace obsolete pneumatic and electronic instruments with instruments using the Foundation fieldbus digital communication standard.

Part EL2 will remove and replace, where required, obsolete chart recorders from the control boards. Additionally, new Control Room video displays and Operator Aid Computer (OAC) work stations will be installed.(Reference 4).Following are specific project objectives:

ELI Part ELI installs a Foundation Fieldbus infrastructure by replacing a number of existing plant 4 to 20 mA instruments with Fieldbus devices and utilizing those instrument cables for the Fieldbus communication network. The Foundation Fieldbus infrastructure will provide an economical way for the future replacement of obsolete pneumatic or electronic instruments with instruments using newer digital communication standards provided by Foundation Fieldbus technology.

The Foundation Fieldbus technology is a digital communication standard that replaces older technology 3-27 psig and 4-20 milliarnp standards and allows control algorithms to reside in the field instrument.

This affords the possibility of single-loop integrity, which means that the control loops connected on a segment can continue to provide control function if the communication between the HMI (Human Machine Interface) and Host is lost.Furthermore, Foundation Fieldbus provides the capability of advanced diagnostics, that can be utilized to gain higher component efficiency and lower maintenance costs.(Reference 4)The infrastructure for this new digital technology will use the existing cables (where possible) emanating from the cable room to designated areas of the plant thus reducing or eliminating the need to pull new cables into the Cable Room. These cables will be utilized to provide desired process data to the Process Control System (PCS) monitors in the Control Room and the OAC. (Reference 4)The PCS is housed in five (5) EMI/RFI qualified cabinets installed in the Cable Room in the vicinity of the Unit I OAC Cabinets.

These cabinets are seismically mounted to the floor and bolted together to ensure a solid mounting configuration.

Cabinets 1 thru 4 contain the Fieldbus communication devices or Fieldbus Universal Bridges that provide the interface between the Fieldbus Devices and the Operators HMI station along with the OAC OPC Server. Cabinet 5 will contain redundant network switches, the OPC Server, Engineering Workstation and two Uninterruptible Power Supplies (UPS). Both the OPC Server and Engineering Workstation have two network cards for redundancy.

Cabinet 5 also contains alarm relays to provide a PCS Trouble Alarm on Statalarm Panel I SA6 configured to alarm on Universal Bridge power supply or Fieldbus power supply failures as monitored by the DC302 module in Chassis I of each cabinet, excessive cabinet temperature, or UPS failures. (Reference 4)OD)00076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 2 of 41 The Universal Bridges consists of a Power Supply for the Backplane, Linking Device (DFI Processor), Power Supply for Fieldbus and Power Supply Impedance module for Fieldbus signal integrity.

Signal communication from the Fieldbus devices and the Linking Devices uses the H I communication standard with a 31.5 kbps communication rate. The Linking Devices communicate with the HMI's and the OAC by Ethernet communication technology at 10/10OMbits communication rate. The system is configured with redundant Universal Bridges and Nortel Network Switches.

Each Universal Bridge will have an Ethernet cable to one of the two Network Switches located in Cabinet 5. From there redundant signal cables will be routed using Duke type SP532 cable to the HMI A on IVB2 and HMI B located in the Unit I and 2 Computer Room.An OPC Server is located in Cabinet 5 which provides an interface to the OAC computer through a series of network switches and routers within the OAC system andhas two network cards, one connected to each Nortel network switch. The HMI B computer located in the Unit 1 and 2 Computer Room is tied in with the OAC Keyboard/Video/Mouse (KVM) network providing the ability of displaying the PCS graphics on multiple monitors in the Control Room. Each Universal Bridge can support four segments and each segment can have up to 32 devices or transmitters per the Fieldbus standard, however for this design, the number of devices will be limited to 8 to 10 per segment. The design installs a total of sixteen Fieldbus Universal Bridges in the four PCS cabinets.:

Assuming eight devices per segment the system can support 512 Fieldbus devices. (Reference 4)Since a large number of instrument cables coming from the field or plant locations utilize Transducer Cabinets I and 2 (1TDCI and 2) in the Cable Room as a connection point to the OAC, these cables were identified for use as the segment or HI trunk lines. These cables are all of single or multi-twisted shielded pair construction, Duke Type 1SPA16G.3, 4SPA16G.3 or 8SPA16G.3.

Four 20-conductor twisted shielded pair cables are to be installed between 1TDC1 and 2 and the PCS Cabinets completing the HI trunk lines to the plant.Transducer Terminal Cabinets 5 and 6 (ITDC5 and ITDC6) located in the basement of the Turbine Building have experienced excessive internal corrosion of the cabinet, instrument racks, tubing and tubing tray over the years and are dismantled and repaired by this design change. The instruments on the tacks are removed along with all tubing back to the instrument valves and all tubing tray. Of the 52 instruments in these cabinets, 16 are replaced with Fieldbus devices under this design change. The remaining instruments are obsolete and are to be replaced with new conventional 4 to 20 mA transmitters under the Equivalent Change Process. The cabinets are removed leaving only the instrument racks which are refurbished and painted. New instrument tubing tray and instrument tubing is installed along with two smaller terminal cabinets labeledl TDC5 and ITDC6.Fieldbus Bricks or potted junction boxes will be installed above the instrument rack for all Fieldbus connections. (Reference 4)Fieldbus junction boxes or Bricks are used to tie spur lines to the segment trunk lines and will be placed in convenient locations around the plant to limit the length of spur lines to OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 3 of 41 the individual devices or transmitters.

The Bricks are environmentally sealed with short circuit protection for the spur lines to limit the current to the spur should the line be short circuited.

The Bricks are mounted on columns at a height of approximately eight (8) feet above the floor in convenient locations around the plant therefore limiting the length of the spur lines to the individual Fieldbus device. The system as presently designed is only 25% loaded leaving a number of installed Bricks with spare capacity to add additional devices. In addition, several segments were left open with no cables or Bricks assigned providing for future growth in areas of the plant not presently covered by the design. The Bricks and instruments are mounted per Instrumentation and Controls Field Installation Standards Specification, OSS-0060.00-00-0001. (Reference 4)The power source for the PCS is obtained from IXO and IXP Motor Control Centers (MCC) located in the Unit 1 Equipment Room. These MCC's provide 208 VAC 30 power to the system through 30 amp breakers.

Since only single phase 208 VAC is required, only two phases and a neutral cable will be utilized.

One 3XJ10G.2 cable will be routed to Cabinet 5 from each MCC. Power to cabinet lighting and a utility receptacle which will only be utilized when cabinet is being accessed will be powered from one phase to neutral. With the exception of the type cooling fans installed and the lights, all equipment is configured for universal power and capable of accepting the 208 VAC 10 power. However, since the cabinets were already configured for 120 VAC and the fact the vendor does not have 208 VAC available for testing, the decision was made to power the equipment from the 120 VAC source during initial testing and FAT and install the UPS's after shipment to Duke. The UPS's consist of a battery pack and stepdown transformer used to provide the 120 VAC to the Fieldbus equipment.

A second battery pack is installed to provide a minimum of 30 minutes under full load conditions.(Reference 4)The following instruments are upgraded to fieldbus compatible instruments by Part ELI of this design change: Signal Sys Loop Description Source Control AS AUX STEAM PRESSURE TO PLANT HEATING PT-0038 IAS-43 AS CONDENSATE HEATING STEAM PRESSURE CONTROL PT-0062 IAS-62 C IA MDEFWP SUCT STRNR D/P PT-0641 C 1B MDEFWP SUCT STRNR D/P PT-0642 C FWP SEAL INJECTION SUMP OUTLET FLOW FT-0041P C FWP A SEAL INJECTION FLOW FT-0042P C FWP B SEAL INJECTION FLOW FT-0043P C CST LEVEL LT-O016P C CONDENSER HOTWELL LEVEL 3 LT-0019 CCW CONDENSER B1 DIFFERENTIAL PRESSURE PT-011 1P CCW CONDENSER B2 DIFFERENTIAL PRESSURE PT-0112P CCW CONDENSER INLET PRESSURE PT-0110P CCW PUMP BAY LEVEL LT-0044P CCW ONS INTAKE FOREBAY LEVEL LT-0008P CS IA BHUT LEVEL LT-0047P CS 1B BHUT LEVEL LT-0048P CS CONC. BORIC ACID STORAGE TANK LEVEL LT-0049P DW MAKEUP FLOW TO UST FT-0066P H GENERATOR GAS PRESSURE PT-0009P OD100076 5059 Eva] Rev O.doc ATTACHMENT 1 10 CFR 50.59 Evaluation, Rev. 0 OD100076 ONS-2005-002 Date: 6/22/06 Page: 4 of 41 Signal Sys Loop Description Source Control HD 101 HOP DISCHARGE PRESSURE PT-0160 HD 1E1 HOP DISCHARGE PRESSURE PT-0162 HD 1D2 HDP DISCHARGE PRESSURE PT-0161 HD 1E2 HOP DISCHARGE PRESSURE PT-0163 HD 1"D HOP DISCHARGE HEADER PRESSURE PT-0153P HD IE HDP DISCHARGE HEADER PRESSURE PT-0154P HD LP HEATER F1 LEVEL LT-0020B 1-HD-296 HD LP HEATER F2 LEVEL LT-0021B 1-HD-301 HD LP HEATER F3 LEVEL LT-0022B 1-"D-306 HD HEATER B1 DRAIN FLOW FT-0064P HD HEATER 62 DRAIN FLOW FT-0065P HPE HEATER C1 STEAM PRESSURE PT-0084P HPE HEATER C2 STEAM PRESSURE PT-0085P HPE HTR B1 SHELL PRESSURE PT-0090P HPE HTR B2 SHELL PRESSURE PT-0091P HPE I ST STAGE REHEATER STEAM SUPPLY HEADER PRESSURE PT-0094P HPE MOISTURE SEP Al STEAM INLET PRESSURE PT-0127P HPE MOISTURE SEP A2 STEAM INLET PRESSURE PT-0128P HPE MOISTURE SEP B2 STEAM INLET PRESSURE PT-0129P HPE MOISTURE SEP B1 STEAM INLET PRESSURE PT-0130P HPE 1ST STAGE REHTR Al STM SUPPLY PT-0135P LPE HEATER El STEAM PRESSURE PT-0088P LPE HEATER E2 STEAM PRESSURE PT-0089P LPE E BLEED LP TURB PRESSURE PT-0083P LPI BWST TEMPERATURE TT-O001P MS 2ND STAGE REHTR A2 STEAM PRESSURE PT-0144P MS 2ND STAGE 1A1 REHTR STEAM SUPPLY PRESSURE PT-0143P I SSH STEAM SEAL HEADER PRESSURE PT-0123P MS LP STEAM FLOW TO FWPT A FT-0091P MS LP STEAM FLOW TO FWPT B FT-0092P MS 2ND STAGE REHTR B1 STEAM PRESSURE PT-0146P MS 2ND STAGE REHTR B2 STEAM PRESSURE PT-0145P MS MAIN STEAM FLOW TO AUX STEAM HEADER FT-0083 MS TURBINE HEADER A STEAM PRESSURE PT-0030A MS TURBINE HEADER B STEAM PRESSURE PT-0031A TO TURBINE BEARING OIL PRESSURE PT-0125P TO TURBINE OPERATING OIL PRESSURE PT-0126P LPE D1 HEATER SHELL PRESSURE PT-0086P LPE D2 HEATER SHELL PRESSURE PT-0087P GWD WASTE GAS DECAY TANK A PRESSURE PT-0020 GWD WASTE GAS DECAY TANK B PRESSURE PT-0021 GWD INTERIM RADWASTE DECAY TANK 1C PT-0069 GWD INTERIM RADWASTE DECAY TANK 1D PT-0070 EL2 Oconee's OAC monitoring and trending capabilities offer an alternative to eliminate not only obsolete L&N recorders but also other selected recorders (e.g. Bailey, Hagan, Honeywell and Westronics).

This design change removes the chart recorders listed in the Table below from the Unit I Control Room and, where noted, the inputs will be wired to either the OAC and/or a new multi-channel chart recorder.

In addition to freeing up Control board space, this design change reduces maintenance labor as well as reducing the impact of non-existent spare parts. As required, holes created by the device removals will be covered with welded plates and overlay. (Reference 4)OD100076 5059 Eva] Rev O.doc ATTACHMENT I 10 CFR 50.59 Evaluation, Rev. 0 OD 100076 ONS-2005-002 Date: 6/22/06 Pane: 5 of 41 To provide additional resources in the Control Room for access to the OAC, two OAC Workstations are installed in IAB2 in place of OAC printers.

Printing from the OAC has been provided by more efficient printers. (Reference 4)The following chart recorders will be disconnected and removed. Existing wiring to the OAC will remain intact (unless otherwise noted): Device ID DESCRIPTION NOTE 1BSCROO85 WR RB PRESSURE, RB% H2, WR RB WATER LEVEL (PAM) 3 ICCR0005 UPPER SURGE TANK LEVEL 3 ICSCR0079 QUENCH TANK LEVELTEMP,PRESS CHART RECDR 2 IFDWCR0054 SG AOPERATE LEVEL (ISA2-21) 9 IFDWCR0055 SG B OPERATE LEVEL (1SA2-33) 9 IFDWCR0056 MAIN FDW FLOW LOOP 'A 9 IFDWCROO57 MAIN FDW FLOW LOOP B'1 9 IFDWCRO427 STEAM GENERATOR IA AND 1B LEVEL 7 IFDWCRO428 AUXILIARY FEEDWATER FLOW 7 lIGENCR0058 GENERATOR VOLTS & AMPS CHART RECORDER 2 IGENCROO59 GENERATOR AMPS CHART RECORDER 8 OGWDCROO33 WASTE GAS DECAY TK DISCH FLW FOR UNITS 1 & 2 4 OGWDCROO35 WGDTNKS IA&B PRESSURE UNITS l&2 (PNEUMATIC) 2 OGWDCRO105 INTERIM WGD TNKS IC& ID PRESSURE (PNEUMATIC) 2 IGWDCR0037 UNIT RB STACK FLOW RECORDER 4 IHCROO78 GENERATOR CORE MONITOR CHART RECORDER 2 IIICROO08 IA INCORE DETECTOR CHART RECORDER 10 IIICROO09 1B INCORE DETECTOR CHART RECORDER 10 IHPECR0010 MSRH TUBE LEAK DETECTOR CHART RECORDER 2 1HPICROO42 LETDOWN STORAGE TANK LEVEL CHART RCDR (ISA2-13) 6 ILPICRO401 BWST LEVEL 3 lLPICRO421 HPI FLOW B, LPI FLOW B, RBS FLOW B 3 1LPICRO424 LPI FLOW AHPI FLOW A,RBS FLOW A 3 ILWDCROO95 RB NORMAL AND EMER SUMP LEVEL IND (TRAIN A) 4 IMSCROO43 MS PRESS HDR A I IMSCRO422 OTSG OUTLET PRESSURE A & B 9 IMTCROO69 MAIN TURBINE VIB & ECC CHART (I SAO-5 1, E-7) 5.IMTCROO70 MAIN TURBINE EXPANSION 5 IMTCROO71 MT SPD & VALVE POSITION 5 IPRCROO82 UNIT RB PURGE FLOW RECORDER 3 IRBCCROO07 RX BLDG TEMP CHART RECORDER 3 1RCCROO44 RC TOTAL FLOW CHART RECORDER (1 SA2-05) 9 IRCCROO45 RC NR PRESS (ISA2-39) 3 IRCCROO46 RC PRESSURE WR CHART RECORDER (1SA2-40) 3 IRCCROO47 PRESSURIZER LEVEL CHART RECORDER 3 IRCCROO49 RC SYSTEM WIDE RANGE COLDLEG TEMP (LOOP A & B) 3 IRCCROO50 RC AVG TEMP CHART RCDR (ISA2-16) 3 IRCCR0O51 RC NR THOT TEMP RECORDER (1SA2-15) 3 IRCCRO420 RV HEAD LVLHOT LEG LVL AND RCS WR PRESS (TRAIN A) 3 IRCCR0423 PZR LEVEL 1&2, AND PZR TEMP (TRAIN A) 6 ODI 00076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 6 of 41 Device ID DESCRIPTION NOTE IRCCR0426 RC SYSTEM WIDE RANGE HOTLEG TEMP (LOOP A & B) 3 1RCCR0429 DEG-SUB COOLING LOOP A 3 1RIACR0020 RIA-31 LPSW RAD MONITOR 8 1RIACR0021 AUX BUILDING GAS MONITOR RIA-32 8 IRIACR0022 RADIATION TREND 1-12 OOS 5 IRIACROO23 RADIATION TREND 13-24 8 IRIACR0024 RADIATION MONITOR 8 IRIACROO89 LWD DISCHARGE RIA 33-34 8 IRIACROO86 RB HIGH RANGE IRIA-58 3 IRPSCR0430 NI-3 WIDE RANGE POWER 3 1OAC-CR-MCRA OAC TREND RECORDER, POINTS 1-3 11 IOAC-CR-MCRB OAC TREND RECORDER, POINTS 4-6 11 I OAC-CR-MCRC OAC TREND RECORDER, POINTS 7-9 11 IOAC-CR-MCRD OAC TREND RECORDER, POINTS 10-12 11 ILPSCRI000 LPSW FLOW TO LPI DECAY HEAT COOLER -TRAIN B 12 Chart Recorder Notes: 1. Chart Recorder removed, leaving existing OAC.2. Chart Recorder removed, inputs wired to the OAC.3. Remove and wire inputs to multi-channel chart recorder.4. Chart recorder removed, inputs wired to OAC and multi-channel Chessell (or equivalent) recorder.5. Recorder removed. No longer needed for trending.6. Recorder removed, inputs wired to new Chessell (or equivalent) recorder.7. Recorder removed -Train A and B inputs separated and wired to new separate Chessell (or equivalent) recorders.

8. EDB change only. Recorders previously removed.9. Recorder removed -Train A and B inputs separated and wired to new separate Chessell (or equivalent) recorders and to OAC. 1 RCCROO44 will accept flow data from both trains and present the sum of total flow to a separate new recorder.10. Incore recorders included per PIP 0-02-5186 (replace recorders).

11. OAC recorders included per PIP 0-03-8050 (remove obsolete, abandoned recorders).

12. LPSW Flow to LPI Decay Heat Cooler Train A and B process points added per Station request.Disconnected cable, if not wired to the OAC, will be spared if possible; otherwise it will be cut back to the first tray point (Reference 4).OD100076 5059 Eval Rev O.doc ATFACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 7 of 41 LICENSING BASES AND ACTIVITY REVIEW REVIEW FOR PART ELI: NRC Regulatory Issue Summary (RIS) 2002-22 (Reference 28), states that the NRC Staff has reviewed EPRI TR-102348, Revision 1 (Reference

29) and the Staff concluded that it provides suitable guidance both for designing a digital replacement and for determining whether the digital replacement can be implemented under 10 CFR 50.59 without prior Staff approval.

The Staff's evaluation of EPRI TR-102348 was attached to RIS 2002-22. The RIS further concluded that when using the guidance of EPRI TR-102348 for the analysis of digital modifications of some safety-significant systems such as RPS and ESFAS, it is likely that these digital modifications would require prior staff review when 10 CFR 50.59 criteria are applied. The equipment replaced by this design change is not required for safety. TR-102348 Section 1.2 states that the document is intended primarily to address digital upgrades to safety systems, but that the guidance can also be applied to upgrades in non-safety systems at the discretion of the licensee.

The relevant portions of EPRI TR-102348 can therefore be used as a guideline (rather than a requirement) for evaluating the non-safety analog to digital design change OD100076 Part ELI.Part ELI of this design change is non-QA. The design change installs a non-QA Fieldbus infrastructure and replaces non-QA pneumatic instruments with Fieldbus devices, however, mounting of new cabinets and human machine interfaces is QA-4.QA-2 designated instruments affected by this design change include 1CSLT-0047P, 1CSLT0048P, OGWDPT-0020, OGWDPT-0021, OGWDPT-0069 and OGWDPT-0070.

Per NSD-307 (Reference 27), QA Condition 2 applies to those non-nuclear safety related systems, structures, and components important to the management and containment of liquid, gaseous, and solid radioactive waste. NSD-307 also states that instruments connected to the QA-2 Class E piping via instrument tubing must meet the process and environmental conditions of the application.

The new Fieldbus instruments are suitable for the applicable applications, i.e., they meet pressure and environmental requirements (Reference 26).Five instrument loops affected by this design change involve valve control (none of the other remaining loops involve control functions).

For those loops involving valve control, the existing pneumatic valve positioner is replaced with a Fieldbus valve positioner using a P1D (Proportional, Integral, Derivative) control algorithm.

The affected valves are 1-AS-VA-0043 (Standby Condensate and Plant Heating Pressure Control), 1-AS-VA-0062 (Condensate Heating Steam Pressure Control), 1 -HD-VA-0296 (Heater F1 Drain Control), I -HD-VA-0301 (Heater F2 Drain Control) and I -HD-VA-0306 (Heater F3 Drain Control).

These five valves are non-safety, non-seismic valves which are not required for the mitigation of any analyzed accident.

The valve bodies, actuator and air supply are unaffected by this design change. The new valve positioners are non-QA and not required to operate to mitigate any analyzed accident or event. Since the valve control algorithm resides within the new valve positioner, the positioner functions OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 8 of 41 independently, i.e., the process loop has single loop integrity and no common failure mode will affect other loops or vice versa (Reference 26)Control loop parameters are displayed on a computer graphics display station referred to as the PCS, located in the Control Room. The PCS is a new system for monitoring and controlling various Balance Of Plant (BOP) systems. The operators use the PCS to make adjustments to the control loop such as setpoint changes and manual valve control. Field devices (such as the new valve positioners) will continue to function, as long as they have power, without a functioning PCS. (Reference 26)The PCS, in its entirety, is a non-safety, non-seismic system (except for control board or panel mounting).

No diversity or separation is required for the PCS. It is not required to be operable during or after an accident.

A loss of this system will not affect any plant operating mode, as reviewed in the UFSAR. There are no plant operating modes or events where this system is required to be operable.

Field devices will continue to function, as long as they have power, without a functioning PCS. Fieldbus instruments have embedded microprocessors that are capable of performing control algorithms independent of the PCS. The new Fieldbus valve positioners installed by this design change use a PID control algorithm.

The PCS is not to be used for safety related applications. (Reference 26)The Instrument Air (IA) System performs only one safety function; the normally closed IA Reactor Building isolation valves and penetration piping must be capable of maintaining Containment Isolation.

This design change does not impact the IA isolation valves or penetration piping.The IA System is not credited to perform an event mitigation function for design basis events (Reference 30). However, availability of IA is necessary for proper operation of the Automatic Feedwater Isolation System (AFIS) as noted in the following discussion:

UFSAR Section 7.9.1 states that AFIS is credited in the steam line break containment response analysis (UFSAR Section 6.2.1.4) and the steam line break tube stress analysis (UFSAR Section 5.2.3.4).

AFIS is not credited for the steam line break core response analyses (UJFSAR Sections 15.13 and 15.17).Although AFIS is not required to mitigate UFSAR Chapter 15 events, Regulatory Compliance has concluded that ONS licensing documentation requires that the main feedwater control valves (MFCV) and startup feedwater control valves (SFCV) close upon a valid AFIS signal for all steam line break events to satisfy containment overpressure and steam generator tube stresses.

If IA is available the MFCVs and SFCVs can be closed successfully for all scenarios and break sizes. However, if air is lost due to a LOOP (loss of offsite power), MFCVs and SFCVs must close with residual air contained in the line and receiver tanks. From review of different cases, the only event of concern, where the MFCVs and SFCVs may not close upon a valid AFIS signal, is the SSLB (small steam line break) accident coincident with a LOOP inside containment.

Tech Specs 3.3.11, 3.3.12, and 3.3.13 address AFIS circuitry.

The AFIS circuitry actuates OD100076 5059 Eval Rev 0.doc ATrACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 9 of 41 various components including the MFCVs and the SFCVs. Tech Spec 3.7.3 addresses the MFCVs and SFCVs and requires two MFCVs and two SFCVs to be operable.

In order for these control valves to be operable, IA must be available.

IA is required for two reasons; a loss of IA causes the control valve to fail-as-is and IA is needed for motive force to close the control valves against system differential pressure (dP). (Reference 31)Safety Analysis in the General Office has analysis determining the AFIS circuitry actuates at different times for different break scenarios.

Safety Analysis understood that IA would be available for ten minutes in order to close the control valves. AFIS is required to mitigate various steam line break sizes with and without a LOOP. During a LOOP, the IA header will depressurize because the IA compressors will lose electrical power. OSC-8222 documents that IA pressure will decrease to 65 psig within 2.1 minutes of LOOP initiation.

OSC-8222 also states that the control valves require an air supply of at least 85.5 psig to close. This 85.5 psig is based upon a dP of about 1275 psid. During a MSLB/LOOP, the dP should be less than 450 psid due to a saturation temperature of 454'F in the Feedwater System. The Valve Engineering Group determined the Feedwater control valves need > 65 psig to reliably close during a MSLB/LOOP.

Test Acceptance Criteria ONTC-x-0245-0001-001 states that the control valves will close within 25 seconds of steam pressure exceeding AFIS setpoint. (Reference 31)Because Safety Analysis does not have an analysis to verify AFIS actuates within 101 seconds (2.1 minutes -25 seconds), it is not known that IA will be available to close the MFCVs and SFCVs within the 2.1 minutes that IA is available above 65 psig. If the valves cannot close, Tech Spec 3.7.3 applies. (Reference 31)Normally, adequate IA is supplied by the Primary IA Compressor.

The Primary IA Compressor or its backup compressor would be available during steam line breaks without a LOOP and therefore can supply air to assure MFCV and SFCV operability.

If adequate IA is not available to close the MFCVs and SFCVs, the valves are not operable.During LOOP events, the Primary 1A Compressor and its backup compressor would not function due to the power loss. Because IA pressure must be > 65 psig to assure operable MFCVs and SFCVs in accordance with Tech Spec 3.7.3, valve operability depends upon an adequate IA supply. (Reference 31)A reliable air source is one that conservatively has at least 65 psig at the time the MFCVs and SFCVs fully close. For large steam line breaks during a LOOP, adequate air is stored in the IA system such that the MFCVs and SFCVs will close within the required timeframe

(-2.1 minutes).

For smaller steam line breaks during a LOOP, the AFIS circuitry might not actuate until after the IA system has depressurized to less than 65 psig.To assure operability, a continuous, reliable air source is needed. To provide a reliable air source, a compensatory action is required.

The compensatory action requires a Diesel Service Air (SA) compressor to be operating and aligned to provide 1055 SCFM air to the IA system. By operating a Diesel SA Compressor, a reliable air supply will be available for smaller steam line breaks during a LOOP when AFIS actuates after 2.1 OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 10 of 41 minutes. Because a compensatory action is required, the MFCVs and SFCVs are Operable but Degraded/Non Conforming. (Reference 3 1)No changes to the UFSAR have been made crediting IA for steam line breaks. Operability is addressed by the compensatory measure to back up IA with a diesel Service Air compressor.

This is an OBD/NCI that must be resolved before changes are incorporated into the UFSAR. (Reference 31)When initially identified, the compensatory action required continuously running a diesel Service Air compressor.

To reduce operator burden, ONOE-1 8827 installed an auto-start circuit for two diesel compressors.

The auto-start compensatory action does not impact other aspects of the facility or procedures described in the UFSAR. (Reference 31)This design change does not adversely affect the existing IA system and compensatory actions taken to alleviate loss of IA during SSLB/LOOP events since the design change does not affect the air supply to affected valves or the existing pneumatic actuator on those valves. In addition, for the pneumatic instruments replaced electronic counterparts by this design change, the air source to the replaced instrumentation is isolated and capped (Reference 26).Upgraded instrument loops affected by design change OD100076 Part ELI use existing basis and resultant values for setpoints and control features.

Loop accuracy calculations have been revised as appropriate.

The fail safe positions of valves and components stay the same as they were before the upgrade. None of the upgraded loops are required for RG 1.97 compliance. (Reference 26)As noted in UFSAR, Section 3.11.5, the control areas of the plant (control rooms, cable rooms and electrical equipment rooms) are designed to provide a suitable environment for the control and electrical equipment.

The Control Room Area Cooling Systems (CRACS) are required to maintain the control areas within specified temperatures (Reference 2, Section 3.7.16 and Reference 3, Section 16.8.1). There are no adverse heat load affects from addition of equipment by part ELI of this design change. The equipment added by part ELI of this design change to the control areas does not adversely affect the ability of CRACS to maintain control area temperatures.

Equipment installed in the cable room and control room will add to the heat load for those rooms; these loads are evaluated and added to Calc OSC-8229. (Reference 26)The seismic considerations for instrumentation and electrical equipment are in accordance with SQUG requirements. (Reference 4)Cabinet mounting and equipment support designs for part ELI of this design change are complete (Reference 4).For those control room panels from which analog devices are removed by part ELI of this design change, the seismic integrity of those panels has been analyzed and found to be not adversely affected.

The mounting of digital instruments has been addressed for adequate/appropriate mounting for the area in which they are located. (Reference 4)OD100076 5059 Eval Rev O.doc ATIACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: I Iof 41 Instruments lCPT0641, 1CPT0642, 1MSPT0030A and 1MSPT0031A are required to maintain pressure boundary (References 21, 22, 23 and 24). The signal output of these instruments are not required for performance of any safety function.

The new fieldbus instrument is designed to maintain pressure boundary and so will not adversely affect the performance of other instrumentation or required pressure boundary. (Reference 26, Attachment A)The instruments replaced by part ELI of this design change are all non-safety related (Reference 4). The original analog instruments and replacement digital instruments are not required for the mitigation of any accident described in the UFSAR.For all the replaced instrument loops, loop upgrades are designed to mimic the original design, and where practical, take advantage of the increased accuracy of the new devices. (Reference 26).The new digital devices are suitable for their service environment.

The equipment is located in a mild environment. (Reference 26)Cables installed or rerouted during installation of the fieldbus devices and network are installed per approved plant procedures. (Reference 4)An electrical 10 CFR 50 Appendix R fire review was performed for the design phase of part ELI with no adverse affects to the Appendix R fire separation requirements (Reference 4).For the digital devices installed by this design change, it has been determined that the installed equipment is electromagneticly compatible with other plant equipment, i.e., the equipment will function satisfactorily in its electromagnetic environment without introducing adverse disturbances to that environment or to other equipment (Reference 26).Power supply sources for the new fieldbus instruments are adequate for the application.

The plant electrical distribution system is not adversely affected by the electrical loads presented by the new fieldbus instruments. (Reference 26)The software/firmware associated with the replacement instruments is characterized as SDQA Category C per NSD-800 (Reference 11), which is an appropriate classification for this application in accordance with Table 800-2 (Definition of Software and Data Quality Assurance Categories) of NSD-800. Document SDQA-10144-ONS specifies minimum and recommended requirements as well as responsibilities to ensure the application provides expected results (Reference 32).REVIEW FOR PART EL2: This part of the design change removes chart recorders from the control boards requiring a large amount of panel board restoration.

A total of eleven new multi-channel recorders are installed in ODI00076 5059 Eval Rev 0.doc A1TACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 ODI 00076 Page: 12 of 41 the Control Room, five on IUB 1, four on lVB I and two on 1VB2. Changes to the Control Boards are evaluated for seismic loading and appropriate calculations updated. (Reference 26)Two OAC Workstations are installed in place of the OAC printers presently located in IAB2.This benchboard requires major rework in order to mount the workstations.

Computers for these workstations are installed in a rack inside the cabinet and accessible from the rear. Changes to the benchboard are evaluated for seismic loading and the appropriate calculations updated.(Reference 4)The selected chart recorders are disconnected and removed. Six of the chart recorders have already been removed, however EDB records will need to be updated. Existing wiring to the OAC will remain intact (unless otherwise noted). In addition, new OAC points are added as required. (Reference 4)UFSAR Section 7.5.1.4.5 states that human factors guidelines are used in determining type and location of displays.

Nuclear Station Directives (NSDs) are followed for labeling considerations.

Human factors and Operations' input is used in display screen development.

NUREG 0700, Rev.2 is used to ensure physical mounting arrangement is acceptable for new display monitors (Reference 26).AFFECTED REG GUIDE 1.97, CATEGORY I VARIABLES:

Recorders 1BSCROO85, ICCROO05, IFDWCRO427, I FDWCRO428, ILPICRO401, ILPICRO424, 1MSCR0422, 1RCCROO46, IRCCRO420, 1RCCRO423, 1RCCRO426, 1 RCCRO429, I RIACROO86 and I RPSCRO430 record input from RG 1.97 Category 1 instrument loops (UFSAR, Sections 7.5.2.1, 7.5.2.2.2, 7.5.2.2.3, 7.5.2.3, 7.5.2.4, 7.5.2.6 through 7.5.2.12, 7.5.2.16, 7.5.2.18, 7.5.2.19 and 7.5.2.23).

RG 1.97, Category 1, provides the most stringent requirements and is intended for key variables.

The design criteria for Category 1 includes environmental qualification, seismic qualification, design against single failure, at least one channel displayed on a direct indicating or recording device, instrumentation energized from station standby power sources, continuous indication display, recording of instrumentation readout information, separation between safety-related and non-safety related equipment using isolation devices, and instruments identified on control panel so that the operator knows that they are for use under accident conditions.

Instrumentation being upgraded for accident monitoring is required to not degrade the accuracy and sensitivity required for normal operation (UFSAR, Sections 7.5.1.4.1 and 7.5.1.4.4).

The design criteria, as interpreted by Duke, for Category I instrumentation includes having at least one channel of QA-1 instrumentation to be displayed on a direct indicating or recording device. Existing indicators for the RG 1.97 Category 1 instrumentation are not affected by this design change. The new multi-channel recorders are seismically mounted and electrically isolated from associated safety signals using qualified isolators (Reference 4).The recording of the Category I variables is discussed in RG 1.97 section 1.3. lg, which states: OD100076 5059 Eval Rev O.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 13 of 41 Recording of instrumentation readout information should be provided.

Where direct and immediate trend or transient information is essential for operator information or action, the recording should be continuously available on dedicated recorders.

Otherwise, it may be continuously updated, stored in computer memory, and displayed on demand.Intermittent displays such as data loggers and scanning recorders may be used if no significant transient response information is likely to be lost by such devices (Reference 5).Duke's interpretation of this recording requirement for Category 1 variables was provided in Reference 6, Section 5.5.1.3.1 (g) and in UFSAR, Section 7.5.1.4.1, item 7. This interpretation was as follows: Recording of instrumentation readout information is provided for at least one of the redundant channels.

Recorders which are utilized as the primary display device will be seismically qualified.

Where direct and intermediate trend or transient information is essential for operator information or action, the recording is continuously available on dedicated recorders.

Otherwise, it may be displayed on non-seismically qualified recorders or continuously updated, stored in computer memory, and displayed on demand. Intermittent displays such as data loggers and scanning recorders may be used if no significant transient response information is likely to be lost by such devices. All analog variables which are wired to the plant computer may be displayed on trend recorders upon demand to provide hard-copy trend information.

The justification for deleting a recorder and relying on the OAC is as follows: Even though direct and immediate trend of this information was never considered essential for operator information or action, recording capability is required as part of RG 1.97 Category I design criteria.

The original design included recorders due to the inability of the old OAC to store this information in memory and display it on demand. The new OAC, however, will store approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of trend data internally and Duke's data archival program (PI) will provide access to data that is older than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This increased capability of the new OAC is considered sufficient to meet the requirement to "continuously update, store in computer memory and display on demand". RG 1.97 does not place any quality requirements on the recording device as long as it is not the primary indication to the operator and a qualified isolation device is provided between it (the OAC) and the primary indication.

However, since the OAC and PI would be used to comply with a regulatory requirement, they are required to be classified as SDQA category "C", which is currently the case. SDQA "C" is used for software and data collection that is involved in meeting NRC regulatory requirements with or without human intervention and which is not categories "A" or "B" (References 5, 11, 16 and 26).Part EL2 of this design change will delete recorders.

In those cases where the input to the existing recorder is already wired to the OAC, those parameters will remain available on the OAC. In other cases, the parameter recorded by the deleted recorder is added to the OAC and/or to a new multi-channel recorder as part of this design change (see Activity Description for details). (Reference 4).OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 14 of 41 RG 1.97 does not establish a requirement for retention of data from the various variables.

However, the conservative approach dictates that data be recorded at T=O of an accident until the accident is declared over. This conservative approach assumes that the data is to be retained forever. However, given that RG 1.97 does not establish any requirements for the storage and retention of this instrumentation's data, the determination of storage and retention requirements is not considered a part of the scope of this design change. The scope of this design change is to ensure that a system is installed that meets the requirements of RG 1.97 and is suitable for long term storage and retention of PAM data. The OAC and PI have been evaluated as suitable for this purpose as noted above.The NRC's acceptance criteria for the earlier Duke response was determined to be that the Regulatory Guide criteria was met, unless Duke had addressed the individual PAM variables as exceptions.

Using the OAC as a recording device was determined to conform to RG 1.97. The changes associated with Part EL2 of this design change are still within the guidelines of RG 1.97 (References 6, 7 and 8).For the following RG 1.97, Category 1 recorded variables, the primary display devices are QA-I indicators which are unaffected by this design change, i.e., the design change does not adversely affect the capability of the affected instrument loops to meet the display requirements of RG 1.97, section 1.3.1 g, for Category I variables

.The direct and immediate trending of the variables is not essential for operator information or action (Reference 26). Therefore, it is not required by RG 1.97 that the recording of the following Category 1 variables be on dedicated or qualified recorders.

Recorder 1BSCR0085 records Reactor Building (RB) Wide Range Pressure, RB Hydrogen Concentration, and RB Wide Range Water Level. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provides details on the displays available for these variables as follows: For RB Wide Range Pressure: RG 1.97 response (Reference

6) states that there are two indicators, with two channels on the computer (trend recording on demand), and one channel recorded.This design change deletes the recorder and wires inputs to a new multi-channel recorder.

The parameter remains available on the OAC. The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.19, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable as written. This design change does not affect function or operation as discussed in the UFSAR.Technical Specification Bases B3.3.8 for containment pressure (wide range) states that one channel is recorded.

The Technical Specification Bases information is correct post-modification.

For RB Hydrogen Concentration:

OD100076 5059 Eval Rcv O.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Pape: 15 of 41 RG 1.97 response (Reference

6) states that there are two indicators, with one channel recorded and two computer points. This design change deletes the recorder and wires inputs to a new multi-channel recorder.

The parameter remains available on the OAC. The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.10, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable as written. This design change does not affect function or operation as discussed in the UFSAR.Technical Specification Bases B3.3.8 for containment hydrogen concentration states that one channel is recorded.

The Technical Specification Bases information is correct post-modification.

For RB Wide Range Water Level: RG 1.97 response (Reference

6) states that there are two indicators, with two channels on the computer (trend recording on demand), and one channel recorded.This design change deletes the recorder and wires inputs to a new multi-channel recorder.

The parameter remains available on the OAC. The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.18, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable as written. This design change does not affect function or operation as discussed in the UFSAR.Technical Specification Bases B3.3.8 for containment sump water level (wide range) states that the variable is recorded on one recorder.

The Technical Specification Bases information is correct post-modification.

Recorder 1 CCROO05 records Upper Surge Tank Level. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display of this variable as follows: RG 1.97 response (Reference

6) states that there is one continuous recorder, and two computer monitoring points. This design change deletes the recorder and wires inputs to a new multi-channel recorder.

The parameter remains available on the OAC. The RG 1.97 information is revised to indicate that the parameter is recorded on a multi-channel recorder.UFSAR, Section 7.5.2.11, states that "The ICCM Train A cabinet provides safety inputs to a dedicated qualified recorder and to a qualified indicator located in the Control Room which provides UST level indication".

The UFSAR Section is revised to read "The ICCM Train A cabinet provides safety inputs to a qualified indicator and to a recorder (through a qualified isolator), both located in the Control Room to provide UST level indication".

A"dedicated qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.OD100076 5059 Eval Rev 0.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 16 of 41 echnical Specification Bases B3.3.8 states that "Te 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 Technical Specification Bases is revised to read "The ICCM Train A cabinet provides UST level input 'to a qualified indicator and to a recorder (through a qualified isolator), both located in the Control Room". A "dedicated qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Recorder 1FDWCRO427 records Steam Generator 1A and lB Level. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that for post accident range there are four gauges, with all channels on the computer (trend recording on demand). This design change deletes existing recorder, separates train A and B inputs and wires each train to new separate recorders.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.4, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable as written. This design change does not affect function or operation as discussed in the UFSAR.Technical Specification Bases B3.3.8 discusses this variable but does not mention recording of the variable.

No change is required to B3.3.8 for this variable.

• • • • (see page 23)Recorder 1FDWCRO428 records Auxiliary Feedwater Flow (Emergency Feedwater Flow -Reference 25). Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are four indicators, with four computer points (trend recording on demand). The RG 1.97 submittal does not mention input to a recorder.

This design change deletes the existing recorder, separates Train A and B inputs and wires each train to new separate recorders.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.40, states that "Emergency Feedwater flow is recorded on a dedicated chart recorder in the Control Room for EFW flow to each steam generator".

The UFSAR Section is revised to state "Emergency Feedwater flow to each steam generator is recorded on separate recorders in the Control Room". The revised UFSAR statement reflects the fact that this design change separates, the flow data to OTSG IA and IB (which previously was recorded on the one recorder 1FDWCR0428) and sends the flow data for OTSG 1A to one recorder and the flow data for OTSG lB to a another recorder.

A "dedicated" recorder is not required for this variable because the recorder is OD 100076 5059 Eval Rev 0.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Pagze: 17 of 41 not the primary indication device and trend and transient information on this variable is not essential for operator information or "on.Technical Specification Bases B3.3.8, LCO 21 (EFW flow) states that "One channel also provides input to a recorder".

This statement in B3.3.8 is revised to read "One channel also provides input to a recorder on Units 2 and 3. On Unit 1, one channel provides input to separate recorders for flow to each SG". The Technical Specification Bases change is acceptable and appropriate to reflect the new recorder arrangement.

• • • • (see page 23)Recorder ILPICRO401 records Borated Water Storage Tank (BWST) Level. Duke's response to RG 1.97 (Reference 6), the UFSAR and the Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there is one duplex indicator, and one channel on the computer (trend recording on demand). The response also states that continuous recording will be provided for one channel. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.6, states that the third channel of qualified instrumentation provides a safety input from train B to a "dedicated qualified recorder".

The UFSAR Section is revised to delete the words "dedicated qualified".

A "dedicated qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for o r information or action.echnical Specification Bases B3.3.8 states that "BWST level measurement is provided by three channels with readout on two indicators and one recorder.

Two of the three channels provide inputs 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 Technical Specification Bases is revised to change the sentence "The third channel provides a safety input to a dedicated recorder" to read "The third channel provides an input to a recorder".

A "dedicated qualified" recorder is not requir~ed for this variable-because- the- recorder is. not. the. primary indication device and trend and transient

/information on this variable is not essential for operator information or action.Recorder ILPICRO424 records LPI Flow A, HPI Flow A and RBS Flow A and recorder I LPICRO421 records LPI Flow B, HPI Flow B, and RBS Flow B. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for these variables as follows: For LPI Flow: RG 1.97 response (Reference

6) states that there are two duplex indicators and two computer points. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been OD100076 5059 Eval Rev 0.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 18 of 41 revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.8, states that each channel signal, A and B respectively, inputs to a "qualified recorder" via the ICCM system cabinets.

The UFSAR Section is revised to delete the word "qualified" and replace it with the word "a" (hence referring to "a recorder").

A "qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Tech Spec Bases B3.3.8 states that flow measurement is provided by one channel per train with readout on a recorder._The Tech Spec Bases information is correct post-modification.

For HPI Flow: RG 1.97 response (Reference

6) states that there are two indicators (one per train).This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.7, states that each channel signal, A and B respectively, inputs to a "dedicated qualified recorder" via the ICCM system cabinets.

The UFSAR Section is revised to delete the words "dedicated qualified".

A "dedicated qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Tech Spec Bases B3.3.8 states that flow measurement is provided by one channel per train with readout on a recorder.

The Tech Spec Bases information is correct post-modification, RB Spray Flow: RG 1.97 response (Reference

6) states that there is one duplex indicator, with two computer points. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.9, states that each channel signal, A and B respectively, inputs to a "qualified recorder" via the ICCM system cabinets.

The UFSAR Section is revised to delete the word "qualified" and replace it with the word "a" (hence referring to "a recorder").

A "qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 19 of 41 Tech Spec Bases B3.3.8 states that flow measurement is provided by one channel per train with readout on a recorder.

The Tech Spec Bases information is correct post-modification.

Recorder IMSCRO422 records Steam Generator Outlet Pressure A and B. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there is a duplex indicator (one per S/G), with all channels on the computer (trend recording on demand). This design change deletes existing recorder, separates train A and B inputs and wires them to new separate recorders and to the OAC. Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.5, states that "One channel per steam generator also provides a safety input to a qualified recorder located in the Control Room" and that the ICCM system cabinets, channels A and B, respectively, also provide non-safety inputs to the OAC. The UFSAR further states that all eight signals, four per steam generator, are also input to the plant computer (OAG) and trend recording is available to the control room operator if demanded.

The OAC inputs are unaffected by this design change. The UFSAR Section is revised to read "One channel per steam generator also provides an input to a recorder located in the Control Room". A "qualified" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Tech Spec Bases B3.3.8 states that one channel per SG provides input to a recorder located in the control room. The Tech Spec Bases information is correct post-modification.

Recorder IRCCROO46 records Reactor Coolant System Wide Range Pressure.

Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are two channels recorded, with three computer points. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.1, states that two channels of RCS pressure are recorded.

This statement is correct post-modification.

However, the UFSAR Section is revised to relocate the statement "Two channels are recorded" to the end of the paragraph for enhanced clarity and readability.

The wording in UFSAR Section 7.5.2.1 remains correct post-modification and no change is required to that UFSAR Section. UFSAR, Section 7.4.2.2.3, states that 'Reactor coolant pressure is recorded on two single-pen strip chart recorders.

One recorder has a range of 1700-2500 PSIG, and its input is the median selected reactor coolant pressure signal selected for control. The other recorder has a range of 0-2500 PSIG, and its input is from a transmitter in the "A" loop'. This statement in the UFSAR is revised to state that 'Reactor coolant pressure is recorded on a multi-OD100076 5059 Eval Rev O.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 20 of 41 channel recorder (for Unit 1) or two single-pen strip chart recorders (for Units 2 and 3).One channel/recorder has a range of 1700-2500 PSIG, and its input is the median selected reactor coolant pressure signal selected for control. The other channel/recorder has a range of 0-2500 PSIG, and its input is from a transmitter in the "A" loop'. The recorder is not the primary indication device for this variable and trend and transient information of this variable is not essential for operator information or action. Note that the wide range recording (0-2500 PSIG) discussed in UFSAR 7.4.2.2.3 is the RG 1.97 Category 1 variable previously recorded on recorder IRCCROO46.

The narrow range recording (1700-2500 PSIG) discussed in UFSAR 7.4.2.2.3 is the variable previously recorded on recorder I RCCR0045 (Reactor Coolant Narrow Range Pressure).

There is no RG 1.97 requirement concerning recording of reactor coolant narrow range pressure.Technical Specification Bases B3.3.8 does not address recording.

The Tech Spec Bases information is correct post-modification.

Recorder 1RCCR0420 records Reactor Vessel Head Level, Hotleg Level, and RCS Wide Range Pressure (Train A). Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: For Reactor Vessel Head Level and Hotleg Level: RG 1.97 response (Reference

6) states that there are two indicators per channel, two channels on the computer, one channel recorded, trending of level measurement is available through the ICC Monitoring System. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

The RG 1.97 information remains correct post-modification.

UFSAR, Section 7.5.2.2.3, states that Train A level measurements are recorded on a continuous recorder on the Main Control Board. The UFSAR Section is acceptable as written. This design change does not affect function or operation as discussed in the UFSAR.Technical Specification Bases B3.3.8 states that "The Reactor Vessel Water Level channels consist of two Reactor Vessel Head Level channels that provide readout on two indicators (RC-LTO 125 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-LT0124) with one channel recorded in the control room". The Tech Spec Bases information is correct post-modification.

For RCS Wide Range Pressure: RG 1.97 response (Reference

6) states that there are three channels on the computer with two channels recorded.

This design change deletes the existing recorder and wires the input to a multi-channel recorder.

The RG 1.97 information remains correct post-modification.

UFSAR, Section 7.5.2.1, states that 'Two channels are recorded'.

The channel recorded on deleted recorder 1 RCCR0420 is recorded on a multi-channel recorder post-modification.

The other channel of RCS Wide Range Pressure is recorded on 0DI00076 5059 Eva! Rev 0.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Paie: 21 of 41 1 RCCR0046 which is also deleted by this design change and the signal provided to another new multi-channel recorder installed by this design change. Therefore, the statement in UFSAR, Section 7.5.2.1, remains correct post-modification.

However, UFSAR Section 7.5.2.1 is revised to relocate the statement

'Two channels are recorded' to the end of the paragraph in which the statement appears.Technical Specification Bases B3.3.8 discusses this variable but does not mention recording of the variable.Recorder I RCCRO423 records Pressurizer Level I and 2 and Pressurizer Temperature.

Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: For Pressurizer Level: RG 1.97 response (Reference

6) states that there is one channel recorded (selected among three channels), and three channels on the computer.

This design change deletes the existing recorder and wires the input to a new multi-channel recorder.Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 5.2.3.10.3, states that pressurizer water level is recorded.

UFSAR, Section 5.2.3.10.5, states that pressurizer level is recorded in the control room.UFSAR, Section 7.4.2.2.3, states that one temperature compensated signal of pressurizer level is recorded.

The UFSAR information is correct post-modification.

Technical Specification Bases B3.3.8 states that "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".

The Technical Specification Bases information is correct post-modification.

For Pressurizer Temperature:

No RG 1.97 requirements were found for recording pressurizer temperature.

This design change deletes the existing recorder and Wires the input to a new multi-channel recorder.UFSAR, Section 7.4.2.2.3, lists pressurizer temperature as non-nuclear process instrumentation but does not address recording of this variable.Technical Specification Bases B3.3.8 does not address this variable.Recorder 1RCCR0426 records RCS Wide Range Hotleg Temperature.

Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are four computer points (with trend recording on demand). This design change deletes the existing recorder and wires the input to a new multi-channel recorder.

Information on the RG 1.97 response has been OD100076 5059 Eval Rev Odoe ATIACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 22 of 41 revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.16, states that this variable inputs to the plant computer through isolation buffers and is recorded on a "dedicated chart recorder" in the Control Room.This UFSAR Section is revised to delete the words "dedicated chart". A "dedicated" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Technical Specification Bases B3.3.8 does not address recording of this variable.

The Technical Specification Bases information is correct post-modification.

• • • • (see page 23)Recorder 1 RCCR0429 records Degrees of Subcooling.

Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are computer driven digital displays, with trend recording available on demand. This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.2.2, states that this variable is "input to the plant computer through isolation buffers and is recorded on a dedicated chart recorder in the Control Room". This UFSAR section is revised to delete the words "dedicated chart" since the variable is input to a multi-channel recorder post-modification.

A "dedicated" recorder is not required for this variable because the recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Technical Specification Bases B3.3.8 does not address recording of this variable.

The Technical Specification Bases information is correct post-modification.**** (see page 23)Recorder IRIACROO86 records RB High Range (IRIA-58).

Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as: RG 1.97 response (Reference

6) states that there are two indicators (one per channel), with two channels on the computer, and one channel recorded.

This design change deletes the existing recorder and wires the input to a multi-channel recorder.

The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.23, does not specifically mention recording of this variable.UFSAR, Section 11.5.2, states that 1RIA-58 has a recorder in the Control Room. This UFSAR information remains correct post-modification.

OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 23 of 41 Technical Specification Bases B3.3.8 for containment area radiation (high range) states that the instrumentation consists of two channels (RIA 57 and 58) with one channel recorded.

The Technical Specification Bases information is correct post-modification.

Recorder I RPSCR0430 records NI-3 Wide Range Power. Duke's response to RG 1.97 (Reference 6), the UFSAR and Technical Specification Bases provide details on the display available for this variable as: RG 1.97 response (Reference

6) states that there are thirteen Control Room indicators (four source, four intermediate, five power), thirteen computer points (four source, four intermediate, five power), with trend recording on demand, and three channels recorded, with six accessible.

This design change deletes the existing recorder and wires the input to a multi-channel recorder.

Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.12 addresses recorder IRPSCRO430 with the statement that "One QA Condition 1 Wide Range channel recorded on a post-accident operation recorder".

This UFSAR Section is revised to remove the words "post-accident operation".

The recorder is not required for post-accident operation of any Oconee Unit. Redundant QA-1 wide range indicators are available and are the primary source for post-accident information/indication of this variable.

The recorder is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Technical Specification Bases, Section B3.3.8, states that the Wide Range Neutron Flux channels consist of two channels of fission chamber based instrumentation with readout on one recorder.

This statement in B3.3.8 is valid post-modification.

• • • • By letter dated March 16, 1989, Duke was informed of a Notice of Deviation (Inspection Report 89-07) concerning the inability of the Unit 2 operator to display trend information for the variables

1) RCS Hotleg Water Temperature, 2) Auxiliary Feedwater Flow, 3) Steam Generator Level, and 4) Degrees of Subcooling.

Duke's submittal for RG 1.97, dated September 28, 1984, indicated use of a computer for the recording of these four Category 1 variables.

The submittal implies that, for these four variables, direct and immediate trend or transient information is not essential for operator information or action at Oconee, and therefore the trend or transient information would be stored in computer memory for display on demand (Reference 13). Duke's written response to the deviation, dated April 17, 1989, stated that "Upon further review, however, Duke Power does feel that continuous monitoring of these variables could enhance post disturbance event review and plans to add dedicated, non-safety grade recorders to monitor one channel of each variable.

These recorder additions are not considered an expansion of Duke Power's RG 1.97 commitments" (Reference 14). The NRC's letter of October 22, 1990, addresses the deviation, references Duke's April 17, 1989 response, and states that "Your response states that you intend to install dedicated recorders for the four variables in question, and on this basis, the matter is closed" (Reference 15). A May 16, 1990 NRC memorandum OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 ,D100076 Page: 24 of 41 included an attached Task Interface Agreement, Oconee Nuclear Station Units 1, 2 and 3, RG 1.97 Inspection, TAC Nos. 74147, 74148 and 74149. The Task Interface Agreement states, in part, that "The licensee did commit to install dedicated, non-safety grade recorders to monitor one channel of each of these four variables.

The licensee has stated that the addition of these recorders is not considered an expansion of their RG 1.97 commitments.

The staff agrees with the licensee that the four variables in question do not fall under the trend and transient recording requirements.

However, this does not remove the RG 1.97 criteria for the recording of one channel for each Category I variable.

This recording may be either a dedicated recorder or continuously updated, stored in computer memory, and displayed on demand. ... The licensee plans to add dedicated, non-safety grade recorders to monitor one channel of each of these variables.

The recording of these variables on non-safety grade, control room recorders would be acceptable provided the licensee used qualified isolation devices for the.interface.between the safety grade loop and the non-safety grade recorders" (Reference 9).lRegulatory Compliance lhas-review-d~th-edocum-entioncon--ne addition of the dedicited, non-safety grade recorders for these four variables.

Based on Technical Specification 3.3.8 PAM instrumentation review, (and review of the documents, Regulatory Compliance found that this design change to the recorders is acceptable and that the requirements of RG 1.97 are met by the design change-Refere-iiceA-7

.__17 The Bases of Technical Specification 3.3.8 provides information that if 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 (Reference 2, Section,3.3.8).

This design change does not modify control room indicators.

For those variables addressed in B3.3.8 as having the variable recorded, the recording function is retained by this design change, i.e., for all RG 1.97 variables previously recorded, the recording capability is retained by this design change.In accordance with RG 1.97 section 1.3.1 a (Design and Qualification Criteria -Category 1), qualification applies to the complete instrumentation channel from sensor to display where the display is a direct indicating meter or recording device. Where the instrumentation channel is to be used in a computer based display, recording, and/or diagnostic program, qualification applies from the sensor to and includes the channel isolation device (References 5 and 6). Existing safety related signals used for input to the non-safety related plant computer are currently isolated from the plant computer by way of QA-1 isolation devices. New safety to non-safety (or QA-1 to non-QA-1) interfaces are isolated using QA-I isolation devices (Reference 26).The plant computer is capable of recording the instrument ranges specified in the Duke submittal of 9/28/84, in UFSAR Section 7.5, and in the Bases to Technical Specification Section B3.3.8 (References 1,2 and 11). Any new devices/components installed by part EL2 of this design change are not required to be environmentally qualified since they are located in a mild environment (Reference 26). Field work is performed using QA-l procedures when required (Control Room panel modifications are considered QA-1 and the modification will meet all seismic requirements as specified) (Reference 26). The panels from which recorders are removed have the resulting hole covered with overlay (Reference 4). A control board seismic review for the control board changes/deletions associated with part EL2 of this design change has been completed with a determination that the control boards are not adversely affected (Reference 4).OD100076 5059 Eval Rev 0.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 25 of 41 A 10 CFR 50 Appendix R fire review was performed for the design phase of part EL2 with no adverse affects identified. (Reference 4).This design change creates no single failures that could cause the loss of multiple trains of indication of the RG 1.97 Category I variables because the new recorders are isolated from safety circuits using qualified isolators (Reference 26). Mounting of new recorders is QA-4, therefore, there are no seismic interactions between seismically qualified and non-seismically qualified structures, systems, or components (Reference 26).AFFECTED RG 1.97, CATEGORY 2 VARIABLES:

and ILWDCROO95 are designated to record input from RG 1.97 Category2 instrument loops (UFSAR, Sections 7.5.2.17 and 7.5.2.53).

RG 1.97, Category 2, includes both QA-1 and non-QA-1 instrumentation.

Category 2 QA-1 design criteria includes environmental qualification, seismic qualification and instrumentation energized from station standby power sources. Category 2 non-QA-1 design criteria includes environmental qualification, seismic qualification only if seismic induced failure of the instrumentation would unacceptably degrade a safety system, instrumentation is designed, procured and installed per Duke standard practices, separation between safety-related and non-safety related equipment using isolation devices and energized from highly reliable power sources (not necessarily safety grade) backed by batteries where momentary interruption is not tolerable. (UFSAR, Sections 7.5.1.4.2 and 7.5.1.4.4).

The recording of the Category 2 variables is discussed in RG 1.97 sections 1.3.2e and 1.3.2f, which states: The instrument signal may be displayed on an individual instrument or it may be processed for display on demand by a CRT or by other appropriate means.The method of display may be by dial, digital, CRT, or stripchart recorder indication.

Effluent radioactivity monitors, area radiation monitors, and meteorology monitors should be recorded.

Where direct and immediate trend or transient information is essential for operator information or action, the recording should be continuously available on dedicated recorders.

Otherwise, it may be continuously updated, stored in computer memory, and displayed on demand. (Reference 5).Duke's interpretation of this recording requirement for Category 2 variables was provided in Reference 6, Section 5.5.1.3.2.3 and in UFSAR, Section 7.5.1.4.2.3.

This interpretation was as follows: The instrument signal may be displayed on an individual instrument or it may be processed for display on demand by a CRT or by other appropriate means.The method of display may be by dial, digital, CRT, or stripchart recorder indication.

Effluent radioactivity monitors and meteorology monitors will be recorded.

Where direct OD100076 5059 Eva] Rev O.doc ATrACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page; 26 of 41 and immediate trend or transient information is essential for operation information or action, the recording is continuously available.

on dedicated recorders.

Otherwise, it may be continuously updated, stored in computer memory, and displayed on demand.(References I and 6).The justification for deleting the recorders and relying on the OAC is as follows: Direct and immediate trend of the information from the deleted recorders was never considered essential for operator information or action, and therefore, continuously updating, storing in computer memory and displaying the data on demand is acceptable for Category 2 variables.

The original design included recorders due to the inability of the old OAC to store this information in memory and display it on demand. The new OAC, however, will store approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of trend data internally and Duke's data archival program (PI) will provide access to data that is older than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This increased capability of the new OAC is considered sufficient to meet the requirement to "continuously update, store in computer memory and display on demand". RG 1.97 does not place any quality requirements on the recording device as long as a qualified isolation device is provided between it (the OAC) and QA-I signals. However, since the OAC and PI would be used to comply with a regulatory requirement, they are required to be classified as SDQA category "C", which is currently the case. SDQA "C" is used for software and data collection that is involved in meeting NRC regulatory requirements with or without human intervention and which is not categories "A" or "B" (Reference 11).For the following RG 1.97, Category 2 recorded variables, the primary display devices are QA-l indicators which are unaffected by this design change, i.e., the design change does not adversely affect the capability of the affected instrument loops to meet the display requirements of RG 1.97, sections 1.3.2e and 1.3.2f for Category 2 variables.

The direct and immediate trending of the variables is not essential for operator information or action (Reference 26). Therefore, it is not required by RG 1.97 that the recording of the following Category 2 variables be on dedicated or qualified recorders.

RecorderqiDCROOCRR 3_7:Fecords Unit Reactor Building Stack Flow (Unit Vent Flow). Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there is one indicator, with one channel recorded, and one computer point. This design change deletes the existing chart recorder and wires the input to the OAC and a new multi-channel recorder.

The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.53, states that "The secondary instrument loop contains the retransmitter, indicator and recorder, and is powered by a highly reliable auxiliary bus".This sentence in UFSAR Section 7.5.2.53 is revised to read "The secondary instrument loop contains the retransmitter, indicator and recorder.

For Units 2 and 3, these devices are powered by a highly reliable auxiliary bus. For Unit 1, the retransmitter and indicator are powered by a highly reliable auxiliary bus". There is no RG 1.97 requirement for the recorder to be powered from a "highly reliable power source". The recorder is a OD100076 5059 Eval Rev 0.doc AlTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 27 of 41 commercial grade component.

For this variable, direct and immediate trend or transient information is not essential for operator information or action.Recorder I HPICROO42 records Letdown Storage Tank Level. Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that one channel (of two selectable) is recorded.This design change deletes the existing recorder and wires the input to a new multi-channel recorder.

The RG 1.97 information is revised to indicate that the one channel (of two selectable) recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.45, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable post-modification as written.Recorder 1 LWDCR0095 records RB Normal and Emergency Sump Level. Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are four indicators, with one channel on the computer (trend recording on demand), and one channel recorded.

This design change deletes the existing recorder and wires the input to the OAC and a multi-channel recorder.

The RG 1.97 information is revised to indicate that the one channel recorded is on a multi-channel recorder.UFSAR, Section 7.5.2.17, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable post-modification as written.In accordance with RG 1.97, section 1.3.2a (Design and Qualification Criteria -Category 2), where a safety related channel signal is to be processed or displayed on demand, qualification applies from the sensor through the channel isolation device (References 5 and 6).Existing safety related signals used for input to the non-safety related plant computer are currently isolated from the plant computer by way of QA-1 isolation devices. New safety to non-safety (or QA-I to non-QA-1) interfaces are isolated using QA-1 isolation devices (Reference 26).The plant computer is capable of recording the instrument ranges specified in the Duke submittal of 9/28/84 and in UFSAR Section 7.5 (References 1 and 11). Any new devices/components installed by part EL2 of this design change are not required to be environmentally qualified since they are located in a mild environment (Reference 26). Field work is performed using QA-I procedures when required (Control Room panel modifications are considered QA-1 and the modification will meet all seismic requirements as specified) (Reference 26). The panels from which recorders are removed have the resulting hole covered with overlay (Reference 4). A control board seismic review for the control board changes/deletions associated with part EL2 of this design change has been completed with a determination that the control boards are not ODI 00076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 28 of 41 adversely affected (Reference 4). A 10 CFR 50 Appendix R fire review was performed for the design phase of part EL2 with no adverse affects identified (Reference 4).Mounting of new recorders is QA-4, therefore, there are no seismic interactions between seismically qualified and non-seismically qualified structures, systems, or components (Reference 26).AFFECTED RG 1.97, CATEGORY 3 VARIABLES:

Recorders 1 CSCR0079, I FDWCR0056, 1FDWCR0057, 0GWDCR0035, 1RBCCROO07 and 1RCCROO49 are designated to record input from RG 1.97 Category 3 instrument loops (UFSAR, Sections 7.5.2.15, 7.5.2.35, 7.5.2.36, 7.5.2.37, 7.5.2.39, 7.5.2.42 and 7.5.2.49).

The design criteria for Category 3 are that the instrumentation is of high quality commercial grade and is selected to withstand the normal power plant service environment. (UFSAR, Section 7.5.1.4.3).

The recording of the Category 3 variables is discussed in RG 1.97 section 1.3.3b, which states: The method of display may be by dial, digital, CRT, or stripchart recorder indication.

Effluent radioactivity monitors, area radiation monitors, and meteorology monitors should be recorded.

Where direct and immediate trend or transient information is essential for operator information or action, the recording should be continuously available on dedicated recorders.

Otherwise, it may be continuously updated, stored in computer memory, and displayed on demand. (Reference 5).Duke's interpretation of this recording requirement for Category 3 variables was provided in Reference 6, Section 5.5.1.3.3 and in UFSAR, Section 7.5.1.4.3.

This interpretation was as follows: The method of display may be by dial, digital, CRT, or stripchart recorder indication.

Effluent radioactivity monitors and meteorology monitors will be recorded.

Where direct and immediate trend or transient information is essential for operator information or action, the recording is continuously available on dedicated recorders.

Otherwise, it may be continuously updated, stored in computer memory, and displayed on demand.(References 1 and 6).The justification for deleting the recorders and relying on the OAC is as follows: Direct and immediate trend of this information was never considered essential for operator information or action, and therefore, continuously updating, storing in computer memory and displaying the data on demand is acceptable for Category 3 variables.

The original design included recorders due to the inability of the old OAC to store this information in memory and display it on demand. The new OAC, however, will store approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of trend data internally and Duke's data archival program (P1) will provide access to data that is older than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This increased capability of the new OAC is considered sufficient to meet the requirement to "continuously update, store in computer memory and display on demand". RG 1.97 does not place any quality OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 29 of 41 requirements on the recording device. However, since the OAC and PI would be used to comply with a regulatory requirement, they are required to be classified as SDQA category "C", which is currently the case. SDQA "C" is used for software and data collection that is involved in meeting NRC regulatory requirements with or without human intervention and which is not categories "A" or "B" (Reference 11).For the following RG 1.97, Category 3 recorded variables, the instrumentation is only required to be of high-quality commercial grade selected to withstand the service environment.

The means of indicating the variables is unaffected by this design change, i.e., the design change does not adversely affect the capability of the affected instrument loops to meet the display requirements of RG 1.97, section 1.3.3b for Category 3 variables.

The direct and immediate trending of the variables is not essential for operator information or action (Reference 26). Therefore, it is not required by RG 1.97 that the recording of the following Category 3 variables be on dedicated recorders.

Recorder 1CSCR0079 records Quench Tank Level, Quench Tank Temperature, and Quench Tank Pressure.

Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for these variables as follows: RG 1.97 response (Reference

6) states that there is one indicator, one computer point, and one channel recorded for each variable (level, temperature, pressure).

This design change deletes the existing recorder and wires the inputs to the OAC. Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Sections 7.5.2.35, 7.5.2.36 and 7.5.2.37, discuss these variables but do not address recording of the variables.

The UFSAR Sections are acceptable post-modification as written.Recorder 1IFDWCR0056 records Main Feedwater Flow Loop A and recorder IFDWCROO57 records Main Feedwater Flow Loop B. Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for these variables as follows: RG 1.97 response (Reference

6) states that there are four channels on the computer, and four channels recorded (selectable, one of two per feedline).

This design change deletes the existing recorders, separates the train A and B inputs and wires those inputs to new separate recorders and to the OAC. Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.39, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable post-modification as written.Recorder OGWDCROO35 records Waste Gas Decay Tanks IA and lB Pressure.

Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for this variable as follows: OD100076 5059 Eval Rev O.doc ATrACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 30 of 41 RG 1.97 response (Reference

6) states that there are two computer points, (one per tank), two channels recorded (one per tank). This design change deletes the existing recorder and wires the inputs to the OAC.. Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.49, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable post-modification as written.Recorder IRBCCROO07 records RB Temperature.

Duke's response to RG 1.97 (Reference 6)and the UFSAR provides details on the displays available for this variable as follows: RG 1.97 response (Reference

6) states that there are thirteen points recorded, and thirteen computer points. This design change deletes the existing recorder and wires the inputs to a multi-channel recorder.

The RG 1.97 information remains correct post-modification.

UFSAR, Section 7.5.2.42, discusses this variable and states that for each of the thirteen dual element thermocouples, one element provides input to the plant computer and one element provides input to a multipoint recorder, the recorder displays a range of 0 to 300°F and the recorder is powered by highly reliable battery backed busses. This UFSAR information remains correct post-modification.

UFSAR Section 7.5.2.42 is revised editorially to change the statement "the multipoint recorder" to read "a multi-channel recorder".

In addition, the UFSAR Section is revised to delete the words "and the recorder are" and replace this with the word "is" in the last sentence of the first paragraph.

The new recorder is not powered from a highly reliable battery backed buss since the new recorder is non-QA, commercial grade, and does not require a highly reliable power source. RG 1.97 does not require a highly reliable battery backed power source for the recording device. The recorder for this variable is not the primary indication device and trend and transient information on this variable is not essential for operator information or action.Recorder 1RCCR0049 records Reactor Coolant System Wide Range Coldleg Temperature.

Duke's response to RG 1.97 (Reference

6) and the UFSAR provide details on the display available for this variable as follows: RG 1.97 response (Reference

6) states that there are two channels recorded, with four computer inputs, and four channels can be trend recorded on demand. This design change deletes the existing recorder and wires the input to a multi-channel recorder.Information on the RG 1.97 response has been revised to reflect the impact of this design change (Commitment Change Evaluation Form per NSD 214).UFSAR, Section 7.5.2.15, discusses this variable but does not address recording of the variable.

The UFSAR Section is acceptable post-modification as written. UFSAR Section 7.4.2.2.3 discusses this recorder when it states that "The third temperature recorder has a range of 50*F to 650°F and its input is selectable from either of four cold leg RTD's, two OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 31 of 41 located in "A" loop cold legs and two located in "B" loop cold legs". UFSAR Section 7.4.2.2.3 requires revision as discussed on page 32.In accordance with RG 1.97, section 1.3.3a (Design and Qualification Criteria -Category 3), the instrumentation is to be of high-quality commercial grade. There is no requirement for an isolation device between the sensor and the display (References 5 and 6).The plant computer is capable of recording the instrument ranges specified in the Duke submittal of 9/28/84 and in UFSAR Section 7.5 (References I and II). Any new devices/components installed by part EL2 of this design change are not required to be environmentally qualified since they are located in a mild environment (Reference 26). The panels from which recorders are removed have the resulting hole covered with overlay (Reference 4). A control board seismic review for the control board changes/deletions associated with part EL2 of this design change has been completed with a determination that the control boards are not adversely affected (Reference 4). A 10 CFR 50 Appendix R fire review was performed for the design phase of part EL2 with no adverse affects identified. (Reference 4).Mounting of new recorders, cabinets is QA-4, therefore, there are no seismic interactions between seismically qualified and non-seismically qualified structures, systems, or components (Reference 26).OTHER NON-RG 1.97 VARIABLES:

Recorders IFDWCROO54 (SG A Operate Level) and 1FDWCROO55 (SG B Operate Level) are used for normal plant operating conditions and are not required for accident conditions, although they may be used for backup verification.

Four transmitters (two per SG) are combined with temperature compensation to feed two recorders.

The four channels are switch selectable for feeding the recorders (UFSAR, Section 7.5.2.4 and Reference 6). UFSAR, Section 7.4.2.2.2, also notes that SO operate level is recorded.

Duke's RG 1.97 response (Reference

6) addressed the SG operate level indication as four transmitters (two per SG) combined with temperature compensation to feed two recorders with ranges of 0"' to 400". The RG 1.97 response notes that these operating range variables are used for normal plant operating conditions and are not required for accident conditions.

The four channels are switch selectable for feeding the recorders.

This design change deletes the existing recorders, wires the inputs to two separate recorders (train A and train B) and to the OAC. Information on the RG 1.97 response has been revised to reflect that the variable is recorded on multi-channel recorders (Commitment Change Evaluation Form per NSD 214).Recorders IIICROO08 (1A Incore Detector) and IIICROO09 (I B Incore Detector) are used for normal plant operating conditions and are not required for accident conditions.

UFSAR, Sections 7.6.2.1 and 7.6.2.2, state that the plant computer provides the normal system readout for the Incore Monitoring System. Backup readout is provided for selected detectors.

There are no RG 1.97 requirements associated with the parameter recorded by these recorders.

This design OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 32 of 41 change deletes the existing recorder and wires the input to a new recorder (Reference 19). The UFSAR information is correct post-modification.

Recorder I RCCRO044 records Reactor Coolant Total Flow. UFSAR, Section 7.4.2.2.2, states that reactor coolant flow signals are provided for each loop, summed for total flow and that total flow is recorded.

UFSAR, Section 7.4.2.3.1.1, states that reactor coolant total flow information is available to the operator on the plant computer for each unit. These UFSAR statements are correct post-modification.

This design change deletes the existing recorder.

Flow data from both trains are summed and total flow recorded on a new recorder.

There are no RG 1.97 requirements associated with this parameter.

Recorder IRCCROO47 records Pressurizer Level. This recording of pressurizer level is not the RG 1.97, Category I parameter discussed in the UFSAR. The RG 1.97 pressurizer level variable is recorded by recorder IRCCRO423.

Hence, there are no RG 1.97 requirements associated with the parameter recorded by this recorder and no UFSAR discussion addresses the non-RG 1.97 recording of pressurizer level. This design change deletes the existing recorder and wires the input to a new multi-channel recorder.

The UFSAR information is correct post-modification.

Recorder 1RCCROO50 records Reactor Coolant Average Temperature and recorder 1RCCR0051 records Reactor Coolant THOT Temperature.

UFSAR, Section 5.2.3.10.3, states that reactor coolant average temperature is recorded.

UFSAR, Section 7.4.2.2.3, states that "Reactor coolant temperature is also recorded on three single-pen strip chart recorders.

One recorder indicating average temperature receives its input from the reactor coolant average temperature selected for control and has a range of 520°F to 620°F. The second temperature recorder has a range of 520'F to 620'F and its input is selectable from either the Loop A, Loop B, or Average THOT signals selected for control. The third temperature recorder has a range of 501F to 650*F and its input is selectable from either of four cold leg RTD's, two located in "A" loop cold legs and two located in "B" loop cold legs". UFSAR Section 7.4.2.2.3 is revised to read "Reactor coolant temperature is also recorded on a multi-channel recorder.

One channel indicating average temperature receives its input from the reactor coolant average temperature selected for control and has a range of 520'F to 620'F. A second channel has a range of 520'F to 620'F and its input is selectable from either the Loop A, Loop B, or Average THOT signals selected for control. A third channel has a range of 50*F to 650*F and its input is selectable from either of four cold leg RTD's, two located in "A" loop cold legs and two located in "B" loop cold legs". The UFSAR revisions are to update the UFSAR text to be consistent with the plant configuration after implementation of this design change. There are no RG 1.97 requirements for monitoring or recording Reactor Coolant Average Temperature or Reactor Coolant THOT Temperature.

This design change deletes the existing recorders and wires the inputs to a new multi-channel recorder.Recorders I GENCRO058 (Generator Volts and Amps),-OGrWDCR00333-(Waste Gas Decay Tank Discharge Flow), OGWDCRO 105 (Interim Waste Gas Decy-Tankys IC and ID Pressure), 1HCR0078 (Generator Core Monitor), IHPECROO10 (MSRH Tube Leak Detector), IMSCROO43 (MS Pressure Header A), IMTCR0069 (Main Turbine Vibration and Eccentricity), 1MTCR0070 (Main Turbine Expansion), 1MTCR0071 (Main Turbine Speed and Valve OD100076 5059 Eval Rev 0.doc ATrACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 33 of 41 Position) and Purge Flow) are not discussed in the UFSAR and there are no RG 1.97 requirements for monitoring or recording these variables.

Deletion of the existing recorders does not adversely affect any design or licensing basis requirement.

Recorders 1OACCRMCRA, IOACCRMCRB, 1OACCRMCRC and 1OACCRMCRD previously were used for trending prior to updating the OAC. These recorders have been out of service for years due to obsolescence and unavailability of spare parts (Reference 18). This activity removes these abandoned recorders.

These recorders are not discussed in the UFSAR and there are no RG 1.97 requirements requiring these recorders.

Deletion of the existing recorders does not adversely affect any design or licensing basis requirement.

Recorders 1GENCR0059, 1RIACROO20, 1RIACROO21, 1RIACROO23, IRIACROO24 and I RIACROO89 have previously been removed from the plant but EDB (Equipment Data Base)was not updated to reflect that fact. This activity will update EDB for these particular recorders.

No change to plant configuration is required concerning these recorders.

Recorder I RIACROO22 is out-of-service and no longer required for radiation trending (note that the other radiation trend recorder, 1RIACROO23, was previously removed).

This activity removes this recorder.

The recorder is not discussed in the UFSAR and there is no RG 1.97 requirement requiring this recorder.

Deletion of the existing recorder does not adversely affect any design or licensing basis requirement.

Any new devices/components installed by part EL2 of this design change are not required to be environmentally qualified since they are located in a mild environment (Reference 26). The panels from which recorders are removed have the resulting hole covered with overlay (Reference 4). A control board seismic review for the control board changes/deletions associated with part EL2 of this design change has been completed with a determination that the control boards are not adversely affected (Reference 4). A 10 CFR 50 Appendix R fire review was performed for the design phase of part EL2 with no adverse affects identified (Reference 4).The Selected Licensee Commitment (SLC) requires revision due to this design change. SLC Table 16.11.3-2, Item I e, refers to deleted recorder 3R0037,iJrt 1 g refers to deleted recorder PRCROO82, and Item 5b refers to deleted recordefr.9 003CRQA3.Per this design/change, SLC Table 16.11.3-2 is revised to Unitize reference to the recorders.

That is, recorders)designated GWDCR0037.PP, CR(0-08--2and GWDCR0033 are correct for Units 2 and 3, while the//Unit 1 recorder designation is MSCCR0001 in all three cases. MSCCR0001 is a multi-channel

(, recrder wile mutipleinus' hscag oteSCi oudt h L nomto ae c61 en 1FW t02 [pag 71 OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 34 of 41 UFSAR revisions are required due to this design change. The affected UFSAR Sections requiring revision are 7.4.2.2.3, 7.5.2.2.2, 7.5.2.1, 7.5.2.5, 7.5.2.6, 7.5.2.7, 7.5.2.8, 7.5.2.9, 7.5.2.11, 7.5.2.12, 7.5.2.16, 7.5.2.40, 7.5.2.42 and 7.5.2.53.

These revisions to the UFSAR are previously discussed in this Evaluation on pages 19, 22, 19, 19, 17, 18, 18, 18, 15, 23, 22, 16, 30 and 26, respectively.

Mounting of new recorders is QA-4, therefore, there are no seismic interactions between seismically qualified and non-seismically qualified structures, systems, or components (Reference 26).10 CFR 50.59 EVALUATION QUESTIONS Does the proposed activity: 1) Result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the UFSAR?No. For Part ELI: The five control valves affected by this design change (new Fieldbus valve positioners) are non-safety, non-seismic valves which are not required for the mitigation of any analyzed accident.

The valve bodies, actuator and air supply are unaffected by this design change. The new valve positioners are non-QA and not required to operate to mitigate any analyzed accident.

Since the valve control algorithm resides within the new valve positioner, the positioner functions independently, i.e., the process loop has single loop integrity and no common failure mode will affect other loops or vice versa.Control loop parameters are displayed on a computer graphics display station referred to as the PCS, located in the Control Room. The PCS, in its entirety, is a non-safety, non-seismic system (except for control board or panel mounting).

No diversity or separation is required for the PCS. It is not required to be operable during or after an accident.There are no plant operating modes or events where the PCS is required to be operable.The PCS is not to be used for safety related applications.

This design change does not adversely affect the existing IA system and compensatory actions taken to alleviate loss of IA during SSLB/LOOP events since the design change does not affect the air supply to affected valves or the existing pneumatic actuator on those valves. In addition, for the pneumatic instruments replaced electronic counterparts by this design change, the air source to the replaced instrumentation is isolated and capped.The equipment added by part ELI of this design change to the control areas does not adversely affect the ability of CRACS to maintain control area temperatures.

OD100076 5059 Eva] Rev 0.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 35 of 41 The original analog instruments and replacement digital instruments are not required for the mitigation of any accident described in the UFSAR and, due to the reliability of the new digital instruments, would not increase the frequency of occurrence of analyzed accidents.

For Part EL2: The recorders removed/replaced and the new workstations installed by Part EL2 of this design change are not initiators of any analyzed accident.

Therefore, this part of the design change will not increase the frequency of occurrence of any UFSAR evaluated accident.2) Result in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR?No. For Part ELi: Part ELI of this design change is non-QA. The design change installs a non-QA Fieldbus infrastructure and replaces non-QA pneumatic instruments with Fieldbus devices, however, mounting of new cabinets and human machine interfaces is QA-4.Five instrument loops affected by this design change involve valve control (none of the other remaining loops involve control functions).

For those loops involving valve control, the existing pneumatic valve positioner is replaced with a Fieldbus valve positioner using a PID (Proportional, Integral, Derivative) control algorithm.

These five valves are non-safety, non-seismic valves. The valve bodies, actuator and air supply are unaffected by this design change. The new valve positioners are non-QA. Since the valve control algorithm resides within the new valve positioner, the positioner functions independently, i.e., the process loop has single loop integrity and no common failure mode will affect other loops or vice versa.Control loop parameters are displayed on a computer graphics display station referred to as the PCS, located in the Control Room. The PCS, in its entirety, is a non-safety, non-seismic system (except for control board or panel mounting).

No diversity or separation is required for the PCS. A loss of this system will not affect any plant operating mode, as reviewed in the UFSAR. There are no plant operating modes or events where this system is required to be operable.

Field devices will continue to function, as long as they have power, without a functioning PCS. Fieldbus instruments have embedded microprocessors that are capable of performing control algorithms independent of the PCS. The PCS is not to be used for safety related applications.

This design change does not adversely affect the existing IA system and compensatory actions taken to alleviate loss of IA during SSLB/LOOP events since the design change does not affect the air supply to affected valves or the existing pneumatic actuator on those valves. In addition, for the pneumatic instruments replaced electronic counterparts by this design change, the air source to the replaced instrumentation is isolated and capped..ODI00076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Paze: 36 of 41 Upgraded instrument loops affected by this design change use existing basis and resultant values for setpoints and control features.

Loop accuracy calculations have been revised as appropriate.

The fail safe positions of valves and components stay the same as they were before the upgrade. None of the upgraded loops are required for RG 1.97 compliance.

The equipment added by part ELI of this design change to the control areas does not adversely affect the ability of CRACS to maintain control area temperatures.

The seismic considerations for instrumentation and electrical equipment are in accordance with SQUG requirements.

Cabinet mounting and equipment support designs for part ELI of this design change are complete.

For those control room panels from which analog devices are removed by part ELI of this design change, the seismic integrity of those panels has been analyzed and found to be not adversely affected.

The mounting of digital instruments has been addressed for adequate/appropriate mounting for the area in which they are located.Instruments I CPT0641, 1 CPT0642, IMSPT0030A and IMSPT003IA are required to maintain pressure boundary (References 21, 22, 23 and 24). The signal output of these instruments are not required for performance of any safety function.

The new fieldbus instrument is designed to maintain pressure boundary and so will not adversely affect the performance of other instrumentation or required pressure boundary.For all the replaced instrument loops, loop upgrades are designed to mimic the original design, and where practical, take advantage of the increased accuracy of the new devices.The new digital devices are suitable for their service environment.

The equipment is located in a mild environment.

Cables installed or rerouted during installation of the fieldbus devices and network are installed per approved plant procedures.

An electrical 10 CFR 50 Appendix R fire review was performed for the design phase of part ELI with no adverse affects to the Appendix R fire separation requirements.

For the digital devices installed by this design change, it has been determined that the installed equipment is electromagneticly compatible with other plant equipment, i.e., the equipment will function satisfactorily in its electromagnetic environment without introducing adverse disturbances to that environment or to other equipment.

Power supply sources for the new fieldbus instruments are adequate for the application.

The plant electrical distribution system is not adversely affected by the electrical loads presented by the new fieldbus instruments.

ODi00076 5059 Eva] Rev O.doc ATTACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 37 of 41 The software/firmware associated with the replacement instruments is characterized as SDQA Category C per NSD-800, which is an appropriate classification for this application in accordance with Table 800-2 (Definition of Software and Data Quality Assurance Categories) of NSD-800. Document SDQA- 10144-ONS specifies minimum and recommended requirements as well as responsibilities to ensure the application provides expected results.For Part EL2: Changes to Control Room boards caused by the removal/addition of recorders have been evaluated for seismic loading concerns and found to be acceptable.

The new recorders are seismically mounted on the Control Room boards. Those new recorders which electrically interface with safety circuits (i.e. receive their signal from safety related loops) are electrically isolated from associated safety signals using qualified isolators.

Recorders are located in a mild (Control Room) environment and hence do not require environmental qualification.

For the RG 1.97 variables recorded by the old or new recorders, the recorders are not the primary display device for the parameter.

Therefore, the recorders are not required by RG 1.97 to be seismically qualified (they are seismically mounted as previously noted). The direct and intermediate trend or transient information of the recorded variables is not essential for operator information or action, therefore, dedicated recorders are not required by RG 1.97 for recording these variables.

In other words, the use of non-dedicated, non-seismically qualified recorders or the OAC to record the affected variables meets the intent of RG 1.97 and is acceptable.

The recorders and new workstations are not considered important to safety since they are non-safety related devices which are not relied upon to mitigate accidents nor would their failure prevent any safety-related SSC from performing its design function.

Therefore, this Part EL2 does not cause a more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety.3) Result in more than a minimal increase in the consequences of an accident previously evaluated in the UFSAR?No. For Part ELI: Several QA-2 designated instruments are affected by this design change. Per NSD-307, QA Condition 2 applies to those non-nuclear safety related systems, structures, and components important to the management and containment of liquid, gaseous, and solid radioactive waste. NSD-307 also states that instruments connected to the QA-2 Class E piping via instrument tubing must meet the process and environmental conditions of the application.

The new Fieldbus instruments are suitable for the applicable applications, i.e., they meet pressure and environmental requirements.

Five loops affected by this design change involve valve control. The five affected valves are non-safety, non-seismic valves which are not required for the mitigation of any OD100076 5059 Eval Rev 0.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 38 of 41 analyzed accident.

The valve bodies, actuator and air supply are unaffected by this design change. The new valve positioners are non-QA and not required to operate to mitigate any analyzed accident or event.The replacement of pneumatic instruments with Fieldbus instruments does not change, degrade, or prevent actions described or assumed in a UFSAR analyzed accident.

The replaced instrumentation is not required to operate for the mitigation of any analyzed accident.

The design change does not alter assumptions made in evaluating the consequences of UFSAR analyzed accidents.

Therefore, the consequences of analyzed accidents are unaffected by Part ELI of this design change.For Part EL2: The new recorders and new workstations are not initiators of any analyzed accident nor are they required for the mitigation of any analyzed accident.

Therefore, this Part EL2 of the design change does not impact the consequence analysis of any UFSAR analyzed accident.4) Result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the UFSAR?No. For Part ELI: Some of the components affected by this design change are designated as QA-2 instruments.

Per NSD-307, QA Condition 2 applies to those non-nuclear safety related systems, structures, and components important to the management and containment of liquid, gaseous, and solid radioactive waste. NSD-307 also states that instruments connected to the QA-2 Class E piping via instrument tubing must meet the process and environmental conditions of the application.

The new Fieldbus instruments are suitable for the applicable applications, i.e., they meet pressure and environmental requirements.

For Part EL2: Malfunctions of the recorders or new workstations will have no impact on consequences of analyzed accidents.

These Part EL2 components are not considered important to safety since they are non-safety related devices which are not relied upon to mitigate accidents nor would their failure prevent any safety-related SSC from performing its design function..5) Create a possibility for an accident of a different type than any previously evaluated in the UFSAR?No. For Parts ELI and EL2: This activity is a design change to the facility that does not introduce the possibility of a new accident because the SSCs added/deleted by this design change are not an initiator of any accident and new failure modes are not introduced.

Therefore, there is no credible possibility for the occurrence of a different accident than is already analyzed in the UFSAR.OD100076 5059 Eval Rev O.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 0D100076 Page: 39 of 41 6) Create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the UFSAR?No. For Parts ELI and EL2: The malfunctions associated with this design change are similar to the malfunctions of the components replaced by this design change, i.e., no new failure modes. Therefore, there are no new malfunctions that need be postulated.

7) Result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or altered?No. For Parts ELI and EL2: This activity is a design change which does not modify structures, systems or components with the potential to affect fission product barriers.

The activity does not result in a change that would cause any system parameter to change. Therefore, this activity does not result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or altered.8) Result in a departure from a method of evaluation described in the UFSAR used in establishing the design bases or in the safety analyses?No. For Parts ELI and EL2: This activity is a design change to the facility and does not constitute a method of evaluation as defined in the UFSAR. This design change does not result in a departure from a UFSAR described analytical methodology (computer code or analysis) used to demonstrate how the plant design meets regulatory requirements and how the plant responds to accidents and events is acceptable.

Therefore, this activity does not result in a departure from a method of evaluation described in the UFSAR and used in establishing the design bases or in the safety analyses.This evaluation is not intending to address any procedures, procedure changes, implementation, or testing activities.

REFERENCES

1) Oconee Nuclear Station Updated Final Safety Analysis Report (UFSAR), effective as of 12/31/04, Sections 1.2.2.9,5.2.3.10.3, 5.2.3.10.5, 7.2.3.9, 7.4.2.2, 7.4.2.2.1,7.4.2.2.2, 7.4.2.2.3, 7.4.2.3.1.1, 7.4.3.1.2, 7.5.1.4.1, 7.5.1.4.2, 7.5.1.4.3, 7.5.1.4.4, 7.5.1.4.5, 7.5.2.1, 7.5.2.2.2, 7.5.2.2.3, 7.5.2.3, 7.5.2.4, 7.5.2.6, 7.5.2.7, 7.5.2.8, 7.5.2.9, 7.5.2.10, 7.5.2.11, 7.5.2.12, 7.5.2.15, 7.5.2.16, 7.5.2.17, 7.5.2.18, 7.5.2.19, 7.5.2.23, 7.5.2.35, 7.5.2.36, 7.5.2.37, 7.5.2.39, 7.5.2.42, 7.5.2.49, 7.5.2.53, 7.6.2.1, 7.6.2.2, 7.7.2, 7.9.1, 8.3.1.4.6, 8.3.1.5, 9.3.2.2.1, 9.3.7.1, 9.3.7.3, 9.4.5, 9.5.1.4.3, 10.1, 10.2.2, 10.4.2.2, 10.4.7.1, 10.4.7.2,11.3,11.5.2,12.4.7 Figures 10-1, 10-4, 11-3, Tables 3-2, 3-68.OD100076 5059 Eval Rev 0.doc ATT'ACHMENT 1 ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 40 of 41 2) Oconee Nuclear Station Technical Specifications, revised as of 1/5/06, and associated bases volume, revised as of 4/12/06, Section 3.3.8, 3.3.10, 3.3.11, 3.3.12, 3.3.13, 3.4.9, 3.4.12, 3.5.2, 3.5.3, 3.5.4, 3.6.5, 3.7.5, 3.7.6.3) Oconee Nuclear Station Selected Licensee Commitments and associated bases, revised as of 4/12/06, Sections 16.5.2, 16.5.13, 16.6.10, 16.6.12, 16.6.13, 16.7.3, 16.7.8, 16.7.11, 16.11.3.4) OD100076, Revision 0, "Unit 1 Foundation Fieldbus Installation, Design and Upgrade of Selected Loops, and Unit I Control Room Chart Recorder Removal/Replacement".

5) Regulatory Guide 1.97, Revision 2, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident".

6) Correspondence from H. B. Tucker (Duke) to H. R. Denton (NRC) dated September 28, 1984, transmitting Revision 6 to the Duke Power Company response to Supplement 1 to NNUREG-0737 for Oconee.7) Correspondence from J. F. Stolz (NRC) to H. B. Tucker (Duke) dated 7/11/85, requesting additional information concerning Reg Guide 1.97 compliance.

8) Correspondence from D B. Matthews (NRC) to H. B. Tucker (Duke) dated 12/19/88, accepting requested deviations from Reg Guide 1.97 for pressurizer level (and other variables).

9) NRC Staff memorandum from G. C. Lainas to L. A. Reyes dated 5/16/90 discussing the recording requirements for Reg Guide 1.97 variables RCS hot leg water temperature, auxiliary feedwater flow, wide range steam generator level, and degrees of subcooling.

10) Correspondence from A F. Gibson (NRC) to H. B. Tucker (Duke) dated 10/22/90, regarding the subject matter in reference 9 above.11) Nuclear System Directive 800, Revision 9, "Software and Data Quality Assurance (SDQA) Program".12) Specification OSS-0254.00-00-4012, Revision 1, "Design Basis Specification for Selected Plant Design Requirements and Programs", Sections 3.5 and 4.5.13) Correspondence from C. A. Julian (NRC) to H. B. Tucker (Duke) dated 3/16/89 concerning a Notice of Deviation (IR 89-07).14) Correspondence from H. B. Tucker (Duke) to NRC dated 4/17/89 concerning Notice of Deviation (IR 89-07).15) Correspondence from A. F. Gibson (NRC) to H. B. Tucker (Duke) dated 10/22/90 concerning Notice of Deviation (IR 89-07).16) 10 CFR 50.59 Evaluation for Minor Modification ONOE-13892.

17) Email from W. A. Schooley to G. F. Grant, etc., dated 9/12/02, forwarding comments from J. E. Smith (Regulatory Compliance).

See Attachment 2.18) PIP 0-03-08050, issued 12/11/2003, concerning obsolete, abandoned chart recorders..'

OD100076 5059 Eval Rev 0.doc ATTACHMENT I ONS-2005-002 10 CFR 50.59 Evaluation, Rev. 0 Date: 6/22/06 OD100076 Page: 41 of 41 19) PIP 0-02-05186, issued 10/2/2002, concerning recorders IIICROO08 and IIICROO09.

20) Not used.21) Drawing O-422K-59, Revisions 0 and OA, "Instrument Detail EFDWP Suction Strainer D/P Transmitter 1CPT0641".

22) Drawing 0-422K-60, Revisions 0 and OA, "Instrument Detail EFDWP Suction Strainer D/P Transmitter 1 CPT0642".23) Drawing O-422N-1 1, Revisions 7 and 7A, "Instrument Detail Main Steam Pressure Trans.".24) Drawing 0-422N- 11-01, Revisions 3 and 3A, "Instrument Detail Main Steam Pressure Trans. Header IB".25) Drawing OFD-121D-1.1, Revisions 28 and 28B, "Flow Diagram of Emergency Feedwater System".26) OSC-8229, Revision 2, "Electrical Design Inputs for OD100076 / OD100288".

27) NSD-307, Revision 24, "Quality Standards Manual".28) NRC Regulatory Issue Summary 2002-22, dated November 25,2002, 'Use of EPRI/NEI Joint Task Force Report, "Guideline on Licensing Digital Upgrades:

EPRI TR-102348, Revision 1, NEI 01-01: A Revision of EPRI TR-102348 to Reflect Changes to the 10 CFR 50.59 Rule'.29) EPRI TR-102348, Revision 1, NEI 01-01, "Guideline on Licensing Digital Upgrades".

30) OSS-0254.00-00-1025, Revision 8, "Design Basis Specification for the Instrument Air (IA) System".31) PIP 0-04-02808, initiated 04/29/2004, concerning how a MSLB could be mitigated during a LOP when neither the MFCVs nor SFCVs have power.32) SDQA-1 0144-ONS, Revision 0, "Software Requirements

& SDQA for Unit Process Control System".OD100076 5059 Eval Rev 0.doc ATTACHMENT 2 10 CFR 50.59 EVALUATION OD/oo 7o _Sheet of2 Willard A Schooley /Gen/DukePower 09/12/2002 04:49 PM To Vandy Kim/GenlDukePower@DukePower, Gary E Wood/Gen/DukePower@DukePower, Gary F Grant/Nuc/DukeEngineering@DukePower cC Donald A Lee/Gen/DukePower bcc Subject Re: NSM ON-12995EL12

-- Forwarded by Willard A Schooley/Gen/DukePower on 09/1212002 04:49 PM --Judy E Smith 09/12/2002 04:39 PM To: Willard A Schootey/Gen/DukePower@DukePower cc: Gary E WoodlGen/DukePower@DukePower, Vandy Kim/Gen/DukePower@DukePower

Subject:

Re: NSM ON-12995EL12[j Based on TS 3.3.8 PAM instrumentation review, and review of the documents you sent, the NSM changes to the recorders is acceptable.

Since the letter specifically states that the addition of the recorders is not an addition to the R.G. 1.97 commitments, I will not file a commitment change. However, I will keep the documentation in the file and feel confident that we will still be meeting the requirements of R. G. 1.97.Judy Smith Willard A Schooley Willard A Schooley 09/05/2002 10:17 AM To: Judy E Smith/Gen/DukePower@DukePower cc: Gary E Wood/Gen/DukePower@DukePower, Vandy Kim/Gen/DukePower@DukePower

Subject:

NSM ON-12995EL12 Judy: Gary Grant brought this to me with a question that-he believes need resolution:

Do these 4 Category 1 variables require a separate, dedicated chart recorder?

The recorders in question are: 1,2 & 3FDWCRO427 Steam Generator 1A and 18 level 1,2,& 3FDWCR0428 Auxiliary Feedwater Flow 1,2,& 3RCCRO426 RC System Wide Range Hotleg Temp (Loop A & B)1,2 & 3RCCR0429 Deg-Sub Cooling Loop A The MARF 170 requires these recorders be removed and the inputs be wired to a backup recorder (They also go to the OAC).I would appreciate your comments on these attachments (ISD 12995 ELi and EL2 plus those from Gary).Bill Schooley ATTACHMENT 2 10 CFR 50.59 EVALUATION ODlooo70 Sheet Z of *2 Unit1 ISD ELI & EL2 Rev 0.do Forwarded by Willard A Schooley/Gen/DukePower on 09/05/2002 09:45 AM -Gary F Grant To: Willard A Schooley/GenlDukePower@DukePower 09/05/2002 09:19 AM cc: bcc:

Subject:

NSM ON-12995EL12 Attached is an NRC memo discussing the requirements for recording four Reg Guide 1.97 variables.

Within the memo there is a statement that "The licensee did commit to install dedicated, non-safety grade recorders to monitor one channel of each of these four variables".

We need. to be sure that removal of existing dedicated recorders for these variables and using the OAC and (non-dedicated) backup recorders is acceptable in regards to the discussion in the attached NRC Staff memo.NRC Staff memo.pd