ML071870229

CFR 50.59 Annual Report; of Changes, Tests, and Experiments Completed Between January 1, 2006, and December 31, 2006

ML071870229
Person / Time
Site:	Oconee
Issue date:	06/29/2007
From:	Brandi Hamilton Duke Energy Carolinas, Duke Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML071870229 (50)

Text

BRUCE H HAMILTON kDuke Vice President EEnergy Oconee Nuclear Station Duke Energy Corporation ON01 VP / 7800 Rochester Highway Seneca, SC 29672 864 885 3487 864 885 4208 fax bhhamilton@duke-energy.corn June 29, 2007 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555

Subject:

Duke Power Company LLC d/b/a Duke Energy Carolinas, LLC Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, 50-287 10 CFR 50.59 Annual Report Attached are descriptions of Oconee facility changes, tests, and experiments which were completed subject to the provisions of 10 CFR 50.59 between January 1, 2006, and December 31, 2006. This report is submitted pursuant to the requirement of 10 CFR 50.59 (d) (2).

If there are any questions, please contact Graham Davenport at (864) 885-3044.

Very truly yours, Bruce H. Hamilton Site Vice President Oconee Nuclear Site Attachment S* *7 www. duke-energy. corn

U. S. Nuclear Regulatory Commission June 29, 2007 Page 2 xc: Dr. W. D. Travers Regional Administrator, Region II U. S. Nuclear Regulatory Commission Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, GA 30303 Mr. D. W. Rich Senior NRC Resident Inspector Oconee Nuclear Site Mr. L. N. Olshan Senior Project-Manager Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, DC 20555

U. S. Nuclear Regulatory Commission June 29, 2007 Page 3 bxc (w/ Attachment): ELL - EC050 ONS Doc Management bxc (w/o Attachment): B. H. Hamilton D A. Baxter R. M. Glover L E Nicholson B G Davenport R. L Gill (NRIA)

R. D Hart (CNS)

K. L Ashe (MNS)

J. V. Weast

U.S. Nuclear Regulatory Commission Page 1 of 46 Type: Nuclear Station Modification [NSM ON-13098]

Title:

This NSM will make modifications to eliminate single active failures associated with the Upper Surge Tank (UST). These modifications involve both "active type" and "passive type" isolation.

==

Description:==

This modification is to add four air-operated valves (AOV) that automatically close when the UST level drops below 7.5 feet. New valves 1C-903 and 904 are to isolate flow to the hotwell and to the Auxiliary Boiler Feedwater (FDW) pump. A bypass valve, 1C-912, is provided around valves 1C-903 and 904. Valves IC-906 and 907 isolate flow to the Powdex Backwash Pump. Both the Auxiliary Boiler FDW pump and Powdex Backwash pump will have pressure switches in the suction line that will trip them on low suction pressure. These pressure switches are to be installed on the first unit that implements the automatic isolation valves C-903, 904, 906, and 907.

The modification is also to add a new Condensate Recirculation path to the UST. This path will allow flow from the Condensate Booster Pump suction line to the UST Riser. A manual throttle valve, 1C-899, and flow indication (locally and on the Operator Aid Computer) are provided. This new Condensate Recirculation path should provide significant operational flexibility during unit start-ups.

Other changes by this modification include:

• upgrade of the hotwell level control system, including replacement of valve 1C-192, and level transmitters LT-17 and LT-19

• removal of electric motor operated valves 1C-152 and 153

• upgrade of the UST level transmitters to proper environmental qualifications

• upgrade of the Emergency Feedwater (EFW) Pump recirculation path to the UST Dome Tank to Class F, QA Condition 1; including seismic qualification of the Dome Tank.

Evaluation: There are currently three somewhat independent paths of water from the UST to the condenser. The modification will combine the supplies to these paths with a common header. With the existing design for normal operating conditions, one of the AOVs can fail closed (e.g., loss of air to valve operator) and this failure will not necessarily prevent another of the AOVs from opening (or remaining open) to supply water from the UST to the condenser hotwell if there is a low hotwell level. In the new design, a failure of one of the new AOVs could prevent water from transferring to the hotwell from the UST through this pathway. The safety function of the valves is to close on low UST level. During certain accidents/events, the valves in both the current and proposed new design will receive a close

U.S. Nuclear Regulatory Commission Page 2 of 46 signal on low UST level. In the new design, the failing closed of one of the new AOVs (1C-903 or 1C-904) can stop the flow of water from the UST to the condenser. The UFSAR describes the three separate pathways from the UST to the condenser hotwell, but the context of this wording is in relation to the pathways being automatically isolated on a low UST level. In the unlikely event that one of the new AOVs does inadvertently close, manual actions could be taken to open the bypass around the new valves. If this action was not taken and the level dropped significantly, a trip of the unit could occur. The loss of air to the new AOVs could occur due to a loss of the non-safety related Instrument Air System or due to a loss of air locally at the valve (e.g., loss of the safety related power supply to the solenoid valve on one of the new valves. A loss of the Instrument Air System would result in the same effect in both the existing and new design. The effect would be that the flowpath(s) from the USTs to the hotwell would be isolated due to fail closed AOVs. If the air supply is lost to one of the new valves (1C-903 or 1C-904), then all three flowpaths would be isolated. But, there are manual actions that could be taken to bypass the failed closed AOV. If the hotwell level is not replenished over time, a trip of the unit could occur. Thus, there is a possible increase in the potential for a turbine/reactor trip if makeup to the hotwell is not able to be achieved. But there are other means for a reactor/turbine trip to occur. UFSAR Section 15.8 provides a number of means for a turbine trip. The potential cause for a turbine trip is described as including a generator trip, low condenser vacuum, loss of turbine lubrication oil, turbine thrust bearing failure, turbine overspeed, main feedwater pump trip, high steam generator level, or a reactor trip. The loss of hotwell level could, if low enough cause the main feedwater pumps to loose suction pressure and ultimately trip. The trip of the main feedwater pumps are listed in the UFSAR section described above. This small potential for a localized loss of air to one of the new valves is considered to be a negligible increase to the overall turbine trip potential and thus is not a "more than a minimal increase" in the frequency of occurrence of an accident previously evaluated in the UFSAR.

The two AOVs (1C-903 and 1C-904) in the common header from the USTs to the hotwell will isolate the UST if a low UST level is detected or if air is lost to the valves. These two AOVs are to be used as the QA-1 Class F boundary so that the UST tank contents will be isolated even in the event of a single failure. The potential for "more than a minimal increase" in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR was investigated with respect to the UST's makeup going into a common header before going to the three separate pathways. Equipment important to safety affected by this modification includes the UST (assured source of EFW),

condenser hotwell (one of the potential long term sources of EFW), and

U.S. Nuclear Regulatory Commission Page 3 of 46 EFW System (provides feedwater in the event of a loss of main feedwater). There are currently three somewhat independent paths of water from the UST to the condenser. The modification will combine the supplies to these paths with a common header. Although flow from the UST to the condenser hotwell is not required to be designed to withstand a single failure, the potential for "more than a minimal increase" in likelihood of occurrence of a malfunction of an SSC important to safety needs to be considered. With the existing design for normal operating conditions, one of the AOVs can fail closed (e.g., loss of air to valve operator) and this failure will not necessarily prevent another of the AOVs from opening (or remaining open) to supply water from the UST to the condenser hotwell if there is a low hotwell level. In the new design, a failure of one of the new AOVs could prevent water from transferring to the hotwell from the UST through this pathway. The safety function of the valves is to close on low UST level. During certain accidents/events, the valves in both the current and proposed new design will receive a close signal on low UST level. In the new design, the failing closed of one of the new AOVs (1C-903, IC-904) can stop the flow of water from the UST to the condenser. The UFSAR describes the three separate pathways from the UST to the condenser hotwell, but the context of this wording is in relation to the pathways being automatically isolated on a low UST level.

The "important to safety" aspect of the condenser hotwell is its function of supplying an EFW supply of water after the UST source has been exhausted. The flowpath from the condenser to the EFW pumps is not adversely affected with the new valves since that flowpath is not used when supplying the EFW pumps via the hotwell. The "important to safety function" of the existing AOVs and the new AOVs in the new design is considered to be their closure on low UST level. This function is enhanced in the new design. Supplying the hotwell from the UST is considered more of an operational issue versus an "equipment important to safety" issue. Thus, the use of a common header with two AOVs in series is not considered to cause a "more than minimal" increase in the likelihood of occurrence of a malfunction of an SSC important to safety previously evaluated in the UFSAR.

The EFW System is used to mitigate accidents involving the loss of main feedwater. The modification will not change the design function of the EFW supply sources as evaluated in the UFSAR. Thus, in an accident involving loss of main feedwater, the EFW System will still be able to mitigate the event as currently described in the UFSAR. There is no adverse effect on containment integrity and no new release paths are created.

The UST will be designed to provide a source of water to the EFW System even in the event of a single failure. The hotwell backup source is not

U.S. Nuclear Regulatory Commission Page 4 of 46 designed to provide the additional EFW water supply in the event of a single failure. The flowpath from the UST to the hotwell is not required to be designed to withstand a single failure for the function of allowing water to flow. This path is designed such that a single failure does not allow UST flow to be depleted to the Hotwell. Thus, the EFW function is not adversely affected with respect to mitigating loss of feedwater scenarios previously evaluated in the UFSAR.

Not upgrading the existing Class G portion of the piping to Class F in the first phase does not cause any adverse effects since the piping is being left as it currently exists from a piping classification perspective.

Based on the above, there were no safety concerns. No Technical Specification or Bases, and Selected Licensee Commitments needs to be changed due to this Design'Change. There are UFSAR changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification / UFSAR Revision [NSM ON-33107] [UFSAR 06-42]

Title:

The purpose of this NSM is to modify the Low Pressure Service Water (LPSW)

System to provide containment isolation of the Reactor Building Auxiliary Coolers (RBAC) during an accident such that the piping to and from the RBACs is not credited as a containment boundary.

==

Description:==

This modification consists of Part A and Part B. All installation activities associated with the conversion of the spare electrical penetrations to mechanical penetration assemblies will constitute Part A. The remaining portions of the modification will be implemented in Part B.

Part A of NSM ON-33107 is to convert two spare electrical penetrations into two mechanical fluid penetrations. The existing spare electrical penetrations consist of 12 inch pipes that pass through containment with a plate welded on the Reactor Building side of the pipe. These spare electrical penetrations will be modified to allow piping to be installed.

Piping that will be used as LPSW System piping in Part B is to pass through the existing 12 inch pipe and is to be connected to the liner plate With a dished head. The dished head will be welded to the containment liner plate. The end of the pipe will extend past the dished head into containment. A pipe cap will be welded to the end of the containment side of the pipe if Part A is to be installed without Part B also being installed.

The dished head/piping/cap will become a portion of the containment pressure boundary. Guide lugs (i.e., lateral restraints) will be provided on the end of the penetration pipe opposite the dished head/cap. The new fluid penetrations will be designated as Penetrations 63 and 64.

U.S. Nuclear Regulatory Commission Page 5 of 46 Part B of the NSM will isolate the LPSW piping associated with the RBACs from the LPSW supply to the "B" Reactor Building Cooling Unit (RBCU). The NSM will tie the RBAC piping to the LPSW supply and return main headers in the Auxiliary Building by utilizing the two converted penetrations from Part A of this NSM. Two air operated valves per penetration (supply header and return header) will be provided as containment isolation valves for the RBAC supply and return piping that penetrates the Reactor Building to ensure that the integrity of the containment is maintained following a design basis accident. Valves, flow measurement orifices, instrumentation, test connections and flanges will also be provided. This modification is to provide seismically qualified QA-1 piping and components to meet the requirements of the Updated Final Safety Analysis Report (UFSAR). The portion of the RBACs piping inside the containment will no longer be credited as a containment barrier.

The modification will remove the existing valve 3LPSW565, which is a Motor Operated Valve (MOV) in the Reactor Building, and the connection to the RBCU piping will be capped. The existing valve 3LPSW566, which is also an MOV located in the reactor building, will be removed.

As a result, the Engineered Safeguards (ES) signal that 3LPSW565 and 566 receives from Channels 5 and 6 will be removed from these valves.

The ES channel 5 signals that currently go to 3LPSW565 and 3LPSW566 are to be utilized with the first outside containment isolation valves (3LPSW 1055 and 3LPSW 1061) for the new penetration assemblies 63 and 64. The ES channel 6 signals that currently go to 3LPSW565 and 3LPSW566 will be utilized with the second outside containment isolation valves (3LPSW1054 and 3LPSW1062).

New waterhammer prevention circuitry, also known as RBAC Isolation Circuitry, is designed to-close the containment isolation valves on low LPSW supply pressure to prevent a column closure waterhammer prior to LPSW system repressurization. The LPSW piping is currently in an operable but degraded/non-conforming condition due to the waterhammer concerns. The operable but degraded/non-conforming condition was established in response to Generic Letter 96-06 issues. To address the waterhammer issue, the NSM will install an instrumentation system that will monitor for low LPSW supply header pressure, indicative of a loss of LPSW, and close RBAC supply and return valves. This new circuitry is to enhance prevention of waterhammer. Since the 10 CFR 50.59 regulation establishes a licensing basis test to determine if licensees can make changes to their facilities without prior NRC approval, this 10 CFR 50.59 evaluates whether the facility change can be implemented without prior NRC approval. The 10 CFR 50.59 does not determine whether the use of the circuitry can be used to resolve this operable but degraded/non-

U.S. Nuclear Regulatory Commission Page 6 of 46 conforming condition. The resolution of the operable but degraded/non-conforming issue is a separate regulatory issue.

Operator Aid Computer indication is to be provided for the 4 new Air Operated Valves (AOV) containment isolation valves' position, the RBACs supply and return flow rates, and a new RBAC tube rupture alarm (based on flow mismatch). To assist in meeting the requirement of Generic Letter 96-06 for thermal overpressure protection, each penetration is provided with a relief valve (3LPSW-1057 and 3LPSW-1089) between the penetration and the adjoining valve inside containment. Piping and valves will be added in the Auxiliary Building between the LPSW supply

& return main headers and the RBAC to allow the hook up and usage of the temporary chiller during outages.

Add new QA-1 auxiliary terminal cabinets in the Unit 3 Cable Room.

These cabinets are necessary on Unit 3 to supply space for this NSM.

Several options are being considered with respect to implementation of this NSM. The first option is to perform the implementation of Part A and Part B together during the same outage. The second option is to install Part A in one outage and Part B during a different outage. A variation within these options is to install the new electrical cabinets that are identified with Part B at any time. If the cabinets are installed independent of Part B, they will not be made functional (i.e., no components installed or cables pulled to them). An additional variation is to install the wet taps identified with Part B (including tapping valves) such that they tie into the new LPSW lines into the existing LPSW supply and return headers at any time. If the wet taps are installed independent of Part B, blind flanges will also be installed. Since the NSM parts may be installed separately, the NSM parts will be evaluated individually. Thus, this evaluation will address both parts implemented together. The implementation of the electrical cabinets and the wet taps (with valves and blind flanges) identified with Part B will be evaluated from the standpoint of them being installed separately also. Thus, this 10 CFR 50.59 will be valid for any of these options or variations.

Revision 1 of this 10 CFR 50.59 was performed to address changes in the modification as reflected in revision 3 of the final scope document. These changes include the cable routing of a QA-1 and a non-QA cable to the Unit 3 Normal Control Engineered Safeguards (ES) cabinet 8. In addition, the scope was expanded to remove and cap some process tubing for drain lines from old Hydrogen Recombiner piping that is located in the East Penetration Room. The revision also removes some wording about the

U.S. Nuclear Regulatory Commission Page 7 of 46 need for a technical specification that would allow credit to be taken for the new circuitry. Clarification is added that the 10 CFR 50.59 regulation does not include resolving operable but degraded/non-conforming issues.

Revision 2 of this 10 CFR 50.59 was performed to address Variation Notice VN33107BL1K. This VN removed some scope that was previously added in revision 3 of the final scope document. The scope that was added in revision 3 of the final scope document that is affected by this VN was to reroute a QA-1 cable and a non-QA cable through the non-QA Auxiliary Control System (ACS) cabinet #14 and then into QA-1 Engineered Safeguards (ES) Cabinet 8. The non-QA ACS cabinet was also to be upgraded to QA-1. At the time of the scope addition, the ability to pull the cable through the cable sleeve to ES cabinet 8 was thought to be filled to capacity. It has now been determined that direct access to the ES cabinet 8 is possible.

This evaluation is not addressing procedures, procedure changes, implementation, or testing activities.

Evaluation: Part A NSM ON-33107 Part A does not meet any of the 10 CFR 50.59 criteria.

Part A does not require a Technical Specification or Selected Licensee Commitment (SLC) changes.

The containment is used to contain releases during accidents. The containment does not cause any accidents previously evaluated in the UFSAR. The new mechanical fluid penetrations do not cause adverse effects with respect to the containment design conditions. Appropriate design conditions are used in the mechanical penetration design. Thus, the containment and associated penetrations are not more likely to malfunction as evaluated in the UFSAR. In addition, there is not more than a minimal increase in the consequences of an accident that requires containment integrity or in the consequences of failure of a component or system that could create radiological releases. This activity does not introduce the possibility of a new accident because the new mechanical fluid penetrations are not an initiator of any accident and no new failure modes are introduced. This activity does not introduce the possibility for a malfunction of an SSC with a different result because the activity does not introduce a failure mode that is not bounded by those described in the UFSAR containment system description or the penetration descriptions.

The fission product barriers are the fuel pellet, cladding, reactor coolant pressure boundary, and containment. This activity modifies the containment barrier, but does not alter plant safety limits, setpoints, or design basis limits for a fission product barrier, thus the activity does not

U.S. Nuclear Regulatory Commission Page 8 of 46 result in exceeding or altering a design basis limit for a fission product barrier as described in the UFSAR. This activity does not involve a change in an evaluation methodology.

UFSAR Section 3.8.1.5.4 is to be revised to include specific codes and code sections for which the converted mechanical penetrations conform.

UFSAR Figure 3-20 is to be revised to include information on the new spare penetrations. Part A was already implemented when revision I of this 10 CFR 50.59 was completed.

Part B NSM ON-33107 Part B does not meet any of the 10 CFR 50.59 criteria.

Part B does not require a Technical Specification change since no licensing basis credit is being taken for the new waterhammer prevention circuitry.

The RBCUs and the RBACs are used to provide normal containment ventilation. The RBCUs also provide cooling during accidents. This NSM does not change the operation or function of the RBCUs during normal or emergency operation.

All new piping is to be stainless steel. The piping outside Containment that extends from the supply and return headers connection to the penetrations is to be QA-1 and Duke Class F, including the piping from the penetration to first manual valve inside containment. The tapping valve and blind flange (if installed) are QA-1 and Duke Class F. The LPSW piping to the RBACs inside Containment past the first manual valve from the penetration is to remain Seismic Category II to prevent adverse interaction of the non-safety piping with safety related components during an earthquake. The pipe class is to remain Class D.

The electrical, instrumentation, and control components that are necessary to process and actuate ES signals and devices or to process and actuate signals and devices associated with the RBAC Isolation Circuitry are QA Condition 1. The RBAC Isolation Circuitry that closes the containment isolation valves on low LPSW pressure is QA-1, but can not be credited for preventing waterhammer to assure LPSW system functions at this time. The solenoid valves and the air supply line from the QA-1 containment isolation valves to the solenoid valves are QA-1 so that the air has a QA-1 flow path for air release when being closed. The non-QA instrumentation is in the Class F portion of the piping and is qualified for pressure boundary, but is not QA-1 for function. The electrical cabinets are mounted QA-1.

U.S. Nuclear Regulatory Commission Page 9 of 46 The new penetrations are to have double isolation barriers which are to consist of two valves for each penetration. The supply of LPSW flow to the RBACs will go directly to the RBACs. This LPSW flow will be isolated on an ES signal like the current design. Thus, a single failure will not prevent the RBACs from being isolated on an ES signal.

To assist in meeting the requirements of Generic Letter 96-06 for thermal overpressure protection, each penetration is provided with a relief valve (3LPSW-1057 and 3LPSW-1089) between the penetration and the adjoining valve inside containment.

The LPSW piping is in an operable but degraded/non-conforming condition due to the waterhammer concerns. The operable but degraded/non-conforming condition was established in response to Generic Letter 96-06. To address the waterhammer issue, the NSM will install an instrumentation system that will monitor for low LPSW supply header pressure, indicative of a loss of LPSW, and close RBAC supply and return valves. This system is to eliminate both column closure waterhammer as well as condensation induced waterhammers. The operable but degraded/non-conforming condition is based on the existing piping configuration. This NSM will modify a portion of that piping. The effect of the modified piping on the response of the piping system to the waterhammer events was evaluated. The circuitry was assumed out of service such that it would not function. The evaluation concluded that the piping changes will not adversely impact the existing predicted waterhammer response of the LPSW piping going to the RBACs. SLC 16.9.12 includes conditions to minimize waterhammers for certain valve positions. These SLC conditions are written for two cases: one case is for a unit(s) that does not have this new RBAC modification installed and another case has this new RBAC modification installed. The SLCs were previously revised to include similar water hammer protection restrictions based on an equivalent RBAC modification for Unit 2. This SLC was written in such a manner because the new waterhammer prevention circuitry is not addressed from the perspective of resolving the operable but degraded/non-conforming condition at this time. Thus, SLC 16.9.12 needed to address a different method of isolating the RBACs for the same conditions in either case. No additional changes are required for SLC 16.9.12 as a result of this Unit 3 NSM.

To assist in mitigating the effects of waterhammer that could be caused by filling of the voided line following the restart of the pump, both system design and specified procedural actions will also be included as part of the NSM. These actions are not currently intended to satisfy the Generic Letter 96-06 issues and are not considered as being part of the licensing basis event mitigation strategy. These actions are only intended to

U.S. Nuclear Regulatory Commission Page 10 of 46 enhance the mitigation of waterhammer forces. The closure speed of the containment isolation valves is selected so that water hammers will not occur.

The LPSW required flow to components (e.g., RBCUs, LPI) is not adversely affected due to this NSM. In addition, flow to non-required loads (e.g., RBACs during normal operation) is not adversely affected.

There are control board changes and QA-I cabinet changes and cabinet additions associated with this NSM. The control boards and QA-I cabinets are seismically qualified after these changes and additions. The cabling and other electrical components are adequately sized. The modification meets the applicable electrical separation criteria and specifications for electrical components as listed and described in the UFSAR. The modification does not create any new seismic/non-seismic interactions for Part B. New safety to non-safety (QA-1 to non-QA-1) electrical interfaces will have QA-1 isolation devices. For Part B, an electrical 10 CFR 50 Appendix R fire review was performed for the design phase with no adverse effects to the Appendix R fire separation requirements. The electrical equipment is qualified for its environment.

The piping and supports of Part B are designed such that they meet applicable design codes when connected to the converted penetrations of Part A. The piping was reanalyzed to address the installation of the wet taps and associated hardware (e.g., tapping valves) for the condition of their being installed separately from Part B.

There are no adverse effects to structures, systems, or components associated with this NSM from missiles generated inside containment or missiles generated from natural phenomena events. There are also no adverse effects due to high or low trajectory missiles.

The new AOVs are to fail closed on a loss of power or loss of air. The outside containment isolation valves each use a Moore controller to throttle the valves. Supply header containment isolation valve 3LPSW-1054 and return header containment isolation valve 3LPSW-1062 have non-QA positioners on them and they can be throttled open using non-QA Moore controllers that are setup as manual loaders. The Moore controllers are located on the control board. The Moore controllers are setup with an interlock from the solenoid valve control circuits for the two supply or two return header valves that will cause the valve demand signal from the Moore to runback to the closed position. This prevents flow from being admitted to the RBACs when LPSW supply pressure is reestablished to prevent a waterhammer. The valves must be slowly reopened. An automatic ramp open function is to perform this action. If the power is lost to the Moore controller, then the respective valve will fail open. Even if the Moore controller loses power, the valve will still close automatically

U.S. Nuclear Regulatory Commission Page II of 46 on receiving an ES signal and the operators can manually close any of the new containment isolation valves with the control room OPEN/CLOSE button. The QA-1 solenoid valves for the outermost containment isolation valves are on one power supply and the QA-1 solenoid valves for the innermost valves are on a different power supply.

A single failure will not prevent the new low pressure logic from actuating on low pressure. But a single failure could cause the new low pressure logic to inadvertently actuate the new AOVs, causing isolation of the RBACs. The RBACs are not safety related or QA-1 and are not used for accident mitigation. The Reactor Building Ventilation System, which includes the RBACs, does not have to meet the single failure criterion.

Thus, assuring the RBACs perform their cooling function, assuming a single failure, is not required as part of the Oconee licensing basis.

The existing monitoring to the RBCUs will remain. The new LPSW lines to and from the RBACs will have flow monitoring instrumentation (flow orifices) and control room alarm included as part of the NSM. The instrumentation will be used to determine a differential flow to assist in detecting a loss of LPSW flow to and from the RBACs. Both the existing differential flow instrumentation for the RBCUs and the new instrumentation for the RBACs are non-QA for function. The existing RBCU differential flow instrumentation is not being changed. The new RBAC differential instrumentation is qualified for the pressure boundary.

There is no known specified closure time for containment isolation valves, but the time chosen is within the ranges of existing containment isolation valves.

The use of double AOVs outside of containment is to ensure that the RBACs are isolated prior to power being returned following an event assuming a single failure. The double isolation of the RBACs eliminates any post accident concerns associated with leakage of the RBACs with respect to containment integrity and sump dilution. The total volume of water that will be discharged from the thermal overpressure relief valve will be very small and will not adversely affect the volume of the sump's contents. This will have a negligible effect on boron concentration in the sump.

The Hydrogen Recombiner has been removed from the licensing basis and is no longer needed. Thus, the process tubing for the old Hydrogen Recombiner drain lines is no longer needed. The tubing to be removed had no other purpose other than supporting the Hydrogen Recombiner when it was functional.

U.S. Nuclear Regulatory Commission Page 12 of 46 This activity does not alter plant safety limits, setpoints, or design basis limits for a fission product barrier. Thus, the activity does not result in exceeding or altering a design basis limit for a fission product barrier as described in the UFSAR. This activity does not involve a change in an evaluation methodology. Thus, this activity does not result in a departure from a method of evaluation in the UFSAR.

Based on the above, there were no safety concerns. No Technical Specification or Bases needs to be changed due to this Design Change.

There were UFSAR, and Selected Licensee Commitments changes required. Prior NRC review and approval is not required.

Type: Nuclear Station Modification [NSM ON-13090, Part AL4] [UFSAR Change 06-45 and 06-46]

Title:

The purpose of Part AL4 of this modification is to improve safety related electrical distribution system and equipment terminal voltages under worst-case accident conditions with degraded grid by load shedding/tripping several non-safety related, non-essential 4160V pump loads following an ES actuation.

==

Description:==

The purpose of Part AL4 of this modification is to improve safety related electrical distribution system and equipment terminal voltages under worst-case accident conditions with degraded grid by load shedding/tripping several non-safety related, non-essential 4160V pump loads following an ES actuation. Load shedding will improve safety related electrical distribution system and equipment terminal voltages at all voltage levels. Load shedding will occur immediately upon ES actuation and a Reactor trip signal generated by Reactor Trip Confirm circuitry.

The load shed circuitry is installed in two separate and redundant load shed panels. LOCA Load Shed Logic (LLSL) circuitry is designed to trip the following 4160V, non-safety related, secondary system pump motors in the event of LOCA or inside-containment MSLB design basis events with offsite power available:

• All four Heater Drain (HD) Pumps.

• Three Condenser Circulating Water (CCW) Pumps - The logic ensures that one CCW Pump (1750 HP) remains running to help maintain condenser vacuum and to provide forced CCW flow for LPSW.

Two Condensate Booster (CB) Pumps - The logic ensures that one CB Pump (2000 HP) remains running to help maintain feedwater flow / Steam Generator level.

U.S. Nuclear Regulatory Commission Page 13 of 46 Two Hotwell (HW) Pumps - The logic ensures that one 11W Pump (1000 HP) remains running to help maintain feedwater flow / Steam Generator level.

The LOCA Load Shed Panel ILSI is located on Turbine Building Mezzanine floor. Fire detection is added in the vicinity of ILS 1.

The two redundant trains of QA-1, load-shed logic are designed with the following requirements:

Train A load shed logic (powered from 125VDC Control Train A:

125VDC Power Panel Board IDIA/Breaker 9) will energize the Train A or Train C Trip Coil (Trip Coil 1 for Buses TC and TE; Trip Coil 2 for Bus TD) of the previously specified pump breakers.

Train B load shed logic (powered from 125VDC Control Train B:

125VDC Power Panel Board IDIB/Breaker 30) will energize the Train B Trip Coil (Trip Coil 2 for Buses TC and TE; Trip Coil 1 for Bus TD) of the previously specified pump breakers.

One LLSL ON/OFF Selector Switch "LOCA/LS System (S600)" is provided in the Control Room at Vertical Board 1VB I to enable/disable both trains of LOCA Load Shed Logic.

Three Pump Protection Selection Switches "CCWP Load Shed Defeat (S602)", "CBP Load Shed Defeat (S603)" and "HWP Load Shed Defeat (S604)" are provided in the Control Room at Vertical Board 1VB 1. For each switch, the Operator-selected position defines which single, running CCW, CB or HW pump is protected from tripping following a LOCA load shed event. The design does not include a HD Pump Protection Selection Switch; all HD pumps are tripped by the LOCA Load Shed Logic scheme.

Two indicating lights LI 100 and Li 101 are provided on the Vertical Board 1VB I to indicate Load Shed Train "A" and Load Shed Train "B" Power status. No Control Room alarms are provided for the LOCA Load Shed Logic Scheme (LLSL).

Digital Computer Points associated with the LLSL are provided on the OAC.

In order to avoid potential spurious unit trips, Train A load shed will actuate if ES Channel 1 actuates and the Reactor trips (from RTC Channel A); Train B will actuate if ES Channel 2 actuates and the Reactor trips (from RTC Channel B).

U.S. Nuclear Regulatory Commission Page 14 of 46 LLSL will not automatically start any pumps; there is no LLSL hardwired interface with pump circuit breaker closing circuits. LLSL automatically resets (i.e., load trip signals are removed) after a time delay of approximately ten seconds. The LLSL is designed with a manual cutout feature to deenergize the LLSL.

This activity is a modification to the facility. This evaluation is not addressing a procedure, procedure change, test, experiment, evolution or implementation activity.

Evaluation: The purpose of modification ON-13090 Part AL4 is to improve safety related electrical distribution system and equipment terminal voltages under worst-case accident conditions with degraded grid by load shedding/tripping several non-safety related, non-essential 4160V pump loads following an ES actuation. If the load shed circuitry is unavailable or fails to operate as designed, the Keowee Units will start and re-power the safety related electrical distribution system as currently designed. The existing system for transfer of power source from the off-site system to the on-site system will remain intact following implementation of this modification.

The load shed circuitry is installed in two separate and redundant load shed panels. Load shedding will occur immediately upon ES actuation and Reactor trip generated by Reactor Trip Confirm circuitry, improving transient voltages. LOCA Load Shed Logic (LLSL) circuitry is added to trip the following 4160V, non-safety related, secondary system pump motors in the event of LOCA or inside-containment MSLB design basis events with offsite power available:

" All four Heater Drain Pumps.

" Three Condenser Circulating Water Pumps - The logic ensures that one CCW Pump remains running to help maintain condenser vacuum and to provide forced CCW flow for LPSW.

• Two Condensate Booster Pumps - The logic ensures that one CB Pump remains running to help maintain feedwater flow /,Steam Generator level.

• Two Hotwell Pumps - The logic ensures that one HW Pump remains running to help maintain feedwater flow / Steam Generator level.

The new load shed circuitry is QA-1, seismically qualified, suitable for its operating environment, and meets requirements for redundancy and separation. Loss of supply voltage will not cause an inadvertent actuation of the load shed circuitry. No single failure (active or passive) of an LLSL component or train will prevent successful accomplishment of LOCA load shed. The load shed logic utilizes the Reactor Trip Confirm signal to

U.S. Nuclear Regulatory Commission Page 15 of 46 prevent a false/spurious ES actuation from causing an inadvertent load shed and subsequent Unit trip. The new load shed circuitry does not adversely affect existing safety related SSCs or safety functions performed by those SSCs, nor is any existing safety analysis adversely affected.

Based on the above, there were no safety concerns. No Technical Specification or Bases, and Selected Licensee Commitments needs to be changed due to this Design Change. There are UFSAR changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification [OD 100219] [UFSAR 06-15, 16, 17, 18 and 19]

Title:

This design change replaces the Unit 1 CRDCS with a new Digital Control Rod Drive Control System (DCRDCS).

==

Description:==

This design change replaces the Unit I CRDCS with a new Digital Control Rod Drive Control System (DCRDCS) and consists of the following major components:

• System Logic Equipment Four Triple Modular Redundant (TMR) Digital Process Controllers with associated 1/0 Modules Pulse Generator/Monitor Modules Communication Modules Redundant 24 VDC System Power Supplies Redundant 24 VDC Field Power Supplies 24 VDC Station Blackout Power Supply

• Motor Control Equipment Reactor Trip Breaker Cabinets Voltage Regulators 3 -phase to 6-phase Power Transformers Redundant Single Rod Power Supplies (SRPS)

Electronic Trip Circuitry

• Reactor Trip Breaker Switchgear and Associated Equipment Reactor Trip Breakers Train A (Breakers A and C)

Reactor Trip Breakers Train B (Breakers B and D)

TMR/AC Interface Boards Control Transformers 24 VDC Trip Confirm Power Supplies Breaker Test Panels

U.S. Nuclear Regulatory Commission Page 16 of 46

• DCRDCS Man/Machine Interfaces Operator Control Panel (on 1UB I)

Rod Position Indication Panel (on 1UB I)

Operator Aid Computer Engineering Workstation (in DCRDCS Control Cabinet)

System Logic circuits receive either manual or automatic control signals and perform the logic functions required to transmit proper commands to the Motor Control Equipment. Rod grouping, position and limit display, operator control switches, and system status indication are processed and provided by the System Logic.

The Motor Control Equipment includes the power supplies and gate circuitry required to energize the motor stators of the drive mechanisms or groups of drive mechanisms.

RTBs provide the interface between the RPS and the CRD System to trip the reactor when one or more parameters exceed setpoint or the operator chooses to trip the reactor manually.

The DCRDCS Man/Machine Interfaces include control room operator control and indication panels. It also includes an Engineering Workstation (EWS) to allow for system configuration, testing, monitoring and/or modifications to application software along with an Operator Workstation (OWS) residing on the Operator Aid Computer (OAC) to allow for display of system graphics and diagnostics.

Evaluation: This design change requires Technical Specification changes due to changes to the RTB arrangement (discussed in detail later in this text). A License Amendment Request (LAR) was submitted to the NRC by letter dated January 15, 2004 to obtain NRC review and approval of the RTB Technical Specification changes. Supplement 1 to the LAR was submitted on March 15, 2004. The NRC response dated November 2, 2004, found the proposed TS changes acceptable (License Amendment No. 341 for ONS Unit 1). This 50.59 does not address the Technical Specification changes. This 50.59 does address those aspects of OD100219 which are outside of the bounds of the LAR submitted for the RTB changes.

This design change replaces the Unit 1 RDCS with a new Digital Control Rod Drive Control System (DCRDCS) and consists of System Logic Equipment, Motor Control Equipment, RTB Switchgear and Associated Equipment, and DCRDCS Man/Machine Interfaces.

U.S. Nuclear Regulatory Commission Page 17 of 46 The CRD control system is not required for accident mitigation, post accident response or offsite release mitigation. It does not perform any plant protective functions. UFSAR requirements for the CRDCS were reviewed and functions required to be performed by the CRDCS, as given in the UFSAR, are retained in the new design. CRDCS functions and setpoints are retained as part of the new DCRDCS. The DCRDCS has no role in the execution of dropping rods during a safety reactor trip. The DCRDCS components are not part of the RPS safety system.

The new DCRDCS is designed to meet the requirements of applicable general design criteria found in UFSAR Section 3.1. The new DCRDCS also meets the general design criteria for the CRD System as given in UFSAR Section 4.5.3.1.1.

Control rod position indication is a Regulatory Guide 1.97, Rev. 2, Type B, Category 3 variable at Oconee. The position indication panel is modified by this design change to change the input voltage span in order to be compatible with the new DCRDCS. The control rod position indications available to the operator will continue to be classified as, and meet the requirements of, a Regulatory Guide 1.97, Rev. 2 Type B Category 3 variable after implementation of this design change.

This design change is designed to comply with the safety, reactivity rate limits, startup considerations, and operational design basis as stated in UFSAR 7.6.

This design change does not affect the existing AMSAC circuitry. The existing AMSAC and DSS trip setpoints are not affected by this design change. With installation of this design change, the actuation portion of the DSS trip is modified. The new DSS design will be better than the existing design. The changes to DSS implemented by this design change are in compliance with the requirements of 10 CFR 50.62. The changes to the DSS actuation have been submitted to the NRC.

Automatic actuation of the shunt trip (for RPS actuation or manual trip) on the new AC RTBs is retained by this design change. The new RTB arrangement complies with the requirements of GL 83-28 for RTB reliability.

The capability of the CRD System to maintain RCS pressure boundary is not affected by this design change. This design change does not affect the CRDMs or their capability to maintain the RCS pressure boundary. The capability of the CRD System to drop control rods on a reactor trip signal is not affected by the replacement of the CRD Control System. The reactor trip function is independent of and separate from the CRD Control System. The replacement of the RTBs will not adversely affect the ability to drop control rods as discussed in License Amendment Request submittals to the NRC.

U.S. Nuclear Regulatory Commission Page 18 of 46 The DCRDCS supports all the functions retained from the replaced CRDCS. The old to new equipment transition is performed at the point of connection to the existing field interfaces. The system is powered from existing busses. The replacement equipment power consumption is less than or equal to current power consumption by the existing CRDCS. The existing CRDCS is designed with hardware isolation devices to protect safety systems from electrical and electronic interference. The existing isolation scheme is reused. The design bases for the isolation features will not be affected by the new DCRDCS. The DCRDCS will communicate with other existing systems or components in a manner that does not affect the other existing systems or components ability to successfully perform their functions. The DCRDCS is a redundant system for all critical functions.

The DCRDCS will not affect existing safety grade trips. The DCRDCS plant interfaces will be compatible with the existing CRDCS inputs and outputs in terms of impedance, voltage, current, and frequency.

The DCRDCS is non-safety related and, therefore, the system does not fall within the scope of 10 CFR 50.49 and environmental qualification per 10 CFR 50.49 is not required. There are no HELB concerns applicable to this design change. The DCRDCS is not required during or after an Appendix R fire.

The total heat load of the new DCRDCS is less that of the replaced CRDCS, and hence does not challenge the ability of the existing HVAC System to handle the heat load.

There are no changes to existing CRDM power sources. The electrical rating of components is adequate for their circuit application. The seismic adequacy of existing cabinets with new DCRDCS components installed has been confirmed. The seismic adequacy and mounting of new DCRDCS components has been confirmed. The design change does not create any new seismic/non-seismic interactions. There are no new safety to non-safety (QA-1 to non-QA-1) electrical interfaces resulting from this design change. The new electrical equipment is suitable for the environment in which it is located.

A Failure Modes and Effects Analysis (FMEA) was performed for the new DCRDCS to determine if adverse effects (i.e., loss of reactor control, uncontrolled rod withdrawal, reactor trip, or prevention of reactor trip) could result from the credible failure of a single component. The results of the FMEA was that "All operation critical to the safe and effective performance of the DCRDCS maintains sufficient redundancy such that no credible single failure can compromise the design".

The portion of design change OD100219 addressed by this evaluation does not result in a change that would cause any fission product barrier

U.S. Nuclear Regulatory Commission Page 19 of 46 parameter to change. The activities reviewed do not result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or altered. The reviewed activities do not adversely affect any plant safety limits, setpoints or design parameters. The reviewed activities do not adversely affect the fuel, fuel cladding, Reactor Coolant System or containment integrity.

The portion of design change OD100219 addressed by this evaluation installs a new DCRDCS, and new RTBs, but does not constitute a method of evaluation.

Based on the above, there were no safety concerns. No Technical Specification or Bases, and Selected Licensee Commitments needs to be changed due to this Design Change. There are UFSAR changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification [OD500910] [UFSAR Change 06-20 and 06-44]

Title:

This Minor Design Change is to revise Oconee design and licensing documentation that will require revision due to the installation of two new Combustion Turbines to replace the three existing Lee Combustion Turbines (LCT).

==

Description:==

The three existing LCTs are not as reliable as in the past. Also vendor support is no longer available for problem solving.

The changes at the Lee Steam Station are as follows:

The three existing 44.1 MVA Westinghouse 301 LCTs are to be replaced with two new 41 MW General Electric LM6000PC Combustion Turbines.

The generators are rated for 0.9 Power Factor (PF) resulting in 45.5 MVA.

The two new LCTs will perform the backup emergency power function for Oconee that is currently performed by the three existing LCTs. The existing LCTs are designated as 4C, 5C, and 6C. The new LCTs will be designated as 7C and 8C. The new LCTs are air cooled as compared to the existing LCTs, which are water cooled.

The new LCT generators are to be connected to the Duke grid through a substation designed in a "ring bus" arrangement. This connection allows either new LCT to be connected through an electrically isolated transmission line to Oconee with the other LCT aligned to the 100 kV substation to supply power to the Duke grid. The existing LCTs are connected through an electrically isolated transmission line to Oconee using circuit switchers. The existing design limits the possibility of

U.S. Nuclear Regulatory Commission Page 20 of 46 connecting another LCT to the Duke grid when certain LCTs are connected to Oconee.

Evaluation: This 10 CFR 50.59 evaluation determined that a License Amendment Request (LAR) is not required for Design Change OD5009 10.

The Lee Combustion Turbines (LCT) and the 100 kV line are part of two subsystems that can supply 100 kV power to Oconee's auxiliary transformer CT-5. These two subsystems, together called the 100 kV Alternate Power System (APS), can provide the power from either a LCT to the Oconee switchgear breakers SL1 and SL2 via an isolated path or from the Central Tie Switchyard to these breakers. The LCTs can be used as Oconee's emergency power supply if the Keowee Hydro Units are unavailable. Thus, the LCTs are a backup to the Keowee Hydro Units and are used for mitigation of loss of power scenarios. The LCTs are not used for normal operation of Oconee.

In the new design, when a LCT is aligned for use as the Oconee emergency power supply, the Central Tie Switchyard will continue to be bypassed. Thus, it will still form an isolated path from the Lee combustion turbine generating units to the Oconee 4160V standby busses.

The pathway from the Central Tie Switchyard to Oconee is also still available and is not adversely affected.

The new LCTs have a slightly higher capacity than the listed rating of the existing LCTs and their rating is also above the rating of transformer CT-

5. Thus, the ability of the new LCTs to supply the emergency power loads is not adversely affected. The new LCTs can also provide the required loads within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The 100 kV APS is classified as non-QA-land non-safety related. This system is not subject to single failure criteria.

Switchgear breakers SLI and SL2, which are qualified QA-1, are the isolation devices between the non-QA-1 100KV APS and the Oconee 4kV Essential Auxiliary Power System. The 100KV APS is not seismically qualified; however, switchgear breakers SL1 and SL2 are seismically qualified. The 100 kV APS is not designed to withstand a tornado or for protection against missiles. But the switchgear breakers SLI and SL2 are located in a Class 1 structure which provides tornado/wind generated missile protection for these breakers. This system does not fall into the scope of 10 CFR 50 Appendix R. Designing for effects of pipe rupture is not required for this system. Since the system is not QA-1, the components of this system are not subject to equipment environmental qualification requirements. Mechanical and electrical separation requirements do not apply to this system.

U.S. Nuclear Regulatory Commission Page 21 of 46 This design change will reduce the number of LCTs from three CTs to two CTs. To address this change, a comparison using PRA was performed.

The component that is being modified is the LCT emergency power supply to Oconee. The component boundary in the failure probability calculation was assumed to encompass the scope of hardware being significantly modified at Lee. The reliability being compared is for the use of Lee to support Oconee as required (use of Lee as an emergency power supply, not as a supply to the grid). These assumptions in the analysis are the more conservative assumptions since including other components would dilute the impact of the change in the number of LCTs.

The analyzed component boundary includes modifications to the substation to the extent needed to address the reliability. The two new LCTs were determined to have a lower failure probability than the current configuration. This means the new design was determined to be more reliable than the existing design.

Only one LCT is specified as being required during certain limiting conditions of operations in technical specifications. And SLC 16.8.6, which currently requires only two LCTs for Maintenance Rule, is not to reduce the number of LCTs required, even though the new LCTs are more reliable.

There is currently out-of-tolerance (OOT) frequency and voltage logic installed at Lee for electrical equipment protection. This design change does not alter the existing +/-10% OOT frequency and voltage logic at Lee (e.g., same function, trip setpoints, same 2 out of 3 logic, same time delay, etc.). The new LCTs have requirements such that their operation is not to reach the OOT logic voltage and frequency setpoints.

Mechanical systems and components can be affected by frequency OOT from emergency power supplies. To protect against these adverse effects, the red marked design basis specification specifies that each LCT shall meet the appropriate frequency requirements during steady state operation as well as during loading or unloading of equipment when required to supply Oconee safety power during emergency operation. These requirements include the LCTs maintaining a steady state frequency of -

1% to +3% rated frequency and staying within +/-5% rated frequency for any expected single load change on an Oconee unit. When outside the

+3%/-1% OOT range for transient loadings, the frequency OOT limits are to return to steady state (+3%/-1% OOT) within 10 seconds.

Both new LCTs will have black start capability. Only one of the existing three LCTs has the black start capability.

U.S. Nuclear Regulatory Commission Page 22 of 46 Based on the above, there were no safety concerns. No Technical Specification or Bases needs to be changed due to this Design Change.

There are UFSAR, and Selected Licensee Commitments changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification [OD100051] [UFSAR Change 07-02]

Title:

Design Change OD100051, Replacement of the Reactor Building Emergency Sump (RBES) Screen for Unit 1.

==

Description:==

This Design Change is to perform the following:

1. Remove the existing trash rack and screen from the RBES and add a strainer assembly with a much larger screen surface area. The existing trash rack has a surface area of approximately 40 sq-ft and the screen has a surface area of approximately 100 sq-ft. The replacement strainer has a filtering surface area of greater than 4800 sq-ft.

2. Due to the height and larger size of the new strainer, which will extend above the Elevation 777 ft. floor level, the storage locations of the Low Pressure Injection (LPI) suction piping containment isolation valve test flanges are to be relocated. The test flanges are also redesigned and are to be used as flow impingement plates if backflow to RBES occurs.

3. In order to accommodate the larger size of the new strainer, the existing sump level instruments are to be relocated from the sides of the sump to the end of the sump.

4. As an aid to outage foreign material exclusion (FME) control and to enhance personnel safety during sump access, a permanently installed strainer is to be added to the 4-inch sump drain.

This Design Change is evaluated as an enhancement to the current licensing basis..

Evaluation: The responses to the eight 10 CFR 50.59 questions are "No." No technical Specification changes are required and, thus, a License Amendment Request (LAR) is not required.

This design change replaces the existing emergency sump screen with a strainer having a larger filtering surface area. It also relocates the sump level instruments due to interference with the layout of the new strainer, replaces and changes the (normal operating) location of the blank flanges used for LPI containment isolation valves leakage testing and adds a small strainer on the 4-inch emergency sump drain to aid in FME control and enhance personnel safety during outages. None of these changes

U.S. Nuclear Regulatory Commission Page 23 of 46 introduce the possibility of a change in the frequency of an accident because none of these items are an initiator of an accident previously evaluated in the UFSAR and no new failure modes are introduced by these changes. These modifications comply with standards applicable to the SSCs being added or modified. No adverse interaction with other systems was identified.

The new strainers provide the same filtering function as the existing screens for the water entering the RBES sump. The head loss through the strainers is insignificantly different from that through the existing screens and the NPSH requirements of the LPI and RBS pumps as described in the UFSAR are unaffected. Therefore, the capability of the pumps to perform their ECCS and building spray functions as previously evaluated in the UFSAR is not adversely affected.

The new strainer has more filtering surface area than the current configuration. An internal missile re-evaluation was performed for the new strainer to demonstrate that no credible internal missile could damage the strainer when needed during a LOCA event. A jet impingement re-evaluation was also performed for the new strainer to demonstrate that no credible High Energy Line Break (HELB) jets could damage the strainer when needed during a LOCA event. The new material required to perform the safety related filtration function is stainless steel and meets QA-1 requirements. Non-safety related material installed above the strainer is seismically supported (mounted QA-4). The reduction in the amount of zinc in the containment as well as the change in mass, volume and surface area of material that can act as a heat sink have been evaluated and were determined to not adversely affect the containment or performance of the ECCS systems.

The relocated level instruments continue to perform the functions of narrow range level indication and post-accident sump level indication.

The instruments are seismically mounted in their new location and continue to meet the same quality and EQ requirements. Their Regulatory Guide 1.97 parameter requirements are also not changed.

No adverse interaction with other systems was identified for either the flow impingement plate or the 4-inch drain strainer. During normal operation, the plates are mounted above or in front of the LPI suction flanges. The head loss due to this configuration is included in the overall strainer head loss evaluation. All bolting inside the strainer is engineered to lock (torque, lock nut, staking, etc.). In the current design, there are also many threaded connections inside the screen which need similar precautions. Control and inspection of threaded connections will adhere to QA-1 requirements. Thus, no loose parts, which could potentially

U.S. Nuclear Regulatory Commission Page 24 of 46 damage the LPI and RBS pumps or other downstream components, can be generated inside the strainer and be swept to the flange by high velocity water.

The new 4-inch drain strainer is to have 3 and 4 mm holes, which are slightly larger than the 2.1 mm holes in the RBES strainer. Due to the inspection, cleaning, and FME controls, there is no mechanism for debris larger than the holes in the RBES strainer screen to enter the drain line.

Any fluid that enters the line from the RBES will have been strained by the RBES strainer. The only fluid entering the drain line from the drain side will come from the LDST, which is clean (relative to particulate material) demineralized (borated) water.

However, even if some small-sized debris (having already passed through or around the strainer) does accumulate in the drain piping between inspections, it is not reasonable to assume that it would agglomerate into larger clumps that would not break-up and pass through the 4-inch strainer during LDST flow into the RBES. Therefore, based on this discussion, no debris is anticipated in this flow stream. However, for conservatism, this strainer is designed such that it will pass the required flow without exceeding the allowable head loss even if 25% plugged. This protects the pumps and other components that circulate water during the recirculation mode (LPI, HPI and RBS systems) from detrimental effects by enhancing outage FME control and does not compromise the operation of the HPI system which utilizes the LDST to RBES flow path. The flow impingement effects due to back flow through the 4-inch drain strainer are not significant and will not impair the function of the RBES strainer.

No new failure modes are introduced by these changes. Therefore these changes do not introduce the possibility of a change in the likelihood of a malfunction or introduce any new malfunctions of any SSC important to safety previously evaluated in the UFSAR.

The new strainers provide the same post-accident filtering function as the existing screens for the water entering the RBES sump. The head loss through the strainers is insignificantly different from that through the existing screens and the NPSH requirements of the LPI and RBS pumps as described in the UFSAR are unaffected. Therefore, the capability of the pumps to perform their ECCS and building spray functions as previously evaluated in the UFSAR is not adversely affected. The relocated level instruments will perform the same post-accident water level monitoring function as in their current location. The addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility of a change in the consequences of an accident previously evaluated in the UFSAR.

U.S. Nuclear Regulatory Commission Page 25 of 46 The replacement strainers, relocated level instruments, addition of flow impingement plates above the sump suction lines and addition of a 4-inch drain strainer do not introduce the possibility of a change in the consequences of a malfunction of SSCs important to safety previously evaluated in the UFSAR since these items do not adversely affect the flow capability, filtering, and level monitoring functions that currently exist.

The RBES and the new strainer provide the same passive collection and filtration function as the existing design. The relocated level instruments' function is not changed. The new flow impingement plates are passive relative to any system interactions. The 4-inch drain strainer does not adversely affect flow capability and provides additional protection for the LPI, HPI and RBS pumps from debris possibly in the drain line by enhancing control of FME during outages.

The replacement strainers, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility of an accident of a different type than previously evaluated in the UFSAR since these items are not accident initiators and have only a passive role during accident mitigation. The.

relocated level instruments have a post accident monitoring function as well as a leak detection system function during normal operation.

However, there is no active function related to this level sensor (i.e., only indication) so no accident can be initiated by level sensor failure.

The replacement strainers, relocated level instruments, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility for a malfunction of an SSC with a different result because no new credible failure modes were introduced by these changes and no adverse interactions with other systems were identified.

The fission product barriers are the fuel pellet, cladding, reactor coolant system pressure boundary, and containment. This design change does not modify any fission product barriers. This modification does not change any controlling numerical values established during the licensing review as presented in the UFSAR for any parameter used to determine the integrity of a fission product barrier. The replacement strainers, relocated level instruments, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not result in a change that would cause an adverse effect in performance of any system as described in the UFSAR. The reduction in the amount of zinc in the containment as well as the change in mass, volume and surface area of material that can act as a heat sink do not adversely affect the containment or performance of the ECCS systems as described in the UFSAR. Therefore, the design change does not result in a design basis

U.S. Nuclear Regulatory Commission Page 26 of 46 limit for a fission product barrier as described in the UFSAR being exceeded or altered. The effect of water depth change in the Reactor Building (e.g., post LOCA) due to the change in the strainers' volumes was reviewed with no concerns identified.

This design change does not revise a computer code or calculation that is described in the UFSAR. It also does not change a design or analysis code described in the UFSAR. This activity does not involve a change in a method of evaluation described in the UFSAR. Thus, the design change does not result in a departure from a method of evaluation in the UFSAR.

Based on the above, there were no safety concerns. No Technical Specification or Bases needs to be changed due to this Design Change.

There are UFSAR and Selected Licensee Commitments changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification [OD100076] [UFSAR 06-08]

Title:

The purpose of this design change for 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.

==

Description:==

EL1 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 milliamp 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.

The infrastructure for this new digital technology will use the existing cables (where possible) emanating from the cable room to designated

U.S. Nuclear Regulatory Commission Page 27 of 46 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.

The PCS is housed in five (5) EMI/RFI qualified cabinets installed in the Cable Room in the vicinity of the Unit 1 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 ISA6 configured to alarm on Universal Bridge power supply or Fieldbus power supply failures as monitored by the DC302 module in Chassis 1 of each cabinet, excessive cabinet temperature, or UPS failures.

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 HI 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 1VB2 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 and has 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.

U.S. Nuclear Regulatory Commission Page 28 of 46 Since a large number of instrument cables coming from the field or plant locations utilize Transducer Cabinets 1 and 2 (ITDC1 and 2) in the Cable Room as a connection point to the OAC, these cables were identified for use as the segment or H1 trunk lines. These cables are all of single or multi-twisted shielded pair construction, Duke Type ISPA16G.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 (1TDC5 and 1TDC6) 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 racks 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' labeledlTDC5 and 1TDC6. Fieldbus Bricks or potted junction boxes will be installed above the instrument rack for all Fieldbus connections.

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 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.

The power source for the PCS is obtained from IXO and 1XP 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

U.S. Nuclear Regulatory Commission Page 29 of 46 and a neutral cable will be utilized. One 3XJIOG.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 1 cD 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.

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 1 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.

To provide additional resources in the Control Room for access to the OAC, two OAC Workstations are installed in lAB2 in place of OAC printers. Printing from the OAC has been provided by more efficient printers.

Evaluation: The instruments replaced by part ELI of this design change are all non-safety related. 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.

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.

U.S. Nuclear Regulatory Commission Page 30 of 46 An electrical 10 CFR 50 Appendix R fire review was performed for the design phase of part ELlwith 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 electromagnetically 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.

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.

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. The panels from which recorders are removed have the resulting hole covered with overlay. 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. A 10 CFR 50 Appendix R fire review was performed for the design phase of part EL2 with no adverse affects identified.

Mounting of new recorders is QA-4; therefore, there are no seismic interactions between seismically qualified and non-seismically qualified structures, systems, or components.

Based on the above, there were no safety concerns. There are UFSAR, Technical Specification Bases and Selected Licensee Commitments changes required. Prior NRC review and approval is not required.

Type: Nuclear Station Modification [OD300050]

Title:

The activity addressed Design Change OD300050, Replacement of the Reactor Building Emergency Sump (RBES) Screen for Unit 3.

U.S. Nuclear Regulatory Commission Page 31 of 46

==

Description:==

This Design Change is to perform the following:

1. Remove the existing trash rack and screen from the RBES and add a strainer assembly with a much larger screen surface area. The existing trash rack has a surface area of approximately 40 sq-ft and the screen has a surface area of approximately 100 sq-ft. The replacement strainer has a filtering surface area of approximately 5200 sq-ft.

2. Due to the height and larger size of the new strainer, which will extend above the Elevation 777 ft. floor level, the storage locations of the Low Pressure Injection (LPI) suction piping containment isolation valve test flanges are to be relocated. The test flanges are also redesigned and are to be used as flow impingement plates if backflow to RBES occurs.

3. In order to accommodate the larger size of the new strainer, the existing sump level instruments are to be relocated from the sides of the sump to the end of the sump.

4. As an aid to outage foreign material exclusion (FMIE) control and to enhance personnel safety during sump access, a permanently installed strainer is to be added to the 4-inch sump drain.

This Design Change is evaluated as an enhancement to the current licensing basis.

Evaluation: The responses to the eight 10 CFR 50.59 questions are "No." No technical Specification changes are required and, thus, a License Amendment Request (LAR) is not required.

This design change replaces the existing emergency sump screen with a strainer having a larger filtering surface area. It also relocates the sump level instruments due to interference with the layout of the new strainer, replaces and changes the (normal operating) location of the blank flanges used for LPI containment isolation valves leakage testing and adds a small strainer on the 4-inch emergency sump drain to aid in FME control and enhance personnel safety during outages. None of these changes introduce the possibility of a change in the frequency of an accident because none of these items are an initiator of an accident previously evaluated in the UFSAR and no new failure modes are introduced by these changes. These modifications comply with standards applicable to the SSCs being added or modified. No adverse interaction with other systems was identified.

The new strainers provide the same filtering function as the existing screens for the water entering the RBES sump. The head loss through the

U.S. Nuclear Regulatory Commission Page 32 of 46 strainers is insignificantly different from that through the existing screens and the NPSH requirements of the LPI and RBS pumps as described in the UFSAR are unaffected. Therefore, the capability of the pumps to perform their ECCS and building spray functions as previously evaluated in the UFSAR is not adversely affected.

The new strainer has more filtering surface area than the current configuration. An internal missile re-evaluation was performed for the new strainer to demonstrate that no credible internal missile could damage the strainer when needed during a LOCA event. A jet impingement re-evaluation was also performed for the new strainer to demonstrate that no credible High Energy Line Break (HELB) jets could damage the strainer when needed during a LOCA event. The new material required to perform the safety related filtration function is stainless steel and meets QA-1 requirements. Non-safety related material installed above the strainer is seismically supported (mounted QA-4). The reduction in the amount of zinc in the containment as well as the change in mass, volume and surface area of material that can act as a heat sink have been evaluated and were determined to not adversely affect the containment or performance of the ECCS systems.

The relocated level instruments continue to perform the functions of narrow range level indication and post-accident sump level indication.

The instruments are seismically mounted in their new location and continue to meet the same quality and EQ requirements. Their Regulatory Guide 1.97 parameter requirements are also not changed.

No adverse interaction with other systems was identified for either the flow impingement plate or the 4-inch drain strainer. During normal operation, the plates are mounted above or in front of the LPI suction flanges. The head loss due to this configuration is included in the overall strainer head loss evaluation. All bolting inside the strainer is engineered to lock (torque, lock nut, staking, etc.). In the current design, there are also many threaded connections inside the screen which need similar precautions. Control and inspection of threaded connections will adhere to QA-1 requirements. Thus, no loose parts, which could potentially damage the LPI and RBS pumps or other downstream components, can be generated inside the strainer and be swept to the flange by high velocity water.

The new 4-inch drain strainer is to have 3 and 4 mm holes, which are slightly larger than the 2.1 mm holes in the RBES strainer. Due to the inspection, cleaning, and FME controls, there is no mechanism for debris larger than the holes in the RBES strainer screen to enter the drain line.

U.S. Nuclear Regulatory Commission Page 33 of 46 Any fluid that enters the line from the RBES will have been strained by the RBES strainer. The only fluid entering the drain line from the drain side will come from the LDST, which is clean (relative to particulate material) demineralized (borated) water.

However, even if some small-sized debris (having already passed through or around the strainer) does accumulate in the drain piping between inspections, it is not reasonable to assume that it would agglomerate into larger clumps that would not break-up and pass through the 4-inch strainer during LDST flow into the RBES. Therefore, based on this discussion, no debris is anticipated in this flow stream. However, for conservatism, this strainer is designed such that it will pass the required flow without exceeding the allowable head loss even if 25% plugged. This protects the pumps and other components that circulate water during the recirculation mode (LPI, HPI and RBS systems) from detrimental effects by enhancing outage FME control and does not compromise the operation of the HPI system which utilizes the LDST to RBES flow path. The flow impingement effects due to back flow through the 4-inch drain strainer are not significant and will not impair the function of the RBES strainer.

No new failure modes are introduced by these changes. Therefore these changes do not introduce the possibility of a change in the likelihood of a malfunction or introduce any new malfunctions of any SSC important to safety previously evaluated in the UFSAR.

The new strainers provide the same post-accident filtering function as the existing screens for the water entering the RBES sump. The head loss through the strainers is insignificantly different from that through the existing screens and the NPSH requirements of the LPI and RBS pumps as described in the UFSAR are unaffected. Therefore, the capability of the pumps to perform their ECCS and building spray functions as previously evaluated in the UFSAR is not adversely affected. The relocated level instruments will perform the same post-accident water level monitoring function as in their current location. The addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility of a change in the consequences of an accident previously evaluated in the UFSAR.

The replacement strainers, relocated level instruments, addition of flow impingement plates above the sump suction lines and addition of a 4-inch drain strainer do not introduce the possibility of a change in the consequences of a malfunction of SSCs important to safety previously evaluated in the UFSAR since these items do not adversely affect the flow capability, filtering, and level monitoring functions that currently exist.

The RBES and the new strainer provide the same passive collection and

U.S. Nuclear Regulatory Commission Page 34 of 46 filtration function as the existing design. The relocated level instruments' function is not changed. The new flow impingement plates are passive relative to any system interactions. The 4-inch drain strainer does not adversely affect flow capability and provides additional protection for the LPI, HPI and RBS pumps from debris possibly in the drain line by enhancing control of FME during outages.

The replacement strainers, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility of an accident of a different type than previously evaluated in the UFSAR since these items are not accident initiators and have only a passive role during accident mitigation. The relocated level instruments have a post accident monitoring function as well as a leak detection system function during normal operation.

However, there is no active function related to this level sensor (i.e., only indication) so no accident can be initiated by level sensor failure.

The replacement strainers, relocated level instruments, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not introduce the possibility for a malfunction of an SSC with a different result because no new credible failure modes were introduced by these changes and no adverse interactions with other systems were identified.

The fission product barriers are the fuel pellet, cladding, reactor coolant system pressure boundary, and containment. This design change does not modify any fission product barriers. This modification does not change any controlling numerical values established during the licensing review as presented in the UFSAR for any parameter used to determine the integrity of a fission product barrier. The replacement strainers, relocated level instruments, addition of flow impingement plates above or in front of the sump suction flanges and addition of a 4-inch drain strainer do not result in a change that would cause an adverse effect in performance of any system as described in the UFSAR. The reduction in the amount of zinc in the containment as well as the change in mass, volume and surface area of material that can act as a heat sink do not adversely affect the containment or performance of the ECCS systems as described in the UFSAR. Therefore, the design change does not result in a design basis limit for a fission product barrier as described in the UFSAR being exceeded or altered. The effect of water depth change in the Reactor Building (e.g., post LOCA) due to the change in the strainers' volumes was reviewed with no concerns identified.

U.S. Nuclear Regulatory Commission Page 35 of 46 This design change does not revise a computer code or calculation that is described in the UFSAR. It also does not change a design or analysis code described in the UFSAR. This activity does not involve a change in a method of evaluation described in the UFSAR. Thus, the design change does not result in a departure from a method of evaluation in the UFSAR.

Based on the above, there were no safety concerns. No Technical Specification or Bases needs to be changed due to this Design Change.

There are UFSAR and Selected Licensee Commitments changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification

Title:

02C23 Core Reload Design

==

Description:==

The purpose of this change is to replace 73 spent fuel assemblies used in Cycle 23 with 56 fresh fuel assemblies (referred to as Batch 25) and 17 reinsert assemblies from the spent fuel pool. The resulting core will allow restart and operation of Oconee Unit 2 Cycle 23 at full design power (2568 MWth) for a cycle length of 508 +/- 10 EFPD.

No new fuel assembly types are being used in 02C23. The fresh fuel assemblies are type Mk-B 1 A; the third such batch of fuel used in Unit 2.

All of the reinserted fuel from the spent fuel pool is of the Mk-B 11 type.

Sixteen of the reinserts from the spent fuel pool are from the O2C21 discharged assemblies and were selected for insertion on the periphery of the core. One reinsert from the spent fuel pool is from the 02C20 discharge assemblies which was selected for the core center position.

The Batch 25 fuel enrichments are comparable to previous core designs.

The cycle design length is comparable to previous cycles, with both a Tavg reduction and power coastdown utilized to reach the end-of-window bumup. Due to steam generator performance issues, the end-of-cycle Tavg reduction may not occur, which would be compensated for by a longer power coastdown.

Other changes to the core design are nominally expected from cycle-to-cycle. Such changes include initial core loading (MtU), batch average burnups, and LBP B-4C wt % and reinsertion. 02C23 places second burn fuel beneath the APSRs rather than third burn fuel like 02C22, but both cycles successfully completed the Reload Design Safety Analysis Review (REDSAR) process.

The Reload Change Document also indicates that 02C23 will have minor core power distribution changes with respect to the previous cycle. The

U.S. Nuclear Regulatory Commission Page 35 of 46 This design change does not revise a computer code or calculation that is described in the UFSAR. It also does not change a design or analysis code described in the UFSAR. This activity does not involve a change in a method of evaluation described in the UFSAR. Thus, the design change does not result in a departure from a method of evaluation in the UFSAR.

Based on the above, there were no safety concerns. No Technical Specification or Bases needs to be changed due to this Design Change.

There are UFSAR and Selected Licensee Commitments changes required.

Prior NRC review and approval is not required.

Type: Nuclear Station Modification

Title:

02C23 Core Reload Design

==

Description:==

The purpose of this change is to replace 73 spent fuel assemblies used in Cycle 23 with 56 fresh fuel assemblies (referred to as Batch 25) and 17 reinsert assemblies from the spent fuel pool. The resulting core will allow restart and operation of Oconee Unit 2 Cycle 23 at full design power (2568 MWth) for a cycle length of 508 +/- 10 EFPD.

No new fuel assembly types are being used in 02C23. The fresh fuel assemblies are type Mk-B I IA; the third such batch of fuel used in Unit 2.

All of the reinserted fuel from the spent fuel pool is of the Mk-B1 1 type.

Sixteen of the reinserts from the spent fuel pool are from the 02C21 discharged assemblies and were selected for insertion on the periphery of the core. One reinsert from the spent fuel pool is from the 02C20 discharge assemblies which was selected for the core center position.

The Batch 25 fuel enrichments are comparable to previous core designs.

The cycle design length is comparable to previous cycles, with both a Tavg reduction and power coastdown utilized to reach the end-of-window burnup. Due to steam generator performance issues, the end-of-cycle Tavg reduction may not occur, which would be compensated for by a longer power coastdown.

Other changes to the core design are nominally expected from cycle-to-cycle. Such changes include initial core loading (MtU), batch average burnups, and LBP B-4C wt % and reinsertion. 02C23 places second burn fuel beneath the APSRs rather than third burn fuel like 02C22, but both cycles successfully completed the Reload Design Safety Analysis Review (REDSAR) process.

The Reload Change Document also indicates that 02C23 will have minor core power distribution changes with respect to the previous cycle. The

U.S. Nuclear Regulatory Commission Page 36 of 46 magnitude, location, and time in life of the maximum fuel assembly and pin peaking changes from 02C22 to 02C23. Changes such as this, as well as marginal changes in rod worth, critical boron concentration and other physics parameters are expected to occur between cycles and are confirmed to be satisfactory through the Reload Design Safety Analysis Review (REDSAR) process.

The reload is designed using NRC reviewed and approved methods (Technical Specification 5.6.5.b) and the 02C23 Core Operating Limits Report complies with Technical Specification 5.6.5.

Evaluation: The subject evaluation was performed to install the core designed for Oconee Nuclear Station Unit 2 Cycle 23. The 02C23 Reload Design Safety Analysis Review (REDSAR), performed in accordance with Nuclear Engineering Division procedure NE-102, "Workplace Procedure for Nuclear Fuel Management", and the 02C23 Reload Safety Evaluation confirm the UFSAR accident analyses remain bounding with respect to predicted 02C23 safety analysis physics parameters (SAPP), and fuel thermal and mechanical performance limits. The SAPP method is described in topical report DPC-NE-3005-PA.

The 02C23 Core Operating Limits Report (COLR) was prepared in accordance with Technical Specification 5.6.5. Based on the above, there were no safety concerns. No Technical Specification or Bases, UFSAR or Selected Licensee Commitments needs to be changed due to this Core Reload Design Change. Prior NRC review and approval is not required.

Type: Nuclear Station Modification

Title:

Oconee Unit 3 Cycle 23 (03C23) Reload Core Design

==

Description:==

The purpose of this change is to replace 69 spent fuel assemblies used in Cycle 22 with 60 fresh fuel assemblies (referred to as Batch 25) and 9 reinsert assemblies from the spent fuel pool. In addition, the Westinghouse LTA program will continue for its second cycle with 4 WH-177 type assemblies remaining from 03C22. The resulting core will allow restart and operation of Oconee Unit 3 Cycle 23 at full design power (2568 MWth) for a cycle length of 501 +

10 EFPD. Following a brief description of the composition of the core design for cycle 23, the changes between 03C22 and 03C23 identified in Reference 6 are detailed below.

No new fuel assembly types are being used in 03C23. The fresh fuel assemblies are type Mk-B 1 IA; the second batch of fuel used in Unit 3. Of

U.S. Nuclear Regulatory Commission Page 37 of 46 the reinserted fuel, eight assemblies are of the Mk-B IOL type. These assemblies were selected for insertion on the peripherary of the core and will be burned for their 4th cycle. A single Mk-B 11 assembly is reinserted from the spent fuel pool for its 3rd cycle, and is located in the center position. The four WH-177 LTA are burned for a second cycle in the H10 and L8 positions with quarter core symmetry.

Fuel cycle design changes between the previous cycle and 03C23 are discussed first. Many fuel cycle design parameters are expected to nominally change from cycle-to-cycle. Such parameters include fuel assembly and fuel rod exposures at the start of and projected values at the end of the cycle. In each instance and where applicable, exposures remain bounded by burnup limits. Likewise, changes in feed batch enrichment, number and composition of LEP assemblies, and number of feed batch assemblies are expected from cycle-to-cycle and confirmed to be bounded by applicable limits in the reload process. Lastly, the design cycle length (501 +1- 10 EFPD) for 03C23 is greater than 03C22.

Evaluation: The subject evaluation was performed to install the core designed for Oconee Nuclear Station, Unit 3 cycle of operation number 23 (03C23).

The 03C23 Reload Design Safety Analysis Review (REDSAR),

performed in accordance with Nuclear Engineering Division procedure NE-102, "Workplace Procedure for Nuclear Fuel Management", and the 03C23 Reload Safety Evaluation (Duke Energy design calculation OSC-8893) confirm the UFSAR accident analyses remain bounding with respect to the predicted 03C23 physics parameters and fuel thermal and mechanical performance limits.

The 03C23 Core Operating Limits Report (COLR) was prepared in accordance with Technical Specification 5.6.5. Based on the above, there were no safety concerns. No Technical Specification or Bases, UFSAR or Selected Licensee Commitments needs to be changed due to this Core Reload Design Change. Prior NRC review and approval is not required.

Type: Selected Licensee Commitments

Title:

This activity introduces a new Selected License Commitment (SLC), 16.9.11.a, "Auxiliary Building Flood Protection Measures", to establish limiting conditions of operation for barriers, detection devices, and mitigating equipment important to auxiliary building flood protection.

==

Description:==

The proposed SLC typically ensures that equivalent or better forms of protection are introduced if the any of the SSCs currently described in the UFSAR are taken out of service. The SLC also ensures that a risk assessment and compensatory actions are taken if any SSCs that provide

U.S. Nuclear Regulatory Commission Page 38 of 46 protection against or during an auxiliary flooding are taken out of service.

Some of the SSCs included in the SLC are not currently described in the UFSAR, but provide additional defense in depth beyond those described.

The risk assessment required by the SLC will be based on overall plant status. For instance, an unmitigated auxiliary building flood might eventually submerge the HPI pump motors if not isolated. If backup sources of seal cooling to the Reactor Coolant Pumps (RCPs) via the Component Cooling (CC) pumps or the Safe Shutdown Facility (SSF) were not available, the risk of a seal LOCA increases. Compensatory actions are developed accordingly.

Evaluation: This activity introduces a new Selected License Commitment (SLC),

16.9.11.a, "Auxiliary Building Flood Protection Measures", to establish limiting conditions of operation for barriers, detection devices, and mitigating equipment important to auxiliary building flood protection. The activity does not introduce or alter a procedure or methodology. The activity also does not introduce a test or experiment not described in the UFSAR. The UFSAR currently describes four SSCs that are used to prevent or mitigate an Auxiliary Building Flood. SSCs are as follows:

• Isolation valves used to prevent flooding from the fire protection system

• Flow limiting valves that restrict the break flow rate

" Manual isolation valves that are used by operators to terminate break flow

" High level room building sump alarms Since the SLC recognizes that these SSCs may be out of service for a short period of time and takes actions accordingly, the design function of those SSCs could, in theory, be adversely impacted. However, the 50.59 evaluation shows that the lack of the function for a pre-determined period results in less than a minimal increase in malfunction or that equivalent or better means of protection is afforded during that period.

Based on the above, there were no safety concerns. No Technical Specification or Bases, UFSAR needs to be changed due to this new Selected Licensee Commitment. Prior NRC review and approval is not required.

Type: Selected Licensee Commitments

Title:

A new Selected Licensee Commitment (SLC) (16.10.8) is proposed for new automatic isolation valves and new bypass valves associated with the series of modifications (Upper Surge Tank Inventory Protection modification).

U.S. Nuclear Regulatory Commission Page 39 of 46

==

Description:==

One set of the new automatic isolation valves provides isolation to the flow path from the Upper Surge Tank (UST) to the hotwell if the UST reaches a specified level. A manual bypass valve and flow path is provided around these two valves. A second set of automatic isolation valves are in the flow path from the UST to the polishing demineralizer backwash pump suction piping. The UST is the assured water source for the EFW System.

The SLC is to be applicable only to those units that have the modifications installed. The SLC is to provide conditions and actions for inoperable automatic isolation valves and for conditions in which the bypass valve is open. The SLC addresses conditions and required actions for three conditions. Condition A is the inoperability of one of the required in-series automatic isolation valves for either the UST to hotwell path (containing valves C-903 and C-904) or the UST to polishing demineralizer backwash pump suction piping path (containing valves C-906 and C-907). Condition B is the inoperability of both of the required in-series automatic isolation valves for either UST diversion path.

Condition C is the opening of the manual bypass valve C-912.

The SLC is desired to assist in protecting a commitment for the UST single failure protection. The proposed SLC that is being addressed in this 10 CFR 50.59 is attached.

Evaluation: The new SLC action statements point to the EFW technical specification (3.7.5) since the redundant valves in series addressed in the SLC are the QA-1 safety related components that are required to isolate the EFW suction source to meet the single failure criterion. For a single failure vulnerability (SLC Condition A) or a potential loss of safety function of isolating the UST (SLC Condition B), the SLC action is to enter an equivalent technical specification condition for the same vulnerabilities in the EFW System.

The condition of an open bypass valve is addressed by UFSAR Section 3.7.3.9, which addresses seismic boundary valves. Valve C-912 is a seismic boundary valve. This UFSAR section provides information that it is acceptable to open normally closed manual seismic boundary valves provided the opening and closing of these valves is controlled by approved plant procedures and the valve will be open for a required operating evolution with a clearly definable beginning and end time. Examples given in the UFSAR section include makeup. Makeup from the UST to the hotwell would be the reason the bypass valve would be opened in the event that automatic isolation valves in the hotwell makeup path were closed or isolated.

U.S. Nuclear Regulatory Commission Page 40 of 46 The SLC provides a definable time that begins when the prerequisite conditions are met and ends at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The SLC bases also provide information that the bypass valve would only be opened temporarily to allow continued unit operation. The bases to the SLC provide the requirement to have procedures to control the evolution. Although the UFSAR allows for the opening and closing of the seismic boundary valve, the SLC action statement requires entry into TS Condition B, which is for only one flow path being available (vulnerable to a single failure). The entry into the TS condition is an extra conservatism for the opening of the seismicboundary valve. The prerequisite conditions in the SLC for opening the bypass valve include maximizing the UST level, placing a dedicated operator in the vicinity of C-912 in constant communication with the control room, and isolating the flow path containing C-176 and C-187.

These required actions are a preventative measure to reduce the possibility that the required minimum water level (volume) in the UST would be reached, which would require entry into TS 3.7.6. The required actions also include closing C-912 if the UST level reaches 7.5 feet to protect the inventory immediately available for the EFW System. The requirement to maximize level in the UST before entering the Condition increases the amount of time that the UST would be available as the EFW suction source before swap over to the hotwell is required. The requirement to dedicate an operator, who is in continuous communication with the control room, and is located in the vicinity of C-912, ensures the valve can be closed expeditiously if required. Isolating the large flow paths containing valves C-176 and C-187 prevents control system failures associated with those valves from consuming UST water rapidly and increases the time available for a dedicated operator in the vicinity of C-912 to close either C-912 or C-902. Valve C-902 is a manual isolation valve in the header supplying valves C903 and C904.

Since these SLC conditions either equate to corresponding EFW operability conditions and actions or are specifically allowed by the UFSAR. Based on the above, there were no safety concerns. No Technical Specification or Bases, UFSAR needs to be changed due to this new Selected Licensee Commitment. Prior NRC review and approval is not required.

Type: Selected Licensee Commitments

Title:

Change to SLC 16.5.3, "Loss of Decay Heat Removal," to remove a non-conservative containment closure time following a loss of decay heat event.

U.S. Nuclear Regulatory Commission Page 41 of 46

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Description:==

Selected Licensee Commitment (SLC) 16.5.3, "Loss of Decay Heat Removal," is being changed to require the capability to achieve containment closure from "within 2 1/22 hours" to "prior to core uncover" applicable whenever the Reactor Cooling System (RCS) level is reduced below 50-inches on LT-5, a.k.a. "reduced inventory" and there is fuel in the vessel. The SLC currently allows 2 1/2 hours to complete containment closure actions, as required by NRC Generic Letter (GL) 88-17. This complies with the literal requirements imposed by the GL but does not meet the intent. The GL was issued with the intent of preventing core uncovery, after a Loss of Decay Heat Removal (DHR) event and while in a reduced inventory state (specific details are described below).

At the time the GL was issued in 1988, the NRC provided a time of 2 1/22 hours for containment isolation from the initial loss of DHR in lieu of analytically determined times. The NRC then went on to state: "These times may be modified as soon as suitable analyses provide better estimates of the time between loss of DHIR and core uncovery." However, when this criterion was imposed, operating cycles were much shorter, refueling outages were much longer, and crud burst cleanup times were routinely greater than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. At that time, the drain down to hot mid-loop typically occurred no sooner than 5 or 6 days into the refueling outage, when decay heat load was much lower than today. This typically allowed for much more than the 2 1/22 hours after a loss of DHR event before core uncovery could possibly occur. Given those conditions, the 2 1/22 hour criterion given in the current SLC was appropriate. However, in the late 1990's and early 2000's, longer operating cycles and outage efficiency gains allowed the station to enter hot mid-loop quicker after reactor shutdown which ultimately challenged the SLC 2 1/22 hour time to core uncovery criteria. As such, the current SLC criterion is non-conservative. Consequently, a more conservative criterion is needed to ensure containment closure capability given the quicker transition times to reduced inventory conditions.

The "worse case" of time to core uncovery has been determined to be 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 31 minutes with RCS level at +14 - inches on LT-5, 1 day after shutdown. This time and RCS level are believed to be sufficiently conservative based on operating experience, and still provides an achievable time to core uncovery/containment closure target. At the end of 2005, three (3) Operations teams completed timed validations for containment closure from outside containment as per Enclosure 5.1 of the appropriate AP. Results revealed that containment could be secured in about 1-hour (actual times varied between 58 minutes and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 13 minutes. Due to the similarity in plant layout and piping configuration between all three Oconee Units, the timed exercise was conducted on a single unit. Duke also included additional conservatisms by taking

U.S. Nuclear Regulatory Commission Page 42 of 46 penalties for Loss of Power and some manual positioning. For any action required inside containment that is not covered by procedure and in accordance with the intent of GL 88-17, Duke has established an administrative program to assure that actions inside containment can be performed as required prior to time to core boil plus habitability time that will vary from cycle to cycle due to differing core parameters. For ONS, this habitability time is 30 minutes.

Specific procedures that address containment closure control, unit shutdown, and loss of decay heat removal, have been reviewed and revised to address the time allowed.

The SLC is also being enhanced by addition of two specific candidate required actions, either of which must be initiated immediately when one or more of the nine (9) initial conditions (given in the SLC) are not met.

The existing SLC only required action to be taken "as directed by the Station Manager or Responsible Group Superintendent," which was deemed to be inadequate guidance. While this is likely to have led to the same response, the change will remove all uncertainty about the adequacy of the required actions.

Other minor changes to the SLC will be implemented which are editorial or administrative in nature.

Evaluation: Generic Letter 88-17 was issued to address concerns about risk resulting from a Loss of DHR event during mid-loop operation. The NRCs evaluation concluded that for B&W plants, establishing containment closure within 2 1/2/ hours would ensure the closure of containment prior to core uncovery, and thus protect the public health and safety by preventing offsite release of airborne radionuclides as a result of such an event.

Changes in core design, including increased fuel enrichment and the trend toward shorter refueling outages have resulted in earlier reduced inventory operation at higher decay heat loads than that utilized in the late 1980s.

This has led to operating conditions in which core uncovery could occur in less than the 2 1/2/2 hours recommended in the Generic Letter.

SLC 16.5.3 will be changed to remove the "within 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />" criterion and replace it with "prior to core uncovery," with the new criterion representing a range of required closure times that will vary as time to core uncovery varies. Changes to the SLC Bases are also being made to acknowledge the new containment closure requirement, reinforce the GL 88-17 expectations that containment closure times consider potential harsh environment effects, and identify the Loss of DHR procedure as the location for "time to core uncovery" information. Clarification is also

U.S. Nuclear Regulatory Commission Page 43 of 46 provided to note that containment closure boundary qualifications for loss of decay heat removal are similar to those credited during movement of recently irradiated fuel as discussed in TS 3.9.3 bases. The term "recently irradiated" was added to distinguish between the requirements of this SLC and normal fuel movement containment closure requirements.

This evaluation concludes that adding a more restrictive containment closure requirement while in reduced inventory operation (RCS level less than 50-inches on LT-5) does not increase the probability or consequences of an accident or equipment malfunction previously evaluated in the UFSAR. In fact, the more restrictive containment closure times serve to potentially reduce the consequences of a Loss of Decay Heat Removal event while in a reduced inventory state. No new accidents could be created by this change, and equipment failure results are unchanged.

There is no change to design limits on fission product barriers and the existing design limits will not be exceeded as a result of this change.

There are no changes to any methodology associated with the design basis or the safety analyses.

Based on the above, there were no safety concerns. No Technical Specification or Bases, UFSAR needs to be changed due to this Selected Licensee Commitment. Prior NRC review and approval is not required.

Type: UFSAR Change Number 06-14

Title:

Oconee Nuclear Station Rod Ejection Accident UFSAR Section 15.12.6, Table 15-16 Changes

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Description:==

The Oconee UFSAR is updated to reflect revisions to the Chapter 15.12 Rod Ejection Accident (REA) dose analysis. The revision to the REA calculation supporting the UFSAR is required to incorporate previously reviewed and approved technical specification changes. The changes affecting the REA analysis include removing credit for the Penetration Room Ventilation System (PRVS) filters in the dose analyses (T.S. 3.7.10 and 5.5.12), and reducing the maximum allowable containment leakage rate in T.S. 5.5.2 from 0.25% to 0.20% of containment air weight per day.

The net effect of these changes is an increase in the unfiltered leakage from containment from 0.1375% to 0.20% (where the 0.1375% was based on 90% filter efficiency, 0.25% per day leakage in which 50% of the leakage passes through the PRVS filters. The approval of these T.S.

changes was based on the NRC's review of the Maximum Hypothetical Accident (MHA) analysis submitted as part of the T.S. change package.

The MHA re-analysis confirmed doses would continue to satisfy regulatory limits following incorporation of the T.S. changes.

U.S. Nuclear Regulatory Commission Page 44 of 46 The DPCo submittal did not include nor did the NRC request additional information addressing the impact of these changes on other accident dose analyses. Besides the MHA, only the REA dose analysis requires containment integrity and postulates fuel failure (i.e. fuel failures that produce RCS specific activity greater than the limits defined in T.S.

3.4.11). Increasing the amount of unfiltered leakage results in an increase in the dose consequences for the REA. The following evaluation assumes the de facto interdependence of the changes, as the NRC approved them coincidentally.

The UFSAR changes necessary to implement the revised technical specifications for the REA include the following:

(a) UFSAR Sect. 15.12.6 is updated to remove the sentence describing credit for PRVS filtration (b) UFSAR Table 15-16 is updated to reflect the dose results of the new REA analysis The NRC states in Reference 5 that "the PRVS is not on the primary success path in the mitigation of a DBA." Furthermore, "the PRVS will not be credited for evaluating potential control room and off-site doses."

Therefore, the first change (a) to the UFSAR may be considered part of the approved technical specification change package and is not evaluated here beyond its impact as a revision to an input assumption in the dose calculation.

Note that no UFSAR changes are needed in Section 15.12 to reflect the reduced containment leakage rate since the UFSAR states that "the assumed containment leak rate is the maximum rate allowed by Technical Specifications." This statement remains valid. The change in the containment air leak rate is properly characterized as input assumption in the dose calculation as well.

Therefore, this 10 CFR 50.59 evaluation is narrowly focused on how the approved technical specifications affect the licensing basis REA environmental consequences. The net impact of the changes is to increase the dose consequences resulting in a revision to the UFSAR (item (b) above).

Evaluation: The proposed activity under evaluation is a change to the Oconee Nuclear Station (ONS) Updated Final Safety Analysis Report (UFSAR) environmental consequences for the rod ejection accident (REA) located in Chapter 15 Section 12.6.

U.S. Nuclear Regulatory Commission Page 45 of 46 The 10 CFR 50.59 evaluation considers two changes to the technical specifications that affect the UFSAR presented REA. The changes to the technical specifications have been previously reviewed and approved by the NRC (refer to the Safety Evaluation by the Office of Nuclear Reactor Regulation related to Amendment No. 338 / 339 / 339 to Renewed Facility Operating License DPR-38 / 47 / 55, June 1, 2004). These changes include 1) not crediting the Penetration Room Ventilation System (PRVS) filters and 2) a reduction in the maximum allowable containment leakage rate from 0.25 to 0.20% containment air weight per day.

The net effect of these changes is to increase the amount of unfiltered containment leakage. The increase in leakage results in an increase in the radiological consequences for accidents requiring containment integrity and postulating fuel failure greater than the technical specification maximum allowed RCS specific activity. The NRC premised approval of the technical specification changes given their review of the impact on the bounding Maximum Hypothetical Accident (MHA) DBA. In addition to the MHA, the REA is the only other ONS DBA that requires containment integrity and postulates fuel failure.

The 10 CFR 50.59 evaluation demonstrates that the technical specification changes' impact on the UFSAR Chapter 15 rod ejection accident dose analysis does not satisfy the criteria in 10 CFR 50.59(c)(2) requiring prior NRC approval. No technical specification changes were identified to implement theproposed activity. It can therefore be concluded the proposed activity does not require NRC approval prior to implementation.

Type: Procedure TT/3/A/0325/015

Title:

Procedure TT/3/A/0325/015 (Turbine Header Pressure Optimization Test) which will temporarily adjust Turbine Header Pressure (THP) between 885 and 910 psig.

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Description:==

This evaluation is for procedure TT/3/A/0325/015 (Turbine Header Pressure Optimization Test) which will temporarily adjust Turbine Header Pressure (THP) between 885 and 910 psig in a manner allowing collection of data at several specified pressure test plateaus for the purpose of determining the optimum Turbine Header Pressure setpoint from a perspective of maximizing Unit Gross Output.

Evaluation: This activity throttles MS control valves such that Turbine Header Pressure is increased from 885 to 910 psig. Since throttling the MS control valves is performed during normal operation to control turbine header pressure, this activity does not increase the frequency of a Turbine Trip or any other accident previously evaluated in the UFSAR. This activity satisfies none of the 10CFR50.59 criteria that would require a

U.S. Nuclear Regulatory Commission Page 46 of 46 license amendment. This activity has been evaluated by the Duke Energy Safety Analysis Group and determined to be bounded by existing Updated Final Safety Analysis Report (UFSAR) transient and accident analyses.

Their evaluation concludes that there exists sufficient margins for every event, such that no adverse affects or safety issues exist relative to the current analyses that address the Fission Product Barriers (fuel assembly cladding, RCS pressure boundary and containment). The scope of review of the analyses was bounded by limiting the decay heat load and range of MS pressures. This was performed by restricting the time span for performing the test to the first 300 EFPD (Effective Full Power Days) and maintaining the range of MS pressures between 885 and 910 psig. There is no impact on the safety analyses or dose consequences. The failure modes for the Main Steam System and related Structures, Systems and Components (SSC's) remain the same. Performing this test maintains the operation of the Main Steam (MS) and related SSC's within design limits and will not result in an accident initiator. Since the proposed test's method of adjusting Turbine Header Pressure is unchanged and within an acceptable normal pressure range that is less than the affected SSC Design Pressures, the postulated failure modes will be the same and with the same or acceptable results. The proposed activity's 'method' of adjusting Turbine Header Pressure is via use of the ICS Turbine Header Pressure Control Station using the setpoint adjustment knob and is not a change from a method of performance. The 'magnitude' and 'range' of the proposed test's Turbine Header Pressure adjustment does not adversely impact the normal and post-trip operation or performance of the Main Steam System or related SSC's. The Duke Energy Safety Analysis Group evaluation of consequences on UFSAR transients and accidents bounds the consequences of SSC malfunctions. The scope of the evaluation is the effect on the UFSAR transient and accident analyses. These analyses are based on currently approved NRC methods. Available margins in these analyses are considered relative to the proposed THP test. No new analyses, revised analyses, or methods are implemented for this evaluation.

Based on the above, there were no safety concerns. There were no Technical Specification, UFSAR and Selected Licensee Commitments changes required. Prior NRC review and approval is not required